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, by competition in the particular geographic areas that we serve and by 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.
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 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.
In addition, we currently process volumes of lower cost crude oils, such as regional sour, heavy Canadian and Black Wax. As part of our current capital initiatives, we plan on providing additional flexibility to both our Navajo and Woods Cross Refineries that will allow us to process a greater degree of these lower cost crude oils. In recent years, the spread or differential between these lower cost heavy/sour crude oils and higher priced light/sweet crude oils has widened. A substantial or prolonged decrease in these crude oil differentials could negatively impact our earnings and cash flows.
We may not be able to successfully execute our business strategies to grow our business.
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 can be processed, increase refinery production capacity, meet new governmental requirements, or maintain the operations of our existing assets. The construction process involves numerous regulatory, environmental, political, and legal uncertainties, most of which are not fully within our control. These projects may not be completed on schedule or at all or at the budgeted cost. 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.
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. 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.
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 or may not produce the results intended. 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.
We may incur significant costs to comply with new or changing environmental, 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 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.
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 of.
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. 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.
For additional information on regulations and related liabilities or potential liabilities affecting our business, see “Regulation” under Items 1 and 2, “Business and Properties.”
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 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 phases of the refining industry.
We are not engaged in any significant 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.
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.
Other refiners could expand existing facilities or build new ones in our markets and significantly affect our profitability. For example, Arizona Clean Fuels Yuma, LLC has obtained a permit to construct a 150,000 BPD refinery in Arizona and is currently seeking financing for that project.
We may not be able to retain existing customers or acquire new customers.
The renewal or replacement of existing sales agreements with our customers 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.
A material decrease in the supply of crude oil available to our refineries could significantly reduce our production levels.
In order to maintain or increase production levels at our refineries, we must continually contract for new crude oil supplies. 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 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.
The potential operation of new refined product transportation pipelines or disruption or proration of existing pipelines could impact the supply of refined products to our existing markets, including El Paso, Albuquerque and Phoenix.
The Longhorn Pipeline is an approximately 72,000 BPD common carrier pipeline that delivers 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. Deliveries of refined products shipped on the Longhorn Pipeline increased significantly during 2007, and we believe the Longhorn Pipeline is currently operating near full capacity. Longhorn Partners Pipeline, L.P., owner of the Longhorn Pipeline, has also announced a planned expansion of its pipeline throughput capacity from 72,000 BPD to 125,000 BPD. Also in 2007, Kinder Morgan completed an expansion of its El Paso, Texas to Tucson and Phoenix, Arizona pipeline, increasing its capacity to approximately 200,000 BPD. Increased supplies of refined product delivered by the Longhorn Pipeline and Kinder Morgan’s El Paso to Phoenix pipeline could result in additional downward pressure on wholesale refined product prices and refined product margins in El Paso, Arizona and related markets.
An additional factor that could affect some of our markets is the presence of pipeline capacity from the West Coast into our Arizona markets. Additional increases in shipments of refined products from the West Coast into the Arizona markets could result in additional downward pressure on refined product prices in these markets.
In addition to the projects described above, other projects have been explored from time to time by refiners and other entities which if completed, could result in further increases in the supply of products to our markets.
In the case of the Albuquerque market, the common carrier pipeline we use to serve this market out of El Paso currently operates at near capacity. However, through our relationship with HEP, our Navajo Refinery has pipeline access to the Albuquerque vicinity and to Bloomfield, New Mexico, that will permit us to deliver a total of up to 45,000 BPD of light products to these locations, thereby eliminating the risk of future pipeline constraints on shipments to Albuquerque. If needed, additional pump stations could further increase HEP’s pipeline capabilities. Any future pipeline constraints or disruptions affecting our ability to transport refined products to Arizona or Albuquerque could, if sustained, adversely affect our results of operations and financial condition.
For additional information on competition in our markets due to new product transportation pipelines or proration of existing pipelines, see “Markets and Competition” under the “Navajo Refinery” discussion under Items 1 and 2, “Business and Properties.”
We depend upon HEP for a substantial portion of the distribution network for our refined products and we own a significant equity interest in HEP.
We currently own a 45% interest in HEP, including the 2% general partner interest. HEP operates a system of refined product pipelines and distribution terminals in Texas, New Mexico, Utah, Arizona, Idaho, Washington and Oklahoma. HEP generates revenues by charging tariffs for transporting refined products 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 and Utah under two 15-year pipelines and terminals agreements expiring in 2019 and 2020. The agreements provide that we transport or terminal volumes on certain of HEP’s facilities that result in revenues to HEP at least equal to specified minimum revenue amounts annually. Furthermore, through our 45% ownership of HEP, we record our share of HEP’s earnings and receive distributions from 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.
The occurrence of any of these risks adversely impacting HEP could affect our distribution system or the earnings and cash flows we receive from HEP and thereby adversely affect our results of operations and financial condition.
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, 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. 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 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 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.
We are exposed to the credit risks of our key customers.
We are subject to risks of loss resulting from nonpayment or nonperformance by our 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.
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. 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.
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.
Item 1B.
Item 1B. Unresolved Staff Comments
We do not have any unresolved staff comments.
Item 3.
Item 3. Legal Proceedings
On May 29, 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 Federal Energy Regulatory Commission (“FERC”) in proceedings brought by us and other parties against SFPP. These proceedings relate to tariffs of common carrier pipelines, which are owned and operated by SFPP, for shipments of refined products from El Paso, Texas to Tucson and Phoenix, Arizona and from points in California to points in Arizona. We are one of several refiners that regularly utilize the SFPP pipeline to ship refined products from El Paso, Texas to Tucson and Phoenix, Arizona. The Court of Appeals in its May 29, 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 by partnerships and ruled in our favor on an issue relating to our rights to reparations when it is determined that certain tariffs we paid to SFPP in the past were too high. We currently estimate that, as a result of this 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 million we received in 2003 from SFPP as reparations for the period from 1992 through July 2000. Because proceedings in the FERC following the Court of Appeals decision have not been completed and final action by the FERC could be subject to further court proceedings, it is not possible at this time to determine what will be the net amount payable to us at the conclusion of these proceedings. We and other shippers have been engaged in settlement discussions with SFPP on remaining issues in the FERC proceedings. These discussions resulted in a partial settlement, which became final in February 2008, providing for a payment to us of approximately $1.3 million with respect to our shipments from El Paso to Tucson and Phoenix for the period from June 1, 2006 through November 30, 2007. The partial settlement leaves for resolution in pending proceedings all remaining issues for other periods.
In January 2008, we settled with a mutual release our lawsuit that had been pending in the United States Court of Federal Claims against the Department of Defense relating to claims totaling approximately $299.0 million with respect to jet fuel sales by two subsidiaries in the years 1982 through 1999. Under the terms of the settlement no amount will be paid to us or by us with respect to this lawsuit.
In discussions beginning in the last half of 2005, the EPA and the State of Utah have asserted that we have Federal CAA liabilities relating to our Woods Cross Refinery because of actions taken or not taken by prior owners of the Woods Cross Refinery, which we purchased from ConocoPhillips in June 2003. We have agreed with the EPA and the State of Utah to settle the issues presented by means of an agreement for a Consent Decree. The proposed agreement, which has not yet been signed by the parties and lodged with the federal district court in Utah, includes obligations for us to make specified additional capital investments currently estimated to total approximately $17 million over several years and to make changes in operating procedures at the refinery. The proposed agreement also requires expenditures by us totaling $250,000 for penalties and a supplemental environmental project of benefit of the community in which the Woods Cross Refinery is located. The agreements for the purchase of the Woods Cross Refinery provide that ConocoPhillips will indemnify us, subject to specified limitations, for environmental claims arising from circumstances prior to our purchase of the refinery. We believe that, in the present circumstances, the amount due to us from ConocoPhillips under the agreements for the purchase of the Woods Cross Refinery would be approximately $1.4 million with respect to the anticipated settlement.
Our Navajo Refining Company subsidiary is 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. The lawsuit, as amended in October 2006 through the filing of a second amended complaint in the U.S. District Court for the Southern District of New York under multidistrict procedures, 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 claims made are for defective design or product, failure to warn, negligence, public nuisance, statutory public nuisance, private nuisance, trespass, and civil conspiracy. The second amended complaint also contains a claim, which is asserted in the complaint only against certain other defendants but which appears to be similar to a claim that has been threatened in a mailing to Navajo by law firms representing the plaintiff in this case, alleging violations of certain provisions of the Toxic Substances Control Act. The lawsuit seeks compensatory damages unspecified in amount, injunctive relief, exemplary and punitive damages, costs, attorney’s fees allowed by law, and interest allowed by law. As of the close of business on the day prior to the date of this report, Navajo has not been served in this case. At the date of this report, it is not possible to predict the likely course or outcome of this litigation.
In December 2006, the Montana Department of Environmental Quality (“MDEQ”) filed in state district court in Great Falls, Montana a Complaint and Application for Preliminary Injunction (the “Complaint”) naming as defendants Montana Refining Company (“MRC”), our subsidiary that owned the Great Falls, Montana refinery until it was sold to an unrelated purchaser in March 2006, and the unrelated company that purchased the refinery from MRC. The MDEQ asserts in the Complaint that the Great Falls refinery exceeded limitations on sulfur dioxide in the refinery’s air emission permit on certain dates in 2004 and 2005 and in 2006 both before and after the sale of the refinery, erroneously certified compliance with limitations on sulfur dioxide emissions, failed to promptly report emissions limit deviations, exceeded limits on sulfur in fuel gas on specified dates in 2005, failed in 2005 to conduct timely testing for certain emissions, submitted late a report required to be submitted in early 2006, failed to achieve a specified limitation on certain emissions in the first three quarters of 2006, and failed to timely submit a report on a 2005 emissions test. The Complaint sought penalties under applicable law of up to $10,000 per violation and an order enjoining MRC and the current owner of the refinery from further violations. While we do not agree with a number of the violations asserted in the Complaint, we and the current owner of the Great Falls refinery have negotiated with the MDEQ both before and after the filing of the Complaint to attempt to settle the issues raised on a compromise basis. At the date of this report, we have negotiated a tentative settlement agreement, which has not yet been put into a signed agreement, under which we would make payments totaling approximately $100,000.
We are a party to various other litigation and proceedings not mentioned in this report which we believe, based on advice of counsel, will not have materially adverse impact on our financial condition, results of operations or cash flows.
Item 4.
Item 4. Submission of Matters to a Vote of Security Holders
No matter was submitted to a vote of security holders during the fourth quarter of 2007.
PART II
Item 5.
Item 5. Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
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 (adjusted for the two-for-one stock split effective June 1, 2006) for the periods indicated:
As of February 7, 2008, we had approximately 39,800 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 limits the payment of dividends. See Note 11 in the “Notes to Consolidated Financial Statements” under Item 8, “Financial Statements and Supplementary Data.”
During 2007, our Board of Directors authorized a total increase of $300.0 million to our 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. The following table includes repurchases made under this program during the fourth quarter of 2007.
On February 25, 2008 our Board of Directors declared a regular quarterly cash dividend of $0.15 per share, payable April 2, 2008 to holders of record on March 19, 2008.
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 Form 10-K.
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.
OVERVIEW
We are principally an independent petroleum refiner operating two refineries in Artesia and Lovington, New Mexico (operated as one refinery) and Woods Cross, Utah. As of December 31, 2007, our refineries had a combined crude capacity of 111,000 BPSD. Our profitability depends largely on the spread between market prices for refined petroleum products and crude oil prices. At December 31, 2007, we also owned a 45% interest in HEP, which owns and operates pipeline and terminalling assets and owns a 70% interest in Rio Grande.
Our principal source of revenue is from the sale of high value light products such as gasoline, diesel fuel and jet fuel in markets in the southwestern and western United States. Our sales and other revenues and net income for the year ended December 31, 2007 were $4,791.7 million and $334.1 million, respectively. Our sales and other revenues and net income for the year ended December 31, 2006 were $4,023.2 million and $266.6 million, respectively. Our principal expenses are costs of products sold and operating expenses. Our total operating costs and expenses for the year ended December 31, 2007 were $4,325.4 million, an increase from $3,661.3 million for the year ended December 31, 2006.
On March 31, 2006 we sold our Montana Refinery to Connacher. The net cash proceeds we received on the sale of amounted to $48.9 million, net of transaction fees and expenses. Additionally we received 1,000,000 shares of Connacher common stock valued at $4.3 million at March 31, 2006. We have presented the results of operations of the Montana Refinery and a net gain of $14.0 million on the sale in discontinued operations.
During 2007, our Board of Directors authorized a total increase of $300.0 million to our 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. During the year ended December 31, 2007, we repurchased 4,022,285 shares at a cost of $211.1 million (of which $12.0 million of the cash settlement was after December 31, 2007) or an average of $52.49 per share. Since inception of our common stock repurchase initiatives beginning in May 2005 through December 31, 2007, we have repurchased 13,530,906 shares at a cost of $518.1 million or an average of $38.29 per share. At December 31, 2007, we had $181.9 million of authorized repurchases remaining under our program.
RESULTS OF OPERATIONS
Financial Data
Balance Sheet Data
Other Financial Data
(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, depletion and amortization. EBITDA is not a calculation provided for under accounting principles generally accepted in the United States; 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. We are reporting EBITDA from continuing operations. EBITDA presented above is reconciled to net income under “Reconciliations to Amounts Reported Under Generally Accepted Accounting Principles” following 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 earnings before interest, taxes, depreciation and amortization (“EBITDA”) to amounts reported under generally accepted accounting principles in financial statements.
Earnings before interest, taxes, depreciation and amortization, which we refer to as EBITDA, is calculated as net income plus (i) interest expense, net of interest income, (ii) income tax provision, and (iii) depreciation, depletion and amortization. EBITDA is not a calculation provided for under accounting principles generally accepted in the United States; 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. We are reporting EBITDA only from continuing operations.
Set forth below is our calculation of EBITDA from continuing operations.
Reconciliations of refinery operating information (non-GAAP performance measures) to amounts reported under generally accepted accounting principles in financial statements.
Refinery gross margin and net operating margin are non-GAAP performance measures that are used by our management and others to compare our refining performance to that of other companies in our industry. We believe these margin measures are helpful to investors in evaluating our refining performance on a relative and absolute basis.
We calculate refinery gross margin and net operating margin using net sales, cost of products and operating expenses, in each case averaged per produced barrel sold. These two margins do not include the effect of depreciation, depletion 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.
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 all of our refineries on a consolidated basis is calculated as shown below.
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 all of our refineries on a consolidated basis is calculated as shown below.
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 revenue
(1)
We purchase finished products when opportunities arise that provide a profit on the sale of such products, or to meet delivery commitments.
(2)
We purchase crude oil and enter into buy/sell exchanges in excess of the needs to supply our refineries. Certain direct sales of this excess crude oil are made to purchasers or users of crude oil. Under new accounting guidance, these sales and related purchases starting April 1, 2006 are being measured at fair value and accounted for as revenues with the related acquisition costs included as cost of products sold. Prior to April 1, 2006, sales and cost of sales attributable to such excess crude oil direct sales were netted and presented in cost of products sold.
(3)
Other refining segment revenue includes the incremental revenues associated with Holly Asphalt subsequent to February 2005 and revenue derived from 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.
Reconciliation of average cost of products per produced barrel sold to total costs of products sold
(1)
We purchase finished products when opportunities arise that provide a profit on the sale of such products, or to meet delivery commitments. Additionally during 2005, we entered into petroleum futures transactions hedging forecasted diesel fuel sales. The positions were fully liquidated during August to November 2005 resulting in gains of $3.2 million for the year ending December 31, 2005, which are recorded as a reduction in cost of products sold.
(2)
We purchase crude oil and enter into buy/sell exchanges in excess of the needs to supply our refineries. Certain direct sales of this excess crude oil are made to purchasers or users of crude oil. Under new accounting guidance, these sales and related purchases starting April 1, 2006 are being measured at fair value and accounted for as revenues with the related acquisition costs included as cost of products sold. Prior to April 1, 2006, sales and cost of sales attributable to such excess crude oil direct sales were netted and presented in cost of products sold.
(3)
Other refining segment costs of products sold includes the incremental costs of products for Holly Asphalt subsequent to February 2005 and costs attributable to sulfur credit sales.
(4)
The above calculations of costs of products from produced products sold can also be computed on a consolidated basis. These amounts may not calculate exactly due to rounding of reported numbers.
Reconciliation of average refinery operating expenses per produced barrel sold to total operating expenses
(1)
Other refining segment operating expenses include the marketing costs associated with our refining segment and the incremental operating expenses of Holly Asphalt subsequent to February 2005.
(2)
The above calculations of refinery operating expenses from produced products sold can also be computed on a consolidated basis. These amounts may not calculate exactly due to rounding of reported numbers.
Reconciliation of net operating margin per barrel to refinery gross margin per barrel to total sales and other revenues
(1)
We purchase finished products when opportunities arise that provide a profit on the sale of such products or to meet delivery commitments.
(2)
We purchase crude oil and enter into buy/sell exchanges in excess of the needs to supply our refineries. Certain direct sales of this excess crude oil are made to purchasers or users of crude oil. Under new accounting guidance, these sales and related purchases starting April 1, 2006 are being measured at fair value and accounted for as revenues with the related acquisition costs included as cost of products sold. Prior to April 1, 2006, sales and cost of sales attributable to such excess crude oil direct sales were netted and presented in cost of products sold.
(3)
Other refining segment revenue includes the revenues associated with Holly Asphalt subsequent to February 2005 and revenue derived from 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.
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, 2007 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 believes that, as of December 31, 2007, the Company maintained effective internal control over financial reporting.
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, 2007. That report appears on page 55.
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, 2007, 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.
In our opinion, Holly Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007, 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, 2007 and 2006, 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, 2007 of Holly Corporation and our report dated February 27, 2008 expressed an unqualified opinion thereon.
/s/ERNST & YOUNG LLP
Dallas, Texas
February 27, 2008
Index to Consolidated Financial Statements
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, 2007 and 2006, 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, 2007. 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.
As described in Note 1 and Note 5 to the consolidated financial statements, in 2006 and 2005, respectively, the Company adopted Statement of Financial Accounting Standards No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans” and No. 123(r), “Share-Based Payments.”
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, 2007 and 2006, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2007, 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, 2007, 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 27, 2008 expressed an unqualified opinion thereon.
/s/ ERNST & YOUNG LLP
Dallas, Texas
February 27, 2008
HOLLY CORPORATION
CONSOLIDATED BALANCE SHEETS
(In thousands, except share data)
See accompanying notes.
\
HOLLY CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
(In thousands, except per share data)
See accompanying notes.
HOLLY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
See accompanying notes.
HOLLY CORPORATION
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
(In thousands)
See accompanying notes.
HOLLY CORPORATION
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(In thousands)
See accompanying notes.
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.
We are principally an independent petroleum refiner, who produces high value light products such as gasoline, diesel fuel and jet fuel. 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. The Woods Cross refinery (“Woods Cross Refinery”), located just north of Salt Lake City, Utah, 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. In conjunction with the refining and pipeline operations, we own a system of crude oil gathering pipelines.
At December 31, 2007, we had a 45% ownership interest in Holly Energy Partners, L.P. (“HEP”). HEP has logistics assets including petroleum product pipelines located in Texas, New Mexico and Oklahoma; ten refined product terminals; two refinery truck rack facilities, a refined products tank farm facility and a 70% interest in Rio Grande Pipeline Company (“Rio Grande”), which owns a pipeline that transports liquid petroleum gases, or LPG’s, from west Texas to the Texas/Mexico border near El Paso for further transport into northern Mexico.
On March 31, 2006, we sold our petroleum refinery in Great Falls, Montana (the “Montana Refinery”) to a subsidiary of Connacher Oil and Gas Limited (“Connacher”). Accordingly, the results of operations of the Montana Refinery and a net gain of $14.0 million on the sale are shown in discontinued operations (see Note 2).
In February 2005, we purchased the remaining 51% interest in NK Asphalt Partners from our joint venture partner for $16.9 million plus working capital which increased our ownership interest from 49% to 100%. The partnership now operates under the name, Holly Asphalt Company (“Holly Asphalt”) and manufactures and markets asphalt and asphalt products in Arizona, New Mexico, Texas and northern Mexico.
We also conduct a small-scale oil and gas exploration and production program and own a 75% interest in a joint venture pipeline project (see Note 9).
Principles of Consolidation: Our consolidated financial statements include our accounts and the accounts of partnerships and joint ventures that we control through 50% or more ownership or through 50% or more variable interest in entities that are considered variable interest entities. All significant intercompany transactions and balances have been eliminated.
Use of Estimates: The preparation of financial statements in accordance with U.S. generally accepted accounting principles 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.
Reclassifications: In the December 31, 2006 consolidated balance sheet, we have reclassified $7.3 million in certain deferred maintenance costs from “prepayments and other” under current assets to “turnaround costs (long-term)” under other assets. This reclassification conforms to our December 31, 2007 balance sheet 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 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. Credit losses are charged to income when accounts are deemed uncollectible and historically have been minimal. Accounts receivable attributable to crude oil resales generally represent the sell side of reciprocal crude oil buy/sell exchange arrangements involved in supplying crude oil to the refineries and resales to other purchasers or users of crude oil with an approximate like amount reflected in accounts payable. 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 and costs at that time. Accordingly, interim LIFO calculations are based on management’s estimates of expected year-end inventory levels and costs and are subject to the final year-end LIFO inventory valuation.
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, 2007, 2006 and 2005.
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 in the period in which the liability 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.
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, 2007, we have an asset retirement obligation of $0.9 million, which is included in “Other long-term liabilities” in our consolidated balance sheets.
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. No impairments of intangibles or goodwill were recorded during the years ended December 31, 2007, 2006 and 2005.
Investment in HEP: Prior to July 1, 2005, our financial statements included the consolidated results of HEP, with the interest we did not own reported as a minority interest in the ownership and earnings. Under the provisions of Financial Accounting Standards Board (“FASB”) Interpretation No. 46 (revised) (“FIN 46”), “Consolidation of Variable Interest Entities,” we deconsolidated HEP effective July 1, 2005 and report our share of the earnings of HEP using the equity method of accounting (see Note 3).
Investments in Joint Ventures: We have accounted for investments in and earnings from joint ventures where we have ownership of 50% or less using the equity method of accounting.
Revenue Recognition: Refined product sales and related cost of sales are recognized when products are shipped and title has passed to customers. Pipeline transportation revenues are recognized as products are shipped on our 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 16 years for refining facilities, 10 to 30 years for pipeline and terminal facilities, 3 to 5 years for transportation vehicles, 10 to 40 years for buildings and improvements and 7 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. To provide the desired crude oil to our refineries, we utilize a combination of crude oil purchases from producers and other petroleum companies and enter into crude oil buy/sell exchanges. When crude oil is purchased in excess of the needs of our refineries, we may resell to other purchasers or users of crude oil. The acquisition costs related to these buy/sell crude oil transactions is recorded in cost of products sold. 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 expensed 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. Recoveries of environmental costs through insurance, indemnification arrangements or other sources are included in other assets to the extent such recoveries are considered probable. See Note 3 for indemnity arrangement with HEP.
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.
Stock-Based Compensation: In December 2004, the FASB issued SFAS No. 123 (revised), “Share-Based Payment.” This revision prescribes the accounting for a wide-range of share-based compensation arrangements, including share options, restricted share plans, performance-based awards, share appreciation rights and employee share purchase plans, and generally requires the fair value of share-based awards to be expensed on the income statement. We elected early adoption of this standard effective July 1, 2005 based on modified retrospective application with early application under SFAS No. 123 (revised) to prior quarters of 2005. Also as part of this adoption, we recorded a cumulative effect of a change in accounting principle relating to our performance units due to the initial effect of measuring these awards at fair value where they were previously measured at intrinsic value. See Note 5 for additional information regarding our adoption of SFAS No. 123 (revised).
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.
Derivative Instruments: All derivative instruments are recognized as either assets or liabilities in the balance sheet and measured at their fair value. Changes in the derivative instrument’s fair value are recognized currently in earnings unless specific hedge accounting criteria are met. See Note 16 for additional information on derivative instruments and hedging activities.
New Accounting Pronouncements:
EITF No. 06-11 “Accounting for Income Tax Benefits of Dividends on Share-Based Payment Awards”
In June 2007, the FASB ratified Emerging Issues Task Force (“EITF”) Issue No. 06-11, Accounting for Income Tax Benefits of Dividends on Share-Based Payment Awards. EITF No. 06-11 requires that tax benefits generated by dividends paid during the vesting period on certain equity-classified share-based compensation awards be classified as additional paid-in capital and included in a pool of excess tax benefits available to absorb tax deficiencies from share-based payment awards. EITF No. 06-11 is effective for fiscal years beginning after December 15, 2007. We will adopt this standard effective for our 2008 fiscal year. We do not expect the adoption of this standard to have a material impact on our financial condition, results of operations and cash flows.
SFAS No. 160 “Noncontrolling Interests in Consolidated Financial Statements - an Amendment of ARB No. 51”
In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements - an Amendment of ARB No. 51. SFAS No. 160 changes the classification of non-controlling interests, also referred to as minority interests, in the consolidated financial statements. It also establishes a single method of accounting for changes in a parent company’s ownership interest that do not result in deconsolidation and requires a parent company to recognize a gain or loss when a subsidiary is deconsolidated. SFAS No. 160 is effective for fiscal years beginning on or after December 15, 2008. Earlier adoption is prohibited. We will adopt this standard effective January 1, 2009. We are currently evaluating the impact of this standard on our financial condition, results of operations and cash flows.
SFAS No. 159 “The Fair Value Option for Financial Assets and Financial Liabilities - Including an Amendment of FASB Statement No. 115”
In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities - Including an Amendment of FASB Statement No 115. SFAS No. 159, which amends SFAS No. 115, allows certain financial assets and liabilities to be recognized, at a company’s election, at fair market value, with any gains or losses for the period recorded in the statement of income. SFAS No. 159 is effective for fiscal years beginning after November 15, 2007, and interim periods in those fiscal years. We will adopt this standard effective January 1, 2008. We do not expect the adoption of this statement to have a material impact on our financial condition, results of operations and cash flows.
SFAS No. 157 “Fair Value Measurements”
In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements. This standard simplifies and codifies guidance on fair value measurements under generally accepted accounting principles. This standard defines fair value, establishes a framework for measuring fair value and prescribes expanded disclosures about fair value measurements. This standard is effective for fiscal years beginning after November 15, 2007. We will adopt this standard effective for our 2008 fiscal year. We do not expect the adoption of this standard to have a material impact on our financial condition, results of operations and cash flows.
Interpretation No. 48 “Accounting for Uncertainty in Income Taxes”
In June 2006, the FASB issued Interpretation No. 48, Accounting for Uncertainty in Income Taxes. This interpretation clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements by prescribing a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. This interpretation also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and
transition. This interpretation is effective for fiscal years beginning after December 15, 2006. We adopted this standard effective January 1, 2007. As a result of the implementation of this standard, we recognized no material adjustment in the liability for unrecognized income tax benefits. Disclosures required by this standard are provided in Note 12.
We are subject to U.S. federal income tax and to the income tax of multiple state jurisdictions. We have substantially concluded all U.S. federal, state and local income tax matters for fiscal years through July 31, 2002. In 2006, the Internal Revenue Service commenced examinations of our U.S. federal income tax returns for the tax years ended July 31, 2003 and December 31, 2003. To date, we do not anticipate that the resolution of this audit will result in a material change to our financial condition, results of operations or cash flows.
Our policy is to recognize potential interest and penalties related to income tax matters 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.
NOTE 2: Discontinued Operations
On March 31, 2006 we sold the Montana Refinery to Connacher. The net cash proceeds we received on the sale of the Montana Refinery amounted to $48.9 million, net of transaction fees and expenses. Additionally we received 1,000,000 shares of Connacher common stock valued at $4.3 million at March 31, 2006. In accounting for the sale, we recorded a pre-tax gain of $22.3 million. The Montana Refinery assets disposed of had a net book value at March 31, 2006 of $13.7 million for property, plant and equipment, $15.4 million for inventories and $2.1 million for other assets, with current liabilities assumed amounting to $0.3 million.
We retained certain quantities of finished product inventories that were not included in the sale to Connacher. These inventories were liquidated during the second quarter of 2006.
The following tables provide summarized income statement information related to discontinued operations:
In accordance with the Montana Refinery sale agreement, we retained certain financial liabilities, including certain environmental liabilities related to required remediation and corrective action for environmental conditions that existed at the time of sale and for financial penalties for infractions that occurred prior to the sale. Based on our estimates, we have accrued $1.9 million as of December 31, 2007 related to such environmental liabilities which is included in our environmental liability accrual as discussed in Note 10.
NOTE 3: Investment in Holly Energy Partners
HEP is a publicly held master limited partnership that commenced operations July 13, 2004 upon the completion of its initial public offering. We currently have a 45% ownership interest in HEP, including our 2% general partner interest.
HEP serves our refineries in New Mexico and Utah under a 15-year pipelines and terminals agreement (“HEP PTA”) expiring in 2019 and a 15-year intermediate pipeline agreement expiring in 2020 (“HEP IPA”). Under the HEP PTA, we pay HEP fees to transport on their refined product pipelines or throughput in their terminals volumes of refined products that will result in minimum annual payments to HEP, currently $39.6 million. Under the HEP IPA, we agreed to transport minimum volumes of intermediate products on the intermediate pipelines that will result in minimum annual payments to HEP, currently $12.8 million. Minimum payments for both agreements will adjust upward based on increases in the producer price index over the term of the agreements. Additionally, we agreed to indemnify HEP up to an aggregate amount of $17.5 million for any environmental noncompliance and remediation liabilities associated with the assets transferred to HEP and occurring or existing prior to the date of the transfers of ownership to HEP. Of this total, indemnification in excess of $15.0 million relates solely to the intermediate pipelines.
On February 28, 2005, HEP closed its acquisition from Alon of four refined products pipelines, an associated tank farm and two refined products terminals. These pipelines and terminals are located primarily in Texas and transport approximately 70% of the light refined products for Alon’s refinery in Big Spring, Texas. The total consideration paid by HEP for these pipeline and terminal assets was $120.0 million in cash and 937,500 Class B subordinated units which, subject to certain conditions, will convert into an equal number of HEP common units five years after the acquisition date. Following the closing of this transaction, we owned 47.9% of HEP including the 2% general partner interest. HEP financed the Alon transaction through a private offering of $150.0 million principal amount of 6.25% senior notes due 2015 (“HEP Senior Notes”). HEP used the proceeds of the offering to fund the $120.0 million cash portion of the consideration for the Alon transaction, and used the balance to repay $30.0 million of outstanding indebtedness under HEP’s credit agreement, including $5.0 million drawn shortly before the closing of the Alon transaction. The consideration paid for the Alon pipeline and terminal assets was allocated to the individual assets acquired based on their estimated fair values. The aggregate consideration amounted to $146.6 million, which consisted of $24.7 million fair value of HEP’s Class B subordinated units, $120.0 million in cash and $1.9 million of transaction costs. In accounting for this acquisition, HEP recorded pipeline and terminal assets of $86.9 million and an intangible asset of $59.7 million, representing the value of the 15-year pipelines and terminals agreement.
On July 8, 2005, we closed on the transaction in which HEP acquired our two parallel intermediate feedstock pipelines which connect our Lovington and Artesia, New Mexico facilities (our revenue commitments on the intermediate pipelines are discussed above under the HEP IPA). The total consideration was $81.5 million, which consisted of approximately $77.7 million in cash, 70,000 common units of HEP and a capital account credit to maintain our existing general partner interest in HEP. HEP financed the $77.7 million cash portion of the consideration for the intermediate pipelines with the proceeds raised from the private sale, which closed simultaneously with the acquisition, of 1.1 million of its common units for $45.1 million to a limited number of institutional investors and the offering, completed in June 2005, of an additional $35.0 million in principal amount of HEP Senior Notes. Navajo Pipeline Co., L.P., one of our subsidiaries, agreed to indemnify HEP’s general partner to the extent it makes any payment in satisfaction of the $35.0 million of the principal amount of the HEP Senior Notes. As a result of this transaction, our ownership interest in HEP was reduced to the current 45%, including the 2% general partner interest.
HEP is a variable interest entity (“VIE”) as defined under FIN 46, and following HEP’s acquisition of the intermediate feedstock pipelines in 2005, we have determined that our beneficial variable interest in HEP was less than 50%; therefore, as required by FIN 46, we deconsolidated HEP effective as of July 1, 2005. The deconsolidation is presented from July 1, 2005 forward, and our share of the earnings of HEP, including any incentive distributions paid through our general partner interest, is now reported using the equity method of accounting. HEP has risk associated with its operations. HEP has three major customers, of which we are one. If any of the customers fails to meet the desired shipping levels or terminates its contracts, HEP could suffer substantial losses unless a new customer is found. If HEP does suffer losses, we would recognize our percentage of those losses based on our ownership percentage in HEP at that time.
We hold 7,000,000 subordinated units and 70,000 common units of HEP as of December 31, 2007. Our rights as holder of subordinated units to receive distributions of cash from HEP are subordinated to the rights of the common unitholders to receive such distributions.
In addition to the intermediate feedstock pipelines acquired by HEP in July 2005, we contributed all of the initial assets of HEP. As these transactions were among entities under common control, the assets were recorded at historical cost by HEP and we did not recognize a gain on the initial contribution or the intermediate pipelines transaction. The intermediate pipelines transaction resulted in a payment to us from HEP of $71.9 million in excess of our historical basis. Since the historical basis was less than the cash received on the transactions, our investment in HEP is a negative investment. The investment balance was eliminated in consolidation until the deconsolidation of HEP on July 1, 2005.
In October 2007, we entered into an agreement that amends the HEP PTA under which HEP has agreed to expand their pipeline system between Artesia, New Mexico and El Paso, Texas (“South System”). The expansion of the South System will include replacing 85 miles of 8-inch pipe with 12-inch pipe, adding 150,000 barrels of refined product storage at their El Paso terminal, improving existing pumps, adding a tie-in to the Kinder Morgan pipeline to Tucson and Phoenix, Arizona, and making related modifications. Currently, this project is expected to be completed by January 2009. The agreement also provides for a tariff increase, expected to be effective May 1, 2008, on our shipments on HEP’s refined product pipelines.
On February 26, 2008, we announced an agreement for the sale of certain pipeline and tankage assets to HEP for $180.0 million. The agreement provides for consideration to us of $171.0 million in cash and HEP common units valued at approximately $9.0 million. The assets include 136 miles of crude oil trunk lines that deliver crude to our Navajo Refinery in southeast New Mexico, approximately 725 miles of gathering and connection pipelines located in west Texas and New Mexico, on-site crude tankage having a combined 600,000 barrels of storage capacity located within the Navajo and Woods Cross Refinery complexes, a jet fuel products pipeline and terminal (terminal leased through September 2011) between Artesia and Roswell, New Mexico, and 10 miles of crude oil and product pipelines that support our Woods Cross Refinery. In connection with the closing of this transaction, we will enter into a 15-year pipelines and tankage agreement with HEP that will contain a minimum annual revenue commitment to HEP from us. We expect this transaction to close in the first quarter of 2008. The consummation of this transaction will constitute a reconsideration event according to the provisions of FIN 46 and, as a result, we will be required to reassess whether or not we are the VIE's primary beneficiary. Should the reassessment indicate that we are the primary beneficiary, we would be required to reconsolidate HEP as of the date the transaction closes.
The following table sets forth the changes in our investment account balance with HEP for the years ended December 31, 2007 and 2006 (In thousands):
The following tables provide summary financial results for HEP.
We have related party transactions with HEP for pipeline and terminal expenses, certain employee costs, insurance costs and administrative costs under the HEP PTA, HEP IPA and an Omnibus Agreement.
NOTE 4: 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 and variable performance shares. The average number of shares of common stock outstanding and per share amounts has been adjusted to reflect the two-for-one stock split effective June 1, 2006. The following is a reconciliation of the denominators of the basic and diluted per share computations for income from continuing operations:
NOTE 5: Stock-Based Compensation
On December 31, 2007, we had three principal share-based compensation plans, which are described below. The compensation cost that has been charged against income for these plans was $10.8 million, $21.2 million and $7.6 million for the years ended December 31, 2007, 2006 and 2005, respectively. The total income tax benefit recognized in the income statement for share-based compensation arrangements was $4.2 million, $7.6 million and $3.0 million for the years ended December 31, 2007, 2006 and 2005, respectively. It is currently our practice to issue new shares for settlement of option exercises, restricted stock grants or performance share units settled in stock. 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, 2007, 2,550,881 shares of common stock were reserved for future grants under the current long-term incentive compensation plan, which reservation allows for awards of options, restricted stock, or other performance awards.
Previously awarded stock options and all other compensation arrangements based on the market value of our common stock have been adjusted to reflect the two-for-one stock split effective June 1, 2006.
Stock Options
Under our Long-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 of each option awarded has been estimated using the Black-Scholes option pricing model.
A summary of option activity and changes during the year ended December 31, 2007 is presented below:
The total intrinsic value of options exercised during the years ended December 31, 2007, 2006 and 2005, was $68.0 million, $30.9 million and $14.9 million, respectively.
All outstanding stock options granted became fully vested during 2006. The total fair value of options vested during the years ended December 31, 2007, 2006 and 2005, was zero, $0.4 million and $0.5 million, respectively.
Cash received from option exercises under the stock option plans for the years ended December 31, 2007, 2006 and 2005, was $2.3 million, $2.6 million and $2.8 million, respectively. The actual tax benefit realized for the tax deductions from option exercises under the stock option plans totaled $26.0 million, $12.0 million and $5.8 million for the years ended December 31, 2007, 2006 and 2005, respectively.
Restricted Stock
Under our Long-Term Incentive Compensation Plan, we grant certain officers, other key employees and outside directors restricted stock awards with substantially all awards vesting generally over a period of one to five years. Although ownership of the shares does not transfer to the recipients until after the shares vest, recipients have dividend rights on these shares from the date of grant. The vesting for certain key executives is contingent upon certain earnings per share 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, 2007 is presented below:
The total intrinsic value of restricted stock vested and transferred to recipients during the years ended December 31, 2007, 2006 and 2005 were $12.9 million, $5.5 million and $2.5 million, respectively. As of December 31, 2007, there was $2.7 million of total unrecognized compensation cost related to nonvested restricted stock grants. That cost is expected to be recognized over a weighted-average period of 0.9 years. The total fair value of shares vested during the year ended December 31, 2007 was $3.4 million.
Performance Share Units
Under our Long-Term Incentive Compensation Plan, we grant certain officers and other key employees performance share units, which are payable in 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” criteria.
During the first quarter of 2007, we granted 42,813 performance share units with a fair value based on our grant date closing stock price of $55.47. In the third quarter of 2007, we granted an additional 2,450 performance share units having a grant date closing stock price of $74.19. 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, 2007, estimated share payouts for outstanding nonvested performance share unit awards ranged from 150% to 200%.
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.
The performance share unit awards payable in cash vested on January 1, 2008. At December 31, 2007, the fair value and cash liability of these awards was based on our closing stock price of $50.89 and a 200% payout factor.
A summary of performance share unit activity and changes during the year ended December 31, 2007 is presented below:
We paid $15.5 million, zero and $6.3 million related to vested performance share units for the years ended December 31, 2007, 2006 and 2005, respectively. As of December 31, 2007, the cash liability associated with these awards was $8.3 million and is recorded in “Accrued liabilities” in our consolidated balance sheets. At December 31, 2007, there was a total of $4.0 million of unrecognized compensation cost related to nonvested performance share units related to stock-settled performance units having a weighted average grant date fair value of $37.82. These costs are expected to be recognized over a weighted-average period of 1.1 years. At December 31, 2007, there was no unrecognized compensation cost related to our nonvested cash-settled performance units as all of these units vest January 1, 2008.
Upon early adoption of SFAS No. 123 (revised), effective July 1, 2005, we recorded a cumulative effect of a change in accounting principle relating to our performance units, due to the initial effect of measuring these awards at fair value, where previously they were measured at intrinsic value. The total cumulative effect of the change in accounting principle recorded upon adoption was a gain of $0.7 million, net of deferred tax expense of $0.4 million.
NOTE 6: Cash and Cash Equivalents and Investments in Marketable Securities
Our investment portfolio consists of cash, cash equivalents, and investments in debt securities primarily issued by government entities. In addition, as part of the sale of the Montana Refinery in 2006, we received 1,000,000 shares of Connacher common stock.
We invest in highly-rated marketable debt securities, primarily issued by government entities that have maturities at the date of purchase of greater than three months. These securities include investments in variable rate demand notes (“VRDN”). Although VRDN may have long-term stated maturities, generally 15 to 30 years, we have designated these securities as available-for-sale and have classified them as current because we view them as available to support our current operations. Rates on VRDN are typically reset either daily or weekly. VRDN may be liquidated at par on the rate reset date. Currently, we do not invest in auction rate securities. We also invest in other marketable debt securities with the maximum maturity of any individual issue not greater than two years from the date of purchase. All of these instruments are classified as available-for-sale, and as a result, are reported at fair value. Interest income is recorded as earned. Unrealized gains and losses, net of related income taxes, are temporary and reported as a component of accumulated other comprehensive income. Upon sale, realized gains and losses on the sale of marketable securities are computed based on the specific identification of the underlying cost of
the securities sold and the unrealized gains and losses previously reported in other comprehensive income are reclassified to current earnings.
The following is a summary of our available-for-sale securities at December 31, 2007:
Interest income on our marketable debt securities for the year ended December 31, 2007 included $10.1 million of interest earned, $0.1 million in realized losses and amortization of $1.4 million in net premiums paid related to our marketable debt securities. During 2007, we received a total of $509.3 million related to sales and maturities of marketable debt securities. Realized losses represent the difference between the purchase price, as amortized, and the market value on the maturity or sales date.
The following is a summary of our available-for-sale securities at December 31, 2006:
Interest income on our marketable debt securities for the year ended December 31, 2006 included $5.6 million of interest earned, $0.1 million in realized losses and amortization of $1.5 million in net premiums paid related to our marketable debt securities. During 2006, we received a total of $319.3 million related to sales and maturities of marketable debt securities. Realized losses represent the difference between the purchase price, as amortized, and market value on the maturity or sales date.
NOTE 7: Inventories
(1)
Other raw materials and unfinished products include feedstocks and blendstocks, other than crude. The inventory carrying value includes the cost of the raw materials and transportation.
(2)
Finished products include gasolines, jet fuels, diesels, asphalts, LPG’s and residual fuels. The inventory carrying value includes the cost of raw materials including transportation and direct production costs.
(3)
Process chemicals include catalysts, additives and other chemicals. The inventory carrying value includes the cost of the purchased chemicals and related freight.
The excess of current cost over the LIFO value of inventory was $199.4 million and $136.6 million at December 31, 2007 and 2006, respectively. We recognized a loss of $0.8 million and a gain of $4.2 million in income from continuing operations in the years ended December 31, 2007 and 2006, respectively, resulting from liquidations of certain LIFO inventory quantities that were carried at lower costs as compared to current costs.
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.
NOTE 8: Properties, Plants and Equipment
We did not capitalize any interest for the years ended December 31, 2007 and 2006.
Depreciation expense was $35.8 million, $30.9 million and $28.5 million for the years ended December 31, 2007, 2006 and 2005, respectively.
NOTE 9: Joint Venture
In December 2007, we entered into a definitive agreement with Sinclair Transportation Company (“Sinclair”) to jointly build 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 (the “UNEV Pipeline”). Under the agreement, we own a 75% interest in the joint venture pipeline and Sinclair will own the remaining 25% interest. The total cost of the pipeline project including terminals is expected to be $300.0 million. Holly’s share of this cost would be $225.0 million. Construction of this project is currently expected to be completed and operational in mid 2009. 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.
NOTE 10: Environmental Costs
Consistent with our accounting policy for environmental remediation costs, we expensed $2.3 million, $5.6 million and $0.5 million for the years ended December 31, 2007, 2006 and 2005, respectively, for environmental remediation obligations. The accrued environmental liability reflected in the consolidated balance sheet was $8.6 million and $7.6 million at December 31, 2007 and 2006, respectively, of which $5.3 million and $6.1 million, respectively, was classified as other long-term liabilities. Costs of future expenditures for environmental remediation are not discounted to their present value.
NOTE 11: Debt
Credit Facility
We have a $175.0 million secured revolving credit facility with Bank of America as administrative agent and lender, with a term of four years and an option to increase the facility to $225.0 million subject to certain conditions. We expect to close on an extension to the credit facility in the first quarter of 2008. This credit facility expires in 2008 and may be used to fund working capital requirements, capital expenditures, acquisitions or other general corporate purposes. Interest on the borrowings is based upon, at our option, (i) the Eurodollar rate plus an applicable rate ranging from 1.25% to 2.50% per annum for each Eurodollar loan and (ii) the base rate plus an applicable rate ranging from 0.00% to 1.25% per annum for each base rate loan. A fee ranging from 1.25% to 2.50% per annum is payable on the outstanding balance of all letters of credit and a commitment fee ranging from 0.30% to 0.50% per annum is payable on the unused portion of the facility. Such interest rate margins and fees are determined based on a quarterly calculation of the ratio of our debt to EBITDA. The borrowing base, which secures the facility, consists of accounts receivable and inventory, and at our option, pledged cash and cash equivalents. The credit facility imposes usual and customary requirements for this type of credit facility, including: (i) maintenance of certain levels of consolidated tangible net worth, interest coverage and leverage ratios; (ii) limitations on liens, investments, indebtedness and dividends; and (iii) a prohibition on changes in control. We were in compliance with all covenants at December 31, 2007. At December 31, 2007, we had outstanding letters of credit totaling $2.5 million, and no outstanding borrowings under our credit facility. At that level of usage, the unused commitment under our current credit facility was $172.5 million at December 31, 2007.
We made cash interest payments of $0.8 million, $0.5 million and $2.0 million for the years ended December 31, 2007, 2006 and 2005, respectively.
NOTE 12: Income Taxes
The provision for income taxes from continuing operations is comprised of the following:
The statutory federal income tax rate applied to pre-tax book income from continuing operations reconciles to income tax expense as follows:
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, 2007 and 2006 are as follows:
We made income tax payments of $139.4 million in 2007, $142.9 million in 2006 and $87.8 million in 2005.
We adopted the provisions of FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes, an Interpretation of FASB Statement No. 109” on January 1, 2007. As a result of the implementation, we recognized no material adjustment in the liability for unrecognized income tax benefits. The total amount of unrecognized tax benefits as of December 31, 2007, was $3.5 million. A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:
Included in the unrecognized tax benefits of $3.5 million at December 31, 2007 are $2.5 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, 2007, we recognized $1.1 million in interest (net of related tax benefits) 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 2007 and prior years will significantly change over the next twelve months.
We are subject to U.S. federal income tax and to the income tax of multiple state jurisdictions. We have substantially concluded all U.S. federal, state and local income tax matters for fiscal years through July 31, 2002. In 2006, the Internal Revenue Service commenced examinations of our U.S. federal income tax returns for the tax years ended July 31, 2003 and December 31, 2003. On February 11, 2008, the Internal Revenue Service informed us that it had completed the examination of these returns, and that the Joint Committee Review Staff was reviewing our case and preparing a report for the Joint Committee on Taxation. To date, we do not anticipate that the resolution of this audit will result in a material change to our financial condition, results of operations or cash flows.
NOTE 13: Stockholders’ Equity
The following table shows our common shares outstanding and the activity during the year:
(1)
Includes shares purchased under the terms of restricted stock agreements to provide funds for the payment of payroll and income taxes due at vesting of restricted stock.
The common shares outstanding in the table above, reflects the June 1, 2006 two-for-one stock split as discussed below.
Two-For-One Stock Split: On May 11, 2006, we announced that our Board of Directors approved a two-for-one stock split payable in the form of a stock dividend of one share of common stock for each issued and outstanding share of common stock. The stock dividend was paid on June 1, 2006 to all holders of record of common stock at the close of business on May 22, 2006.
All references to the number of shares of common stock and per share amounts for all periods presented have been adjusted to reflect the split on a retrospective basis.
Common Stock Repurchases: During 2007, our Board of Directors authorized a total increase of $300.0 million to our 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. During the year ended December 31, 2007, we repurchased 4,022,285 shares at a cost of $211.1 million (of which $12.0 million of the cash settlement was after December 31, 2007) or an average of $52.49 per share. Since inception of our common stock repurchase initiatives beginning in May 2005 through December 31, 2007, we have repurchased 13,530,906 shares at a cost of $518.1 million or an average of $38.29 per share. At December 31, 2007, we had $181.9 million of authorized repurchases remaining under our program.
During the year ended December 31, 2007, we repurchased at market price from certain executives 121,420 shares of our common stock at a cost of $5.1 million; these purchases were made under the terms of restricted stock agreements to provide funds for the payment of payroll and income taxes due at the vesting of restricted shares in the case of executives who did not elect to satisfy such taxes by other means.
NOTE 14: Other Comprehensive Income (Loss)
The components and allocated tax effects of other comprehensive income (loss) are as follows:
The temporary unrealized loss on securities available-for-sale is due to changes in the market prices of securities.
Accumulated other comprehensive loss in the equity section of the balance sheet includes:
NOTE 15: Retirement Plans
Retirement Plan: We have a non-contributory defined benefit retirement plan that covers substantially all employees. 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, the retirement plan was frozen to new employees not covered by collective bargaining agreements with labor unions. To the extent an 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.
We adopted SFAS No. 158, effective as of December 31, 2006, which required us to recognize the under-funded status of our defined benefit retirement plan as a liability in our consolidated balance sheets, with the change in our funded status recorded as a component of other comprehensive income.
The following table sets forth the changes in the benefit obligation and plan assets of our retirement plan for the years ended December 31, 2007 and 2006:
The accumulated benefit obligation was $55.4 million and $46.8 million at December 31, 2007 and 2006, respectively. The measurement dates used for our retirement plan were December 31, 2007 and 2006.
The weighted average assumptions used to determine end of period benefit obligations:
Net periodic pension expense consisted of the following components:
The weighted average assumptions used to determine net periodic benefit expense:
The estimated amounts that will be amortized from accumulated other comprehensive income into net periodic benefit expense in 2008 are as follows:
At year end, our retirement plan assets were allocated as follows:
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% equity investments and 30% fixed income investments. Equity investments include a blend of domestic growth and value stocks of various sizes of capitalization and international stocks.
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 to $10.0 million to the retirement plan in 2008. Benefit payments, which reflect expected future service, are expected to be paid as follows: $5.4 million in 2008; $4.8 million in 2009; $5.7 million in 2010; $6.6 million in 2011, $7.5 million in 2012 and $49.5 million in 2013-2017.
Retirement Restoration 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 $0.8 million, $0.8 million and $0.9 million for the years ended December 31, 2007, 2006 and 2005, respectively, in connection with this plan. The accrued liability reflected in the consolidated balance sheets was $6.6 million and $5.8 million at December 31, 2007 and 2006, respectively. As of December 31, 2007, the projected benefit obligation under this plan was $6.6 million. Benefit payments, which reflect expected future service, are expected to be paid as follows: $1.7 million in 2008; $0.5 million in 2009; $0.5 million in 2010; $1.9 million in 2011; $0.3 million in 2012 and $2.8 million in 2013-2017.
Defined Contribution 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 $0.6 million, $1.9 million and $1.4 million for the years ended December 31, 2007, 2006 and 2005, respectively, in connection with these plans.
Postretirement Medical 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 $7.5 million and $2.1 million at December 31, 2007 and 2006, 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 December 31, 2007, the total accumulated postretirement benefit obligation under our postretirement medical plans was $7.5 million.
NOTE 16: Derivative Instruments and Hedging Activities
Historically, we have utilized petroleum commodity futures contracts principally to help manage the price risk inherent in purchasing crude oil in advance of the delivery date and as a hedge for fixed-price sales contracts of refined products. We have also utilized commodity price swaps and collar options to help manage the exposure to price volatility relating to forecasted purchases of natural gas. We regularly utilize contracts that provide for the purchase of crude oil and other feedstocks and for the sale of refined products. Certain of these contracts may meet the definition of a derivative instrument in accordance with SFAS No. 133, as amended. We believe these contracts qualify for the normal purchases and normal sales exception under SFAS No. 133, as amended, because deliveries under the contracts will be in quantities expected to be used or sold over a reasonable period of time in the normal course of business. Accordingly, these contracts are designated as normal purchases and normal sales contracts and are not required to be recorded as derivative instruments under SFAS No. 133, as amended.
During 2005, we entered into two different types of hedging transactions, neither of which involved arrangements designated as hedging instruments per the requirements of SFAS No. 133, and therefore all gains and losses were recorded as incurred. The first transaction was entered into in July 2005 and related to our forecasted August 2005 liquidation of 100,000 barrels of crude oil at our Woods Cross Refinery, where our objective was to fix the price of crude oil associated with the liquidation. To affect the hedge, we sold crude oil futures contracts in July 2005 and liquidated the positions in August 2005 matching when the crude oil inventory was slated for production. We recognized a loss of $535,000 on this transaction and recorded it as an increase in cost of products sold. The other
type of transaction we have entered into from time to time beginning in July 2005 relates to forecasted sales of diesel fuel from our refineries, where our principal objective is to take advantage of the high margins (or crack spreads, being the difference between the price of diesel fuel and the cost of crude oil) on a portion of our diesel fuel sales. To effect these hedges, we sold heating oil futures (which most closely match diesel fuel pricing) and bought crude oil futures. We have also entered into commodity swap transactions (the terms of which mirror the futures contracts entered into) to effect the same strategy on a portion of these hedges. Our objective is either to liquidate the positions as the crack spreads return to more normalized levels or to hold these positions until the forecasted diesel fuel sales are made, effectively locking in the diesel fuel crack spreads (or margins) at the high levels. Our strategy is to enter into these transactions only when the margins are at historically very high levels and to have no more than 25% of our diesel fuel production hedged at any given time. During 2005, we entered into hedges totaling 1,505,000 barrels covering forecasted diesel fuel sales from November 2005 to February 2006. The positions were fully liquidated during August to November 2005 resulting in a realized gain of $3.2 million, which was recorded as a decrease in cost of products sold. Since November 2005, no such transactions have transpired.
NOTE 17: Lease Commitments
We lease certain facilities and equipment under operating leases, most of which contain renewal options. At December 31, 2007, the minimum future rental commitments under operating leases having noncancellable lease terms in excess of one year are as follows (in thousands):
Rental expense charged to operations was $3.2 million, $2.3 million and $5.1 million for the years ended December 31, 2007, 2006 and 2005, respectively.
NOTE 18: Contingencies and Contractual Obligations
Contingencies
On May 29, 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 Federal Energy Regulatory Commission (“FERC”) in proceedings brought by us and other parties against SFPP. These proceedings relate to tariffs of common carrier pipelines, which are owned and operated by SFPP, for shipments of refined products from El Paso, Texas to Tucson and Phoenix, Arizona and from points in California to points in Arizona. We are one of several refiners that regularly utilize the SFPP pipeline to ship refined products from El Paso, Texas to Tucson and Phoenix, Arizona. The Court of Appeals in its May 29, 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 by partnerships and ruled in our favor on an issue relating to our rights to reparations when it is determined that certain tariffs we paid to SFPP in the past were too high. We currently estimate that, as a result of this 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 million we received in 2003 from SFPP as reparations for the period from 1992 through July 2000. Because proceedings in the FERC following the Court of Appeals decision have not been completed and final action by the FERC could be subject to further court proceedings, it is not possible at this time to determine what will be the net amount payable to us at the conclusion of these proceedings. We and other shippers have been engaged in settlement discussions with SFPP on remaining issues in the FERC proceedings. These discussions resulted in a partial settlement, which became final in February 2008, providing for a payment to us of approximately $1.3 million with respect to our shipments from El Paso to Tucson and Phoenix for the period from June 1, 2006 through November 30, 2007. The partial settlement leaves for resolution in pending proceedings all remaining issues for other periods.
In discussions beginning in the last half of 2005, the EPA and the State of Utah have asserted that we have Federal CAA liabilities relating to our Woods Cross Refinery because of actions taken or not taken by prior owners of the Woods Cross Refinery, which we purchased from ConocoPhillips in June 2003. We have agreed with the EPA and the State of Utah to settle the issues presented by means of an agreement for a Consent Decree. The proposed agreement, which has not yet been signed by the parties and lodged with the federal district court in Utah, includes obligations for us to make specified additional capital investments currently estimated to total approximately $17 million over several years and to make changes in operating procedures at the refinery. The proposed agreement also requires expenditures by us totaling $250,000 for penalties and a supplemental environmental project of benefit of the community in which the Woods Cross Refinery is located. The agreements for the purchase of the Woods Cross Refinery provide that ConocoPhillips will indemnify us, subject to specified limitations, for environmental claims arising from circumstances prior to our purchase of the refinery. We believe that, in the present circumstances, the amount due to us from ConocoPhillips under the agreements for the purchase of the Woods Cross Refinery would be approximately $1.4 million with respect to the anticipated settlement.
Our Navajo Refining Company subsidiary is 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. The lawsuit, as amended in October 2006 through the filing of a second amended complaint in the U.S. District Court for the Southern District of New York under multidistrict procedures, 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 claims made are for defective design or product, failure to warn, negligence, public nuisance, statutory public nuisance, private nuisance, trespass, and civil conspiracy. The second amended complaint also contains a claim, which is asserted in the complaint only against certain other defendants but which appears to be similar to a claim that has been threatened in a mailing to Navajo by law firms representing the plaintiff in this case, alleging violations of certain provisions of the Toxic Substances Control Act. The lawsuit seeks compensatory damages unspecified in amount, injunctive relief, exemplary and punitive damages, costs, attorney’s fees allowed by law, and interest allowed by law. As of the close of business on the day prior to the date of this report, Navajo has not been served in this case. At the date of this report, it is not possible to predict the likely course or outcome of this litigation.
In December 2006, the Montana Department of Environmental Quality (“MDEQ”) filed in state district court in Great Falls, Montana a Complaint and Application for Preliminary Injunction (the “Complaint”) naming as defendants Montana Refining Company (“MRC”), our subsidiary that owned the Great Falls, Montana refinery until it was sold to an unrelated purchaser in March 2006, and the unrelated company that purchased the refinery from MRC. The MDEQ asserts in the Complaint that the Great Falls refinery exceeded limitations on sulfur dioxide in the refinery’s air emission permit on certain dates in 2004 and 2005 and in 2006 both before and after the sale of the refinery, erroneously certified compliance with limitations on sulfur dioxide emissions, failed to promptly report emissions limit deviations, exceeded limits on sulfur in fuel gas on specified dates in 2005, failed in 2005 to conduct timely testing for certain emissions, submitted late a report required to be submitted in early 2006, failed to achieve a specified limitation on certain emissions in the first three quarters of 2006, and failed to timely submit a report on a 2005 emissions test. The Complaint sought penalties under applicable law of up to $10,000 per violation and an order enjoining MRC and the current owner of the refinery from further violations. While we do not agree with a number of the violations asserted in the Complaint, we and the current owner of the Great Falls refinery have negotiated with the MDEQ both before and after the filing of the Complaint to attempt to settle the issues raised on a compromise basis. At the date of this report, we have negotiated a tentative settlement agreement, which has not yet been put into a signed agreement, under which we would make payments totaling approximately $100,000.
We are a party to various other litigation and proceedings not mentioned in this report which we believe, based on advice of counsel, will not have a materially adverse impact on our financial condition, results of operations or cash flows.
Contractual Obligations
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 over a fifteen year period commencing on a date at our discretion prior to December 31, 2009. The contract also requires the payment of a base facility charge for use of the supplier’s facility over the supply term. We expect to initiate the supply term start date at the end of 2008.
We also have two crude oil transportation agreements that obligate us to ship a total of approximately 21,000 barrels per day for initial terms of 10 years. Our obligations under these agreements are subject to certain conditions including completion of construction and expansion projects by the transportation companies, and the tariffs that will apply to these commitments have not been finalized. We expect approximately one-half of the total shipment commitment to begin no earlier than the fourth quarter of 2009 and the other one-half to begin no earlier than the fourth quarter of 2010.
Other contractual obligations relate to the transportation of natural gas and feedstocks to our refineries under contracts expiring in 2015 and 2016 and various service contracts with expiration dates through 2011.
NOTE 19: Segment Information
Our operations are currently organized into one reportable segment, Refining. The Refining segment includes the Navajo Refinery, Woods Cross Refinery and Holly Asphalt. Our operations that are not included in the
Refining segment include the operations of Holly Corporation, the parent company, and a small-scale oil and gas exploration and production program.
The Refining segment involves the purchase and refining of crude oil and wholesale and branded marketing of refined products, such as gasoline, diesel fuel and jet fuel, and includes our Navajo Refinery and Woods Cross Refinery. The petroleum products produced by the Refining segment are marketed in Texas, New Mexico, Arizona, Utah, Wyoming, Idaho, Washington and northern Mexico. The Refining segment also includes certain crude oil pipelines that we own and operate in conjunction with our refining operations as part of the supply networks of the refineries. The Refining segment also includes Holly Asphalt Company which manufactures and markets asphalt and asphalt products in Arizona, New Mexico, Texas and northern Maxico.
Prior to our deconsolidation of HEP effective July 1, 2005, our operations were organized into two segments, which were Refining and HEP. Our operations that were not included in either the Refining or HEP segments included the operations of Holly Corporation, the parent company, consisting primarily of general and administrative expenses as well as a small-scale oil and gas exploration and production program. The consolidations and eliminations column included the elimination of the revenue and costs associated with HEP’s pipeline transportation services for us.
The HEP segment involved all of the operations of HEP through June 30, 2005 (prior to the deconsolidation), including approximately 1,300 miles (780 miles prior to the Alon asset acquisition) of pipeline assets principally in Texas, New Mexico and Oklahoma and refined product terminals in several Southwest and Rocky Mountain states. The HEP segment also included a 70% interest in Rio Grande Pipeline Company (“Rio Grande”), which provides petroleum products transportation. Revenues from the HEP segment were 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 in Rio Grande.
NOTE 20: Significant Customers
All revenues were 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 approximately $200.0 million (5%) of our revenues in 2007, $144.4 million (4%) of our revenues in 2006 and $82.0 million (3%) of revenues in 2005. In 2007, 2006 and 2005, we had several significant customers, none of which accounted for more than 10% of our revenues.
NOTE 21: Quarterly Information (Unaudited)
(1)
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.
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 certified 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 Exchange Act Rule 13a-15(e)) as of the end of the period covered by this annual report on Form 10-K. Based on that evaluation, the principal executive officer and principal financial officer concluded that the design and operation of our disclosure controls and procedures are effective in ensuring that information we are required to disclose in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms.
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 Registered Public Accounting Firm.”
Item 9B.
Item 9B. Other Information
There have been no events that occurred in the fourth quarter of 2007 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 and 406 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 8, 2008 and is incorporated herein by reference.
New York Stock Exchange Certification
In 2007, 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 Item 402 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 8, 2008 and is incorporated herein by reference.
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 8, 2008 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 8, 2008 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 8, 2008 and is incorporated herein by reference.
PART IV
Item 15.
Item 15. Exhibits and Financial Statement Schedules
(a) Documents filed as part of this report
(1) Index to Consolidated Financial Statements
(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
See Index to Exhibits on pages 91 to 94.
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 28, 2008
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.
HOLLY CORPORATION
INDEX TO EXHIBITS
Exhibits are numbered to correspond to the exhibit table
in Item 601 of Regulation S-K
-91 -
-92 -
-93 -
+
Filed herewith.
*
Constitutes management contracts or compensatory plans or arrangements.
-94 -