SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
| | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) | |
| þ | OF THE SECURITIES EXCHANGE ACT OF 1934 | |
| | For the Fiscal Year Ended: December 31, 2008 | |
| | OR TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) | |
| o | OF THE SECURITIES EXCHANGE ACT OF 1934 | |
| | For the transition period from . . . . to . . . . | |
Commission File Number: 1-7627
FRONTIER OIL CORPORATION
(Exact name of registrant as specified in its charter)
| Wyoming | | 74-1895085 |
| (State or other jurisdiction of | | (I.R.S. Employer |
| incorporation or organization) | | Identification No.) |
| | | |
| 10000 Memorial Drive, Suite 600 | | 77024-3411 |
| Houston, Texas | | (Zip Code) |
| (Address of principal executive offices) | | |
Registrant’s telephone number, including area code: (713) 688-9600
Securities registered pursuant to Section 12(b) of the Act:
| | Name of Each Exchange |
| Title of Each Class | | on Which Registered |
| Common Stock | | New York Stock Exchange |
Securities registered pursuant to Section 12(g) of the Act:
None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
Yes þ No ¨
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
Yes ¨ No þ
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Yes þ No ¨
Indicate by check mark if disclosure of delinquent filers pursuant to rule 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ü
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
(Check one)
Large accelerated filer þ Accelerated filer ¨ Non-accelerated filer ¨ Smaller reporting company ¨
(Do not check if a smaller reporting company)
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes ¨ No þ
The aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold as of June 30, 2008 was $2.1 billion.
The number of shares of common stock outstanding as of February 20, 2009 was 103,919,472.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Annual Proxy Statement for the registrant’s 2009 annual meeting of shareholders are incorporated by reference into Items 10 through 14 of Part III.
Forward-Looking Statements
This Form 10-K contains “forward-looking statements” as defined by the Securities and Exchange Commission (“SEC”). Such statements are those concerning contemplated transactions and strategic plans, expectations and objectives for future operations. These include, without limitation:
| · | statements, other than statements of historical fact, that address activities, events or developments that we expect, believe or anticipate will or may occur in the future; |
| · | statements relating to future financial performance, future capital sources and other matters; and |
| · | any other statements preceded by, followed by or that include the words “anticipates,” “believes,” “expects,” “plans,” “intends,” “estimates,” “projects,” “could,” “should,” “may,” or similar expressions. |
Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this Form 10-K are reasonable, we can give no assurance that such plans, intentions or expectations will be achieved. These statements are based on assumptions made by us based on our experience and perception of historical trends, current conditions, expected future developments and other factors that we believe are appropriate in the circumstances. Such statements are subject to a number of risks and uncertainties, many of which are beyond our control. You are cautioned that any such statements are not guarantees of future performance and that actual results or developments may differ materially from those projected in the forward-looking statements.
All forward-looking statements contained in this Form 10-K only speak as of the date of this document. We undertake no obligation to update or revise publicly any revisions to any such forward-looking statements that may be made to reflect events or circumstances after the date of this Form 10-K, or to reflect the occurrence of unanticipated events.
The terms “Frontier,” “we,” “us” and “our” as used in this Form 10-K refer to Frontier Oil Corporation and its subsidiaries, except where it is clear that those terms mean only the parent company. When we use the term “Rocky Mountain region,” we refer to the states of Colorado, Wyoming, western Nebraska, Montana and Utah, and when we use the term “Plains States,” we refer to the states of Kansas, Oklahoma, eastern Nebraska, Iowa, Missouri, North Dakota and South Dakota.
Overview
We are an independent energy company, organized in the State of Wyoming in 1977, engaged in crude oil refining and the wholesale marketing of refined petroleum products. We operate refineries (the “Refineries”) in Cheyenne, Wyoming and El Dorado, Kansas with a total annual average crude oil capacity of approximately 182,000 barrels per day (“bpd”). Both of our Refineries are complex refineries, which means that they can process heavier, less expensive types of crude oil and still produce a high percentage of gasoline, diesel fuel and other high value refined products. We focus our marketing efforts in the Rocky Mountain region and the Plains States, which we believe are among the most attractive refined products markets in the United States. The operations of refining and marketing of petroleum products are considered part of one reporting segment.
Cheyenne Refinery. Our Cheyenne Refinery has a permitted crude oil capacity of 52,000 bpd on a twelve-month average. We market its refined products primarily in the eastern slope of the Rocky Mountain region, which encompasses eastern Colorado (including the Denver metropolitan area), eastern Wyoming and western Nebraska (the “Eastern Slope”). The Cheyenne Refinery has a coking unit, which allows the refinery to process extensive amounts of heavy crude oil for use as a feedstock. The ability to process heavy crude oil lowers our raw material costs because heavy crude oil is generally less expensive than lighter types of crude oil. For the year ended December 31, 2008, heavy crude oil constituted approximately 76% of the Cheyenne Refinery’s total crude oil charge. For the year ended December 31, 2008, the Cheyenne Refinery’s product yield included gasoline (45%), diesel fuel (31%) and asphalt and other refined petroleum products (24%).
El Dorado Refinery. The El Dorado Refinery is one of the largest refineries in the Plains States and the Rocky Mountain region with crude oil capacity of 130,000 bpd. The El Dorado Refinery can select from many different types of crude oil because of its direct access to Cushing, Oklahoma, which is connected by pipelines to the Gulf Coast and to Canada. This access, combined with the El Dorado Refinery’s complexity (including a coking unit), gives it the flexibility to refine a wide variety of crude oils. In connection with our acquisition of the El Dorado Refinery in 1999, we entered into a 15-year refined product offtake agreement for gasoline and diesel production at this refinery with Shell Oil Products US (“Shell”). Shell has also agreed to purchase all jet fuel production until the end of the product offtake agreement. As our deliveries to Shell have declined per the terms of the refined product offtake agreement, we have marketed an increasing portion of the El Dorado Refinery’s gasoline and diesel in the same markets where Shell currently sells the El Dorado Refinery’s products, primarily in Denver and throughout the Plains States. For the year ended December 31, 2008, the El Dorado Refinery’s product yield included gasoline (50%), diesel and jet fuel (40%) and chemicals and other refined petroleum products (10%).
Other Assets. The Company owns Ethanol Management Company (“EMC”) which is a 25,000 bpd products terminal and blending facility located near Denver, Colorado.
Varieties of Crude Oil and Products. Traditionally, crude oil has been classified within the following types:
· sweet (low sulfur content),
· sour (high sulfur content),
· light (high gravity),
· heavy (low gravity) and
· intermediate (if gravity or sulfur content is in between).
For the most part, heavy crude oil tends to be sour and light crude oil tends to be sweet. When refined, light crude oil produces a higher proportion of high value refined products such as gasoline, diesel and jet fuel and, as a result, is more expensive than heavy crude oil. In contrast, heavy crude oil produces more low value by-products and heavy residual oils. The discount at which heavy crude oil sells compared to light crude oil is known in the industry as the light/heavy spread or differential, while the discount at which sour crude oil sells compared to light crude oil is known as the sweet/sour, or WTI/WTS, spread or differential. Coking units, such as the ones at our Refineries, can process certain by-products and heavy residual oils to produce additional volumes of gasoline and diesel, thus increasing the aggregate yields of higher value refined products from the same initial barrel of crude oil.
Refineries are frequently classified according to their complexity, which refers to the number, type and capacity of processing units at the refinery. Each of our Refineries possesses a coking unit, which provides substantial upgrading capacity and generally increases a refinery’s complexity rating. Upgrading capacity refers to the ability of a refinery to produce high yields of high value refined products such as gasoline and diesel from heavy and intermediate crude oil. In contrast, refiners with low upgrading capacity must process primarily light, sweet crude oil to produce a similar yield of gasoline and diesel. Some low complexity refineries may be capable of processing heavy and intermediate crude oil, but they will produce large volumes of by-products, including heavy residual oils and asphalt. Because gasoline, diesel and jet fuel sales generally achieve higher margins than are available on other refined products, we expect that these products will continue to make up the majority of our production.
Refinery Maintenance. Each of the processing units at our Refineries requires scheduled significant maintenance and repair shutdowns (referred to as “turnarounds”) during which the unit is not in operation. Turnaround cycles vary for different units but are generally required every one to five years. In general, turnarounds at our Refineries are managed so that some units continue to operate while others are down for scheduled maintenance. We also coordinate operations by staggering turnarounds between our two Refineries. Turnarounds are implemented using our regular personnel as well as additional contract labor. Once started, turnaround work typically proceeds 24 hours per day to minimize unit downtime. We defer the costs of turnarounds, reflected as “Deferred turnaround costs” on the Consolidated Balance Sheets, and subsequently amortize them on a straight-line basis over the period of time estimated to lapse until the next turnaround occurs. We normally schedule our turnaround work during the spring or fall of each year. When we perform a turnaround, we may increase product inventories prior to the turnaround to minimize the impact of the turnaround on our sales of refined products.
During 2008, the major turnaround work at the El Dorado Refinery involved the crude unit, the coker and the reformer. The timing of the 2008 El Dorado Refinery turnarounds coincided with the completion of the crude unit and vacuum expansion and the coker expansion projects. We are planning turnaround work and catalyst replacement on a distillate hydrotreater at the El Dorado Refinery in March 2009. We also have major turnaround work scheduled on the gofiner, fluid catalytic cracking unit (“FCCU”) and related units at the El Dorado refinery in the fall of 2009.
At the Cheyenne Refinery, 2008 turnaround work was modest in scope and involved a naphtha hydrotreater and its associated reformer, diesel hydrotreater, and sulfur recovery unit. The Cheyenne Refinery has no major turnaround work planned for 2009.
Cheyenne Refinery. The primary market for the Cheyenne Refinery’s refined products is the Eastern Slope. For the year ended December 31, 2008, we sold approximately 87% of the Cheyenne Refinery’s gasoline volumes in Colorado and 11% in Wyoming. For the year ended December 31, 2008, we sold approximately 69% of the Cheyenne Refinery’s diesel in Wyoming and 25% in Colorado. Because of the location of the Cheyenne Refinery, we are able to sell a significant portion of its diesel product from the truck rack at the Refinery, thereby eliminating transportation costs. The gasoline and remaining diesel produced by this Refinery are primarily shipped via pipeline to terminals for distribution by truck or rail. Pipeline shipments from the Cheyenne Refinery are handled mainly by the Plains All American Pipeline (formerly Rocky Mountain Pipeline), serving Denver and Colorado Springs, Colorado, and the ConocoPhillips Pipeline, serving Sidney, Nebraska.
We sell refined products from our Cheyenne Refinery to a broad base of independent retailers, jobbers and major oil companies. Refined product prices are determined by local market conditions at distribution centers known as “terminal racks,” and prices at the terminal racks are posted daily by sellers. The customer at a terminal rack typically supplies its own truck transportation. In the year ended December 31, 2008, approximately 87% of the Cheyenne Refinery’s sales were made to its 25 largest customers compared to the year ended December 31, 2007, when approximately 91% of the Cheyenne Refinery’s sales were made to its 25 largest customers. Occasionally, volumes sold exceed the Refinery’s production, in which case we purchase product in the spot market as needed.
El Dorado Refinery. The primary markets for the El Dorado Refinery’s refined products are Colorado and the Plains States, which include the Kansas City metropolitan area. The gasoline, diesel and jet fuel produced by the El Dorado Refinery are primarily shipped via pipeline to terminals for distribution by truck or rail. The NuStar Pipeline Operating Partnership L.P. Pipeline, serving the northern Plains States, the Magellan Pipeline Company, L.P. (“Magellan”) mountain pipeline serving Denver, Colorado, and the Magellan mid-continent pipeline serving the Plains States handle shipments from our El Dorado Refinery.
For the year ended December 31, 2008, Shell was the El Dorado Refinery’s largest customer, and our only customer which represented more than 10% of our total consolidated sales. For 2008, sales to Shell represented approximately 50% of the El Dorado Refinery’s total sales and 37% of our total consolidated sales. Under the offtake agreement, Shell purchases gasoline, diesel and jet fuel produced by the El Dorado Refinery at market-based prices. Initially in 1999, Shell purchased all of the El Dorado Refinery’s production of these products. Beginning in 2000, we retained and marketed 5,000 bpd of the Refinery’s gasoline and diesel production, and the retained portion increases by 5,000 bpd each year through 2009. In 2008, the Company entered into an amendment to the offtake agreement that allowed the Company to retain and market an additional 10,000 bpd of diesel production due to the coker expansion project and improved refinery efficiencies. In aggregate during 2008, we retained and marketed 55,000 bpd of the Refinerys’ gasoline and diesel production. As our sales to Shell under this agreement decrease, we intend to sell the gasoline and diesel produced by the El Dorado Refinery in the same general markets currently served by Shell, as previously described.
Cheyenne Refinery. The most competitive market for the Cheyenne Refinery’s products is the Denver metropolitan area. Other than the Cheyenne Refinery, three principal refineries serve the Denver market: an approximate 70,000 bpd refinery near Rawlins, Wyoming and an approximate 25,000 bpd refinery in Casper, Wyoming, both owned by Sinclair Oil Company (“Sinclair”); and a 90,000 bpd refinery located in Denver and owned by Suncor Energy (U.S.A.) Inc. (“Suncor”). Five product pipelines also supply Denver, including three from outside the region that enable refined products from other regions to be sold in the Denver market. Refined products shipped from other regions typically bear the burden of higher transportation costs.
The Suncor refinery located in Denver has lower product transportation costs to serve the Denver market than we do. However, the Cheyenne Refinery has lower crude oil transportation costs because of its proximity to the Guernsey, Wyoming hub, the major crude oil pipeline hub in the Rocky Mountain region. Moreover, unlike Sinclair and Suncor, we only sell our products to the wholesale market. We believe that our commitment to the wholesale market gives us certain marketing advantages over our principal competitors in the Eastern Slope area, all of which also have retail outlets, because we do not compete directly with independent retailers of gasoline and diesel.
El Dorado Refinery. The El Dorado Refinery faces competition from other Plains States and mid-continent refiners, but the principal competitors for the El Dorado Refinery are Gulf Coast refiners. Although our Gulf Coast competitors typically have lower production costs because of their size (economies of scale) than the El Dorado Refinery, we believe that our competitors’ higher refined product transportation costs allow our El Dorado Refinery to compete effectively in the Plains States and Rocky Mountain region with the Gulf Coast refineries. The Plains States and mid-continent regions are supplied by three product pipelines (Magellan Midstream Partners, L.P., Explorer Pipeline and Nustar Energy L.P.) that originate from the Gulf Coast.
We purchase crude oil from numerous suppliers, including major oil companies, marketing companies and large and small independent producers, under arrangements which contain market-responsive pricing provisions. Most of these arrangements are subject to cancellation by either party or have terms that are not in excess of one year and are subject to periodic renegotiation. We intend to continue purchasing crude oil from a variety of suppliers and typically under short-term commitments. In the event we become unable to purchase crude oil from any one of these sources, we believe that adequate alternative supplies of crude oil would be available. Crude oil charges are the quantity of crude oil and other feedstock processed through Refinery units.
Cheyenne Refinery. In the year ended December 31, 2008, we obtained approximately 64% of the Cheyenne Refinery’s crude oil charge from Canada, 15% from Wyoming, 16% from Colorado and 5% from other domestic sources. During the same period, heavy crude oil constituted approximately 76% of the Cheyenne Refinery’s total crude oil charge, compared to 72% in 2007. Cheyenne is 88 miles south of Guernsey, Wyoming, the main hub and crude oil trading center for the Rocky Mountain region. We transport crude oil from Guernsey to the Cheyenne Refinery via common carrier pipelines owned by Plains All American Pipeline and Suncor Energy. Ample quantities of heavy crude oil are available at Guernsey, including both locally produced Wyoming general sour and imported Canadian heavy crude oil, which is supplied by the Express pipeline system. This type of crude oil typically sells at a discount from lighter crude oil prices.
El Dorado Refinery. In the year ended December 31, 2008, we obtained approximately 57% of the El Dorado Refinery’s crude oil charge from Texas, 26% from Canada, 5% from Kansas, 10% from the Gulf of Mexico, and the remaining 2% from other foreign and domestic locations. El Dorado is 125 miles north of Cushing, Oklahoma, a major crude oil hub. The Cushing hub is supplied by the Seaway Pipeline, which runs from the Gulf Coast; the Basin Pipeline, which runs through Wichita Falls, Texas from West Texas; the Sun Pipeline, which originates at the Gulf Coast and connects to the Basin Pipeline at Wichita Falls; and the Spearhead Pipeline, which connects at Griffith, Indiana with the Enbridge Pipeline to bring crude oil from Canada. The Osage Pipeline runs from Cushing to El Dorado and transported approximately 95% of our crude oil charge during the year ended December 31, 2008. The remainder of our crude oil charge was transported to the El Dorado Refinery through Kansas gathering system pipelines. We have a Transportation Services Agreement to transport up to 38,000 bpd of crude oil on the Spearhead Pipeline from Griffith, Indiana to Cushing, Oklahoma, enabling us to transport heavy Canadian crude oil to our El Dorado Refinery. The initial term of this agreement expires in 2016. We have the right to extend the agreement for an additional ten years and increase the volume transported under a preferential tariff to 50,000 bpd.
Environmental Matters. See “Environmental” in Note 12 in the “Notes to Consolidated Financial Statements.”
We are subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) and comparable state occupational safety statutes.
The Cheyenne Refinery’s OSHA recordable incident rate in 2008 of 2.52 is higher than the latest reported U.S. refining industry average of 1.6 as compiled by the United States Department of Labor. While the frequency of injuries at the Cheyenne Refinery has risen above the industry average, we continue to emphasize safety at all levels of the Cheyenne Refinery organization. The Cheyenne Refinery’s 2008 contractor recordable rate was 2.9, representing six recordable injuries. Overall contractor work and, thus, man-hours was lower at the Cheyenne Refinery. As a result, the incidence rate is then significantly increased with any single recordable injury that occurs at the Refinery. During 2009, we intend to focus on safety by improving procedures and training for all Refinery workers in the coming year. These efforts include programs in both areas of occupational and process safety initiatives and are comprehensive across all areas of the Refinery.
The El Dorado Refinery’s OSHA recordable incident rate of 0.67 in 2008 is a significant improvement from the rate of 0.95 for 2007, and compares favorably to the U.S. refining average of 1.6. Management and employees at the El Dorado Refinery remain committed to programs, processes and behaviors that drive safety excellence. Improvement in contractor safety continued to be a key initiative for the El Dorado Refinery during 2008. Behavior-based safety programs were introduced in 2004 for our own employees. During 2006, we began including the majority of our contractor base in these programs as well. These efforts have resulted in a significant increase in contractor safety awareness and much improved contractor safety results. Our employees and management continue to dedicate their efforts to a balanced safety program that combines individual behavioral elements in a safety-coaching environment with structured, management-driven programs to improve the safety of our facilities and operating procedures. Our objective is to provide a safe working environment for employees and contractors and continue educating them about how to work safely. Encouraging all employees and contractors to contribute toward improving safety performance through personal involvement in safety-related activities is an industry-proven method of reducing injuries.
At December 31, 2008, we employed approximately 860 full-time employees: 95 in the Houston and Denver offices, 350 at the Cheyenne Refinery, and 415 at the El Dorado Refinery. The Cheyenne Refinery employees included approximately 130 administrative and technical personnel and approximately 220 union members. The El Dorado Refinery employees included 155 administrative and technical personnel and approximately 260 union members. The union members at our El Dorado Refinery are represented by the United Steel, Paper and Forestry, Rubber, Manufacturing, Energy, Allied Industrial and Service Workers International Union (“USW”). The union members at our Cheyenne Refinery are represented by seven bargaining units, the largest being the USW and the others with various craft unions.
For our Cheyenne Refinery, the current contract between the Company, the USW, and its Local 8-0574 expires in July 2009. The current contract between the Company, the craft unions, and its various local chapters expires in June 2009.
At our El Dorado Refinery, the current contract between the Company, the USW, and its Local 5-241 expires in January 2012.
Item 1A. Risk Factors Relating to Our Business Crude oil prices and refining margins significantly impact our cash flow and have fluctuated substantially in the past.Our cash flow from operations is primarily dependent upon producing and selling refined products at margins that are high enough to cover our fixed and variable expenses. In recent years, crude oil costs and crack spreads (the difference between refined product sales prices and crude oil prices) have fluctuated substantially. Factors that may affect crude oil costs and refined product prices include:
· overall demand for crude oil and refined products;
· general economic conditions;
· the level of foreign and domestic production of crude oil and refined products;
· the availability of imports of crude oil and refined products;
· the marketing of alternative and competing fuels;
· the extent of government regulation;
· global market dynamics;
· product pipeline capacity;
· local market conditions; and
· the level of operations of competing refineries.
Crude oil supply contracts are generally short-term contracts with price terms that change as market prices change. Our crude oil requirements are supplied from sources that include:
· major oil companies;
· crude oil marketing companies;
· large independent producers; and
· smaller local producers.
The price at which we can sell gasoline and other refined products is strongly influenced by the price of crude oil. Generally, an increase or decrease in the price of crude oil results in a corresponding increase or decrease in the price of gasoline and other refined products. However, if crude oil prices increase significantly, our operating margins would fall unless we could pass along these price increases to our customers.
Our Refineries maintain inventories of crude oil, intermediate products and refined products, the value of each being subject to fluctuations in market prices. Our inventories of crude oil, unfinished products and finished products are recorded at the lower of cost on a first-in, first-out (“FIFO”) basis or market prices. As a result, a rapid and significant increase or decrease in the market prices for crude oil or refined products could have a significant short-term impact on our earnings and cash flow.
Our profitability is affected by crude oil differentials, which may decline and accordingly decrease our profitability.
The light/heavy crude oil differentials that we report are the average differential between the benchmark West Texas Intermediate (“WTI”) crude oil priced on the New York Mercantile Exchange and the heavy crude oil priced as delivered to our Cheyenne Refinery or El Dorado Refinery, respectively. The WTI/WTS (sweet/sour) crude oil differential is the average differential between benchmark WTI crude oil priced on the New York Mercantile Exchange and West Texas sour crude oil priced at Midland, Texas. Our profitability at our Cheyenne Refinery is affected by the light/heavy crude oil differential, and our profitability at our El Dorado Refinery is affected by the WTI/WTS crude oil differential. Starting in March 2006, when our El Dorado Refinery began receiving heavy Canadian crude oil through the Spearhead Pipeline, its profitability also began benefiting from the light/heavy crude oil differential. We typically prefer to refine heavy sour crude oil at the Cheyenne Refinery and intermediate sour crude oil at the El Dorado Refinery because these crudes provide a higher refining margin than light or sweet crude oil does. Accordingly, any reduction of these crude oil differentials will reduce our profitability. The Cheyenne Refinery light/heavy crude oil differential averaged $17.15 per barrel in the year ended December 31, 2008, compared to $18.95 per barrel in the same period in 2007. The El Dorado Refinery light/heavy crude oil differential averaged $17.85 per barrel in the year ended December 31, 2008 compared to $21.00 per barrel in 2007. The WTI/WTS crude oil differential averaged $3.92 per barrel in the year ended December 31, 2008, compared to $5.02 per barrel in the same period in 2007. Crude oil prices were historically high during the first seven months of 2008, contributing to higher light/heavy crude oil differentials and WTI/WTS crude oil differentials. Crude oil prices dropped dramatically during the latter part of 2008, which resulted in significant narrowing of the light/heavy crude oil differentials and WTI/WTS crude oil differentials.
Our risk management activities may generate substantial losses and limit potential gains.
In order to hedge and limit potential financial losses on certain of our inventories, we from time to time enter into derivative contracts to make forward sales or purchases of crude oil, refined products, natural gas and other commodities. We may also use options or swaps to accomplish similar objectives. Our inventory hedging strategies generally produce losses when hedged crude oil or refined products increase in value. During the year ended December 31, 2008, we incurred a pre-tax hedging gain of $146.5 million recorded in “Other revenues” in the Consolidated Statements of Income. Offsetting the benefit of our hedges is the economic loss realized when we liquidate inventory which had been hedged. The value of the hedged inventory generally moves in an opposite direction to the value of the hedge contract. However, due to mark to market accounting requirements and cash margin requirements of commodities exchanges and various counterparties, there may be timing differences between when hedging losses are incurred and when the related physical inventories are sold. In certain instances, these derivative contracts are accounted for as hedges, but there is potential risk that these hedges may not be considered effective from an accounting perspective and would be marked to market in our financial statements. To the extent we use progressively more Canadian crude oil at our Refineries, both our total crude oil inventories and the amount of hedged inventories are likely to increase in future periods. See “Quantitative and Qualitative Disclosures about Market Risk” in Part II, Item 7A.
Instability and volatility in the financial markets could have a negative impact on our business, financial condition, results of operations and cash flows.
The financial markets have recently experienced substantial and unprecedented volatility as a result of dislocations in the credit markets. Market disruptions such as those currently being experienced in the United States and abroad may increase our cost of borrowing or adversely affect our ability to access sources of liquidity upon which we may rely to finance our operations and satisfy our obligations as they become due, and capital may not be available on terms that are reasonably acceptable to us, or at all. These disruptions may include turmoil in the financial services industry, including substantial uncertainty surrounding particular lending institutions with which we do business, reduction in available trade credit due to counterparties liquidity concerns, more strict lending requirements, unprecedented volatility in the markets where our outstanding securities trade, and general economic downturns in the areas where we do business. In addition, a general economic slowdown or the lack of liquidity may result in contractual counterparties with which we do business being unable to satisfy their obligations to us in a timely manner, or at all.
We maintain significant amounts of cash and cash equivalents at several financial institutions that are in excess of federally insured limits. During the year ended December 31, 2008, we recorded a loss of $499,000 on money market funds that had investments in Lehman Brothers, which filed for bankruptcy. Given the current instability of financial institutions, we may experience further losses on our cash and cash equivalents.
External factors beyond our control can cause fluctuations in demand for our products, prices and margins, which may negatively affect income and cash flow.
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. 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, 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.
In addition, 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. 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 of 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 results of operations and cash flows.
We are dependent on others to supply us with substantial quantities of raw materials.
Our business involves converting crude oil and other refinery charges into liquid fuels. We own no crude oil or natural gas reserves and depend on others to supply these feedstocks to our Refineries. We use large quantities of natural gas and electricity to provide heat and mechanical energy required by our processing units. Disruption to our supply of crude oil, natural gas or electricity, or the continued volatility in the costs thereof, could have a material adverse effect on our operations. In addition, our investment in inventory is affected by the general level of crude oil prices, and significant increases in crude oil prices could result in substantial working capital requirements to maintain inventory volumes.
Our Refineries face operating hazards, and the potential limits on insurance coverage could expose us to significant liability costs.
Our operations could be subject to significant interruption, and our profitability could be impacted if either of our Refineries experienced a major accident or fire, was damaged by severe weather or other natural disaster, or was otherwise forced to curtail its operations or shut down. If a crude oil pipeline that supplies crude oil to our Refineries became inoperative, crude oil would have to be supplied to our Refineries through an alternative pipeline or from additional tank truck deliveries to the Refineries. Alternative supply arrangements could require additional capital expenditures, hurt our business and profitability and cause us to operate the affected Refinery at less than full capacity until pipeline access was restored or crude oil transportation was fully replaced. In addition, a major accident, fire or other event could damage our Refineries or the environment or cause personal injuries. If either of our Refineries experiences a major accident or fire or other event or an interruption in supply or operations, our business could be materially adversely affected if the damage or liability exceeds the amounts of business interruption, property, terrorism and other insurance that we maintain against these risks.
Our Refineries consist of many processing units, a number of which have been in operation for many years. One or more of the units may require additional unscheduled down time for unanticipated maintenance or repairs that are more frequent than our scheduled turnaround for such units. Scheduled and unscheduled maintenance could reduce our revenues during the period of time that our units are not operating.
We face substantial competition from other refining companies, and greater competition in the markets where we sell refined products could adversely affect our sales and profitability.
The refining industry is highly competitive. Many of our competitors are large, integrated, major or independent oil companies that, because of their more diverse operations, larger refineries and stronger capitalization, may be better positioned than we are to withstand volatile industry conditions, including shortages or excesses of crude oil or refined products or intense price competition at the wholesale level. Many of these competitors have financial and other resources substantially greater than ours.
We are not engaged in the petroleum exploration and production business and therefore do not produce any of our crude oil feedstocks. 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 crude oil 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, such as wind, solar and hydropower, 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 our industry, there could be a material adverse effect on our business, financial condition and results of operations.
Our operations involve environmental risks that may require us to make substantial capital expenditures to remain in compliance or that could give rise to material liabilities.
Our results of operations may be affected by increased costs of complying with the extensive environmental laws to which our business is subject and from any possible contamination of our facilities as a result of accidental spills, discharges or other releases of petroleum or hazardous substances.
Our operations are subject to extensive federal, state and local environmental and health and safety laws and regulations relating to the protection of the environment, including those governing the emission or discharge of pollutants into the air and water, product specifications and the generation, treatment, storage, transportation, disposal or remediation of solid and hazardous waste and materials. Environmental laws and regulations that affect the operations, processes and margins for our refined products are extensive and have become progressively more stringent. Additional legislation or regulatory requirements or administrative policies could be imposed with respect to our products or activities. Compliance with more stringent laws or regulations or more vigorous enforcement policies of the regulatory agencies could adversely affect our financial position and results of operations and could require us to make substantial expenditures. Any noncompliance with these laws and regulations could subject us to material administrative, civil or criminal penalties or other liabilities. For examples of existing and potential future regulations and their possible effects on us, please see “Environmental” in Note 12 in the “Notes to Consolidated Financial Statements.”
Our business is inherently subject to accidental spills, discharges or other releases of petroleum or hazardous substances. Past or future spills related to any of our operations, including our Refineries, pipelines or product terminals, could give rise to liability (including potential cleanup responsibility) to governmental entities or private parties under federal, state or local environmental laws, as well as under common law. This could involve contamination associated with facilities that we currently own or operate, facilities that we formerly owned or operated and facilities to which we sent wastes or by-product for treatment or disposal and other contamination. Accidental discharges could occur in the future, future action may be taken in connection with past discharges, governmental agencies may assess penalties against us in connection with past or future contamination and third parties may assert claims against us for damages allegedly arising out of any past or future contamination. The potential penalties and clean-up costs for past or future releases or spills, the failure of prior owners of our facilities to complete their clean-up obligations, the liability to third parties for damage to their property, or the need to address newly-discovered information or conditions that may require a response could be significant, and the payment of these amounts could have a material adverse effect on our business, financial condition and results of operations.
Our operations are subject to various laws and regulations relating to occupational health and safety, which could give rise to increased costs and material liabilities.
The nature of our business may result from time to time in industrial accidents. Our operations are subject to various laws and regulations relating to occupational health and safety. Continued efforts to comply with applicable health and safety laws and regulations, or a finding of non-compliance with current regulations, could result in additional capital expenditures or operating expenses, as well as fines and penalties.
We could incur substantial costs or disruptions in our business if we cannot obtain or maintain necessary permits and authorizations.
Our operations require numerous permits and authorizations under various laws and regulations, including environmental and health and safety laws and regulations. These authorizations and permits are subject to revocation, renewal or modification and can require operational changes, which may involve significant costs, to limit impacts or potential impacts on the environment and/or health and safety. A violation of these authorization or permit conditions or other legal or regulatory requirements could result in substantial fines, criminal sanctions, permit revocations, injunctions and/or refinery shutdowns. In addition, major modifications of our operations could require changes to our existing permits or expensive upgrades to our existing pollution control equipment, which could have a material adverse effect on our business, financial condition or results of operations.
Hurricanes along the Gulf Coast could disrupt our supply of crude oil and our ability to complete capital investment projects in a timely manner.
In 2005 and 2008, tropical hurricanes and related storm activity, such as windstorms, storm surges, floods and tornadoes, caused extensive and catastrophic physical damage in and to coastal and inland areas located in the Gulf Coast region of the United States (parts of Texas, Louisiana, Mississippi and Alabama) and certain other parts of the southeastern parts of the United States. Some of the materials we use for our capital projects are fabricated at facilities located along the Gulf Coast. Should other storms of this nature occur in the future, it is possible that the storms and their collateral effects could result in delays or cost increases for our capital investment projects.
In addition, supplies of crude oil to our El Dorado Refinery are sometimes shipped from Gulf Coast production or terminaling facilities. This crude oil supply source could be potentially threatened in the event of future catastrophic damage to such facilities.
We may have labor relations difficulties with some of our employees represented by unions.
Approximately 56 percent of our employees were covered by collective bargaining agreements at December 31, 2008. Our El Dorado Refinery union contract expires in 2012 and our Cheyenne Refinery union contracts expire by July 2009, and there is no assurance that we will be able to enter into new contracts on terms acceptable to us or at all. A failure to do so may increase our costs or result in an interruption of our business. See Item 1 “Business-Employees.” In addition, employees may conduct a strike at some time in the future, which may adversely affect our operations.
Terrorist attacks and threats or actual war may negatively impact our business.
Terrorist attacks in the United States and the war in Iraq, as well as events occurring in response to or in connection with them, including future terrorist attacks against U.S. targets, rumors or threats of war, actual conflicts involving the United States or its allies, or military or trade disruptions affecting our suppliers or our customers, could adversely impact our operations. In addition, any terrorist attack could have an adverse impact on energy prices, including prices for our crude oil and refined products, and an adverse impact on the margins from our refining and marketing operations. As a result, there could be delays or losses in the delivery of supplies and raw materials to us, decreased sales of our products and extensions of time for payment of accounts receivable from our customers.
None.
Refining and Terminal Operations We own an approximately 255 acre site on which the Cheyenne Refinery is located in Cheyenne, Wyoming and an approximately 1,000 acre site on which the El Dorado Refinery is located in El Dorado, Kansas. We lease the approximately two acre site in Henderson, Colorado on which our products and blending terminal is located.
Other Properties
We lease approximately 6,500 square feet of office space in Houston, Texas for our corporate headquarters under a lease expiring in October 2009. We also lease approximately 28,000 square feet of office space in Denver, Colorado under a lease expiring in April 2012 for our refining, marketing and raw material supply operations.
See “Litigation” and “Environmental” in Note 12 in the “Notes to Consolidated Financial Statements.”
Item 4. Submission of Matters to a Vote of Security Holders
None.
We file reports with the SEC, including annual reports on Form 10-K, quarterly reports on Form 10-Q and other reports from time to time. The public may read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Room 1580, Washington, DC, 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. We are an electronic filer, and the SEC’s Internet site at http://www.sec.gov contains the reports, proxy and information statements, and other information filed electronically.
As required by Section 402 of the Sarbanes-Oxley Act of 2002, we have adopted a code of ethics that applies to our chief executive officer, chief financial officer and principal accounting officer. This code of ethics is posted on our web site. Our web site address is: http://www.frontieroil.com. We make our web site content available for informational purposes only. It should not be relied upon for investment purposes, nor is it incorporated by reference in this Form 10-K. We make available on this web site under “Investor Relations,” free of charge, our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports as soon as reasonably practicable after we electronically file those materials with, or furnish those materials to, the SEC.
We filed our 2008 annual CEO certification with the New York Stock Exchange (“NYSE”) on April 23, 2008. We anticipate filing our 2009 annual CEO certification with the NYSE on or about May 8, 2009. In addition, we filed with the SEC as exhibits to our Form 10-K for the year ended December 31, 2008 the CEO and CFO certifications required under Section 302 of the Sarbanes-Oxley Act of 2002.
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities Our common stock is listed on the New York Stock Exchange under the symbol FTO. The quarterly high and low sales as reported on the New York Stock Exchange for 2008 and 2007 are shown in the following table:
| 2008 | | High | | | Low | |
| Fourth quarter | | $ | 18.38 | | | $ | 7.51 | |
| Third quarter | | | 24.26 | | | | 16.49 | |
| Second quarter | | | 33.00 | | | | 23.03 | |
| First quarter | | | 41.00 | | | | 25.22 | |
| 2007 | | High | | | Low | |
| Fourth quarter | | $ | 49.13 | | | $ | 39.54 | |
| Third quarter | | | 49.10 | | | | 31.61 | |
| Second quarter | | | 45.75 | | | | 31.95 | |
| First quarter | | | 33.75 | | | | 25.47 | |
The approximate number of holders of record for our common stock as of February 20, 2009 was 912. The quarterly cash dividend on our common stock was $0.03 per share for the quarters ended June 30, 2006 through March 31, 2007. The quarterly cash dividend was $0.05 per share for the quarters ended June 30, 2007 through March 31, 2008. The quarterly cash dividend was $0.06 per share for the quarters ended June 30, 2008 through December 31, 2008. Our 6.625% Senior Notes, our 8.5% Senior Notes and our Revolving Credit Facility may restrict dividend payments based on the covenants related to interest coverage and restricted payments. See Notes 6 and 7 in the “Notes to Consolidated Financial Statements.”
The following graph indicates the performance of our common stock against the S&P 500 Index and against a refining peer group which is comprised of Sunoco Inc., Holly Corporation, Valero Energy Corporation and Tesoro Corporation. The following information in this Item 5 of this Annual Report on Form 10-K is not deemed to be “soliciting material” or to be “filed” with the SEC or subject to Regulation 14A or 14C under the Securities Exchange Act of 1934 or to the liabilities of Section 18 of the Securities Exchange Act of 1934, and will not be deemed to be incorporated by reference into any filing under the Securities Act of 1933 or the Securities Exchange Act of 1934, except to the extent we specifically incorporate it by reference into such a filing.
| Five Year Financial Data | | | | | | | | | | | | | | | |
| (Unaudited) | | Years Ended December 31, | |
| | | 2008 | | | 2007 | | | 2006 | | | 2005 | | | 2004 | |
| | | (Dollars in thousands, except per share amounts) | |
| | | | | | | | | | | | | | | | |
| Revenues | | $ | 6,498,780 | | | $ | 5,188,740 | | | $ | 4,795,953 | | | $ | 4,001,162 | | | $ | 2,861,716 | |
| | | | | | | | | | | | | | | | | | | | | |
| Operating income | | | 116,753 | | | | 755,795 | | | | 574,194 | | | | 450,013 | | | | 142,903 | |
| | | | | | | | | | | | | | | | | | | | | |
Cumulative effect of accounting change, net of income taxes (1) | | | - | | | | - | | | | - | | | | (2,503 | ) | | | - | |
| | | | | | | | | | | | | | | | | | | | | |
| Net income | | | 80,234 | | | | 499,125 | | | | 379,277 | | | | 275,158 | | | | 69,392 | |
| | | | | | | | | | | | | | | | | | | | | |
| Basic earnings per share: | | | | | | | | | | | | | | | | | | | | |
Before cumulative effect of accounting change | | $ | 0.78 | | | $ | 4.67 | | | $ | 3.40 | | | $ | 2.51 | | | $ | 0.65 | |
Cumulative effect of accounting change (1) | | | - | | | | - | | | | - | | | | (0.02 | ) | | | - | |
| Net income | | $ | 0.78 | | | $ | 4.67 | | | $ | 3.40 | | | $ | 2.49 | | | $ | 0.65 | |
| | | | | | | | | | | | | | | | | | | | | |
| Diluted earnings per share: | | | | | | | | | | | | | | | | | | | | |
Before cumulative effect of accounting change | | $ | 0.77 | | | $ | 4.62 | | | $ | 3.37 | | | $ | 2.44 | | | $ | 0.63 | |
Cumulative effect of accounting change (1) | | | - | | | | - | | | | - | | | | (0.02 | ) | | | - | |
| Net income | | $ | 0.77 | | | $ | 4.62 | | | $ | 3.37 | | | $ | 2.42 | | | $ | 0.63 | |
| | | | | | | | | | | | | | | | | | | | | |
Working capital (current assets less current liabilities) | | $ | 651,352 | | | $ | 529,510 | | | $ | 479,518 | | | $ | 270,145 | | | $ | 106,760 | |
| | | | | | | | | | | | | | | | | | | | | |
| Total assets | | | 2,018,469 | | | | 1,863,848 | | | | 1,523,925 | | | | 1,223,057 | | | | 770,177 | |
| | | | | | | | | | | | | | | | | | | | | |
| Long-term debt | | | 347,220 | | | | 150,000 | | | | 150,000 | | | | 150,000 | | | | 150,000 | |
| | | | | | | | | | | | | | | | | | | | | |
| Shareholders' equity | | | 1,051,140 | | | | 1,038,614 | | | | 775,854 | | | | 478,692 | | | | 271,120 | |
| | | | | | | | | | | | | | | | | | | | | |
Dividends declared per common share | | $ | 0.230 | | | $ | 0.180 | | | $ | 0.100 | | | $ | 0.575 | | | $ | 0.055 | |
| | | | | | | | | | | | | | | | | | | | | |
(1) As of December 31, 2005, we adopted FASB Interpretation No. 47, "Accounting for Conditional Asset Retirement Obligations." | |
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
General
Frontier operates Refineries in Cheyenne, Wyoming and El Dorado, Kansas as previously discussed in Part I, Item 1 of this Form 10-K. We focus our marketing efforts in the Rocky Mountain and Plains States regions of the United States. We purchase crude oil to be refined and market refined petroleum products, including various grades of gasoline, diesel, jet fuel, asphalt and other by-products.
Results of Operations
To assist in understanding our operating results, please refer to the operating data at the end of this analysis which provides key operating information for our Refineries. Refinery operating data is also included in our quarterly reports on Form 10-Q and on our web site at http://www.frontieroil.com. We make our web site content available for informational purposes only. It should not be relied upon for investment purposes, nor is it incorporated by reference in this Form 10-K.
Overview
Our Refineries have a total annual average crude oil capacity of approximately 182,000 bpd. The four significant indicators of our profitability, which are reflected and defined in the operating data at the end of this analysis, are the gasoline crack spread, the diesel crack spread, the light/heavy crude oil differential and the WTI/WTS crude oil differential. Other significant factors that influence our financial results are refinery utilization, crude oil price trends, asphalt and by-product margins and refinery operating expenses (including natural gas and maintenance). Under our first-in, first-out (“FIFO”) inventory accounting method, crude oil price trends can cause significant fluctuations in the inventory valuation of our crude oil, unfinished products and finished products, thereby resulting in inventory gains (lowering “Raw material, freight and other costs”) when crude oil prices increase and inventory losses (increasing “Raw material, freight and other costs”) when crude oil prices decrease during the reporting period. As crude prices rose during the first seven months of 2008; we realized inventory gains; however, as crude prices declined quickly during the latter part of the year and gasoline and diesel margins contracted, we realized significant inventory losses resulting in an overall inventory loss for the year. We typically do not use derivative instruments to offset price risk on our base level of operating inventories. See “Price Risk Management Activities” under Item 7A for a discussion of our utilization of futures trading.
Crude oil market fundamentals, changes in the macro-economy and geopolitical considerations have caused crude oil prices to be highly volatile. Our results for the year ended December 31, 2008 were negatively impacted by several factors, the primary ones being the rapid increase in crude oil prices during the first seven months of 2008 followed by a rapid decline in crude oil prices the remainder of the year and the weakening U.S. economy. These factors reduced the demand for gasoline, causing a substantial drop in gasoline margins. In addition, our margins on asphalt and other products declined substantially during the first seven months of 2008 as sales prices for these products increased only modestly compared to the significant increase in crude prices.
2008 Compared with 2007
Overview of Results
We had net income for the year ended December 31, 2008, of $80.2 million, or $0.77 per diluted share, compared to net income of $499.1 million, or $4.62 per diluted share, for the same period in 2007. Our operating income of $116.8 million for the year ended December 31, 2008 reflected a decrease of $639.0 million from the $755.8 million operating income for the comparable period in 2007. The average gasoline crack spread was significantly lower during 2008 ($4.75 per barrel) than in 2007 ($17.99 per barrel), and the light/heavy crude oil differentials decreased. The average diesel crack spread was higher during 2008 ($24.59 per barrel) than in 2007 ($22.19 per barrel).
Specific Variances
Refined product revenues. Refined product revenues increased $1.07 billion, or 20%, from $5.27 billion to $6.34 billion for the year ended December 31, 2008 compared to 2007. This increase was due to an increase in average product sales prices ($19.30 higher per sales barrel) partially offset by lower product sales volumes in 2008 (3,776 fewer bpd). Sales prices increased primarily because of higher average crude oil prices in 2008 compared to 2007.
Manufactured product yields. Manufactured product yields (“yields”) are the volumes of specific materials obtained through the distilling of crude oil and the operations of other refinery process units. Yields decreased 5,139 bpd at the El Dorado Refinery and increased 1,773 bpd at the Cheyenne Refinery for the year ended December 31, 2008 compared to 2007. The decrease in yields at the El Dorado Refinery was due to the planned major turnaround work on the crude unit, the coker and the reformer during March and April of 2008.
Other revenues. Other revenues increased $237.6 million to a $156.6 million gain for the year ended December 31, 2008 compared to an $80.9 million loss for 2007, the primary source of which was $146.5 million in net realized and unrealized gains from derivative contracts to hedge in-transit crude oil and excess inventories during the year ended December 31, 2008 compared to $86.4 million in net realized and unrealized losses from derivative contracts to hedge in-transit crude oil and excess inventories in 2007. See “Price Risk Management Activities” under Item 7A and Note 11 in the “Notes to Consolidated Financial Statements” for a discussion of our utilization of commodity derivative contracts. We had gasoline sulfur credit sales of $4.6 million in 2008 compared to $4.8 million in 2007 and $4.5 million of ethanol Renewable Identification Number (“RIN”) sales in 2008 (none in 2007). Ethanol RINs were created to assist in tracking the compliance with national EPA regulations for blending of renewable fuels.
Raw material, freight and other costs. Raw material, freight and other costs include crude oil and other raw materials used in the refining process, purchased products and blendstocks, freight costs for FOB destination sales, as well as the impact of changes in inventory. Raw material, freight and other costs increased by $1.91 billion, or 47%, during the year ended December 31, 2008, from $4.04 billion in 2007 to $5.95 billion in 2008. The increase in raw material, freight and other costs when compared to 2007 was due to higher average crude prices, increased purchased products, lower light/heavy crude oil differentials and inventory losses in 2008 compared to inventory gains in 2007, partially offset by decreased overall crude oil charges during the year ended December 31, 2008 compared to 2007. The average NYMEX WTI priced on the New York Mercantile Exchange was $99.75 per barrel for the year ended December 31, 2008 compared to $72.39 per barrel for the year ended December 31, 2007. Average crude oil charges were 142,938 bpd for the year ended December 31, 2008 compared to 146,046 bpd in 2007. For the year ended December 31, 2008, we realized an increase in raw material, freight and other costs as a result of net inventory losses of approximately $157.4 million after tax ($254.7 million pretax, comprised of a $184.5 million loss at the El Dorado Refinery and a $70.2 million loss at the Cheyenne Refinery) due to decreasing crude oil and refined product prices during the latter part of 2008. For the year ended December 31, 2007, we realized a decrease in raw material, freight and other costs as a result of net inventory gains of approximately $78.4 million after tax ($126.3 million pretax, comprised of a $84.9 million gain at the El Dorado Refinery and a $41.4 million gain at the Cheyenne Refinery) due to increasing crude oil and refined product prices during 2007.
The Cheyenne Refinery raw material, freight and other costs of $92.58 per sales barrel for the year ended December 31, 2008 increased from $62.08 per sales barrel in the same period in 2007 due to higher average crude oil prices, increased purchased products, lower light/heavy crude oil differentials and inventory losses in 2008 compared to inventory gains in 2007. Average crude oil charges of 43,590 bpd for the year ended December 31, 2008 were higher than the 41,778 bpd in 2007 because of a spring 2007 turnaround, a temporary shutdown of the FCCU in the third quarter of 2007, and a December 2007 fire in the coker unit at the Cheyenne Refinery. The heavy crude oil utilization rate at the Cheyenne Refinery expressed as a percentage of the total crude oil charge increased to 76% in the year ended December 31, 2008, from 72% in 2007. The light/heavy crude oil differential for the Cheyenne Refinery averaged $17.15 per barrel in the year ended December 31, 2008 compared to $18.95 per barrel in 2007.
The El Dorado Refinery raw material, freight and other costs of $99.94 per sales barrel for the year ended December 31, 2008 increased from $66.25 per sales barrel in the same period in 2007 due to higher average crude oil prices, lower light/heavy differentials and inventory losses in 2008 compared to inventory gains in 2007 partially offset by decreased overall crude oil charges. Average crude oil charges were 99,347 bpd for the year ended December 31, 2008, compared to 104,268 bpd in 2007. The decrease in average crude oil charges was due to the planned major turnaround work on the crude unit, the coker and the reformer during March and April of 2008. We realized a light/heavy crude oil differential of $17.85 per barrel during 2008 compared to $21.00 per barrel in 2007. For the year ended December 31, 2008, the heavy crude oil utilization rate at our El Dorado Refinery expressed as a percentage of the total crude oil charge was approximately 17%, compared to 15% in 2007. The WTI/WTS crude oil differential decreased from an average of $5.02 per barrel in the year ended December 31, 2007 to an average of $3.92 per barrel in 2008.
Refinery operating expenses. Refinery operating expenses, excluding depreciation, include both the variable costs (energy and utilities) and the fixed costs (salaries, taxes, maintenance costs and other) of operating the Refineries. Refinery operating expenses, excluding depreciation, increased $20.8 million, or 7%, to $321.4 million in the year ended December 31, 2008 from $300.5 million in 2007.
The Cheyenne Refinery operating expenses, excluding depreciation, were $116.7 million in the year ended December 31, 2008 compared to $109.2 million in 2007. The increased expenses and the 2008 compared to 2007 variances included: increased additives and chemicals costs ($4.4 million due to both price and volume increases), higher turnaround amortization ($2.8 million due to amortization of costs of 2007 turnarounds), higher electricity costs ($1.1 million due to both price and volume increases), increased natural gas costs ($819,000 due to increased prices partially offset by lower volumes), higher property and other taxes ($720,000 due to refinery additions), demurrage ($443,000) and training ($397,000). These increases were partially offset by decreased maintenance costs ($3.8 million) as 2007 maintenance costs included $3.8 million of costs relating to repairs from the December 2007 coker unit fire, and decreased environmental costs ($879,000).
The El Dorado Refinery operating expenses, excluding depreciation, were $204.7 million in the year ended December 31, 2008, increasing from $191.3 million for the year ended December 31, 2007. The primary areas of increased costs and the variance amounts for the 2008 period compared to the 2007 period were: increased maintenance costs ($9.5 million, primarily related to demolition, catalyst and repair costs incurred during the March 2008 turnaround), increased salaries and benefits expenses ($3.0 million, mostly due to increased overtime in relation to the March 2008 turnaround), higher electricity costs ($1.5 million), increased operating supplies costs ($710,000) and higher turnaround amortization ($571,000). These increases were partially offset by decreased environmental costs of $1.6 million because 2007 included $1.2 million in environmental penalties and there were no penalties in 2008.
Selling and general expenses. Selling and general expenses, excluding depreciation, decreased $11.2 million, or 20%, from $55.3 million for the year ended December 31, 2007 to $44.2 million for the year ended December 31, 2008, primarily due to the $6.3 million recognition of the loss on the Beverly Hills settlement during the year ended December 31, 2007. In addition, salaries and benefits expense (including stock-based compensation expense) during the year ended December 31, 2008 decreased $3.8 million compared to the same period in 2007. See Note 9 under “Stock-based Compensation” in the “Notes to Consolidated Financial Statements” for a detailed discussion of our stock-based compensation. Stock-based compensation expense was $17.2 million for the year ended December 31, 2008 compared to $20.0 million in 2007.
Depreciation, amortization and accretion. Depreciation, amortization and accretion increased $12.7 million, or 24%, from $53.0 million for the year ended December 31, 2007 to $65.8 million in 2008 because of increased capital investments in our Refineries, including our El Dorado Refinery crude unit and vacuum tower expansion project placed into service in the second quarter of 2008.
Net gains on sales of assets. The $44,000 gain on the sale of assets during the year ended December 31, 2008 compares to a $15.2 million gain on sale of assets in 2007. The 2007 gain resulted from a gain of $17.3 million from the sale of our 34.72% interest in a crude oil pipeline in Wyoming and a 50% interest in two crude oil tanks in Guernsey, Wyoming in September 2007, partially offset by the buyout and sale of a leased aircraft.
Interest expense and other financing costs. Interest expense and other financing costs of $15.1 million for the year ended December 31, 2008 increased $6.4 million, or 72%, from $8.8 million in 2007. The increase in interest expense related to interest of $4.9 million on the new 8.5% Senior Notes offering, $540,000 higher interest expense on the Utexam Master Crude Oil Purchase and Sale Contract (“Utexam Arrangement”) (see “Leases and Other Commitments” in Note 12 in the “Notes to Consolidated Financial Statement”), and $711,000 increased interest and facility fees on our revolving credit facility. Capitalized interest for the year ended December 31, 2008 was $6.6 million compared to $8.1 million in 2007. These increased expenses were partially offset by a $1.2 million reversal of prior years interest expenses for 2004 income tax contingency interest accruals due to the statute of limitations expiring. Average debt outstanding (excluding amounts payable under the Utexam Arrangement) increased to $398.1 million during the year ended December 31, 2008 from $150.0 million for the same period in 2007.
Interest and investment income. Interest and investment income decreased $16.4 million, or 75%, from $21.9 million in the year ended December 31, 2007 to $5.4 million in the year ended December 31, 2008, due to lower cash balances during the first eight months (prior to receiving the proceeds from our 8.5% Senior Notes offering) of 2008 and lower interest rates on invested cash.
Provision for income taxes. The provision for income taxes for the year ended December 31, 2008 was $26.8 million on pretax income of $107.0 million (or 25.0%) compared to $269.7 million on pretax income of $768.9 million (or 35.1%) in 2007. The effective tax rate for the year ended December 31, 2008 was lower than the effective tax rate in the comparable period in 2007 primarily from recognizing the benefit from $23.3 million of Kansas income tax credits for expansion projects at our El Dorado Refinery which reduced the effective tax rate (net of federal tax impact) by approximately 14%. The American Jobs Creation Act of 2004 (“the Act”) created Internal Revenue Code Section 199 (“Section 199”), which provides an income tax benefit to domestic manufacturers. We recorded income tax benefits under Section 199 of approximately $15.4 million and $5.7 million, in our 2007 and 2006 income tax provisions, respectively. The effective tax rate in 2008 was increased by approximately 2.9% due to reversing previously recognized 2007 and 2006 production activities deductions from filing an amended 2006 return in 2008 and the planned carryback of the 2008 taxable loss. The Company did not recognize a benefit from the production activities deduction in 2008, as it had a taxable loss. The Act also benefited our 2006 current income taxes payable by allowing us an accelerated depreciation deduction of 75% of qualified capital costs incurred to achieve low sulfur diesel fuel requirements (See “Environmental” under Note 12 in the “Notes to Consolidated Financial Statements”). The Act also provided for a $0.05 per gallon federal income tax credit on compliant diesel fuel up to an amount equal to the remaining 25% of these qualified capital costs. The $0.05 per gallon federal income tax credit allowed us to realize an $8.5 million federal income tax credit ($5.5 million excess tax benefit) and a $22.4 million federal income tax credit ($14.5 million excess tax benefit) in the years ended December 31, 2007 and 2006, respectively. This credit reduced our 2007 and 2006 income taxes payable and reduced our overall effective income tax rate for those years. The Energy Policy Act of 2005 added Section 179C to the Internal Revenue Code which provides an accelerated deduction for qualified capital costs incurred to expand an existing refinery. This accelerated deduction allows an expense deduction of 50% of such costs in the year the qualified projects are placed in service with the remaining costs depreciable under regular tax depreciation rules. This Section 179C deduction has benefited our cash flow for income taxes by reducing our taxable income for 2006 and 2007 and is a primary factor in our 2008 taxable loss. See “Income Taxes” in Note 8 in the “Notes to Consolidated Financial Statements” for more information on our income taxes and detailed information on our deferred tax assets.
2007 Compared with 2006
Overview of Results
We had net income for the year ended December 31, 2007, of $499.1 million, or $4.62 per diluted share, compared to net income of $379.3 million, or $3.37 per diluted share, in 2006. Our operating income of $755.8 million for the year ended December 31, 2007, reflected an increase of $181.6 million from the $574.2 million operating income for the comparable period in 2006. The average diesel crack spread was higher during 2007 ($22.19 per barrel) than in 2006 ($20.13 per barrel). The average gasoline crack spread was also higher during 2007 ($17.99 per barrel) than in 2006 ($12.82 per barrel), and the light/heavy crude oil differentials improved.
Specific Variances
Refined product revenues. Refined product revenues increased $510.0 million, or 11%, from $4.8 billion to $5.3 billion for the year ended December 31, 2007 compared to 2006. This increase was due to an increase in average product sales prices ($9.05 higher per sales barrel) partially offset by lower product sales volumes in 2007 (1,890 fewer bpd). Sales prices increased primarily as a result of increased crude oil prices and improvements in the gasoline and diesel crack spreads.
Manufactured product yields. Yields decreased 1,826 bpd at the El Dorado Refinery and 4,067 bpd at the Cheyenne Refinery for the year ended December 31, 2007 compared to 2006. Planned and unplanned shut downs at the Cheyenne Refinery during 2007 caused yields to be lower during 2007 than 2006. At the El Dorado Refinery, we processed more heavy crude oils during 2007 than in 2006, which resulted in decreased yields.
Other revenues. Other revenues decreased $117.2 million to an $80.9 million loss for the year ended December 31, 2007, compared to a $36.3 million gain in 2006, the sources of which were $86.4 million in net losses from derivative contracts in the year ended December 31, 2007 compared to net derivative gains of $34.6 million for the same period in 2006 offset by $4.8 million in gasoline sulfur credit sales in 2007 ($1.5 million in 2006). See “Price Risk Management Activities” under Item 7A and Note 11 in the “Notes to Consolidated Financial Statements” for a discussion of our utilization of commodity derivative contracts.
Raw material, freight and other costs. Raw material, freight and other costs increased by $188.3 million, or 5%, during the year ended December 31, 2007, from $3.9 billion in 2006 to $4.0 billion in 2007. The increase in raw material, freight and other costs when compared to 2006 was due to higher average crude prices, offset by lower crude oil charges and inventory gains in the year ended December 31, 2007 compared to inventory losses in the year ended December 31, 2006. We benefited from improved light/heavy crude oil differentials during the year ended December 31, 2007 compared to 2006. The average WTI crude oil priced on the New York Mercantile Exchange was $72.39 for the year ended December 31, 2007 compared to $66.22 for the year ended December 31, 2006. Average crude oil charges were 146,046 bpd for the year ended December 31, 2007, compared to 154,473 bpd in 2006. For the year ended December 31, 2007, we realized a decrease in raw material, freight and other costs as a result of net inventory gains of approximately $78.4 million after tax ($126.3 million pretax, comprised of an $84.9 million gain at the El Dorado Refinery and a $41.4 million gain at the Cheyenne Refinery) due to increasing crude oil and refined product prices during 2007. For the year ended December 31, 2006, we realized an increase in raw material, freight and other costs as a result of net inventory losses of approximately $16.1 million after tax ($25.7 million pretax, comprised of a $31.7 million loss at the El Dorado Refinery and a $6.0 million gain for the Cheyenne Refinery) due to decreasing crude oil and refined product prices during the latter part of 2006.
The Cheyenne Refinery raw material, freight and other costs of $62.08 per sales barrel for the year ended December 31, 2007 increased from $57.07 per sales barrel in 2006 due to higher crude oil prices, partially offset by an inventory gain in 2007 compared to an inventory loss in 2006, fewer crude oil charges in 2007 and the benefit of an improved light/heavy crude oil differential in 2007. Average crude oil charges of 41,778 bpd for the year ended December 31, 2007 were lower than the 45,999 bpd in the comparable period in 2006 because of a spring 2007 turnaround, a temporary shutdown of the FCCU in the third quarter, and a December 2007 fire in the coker unit at the Cheyenne Refinery. The heavy crude oil utilization rate at the Cheyenne Refinery expressed as a percentage of the total crude oil charge decreased to 72% in the year ended December 31, 2007, from 73% in 2006. The light/heavy crude oil differential for the Cheyenne Refinery averaged $18.95 per barrel in the year ended December 31, 2007 compared to $17.49 per barrel in 2006.
The El Dorado Refinery raw material, freight and other costs of $66.25 per sales barrel for the year ended December 31, 2007 increased from $63.15 per sales barrel in 2006 due to higher average crude oil prices partially offset by inventory gains in 2007 compared to inventory losses in 2006 and lower crude oil charges in 2007. Average crude oil charges were 104,268 bpd for the year ended December 31, 2007, compared to 108,475 bpd in 2006. Due to the favorable light/heavy differentials, we ran more heavy crude oil in 2007 which limited the overall crude rate. We realized a light/heavy crude oil differential of $21.00 per barrel during 2007. In 2006, our El Dorado Refinery began charging Canadian heavy crude oil and achieved a light/heavy crude oil differential of $19.48 per barrel. For the year ended December 31, 2007, the heavy crude oil utilization rate at our El Dorado Refinery expressed as a percentage of the total crude oil charge was approximately 15%, compared to 11% in 2006. The WTI/WTS crude oil differential decreased from an average of $5.22 per barrel in the year ended December 31, 2006 to an average of $5.02 per barrel in 2007.
Refinery operating expenses. Refinery operating expenses, excluding depreciation, increased $23.4 million, or 8%, to $300.5 million in the year ended December 31, 2007 from $277.1 million in 2006.
The Cheyenne Refinery operating expenses, excluding depreciation, were $109.2 million in the year ended December 31, 2007, compared to $101.9 million in 2006. The increased expenses included higher maintenance costs ($5.6 million, with $3.8 million of the costs relating to repair from a coker unit fire in December 2007), higher salaries and benefits ($3.5 million, including $1.0 million in increased maintenance salaries and $1.1 million additional bonus costs due to an increased number of employees), higher turnaround amortization ($1.5 million) and higher consulting and legal expenses ($1.4 million). These increases were partially offset by decreased environmental costs ($3.2 million, primarily related to an estimated waste water pond clean up accrual recorded in 2006 of $5.0 million offset by a $3.0 million increase in groundwater remediation accrual in 2007), electricity costs ($1.6 million) and natural gas costs ($1.0 million).
The El Dorado Refinery operating expenses, excluding depreciation, were $191.3 million in the year ended December 31, 2007, increasing from $175.3 million in 2006. The primary areas of increased costs were in higher property taxes ($6.0 million), increased chemicals and additives costs ($3.8 million), higher salaries and benefits ($2.6 million, including $1.2 million in increased bonus costs and $715,000 in increased stock-based compensation costs), higher consulting and legal expenses ($1.7 million), higher natural gas costs ($1.3 million) and higher environmental expenses ($1.2 million).
Selling and general expenses. Selling and general expenses, excluding depreciation, increased $2.9 million, or 5%, from $52.5 million for the year ended December 31, 2006 to $55.3 million in 2007, primarily due to a $1.3 million increase in salaries and benefits expense, which resulted from $4.3 million in additional stock-based compensation expense and general salary increases, offset by a $3.8 million reduction in cash bonus expense. See Note 9 under “Stock-based Compensation” in the “Notes to Consolidated Financial Statements” for a detailed discussion of our stock-based compensation. Stock-based compensation expense was $20.0 million for the year ended December 31, 2007 compared to $15.8 million for the comparable period in 2006. Beverly Hills litigation costs also increased by $641,000 in the year ended December 31, 2007, compared to the year ended December 31, 2006.
Depreciation, amortization and accretion. Depreciation, amortization and accretion increased $11.8 million, or 29%, from $41.2 million for the year ended December 31, 2006 to $53.0 million in 2007 because of increased capital investment in our Refineries, including the ultra low sulfur diesel projects placed into service in the middle of the second quarter of 2006 and our Cheyenne Refinery coker expansion project placed into service in the second quarter of 2007. We also had higher depreciation expense during 2007 due to changes in the estimated useful lives of certain assets that were retired in 2008 or are expected to be retired in 2009 in connection with certain of our capital projects.
Net gains on sales of assets. The $15.2 million gain on sale of assets during the year ended December 31, 2007 resulted from a gain of $17.3 million from the sale of our 34.72% interest in a crude oil pipeline in Wyoming and a 50% interest in two crude oil tanks in Guernsey, Wyoming in September 2007, partially offset by the buyout and sale of a leased aircraft.
Interest expense and other financing costs. Interest expense and other financing costs of $8.8 million for the year ended December 31, 2007 decreased $3.4 million, or 28%, from $12.1 million in 2006. The decrease was due to $8.1 million of interest cost being capitalized in the year ended December 31, 2007, compared to $3.8 million of interest cost being capitalized in the year ended December 31, 2006, offset by $2.4 million in accrued interest expense for income tax contingencies in 2007 ($1.5 million in 2006) and $2.2 million ($1.9 million in 2006) in facility costs and financing expenses related to the Utexam Master Crude Oil Purchase and Sale Contract entered into in March 2006 (“Utexam Arrangement”) (see “Leases and Other Commitments” in Note 12 in the “Notes to Consolidated Financial Statements”). Average debt outstanding (excluding amounts payable under the Utexam Arrangement) decreased to $150.0 million during the year ended December 31, 2007 from $151.7 million in 2006.
Interest and investment income. Interest and investment income increased $3.8 million, or 21%, from $18.1 million in the year ended December 31, 2006 to $21.9 million in 2007, due to larger cash balances and higher interest rates on invested cash.
Provision for income taxes. The provision for income taxes for the year ended December 31, 2007 was $269.7 million on pretax income of $768.9 million (or 35.1%) compared to $200.8 million on pretax income of $580.1 million (or 34.6%) in 2006. The American Jobs Creation Act of 2004 (“the Act”) benefited our 2006 current income taxes payable by allowing us an accelerated depreciation deduction of 75% of qualified capital costs incurred to achieve low sulfur diesel fuel requirements (See “Environmental” under Note 12 in the “Notes to Consolidated Financial Statements”). The Act also provides for a $0.05 per gallon federal income tax credit on compliant diesel fuel up to an amount equal to the remaining 25% of these qualified capital costs. The $0.05 per gallon federal income tax credit allowed us to realize an $8.5 million federal income tax credit ($5.5 million excess tax benefit) and a $22.4 million federal income tax credit ($14.5 million excess tax benefit) in the years ended December 31, 2007 and 2006, respectively. This credit reduced our 2007 and 2006 income taxes payable and reduced our overall effective income tax rate for those years. Another provision of the Act, the Section 199 production activities deduction for manufacturers, benefited our 2007 and 2006 income taxes payable by an estimated $16.0 million and $5.7 million, respectively, and reduced our overall effective tax rate in both of those years. See Note 8 in the “Notes to Consolidated Financial Statements” for detailed information on our deferred tax assets.
Liquidity and Capital Resources
Cash flows from operating activities. Net cash provided by operating activities was $297.3 million for the year ended December 31, 2008 compared to net cash provided by operating activities of $429.0 million during the year ended December 31, 2007. Lower operating income decreased cash flow for 2008 but was partially offset by cash flows provided from working capital changes during 2008.
Working capital changes provided a total of $65.3 million of cash in the year ended December 31, 2008 while using $137.2 million of cash in 2007. The most significant working capital item providing cash during the year ended December 31, 2008 was a decrease in inventories of $245.8 million. The decrease in inventories was primarily due to lower average prices of both crude oil and refined products at December 31, 2008 compared to December 31, 2007.
Working capital uses of cash during the year ended December 31, 2008 included a decrease in accounts payable of $117.4 million, and an increase in trade, note and other receivables of $28.8 million. The decrease in accounts payable was mainly due to a decreased crude payable from lower crude costs at December 31, 2008 compared to December 31, 2007. The increase in trade, note and other receivables primarily resulted from an income tax receivable of $116.1 million as of December 31, 2008 compared to $24.1 million as of December 31, 2007, offset by lower trade receivables due to lower prices of refined products as of December 31, 2008 compared to December 31, 2007.
We made estimated federal and state income tax payments of $47.5 million and $12.2 million, respectively, during the year ended December 31, 2008. As of December 31, 2008, we had estimated receivables for state income taxes of $15.8 million and federal income taxes of $100.3 million.
At December 31, 2008, we had $483.5 million of cash and cash equivalents, working capital of $651.4 million and $283.0 million available for borrowings under our revolving credit facility. Our operating cash flows are affected by crude oil and refined product prices and other risks as discussed in Item 7A “Quantitative and Qualitative Disclosures About Market Risks.”
Cash flows used in investing activities. Capital expenditures during the year ended December 31, 2008 were $209.4 million, which included approximately $133.4 million for the El Dorado Refinery and $75.4 million for the Cheyenne Refinery. The $133.4 million of capital expenditures for our El Dorado Refinery included $34.2 million to complete the crude unit and vacuum tower expansion ($153.6 million total cost), $26.6 million on the coke drum replacement, which was substantially completed in the third quarter of 2008 ($60.4 million estimated total cost), and $20.3 million on the gasoil hydrotreater revamp, as well as operational, payout, safety, administrative, environmental and optimization projects. The $75.4 million of capital expenditures for our Cheyenne Refinery included approximately $11.8 million for the boiler replacement ($14.0 million estimated total cost), $8.7 million for the amine plant ($21.3 million total cost), $11.0 million for the new Cheyenne Refinery office building ($15.4 million estimated total cost), and $3.1 million for the coker expansion, as well as environmental, operational, safety, administrative and payout projects. We funded our 2008 capital expenditures with cash generated from our operations.
Under the provisions of the purchase agreement with Shell for our El Dorado Refinery, we were required to make contingent earn-out payments for each of the years 2000 through 2007 equal to one-half of the excess over $60.0 million per year of the El Dorado Refinery’s annual revenues less raw material, freight and other costs and refinery operating expenses, excluding depreciation. The total amount of these potential contingent earn-out payments was capped at $40.0 million, with an annual cap of $7.5 million. Such contingency payments were recorded as additional acquisition costs. A final payment of $7.5 million was paid in early 2008, based on 2007 results, and was accrued as of December 31, 2007. Including the final payment made in early 2008, we paid a total of $37.5 million for contingent earn-out payments and are no longer subject to this provision of the Shell agreement.
Cash flows from financing activities. On September 15, 2008, the Company issued $200.0 million aggregate principal amount of 8.5% Senior Notes. The 8.5% Senior Notes, which mature on September 15, 2016, were issued at a 1.42% discount ($2.8 million) and the Company received net proceeds (after underwriting fees) of $195.3 million. Interest on the notes is paid semi-annually. The 8.5% Senior Notes are redeemable, at the option of the Company, at 104.25% after September 15, 2012, declining to 100.0% in 2014. Prior to September 15, 2012, the Company may at its option redeem the 8.5% Senior Notes at a make-whole amount, plus accrued and unpaid interest. The proceeds from the notes offering are being used for general corporate purposes.
During the year ended December 31, 2008, we spent $56.3 million to repurchase stock under the stock repurchase program discussed below. Treasury stock also increased by 386,350 shares ($10.8 million) from stock surrendered by employees to pay minimum withholding taxes on stock-based compensation which vested during 2008. We also paid $23.1 million in dividends during the year ended December 31, 2008.
Through December 31, 2007, our Board of Directors had approved a total of $300 million for share repurchases, of which $243.6 million had been spent. In February 2008, our Board of Directors approved an additional $100 million to be utilized for share repurchases. As indicated above, we used $56.3 million to repurchase stock under this program during the year ended December 31, 2008, leaving a remaining authorization of $100.2 million.
During the year ended December 31, 2008, we issued 160,000 shares of common stock from our treasury in connection with stock option exercises by employees and members of our Board of Directors, for which we received $405,000 in cash and 9,224 shares ($306,000) of our common stock in stock swaps where stock was surrendered to facilitate the exercise of the option.
As of December 31, 2008, we had $347.2 million of long-term debt, due starting in 2011, and no borrowings under our revolving credit facility. We had $12.5 million of outstanding letters of credit under our revolving credit facility. We were in compliance with the financial covenants of our revolving credit facility as of December 31, 2008. We had shareholders’ equity of $1.05 billion as of December 31, 2008.
Our Board of Directors declared regular quarterly cash dividends of $0.05 per share in December 2007 and February 2008, which were paid in January and April 2008, respectively. In April 2008, our Board of Directors announced an increase in the regular quarterly cash dividend to $0.06 per share ($0.24 annualized) for shareholders of record on June 27, 2008, which was paid in July 2008. In August and November 2008, the Company declared regular quarterly cash dividends of $0.06 per share, which were paid in October 2008 and January 2009, respectively. The total cash required for the dividend declared in November 2008 was approximately $6.2 million and was accrued as a dividend payable at year-end. “Accrued dividends” are included in the line item “Accrued Liabilities and Other” on the Consolidated Balance Sheets and includes dividends accrued to date on restricted stock, which are not paid until the restricted stock vests.
Future capital expenditures
Significant future capital projects. The gasoil hydrotreater revamp at the El Dorado Refinery is the key project to achieve gasoline sulfur compliance for our El Dorado Refinery and has a total estimated cost of $90 million ($36.5 million incurred as of December 31, 2008) (see “Environmental” in Note 12 in the “Notes to Condensed Consolidated Financial Statements”). The project will also result in a significant yield improvement for the catalytic cracking unit and is anticipated to be completed in the first quarter of 2010. As of December 31, 2008, outstanding non-cancelable purchase commitments for the gasoil hydrotreater revamp were $1.7 million. The scope of the El Dorado Refinery’s originally planned $84 million catalytic cracker expansion project was reduced to $29.0 million ($5.0 million incurred as of December 31, 2008) because of the low gasoline margins and generally weak economic conditions. The project is anticipated to be completed in the fall of 2009 and had outstanding non-cancelable purchase commitments at December 31, 2008 of $1.6 million. The El Dorado Refinery catalytic cracker regenerator emission control project, with a fall 2009 estimated completion date and total estimated cost of $34 million ($16.6 million incurred as of December 31, 2008), will add a scrubber to improve the environmental performance of the unit, specifically as it relates to flue-gas emissions. This project is necessary to meet various EPA requirements (see “Environmental” in Note 12 in the “Notes to Condensed Consolidated Financial Statements”). At December 31, 2008, the catalytic cracker regenerator emission control project had outstanding non-cancelable purchase commitments of $800,000. The above amounts include estimated capitalized interest.
2009 capital expenditures. Including the projects discussed above, 2009 capital expenditures aggregating approximately $187.5 million are currently planned, and include $136.4 million at our El Dorado Refinery, $50.4 million at our Cheyenne Refinery, $287,000 at our products terminal and blending facility and $392,000 at our Denver and Houston offices. The $136.4 million of planned capital expenditures for our El Dorado Refinery includes $49.1 million for the gasoil hydrotreater revamp project, $23.2 million for the catalytic cracker expansion project and $16.9 million for the catalytic cracker regenerator emission control project, as mentioned above, as well as environmental, operational, safety, payout and administrative projects. The $50.4 million of planned capital expenditures for our Cheyenne Refinery includes environmental, operational, safety, payout and administrative projects. We expect that our 2009 capital expenditures will be funded with cash generated by our operations and by using a portion of our existing cash balance, if necessary. We will continue to review our capital expenditures in light of market conditions. We may experience cost overruns and/or schedule delays on any of these projects.
Contractual Cash Obligations
The table below lists the contractual cash obligations we have by period. These items include our long-term debt based on their maturity dates, our operating lease commitments, purchase obligations and other long-term liabilities.
Our operating leases include building, equipment, aircraft and vehicle leases, which expire from 2009 through 2017, as well as an operating sublease for the use of the cogeneration facility at our El Dorado Refinery. The non-cancelable sublease, entered into in connection with the acquisition of our El Dorado Refinery in 1999, expires in 2016 with an option that allows us to renew the sublease for an additional eight years. This lease has both a fixed and a variable component.
Purchase obligations include agreements to purchase goods or services that are enforceable and legally binding and that specify terms, including fixed or minimum quantities to be purchased, fixed, minimum or variable price provisions, and the approximate timing of the transaction. Purchase obligations exclude agreements that are cancelable without penalty.
The amounts shown below for transportation, terminalling and storage contractual obligations include our anticipated commitments based on our agreements for shipping crude oil on the Express Pipeline, the Spearhead Pipeline, the Plains All American Pipeline and the Osage Pipeline.
For more information on the agreements discussed above, see “Lease and Other Commitments” in Note 12 in the “Notes to Consolidated Financial Statements.”
| | | Payments Due by Period | |
| Contractual Cash Obligations | | Total | | | Within 1 year | | | Within 2-3 years | | | Within 4-5 years | | | After 5 years | |
| | | (in thousands) | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
| Long-term debt | | $ | 350,000 | | | $ | - | | | $ | 150,000 | | | $ | - | | | $ | 200,000 | |
| | | | | | | | | | | | | | | | | | | | | |
| Interest on long-term debt | | | 158,371 | | | | 26,938 | | | | 51,391 | | | | 34,000 | | | | 46,042 | |
| | | | | | | | | | | | | | | | | | | | | |
| Operating leases | | | 64,946 | | | | 13,020 | | | | 22,172 | | | | 12,758 | | | | 16,996 | |
| | | | | | | | | | | | | | | | | | | | | |
| Capital leases | | | 3,910 | | | | 362 | | | | 817 | | | | 958 | | | | 1,773 | |
| | | | | | | | | | | | | | | | | | | | | |
| Purchase obligations: | | | | | | | | | | | | | | | | | | | | |
Crude supply, feedstocks and natural gas (1) | | $ | 274,304 | | | $ | 274,304 | | | $ | - | | | $ | - | | | $ | - | |
| | | | | | | | | | | | | | | | | | | | | |
| Transportation, terminalling and storage | | | 337,574 | | | | 61,260 | | | | 107,955 | | | | 72,541 | | | | 95,818 | |
| | | | | | | | | | | | | | | | | | | | | |
| Refinery capital projects | | | 4,753 | | | | 4,753 | | | | - | | | | - | | | | - | |
| | | | | | | | | | | | | | | | | | | | | |
| Other goods and services | | | 4,481 | | | | 4,299 | | | | 141 | | | | 41 | | | | - | |
| Total purchase obligations | | $ | 621,112 | | | $ | 344,616 | | | $ | 108,096 | | | $ | 72,582 | | | $ | 95,818 | |
| | | | | | | | | | | | | | | | | | | | | |
| Contingent income tax liabilities | | | 28,057 | | | | - | | | | 27,575 | | | | 482 | | | | - | |
| | | | | | | | | | | | | | | | | | | | | |
| Other long-term liabilities | | | 12,211 | | | | - | | | | 3,860 | | | | 2,897 | | | | 5,454 | |
| | | | | | | | | | | | | | | | | | | | | |
Pension and post-retirement healthcare and other benefit plans funding requirements (2) | | | 221 | | | | 221 | | | | - | | | | - | | | | - | |
| | | | | | | | | | | | | | | | | | | | | |
| Total contractual cash | | $ | 1,238,828 | | | $ | 385,157 | | | $ | 363,911 | | | $ | 123,677 | | | $ | 366,083 | |
| | | | | | | | | | | | | | | | | | | | | |
(1) Crude supply, feedstocks and natural gas future obligations were calculated using current market prices and/or prices established in applicable contracts. Of these obligations, $234.7 million relate to January and February 2009 feedstock and natural gas requirements of the Refineries. | |
(2) The unfunded pension plan obligation at December 31, 2008 was $221,000. The Company expects the ultimate amount it will fund in 2009 to terminate the pension plan will be based on actual return on plan assets through the termination date versus the benefit obligation at the termination date. Our retiree health care plan is unfunded. Future payments for retiree health care benefits are estimated for the next ten years in Note 10 " Employee Benefit Plans" in the "Notes to Consolidated Financial Statements." | |
Off-Balance Sheet Arrangements
We have an interest in one unconsolidated entity (see Note 1 “Nature of Operations” in the “Notes to Consolidated Financial Statements”). Other than facility and equipment leasing agreements, we do not participate in any transactions, agreements or other contractual arrangements which would result in any off-balance sheet liabilities or other arrangements to us.
Environmental
We will be making significant future capital expenditures to comply with various environmental regulations. See “Environmental” in Note 12 in the “Notes to Consolidated Financial Statements.”
Application of Critical Accounting Policies
The preparation of financial statements in accordance with United States generally accepted accounting principles requires our management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates. The following summary provides information about our critical accounting policies, including identification of those involving critical accounting estimates, and should be read in conjunction with Note 2 “Significant Accounting Policies” in the “Notes to Consolidated Financial Statements.”
Turnarounds. Normal maintenance and repairs are expensed as incurred. Planned major maintenance (“turnarounds”) is the scheduled and required shutdown of refinery processing units for significant overhaul and refurbishment. Turnaround costs include contract services, materials and rental equipment. The costs of turnarounds are deferred when incurred and amortized on a straight-line basis over the period of time estimated to lapse until the next turnaround occurs. These deferred charges are included in our Consolidated Balance Sheets in “Deferred turnaround costs.” Also included in our Consolidated Balance Sheets in “Deferred catalyst costs” are the costs of the catalyst that is replaced at periodic intervals when the quality of the catalyst has deteriorated beyond its prescribed function. The catalyst costs are deferred when incurred and amortized on a straight-line basis over the estimated useful life of the specific catalyst. The amortization expenses for deferred turnaround and catalyst costs are included in “Refinery operating expenses, excluding depreciation” in our Consolidated Statements of Income. Since these policies rely on our estimated timing for the next turnaround and the useful lives of the catalyst, adjustments can occur in the amortization expenses as these estimates change.
Inventories. Inventories of crude oil, unfinished products and all finished products are recorded at the lower of cost on a FIFO basis or market. Crude oil includes both domestic and foreign crude oil volumes at its cost and associated freight and other cost. Unfinished products (work in process) include any crude oil that has entered into the refining process, and other feedstocks that are not finished as far as refining operations are concerned. These include unfinished gasoline and diesel, blendstocks and other feedstocks. Finished product inventory includes saleable gasoline, diesel, jet fuel, chemicals, asphalt and other finished products. Unfinished and finished products inventory values have components of raw material, the associated raw material freight and other costs, and direct refinery operating expense allocated when refining begins relative to their proportionate market values. The FIFO method of accounting for inventories sometimes results in our recognizing substantial gains (in periods of rising prices) or losses (in periods of falling prices) from our inventories of crude oil and products. While we believe that this accounting method accurately reflects the results of our operations, many other refining companies utilize the last-in, first-out (“LIFO”) method of accounting for inventories. Thus, a comparison of our results to those of other refineries must take into account the impact of the inventory accounting differences.
Asset Retirement Obligations. We account for asset retirement obligations as required under the Financial Accounting Standards Board (“FASB”) Statement of Financial Accounting Standard (“FAS”) No. 143, “Accounting for Retirement Asset Obligations.” FAS No. 143 requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which the liability is incurred, with the associated asset retirement costs being capitalized as a part of the carrying amount of the long-lived asset. FAS No. 143 also includes disclosure requirements that provide a description of asset retirement obligations and reconciliation of changes in the components of those obligations.
In March 2005, the FASB issued FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations” (“FIN 47”). FIN 47 clarified that the term “conditional asset retirement obligation” as used in FAS No. 143 refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the reporting entity. Since the obligation to perform the asset retirement activity is unconditional, FIN 47 provides that a liability for the fair value of a conditional asset obligation should be recognized if that fair value can be reasonably estimated, even though uncertainty exists about the timing and/or method of settlement. FIN 47 also clarifies when an entity would have sufficient information to reasonably estimate the fair value of a conditional asset retirement obligation under FAS No. 143. At December 31, 2008, our asset retirement obligation was $6.3 million.
Asset retirement obligations are affected by regulatory changes and refinery operations as well as changes in pricing of services. In order to determine fair value, management must make certain estimates and assumptions, including, among other things, projected cash flows, a credit-adjusted risk-free interest rate, and an assessment of market conditions that could significantly impact the estimated fair value of the asset retirement obligation. These estimates and assumptions are subjective and are currently based on historical costs with adjustments for estimated future changes in the associated costs. Therefore, we expect the dollar amount of these obligations to change as more information is obtained. A 1% change in pricing of services would cause an approximate $50,000 change to the asset retirement obligation. We believe that we adequately accrued for our asset retirement obligations as of December 31, 2008 and that changes in estimates in future periods will not have a significant effect on our results of operations or financial condition. See “Significant Accounting Policies” in Note 2 in the “Notes to Consolidated Financial Statements” for further information about asset retirement obligations.
Environmental Expenditures. Environmental expenditures are expensed or capitalized based upon their future economic benefit. Costs that improve a property’s pre-existing condition, and costs that prevent future environmental contamination, are capitalized. Remediation costs related to environmental damage resulting from operating activities subsequent to acquisition are expensed. Liabilities for these expenditures are recorded when it is probable that obligations have been incurred and the amounts can be reasonably estimated. Such estimates are subject to change due to many factors, including the identification of new sites requiring remediation, changes in environmental laws and regulations and their interpretation, additional information related to the extent and nature of remediation efforts, and potential improvements in remediation technologies.
Pension and Other Post-retirement Benefit Obligations. We have significant pension and post-retirement benefit liabilities and costs that are developed from actuarial valuations. Inherent in these valuations are key assumptions, including discount rates, expected returns on plan assets and health care inflation rates. Changes in these assumptions are primarily influenced by factors outside of our control. These assumptions can have a significant effect on the amounts reported in our consolidated financial statements. See Note 10 “Employee Benefit Plans” in the “Notes to Consolidated Financial Statements” for more information about these plans and the current assumptions used.
Income Taxes. We provide for income taxes in accordance with FAS No. 109, “Accounting for Income Taxes” (“FAS 109”) and FASB Interpretation No. 48, “Accounting for Uncertain Tax Positions – An Interpretation of FAS 109” (“FIN 48���). We record deferred tax assets and liabilities to account for the expected future tax consequences of events that have been recognized in our financial statements and our tax returns. We routinely assess the realizability of our deferred tax assets and if we conclude that it is more likely than not that some portion or all of the deferred tax assets will not be realized, the tax asset would be reduced by a valuation allowance. We consider future taxable income in making such assessments, which requires numerous judgments and assumptions. We record contingent income tax liabilities, interest and penalties, as provided for in FIN 48, based on our estimate as to whether, and the extent to which, additional taxes may be due.
New Accounting Pronouncements
See “New Accounting Pronouncements” in Note 2 in the “Notes to Consolidated Financial Statements.”
Market Risks
See Item 7A “Quantitative and Qualitative Disclosure about Market Risk” and Notes 2 and 14 in the “Notes to Consolidated Financial Statements” under “Price Risk Management Activities” for a discussion of our various price risk management activities. When we make the decision to manage our price exposure, our objective is generally to avoid losses from negative price changes, realizing we will not obtain the benefit of positive price changes.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Impact of Changing Energy Prices. Our earnings and cash flows, as well as estimates of future cash flows, are sensitive to changes in energy prices. The prices of crude oil and refined products have fluctuated substantially in recent years. These prices depend on many factors, including the overall demand for crude oil and refined products, which in turn depend on, among other factors, general economic conditions, the level of foreign and domestic production of crude oil and refined products, the availability of imports of crude oil and refined products, the marketing of alternative and competing fuels, the extent of government regulations and global market dynamics. The prices we receive for refined products are also affected by factors such as local market conditions and the level of operations of other refineries in our markets. The prices at which we can sell gasoline and other refined products are strongly influenced by the price of crude oil. Generally, an increase or decrease in the price of crude oil results in a corresponding increase or decrease in the price of gasoline and other refined products. The timing of the relative movement of the prices, however, can impact profit margins, which could significantly affect our earnings and cash flows.
Under our FIFO inventory accounting method, crude oil price movements can cause significant fluctuations in the valuation of our crude oil, unfinished products and finished products inventories, resulting in inventory gains when crude oil prices increase and inventory losses when crude oil prices decrease during the reporting period.
Price Risk Management Activities. At times, we enter into commodity derivative contracts to manage our price exposure to our inventory positions, purchases of foreign crude oil and consumption of natural gas in the refining process or to fix margins on certain future production. The commodity derivative contracts used by us may take the form of futures contracts, collars or price swaps. We believe that there is minimal credit risk with respect to its counterparties. We account for our commodity derivative contracts that do not qualify for hedge accounting under FAS No. 133, “Accounting for Derivative Instruments and Hedging Activities”, under mark-to-market accounting and gains and losses on transactions are reflected in “Other revenues” on the Consolidated Statements of Income for each period. When the derivative contracts are designated as fair value hedges for accounting purposes, the gains or losses are recognized in the related inventory in “Inventory of crude oil, products and other” on the Consolidated Balance Sheets and ultimately, when the inventory is charged or sold, in “Raw material, freight and other costs” on the Consolidated Statements of Income. See “Price Risk Management Activities” under Note13 in the “Notes to Consolidated Financial Statements.”
Our outstanding derivative sale contracts and net unrealized gains as of December 31, 2008 are summarized below:
| Commodity | | Period | | Volume (thousands of bbls) | | Expected Close Out Date | | Unrealized Net Gain (Loss) (in thousands) | |
| Crude Oil | | February 2009 | | | 1,733 | | February 2009 | | $ | 10,799 | |
| Crude Oil | | March 2009 | | | 1,062 | | March 2009 | | | (2,215 | ) |
Interest Rate Risk. Borrowings under our revolving credit facility bear a current market rate of interest. A one percent increase or decrease in the interest rates on our revolving credit facility would not significantly affect our earnings or cash flows. Our $150.0 million principal 6.625% Senior Notes due 2011 and $200.0 million 8.5% Senior Notes due 2016 that were outstanding at December 31, 2008 have fixed interest rates. Thus, our long-term debt is not exposed to cash flow risk from interest rate changes. Our long-term debt, however, is exposed to fair value risk. The estimated fair value of our 6.625% Senior Notes was $135.8 million and our 8.5% Senior Notes was $176.5 million at December 31, 2008.
Operating Data
The following tables set forth the refining operating statistical information on a consolidated basis and for each Refinery for 2008, 2007 and 2006. The statistical information includes the following terms:
| · | NYMEX WTI - the benchmark West Texas Intermediate crude oil priced on the New York Mercantile Exchange. |
| · | Charges - the quantity of crude oil and other feedstock processed through Refinery units on a bpd basis. |
| · | Manufactured product yields - the volumes of specific materials that are obtained through the distilling of crude oil and the operations of other refinery process units on a bpd basis. |
| · | Gasoline and diesel crack spreads - the average non-oxygenated gasoline and diesel net sales prices that we receive for each product less the average NYMEX WTI crude oil price. |
| · | Cheyenne light/heavy crude oil differential - the average differential between the NYMEX WTI crude oil price and the heavy crude oil delivered to the Cheyenne Refinery. |
| · | WTI/WTS crude oil differential - the average differential between the NYMEX WTI crude oil price and the West Texas sour crude oil priced at Midland, Texas. |
| · | El Dorado Refinery light/heavy crude oil differential - the average differential between the NYMEX WTI crude oil price and the heavy crude oil delivered to the El Dorado Refinery. |
| | | Years Ended December 31, | |
| Consolidated: | | 2008 | | | 2007 | | | 2006 | |
| Charges (bpd) | | | | | | | | | |
| Light crude | | | 30,265 | | | | 31,171 | | | | 39,659 | |
| Heavy and intermediate crude | | | 112,673 | | | | 114,875 | | | | 114,814 | |
| Other feed and blendstocks | | | 18,899 | | | | 18,831 | | | | 17,346 | |
| Total | | | 161,837 | | | | 164,877 | | | | 171,819 | |
| | | | | | | | | | | | | |
| Manufactured product yields (bpd) | | | | | | | | | | | | |
| Gasoline | | | 76,573 | | | | 76,974 | | | | 81,484 | |
| Diesel and jet fuel | | | 58,748 | | | | 55,889 | | | | 57,678 | |
| Asphalt | | | 3,477 | | | | 5,945 | | | | 6,032 | |
| Other | | | 18,717 | | | | 22,074 | | | | 21,580 | |
| Total | | | 157,515 | | | | 160,882 | | | | 166,774 | |
| | | | | | | | | | | | | |
| Total product sales (bpd) | | | | | | | | | | | | |
| Gasoline | | | 85,515 | | | | 88,744 | | | | 89,895 | |
| Diesel and jet fuel | | | 58,139 | | | | 56,862 | | | | 57,326 | |
| Asphalt | | | 3,900 | | | | 5,988 | | | | 6,138 | |
| Other | | | 18,818 | | | | 18,554 | | | | 18,679 | |
| Total | | | 166,372 | | | | 170,148 | | | | 172,038 | |
| | | | | | | | | | | | | |
| Refinery operating margin information (per sales barrel) | | | | | | | | | | | | |
| Refined products revenue | | $ | 104.15 | | | $ | 84.85 | | | $ | 75.80 | |
| Raw material, freight and other costs | | | 97.73 | | | | 65.04 | | | | 61.33 | |
| Refinery operating expenses, excluding depreciation | | | 5.28 | | | | 4.84 | | | | 4.41 | |
| Depreciation, amortization and accretion | | | 1.08 | | | | 0.85 | | | | 0.65 | |
| | | | | | | | | | | | | |
Average NYMEX WTI (per barrel) (1) | | $ | 99.75 | | | $ | 72.39 | | | $ | 66.22 | |
Average light/heavy differential (per barrel) (1) | | | 17.38 | | | | 19.65 | | | | 18.01 | |
Average gasoline crack spread (per barrel) (1) | | | 4.75 | | | | 17.99 | | | | 12.82 | |
Average diesel crack spread (per barrel) (1) | | | 24.59 | | | | 22.19 | | | | 20.13 | |
| | | | | | | | | | | | | |
| Average sales price (per sales barrel) | | | | | | | | | | | | |
| Gasoline | | $ | 105.64 | | | $ | 92.15 | | | $ | 80.79 | |
| Diesel and jet fuel | | | 123.69 | | | | 94.55 | | | | 86.62 | |
| Asphalt | | | 65.74 | | | | 44.69 | | | | 37.68 | |
| Other | | | 45.02 | | | | 33.18 | | | | 31.11 | |
(1) Prior period amounts are restated to reflect current year presentation utilzing NYMEX WTI as the benchmark. | |
| | | Years Ended December 31, | |
| Cheyenne Refinery: | | 2008 | | | 2007 | | | 2006 | |
| Charges (bpd) | | | | | | | | | |
| Light crude | | | 10,128 | | | | 11,545 | | | | 12,436 | |
| Heavy and intermediate crude | | | 33,462 | | | | 30,233 | | | | 33,563 | |
| Other feed and blendstocks | | | 1,283 | | | | 1,304 | | | | 1,694 | |
| Total | | | 44,873 | | | | 43,082 | | | | 47,693 | |
| | | | | | | | | | | | | |
| Manufactured product yields (bpd) | | | | | | | | | | | | |
| Gasoline | | | 19,379 | | | | 17,504 | | | | 19,089 | |
| Diesel | | | 13,528 | | | | 12,281 | | | | 14,261 | |
| Asphalt | | | 3,477 | | | | 5,945 | | | | 6,032 | |
| Other | | | 6,987 | | | | 5,868 | | | | 6,283 | |
| Total | | | 43,371 | | | | 41,598 | | | | 45,665 | |
| | | | | | | | | | | | | |
| Total product sales (bpd) | | | | | | | | | | | | |
| Gasoline | | | 26,920 | | | | 27,427 | | | | 26,569 | |
| Diesel | | | 13,112 | | | | 12,486 | | | | 14,147 | |
| Asphalt | | | 3,900 | | | | 5,988 | | | | 6,138 | |
| Other | | | 6,013 | | | | 3,577 | | | | 4,662 | |
| Total | | | 49,945 | | | | 49,478 | | | | 51,516 | |
| | | | | | | | | | | | | |
| Refinery operating margin information (per sales barrel) | | | | | | | | | | | | |
| Refined products revenue | | $ | 100.96 | | | $ | 83.04 | | | $ | 74.08 | |
| Raw material, freight and other costs | | | 92.58 | | | | 62.08 | | | | 57.07 | |
| Refinery operating expenses, excluding depreciation | | | 6.38 | | | | 6.05 | | | | 5.42 | |
| Depreciation, amortization and accretion | | | 1.44 | | | | 1.29 | | | | 1.00 | |
| | | | | | | | | | | | | |
Average light/heavy crude oil differential (per barrel) (1) | | $ | 17.15 | | | $ | 18.95 | | | $ | 17.49 | |
Average gasoline crack spread (per barrel) (1) | | | 5.99 | | | | 17.53 | | | | 14.30 | |
Average diesel crack spread (per barrel) (1) | | | 27.80 | | | | 25.61 | | | | 23.07 | |
| | | | | | | | | | | | | |
| Average sales price (per sales barrel) | | | | | | | | | | | | |
| Gasoline | | $ | 106.54 | | | $ | 92.55 | | | $ | 83.35 | |
| Diesel | | | 128.04 | | | | 98.84 | | | | 89.99 | |
| Asphalt | | | 65.74 | | | | 44.69 | | | | 37.68 | |
| Other | | | 39.82 | | | | 19.20 | | | | 20.91 | |
| | | | | | | | | | | | | |
| El Dorado Refinery: | | | | | | | | | | | | |
| Charges (bpd) | | | | | | | | | | | | |
| Light crude | | | 20,137 | | | | 19,626 | | | | 27,224 | |
| Heavy and intermediate crude | | | 79,210 | | | | 84,642 | | | | 81,251 | |
| Other feed and blendstocks | | | 17,616 | | | | 17,527 | | | | 15,652 | |
| Total | | | 116,963 | | | | 121,795 | | | | 124,127 | |
| | | | | | | | | | | | | |
| Manufactured product yields (bpd) | | | | | | | | | | | | |
| Gasoline | | | 57,194 | | | | 59,470 | | | | 62,395 | |
| Diesel and jet fuel | | | 45,220 | | | | 43,608 | | | | 43,417 | |
| Other | | | 11,730 | | | | 16,205 | | | | 15,297 | |
| Total | | | 114,144 | | | | 119,283 | | | | 121,109 | |
| | | | | | | | | | | | | |
| Total product sales (bpd) | | | | | | | | | | | | |
| Gasoline | | | 58,595 | | | | 61,318 | | | | 63,327 | |
| Diesel and jet fuel | | | 45,027 | | | | 44,376 | | | | 43,179 | |
| Other | | | 12,804 | | | | 14,977 | | | | 14,018 | |
| Total | | | 116,426 | | | | 120,671 | | | | 120,524 | |
| | | | | | | | | | | | | |
| Refinery operating margin information (per sales barrel) | | | | | | | | | | | | |
| Refined products revenue | | $ | 105.52 | | | $ | 85.59 | | | $ | 76.53 | |
| Raw material, freight and other costs | | | 99.94 | | | | 66.25 | | | | 63.15 | |
| Refinery operating expenses, excluding depreciation | | | 4.80 | | | | 4.34 | | | | 3.98 | |
| Depreciation, amortization and accretion | | | 0.92 | | | | 0.67 | | | | 0.50 | |
| | | | | | | | | | | | | |
| Average WTI/WTS crude oil differential (per barrel) | | $ | 3.92 | | | $ | 5.02 | | | $ | 5.22 | |
Average light/heavy crude oil differential (per barrel) (1) | | | 17.85 | | | | 21.00 | | | | 19.48 | |
Average gasoline crack spread (per barrel) (1) | | | 4.18 | | | | 18.19 | | | | 12.20 | |
Average diesel crack spread (per barrel) (1) | | | 23.66 | | | | 21.23 | | | | 19.17 | |
| | | | | | | | | | | | | |
| Average sales price (per sales barrel) | | | | | | | | | | | | |
| Gasoline | | $ | 105.22 | | | $ | 91.98 | | | $ | 79.72 | |
| Diesel and jet fuel | | | 122.42 | | | | 93.34 | | | | 85.51 | |
| Other | | | 47.47 | | | | 36.52 | | | | 34.51 | |
(1) Prior period amounts are restated to reflect current year presentation utilzing NYMEX WTI as the benchmark. | |
Item 8. Financial Statements and Supplementary Data
To the Board of Directors and Shareholders of Frontier Oil Corporation:
We have audited the accompanying consolidated balance sheets of Frontier Oil Corporation and subsidiaries (the “Company”) as of December 31, 2008 and 2007, and the related consolidated statements of income, changes in shareholders’ equity and comprehensive income, and cash flows for each of the three years in the period ended December 31, 2008. Our audits also included the financial statement schedules listed in the Index at Item 15. These consolidated financial statements and financial statement schedules are the responsibility of the Company’s management. Our responsibility is to express an opinion on the financial statements and financial statement schedules based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Frontier Oil Corporation and subsidiaries as of December 31, 2008 and 2007, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2008, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth therein.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2008, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 24, 2009 expressed an unqualified opinion on the Company’s internal control over financial reporting.
DELOITTE & TOUCHE LLP
February 24, 2009
CONTROL OVER FINANCIAL REPORTING
The management of Frontier Oil Corporation is responsible for establishing and maintaining adequate internal control over financial reporting. Our internal control system was designed to provide reasonable assurance to the Company’s management and board of directors regarding the preparation and fair presentation of published financial statements. 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.
Frontier Oil Corporation’s management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2008. In making this assessment, it used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control-Integrated Framework. Based on our assessment, we believe that, as of December 31, 2008, the Company’s internal control over financial reporting is effective based on those criteria.
Frontier Oil Corporation’s independent registered public accounting firm has issued an audit report on the effectiveness of the Company’s internal control over financial reporting. This report appears on the following page.
February 24, 2009
Michael C. Jennings
President and Chief Executive Officer
Doug S. Aron
Executive Vice President and Chief Financial Officer
Nancy J. Zupan
Vice President and Chief Accounting Officer
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of Frontier Oil Corporation:
We have audited the internal control over financial reporting of Frontier Oil Corporation and its subsidiaries (the “Company”) as of December 31, 2008 based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company'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 on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on 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 by, or under the supervision of, the company's principal executive and principal financial officers, or persons performing similar functions, and effected by the company's board of directors, management, and other personnel 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 the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the 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, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2008, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements and financial statement schedules as of and for the year ended December 31, 2008 of the Company and our report dated February 24, 2009, expressed an unqualified opinion on those financial statements and financial statement schedules.
DELOITTE & TOUCHE LLP
Denver, Colorado
February 24, 2009
|
| Consolidated Statements of Income |
| | | | | | | | | | |
| | | Years Ended December 31, | |
| | | 2008 | | | 2007 | | | 2006 | |
| | | (in thousands, except per share data) | |
| Revenues: | | | | | | | | | |
| Refined products | | $ | 6,342,144 | | | $ | 5,269,674 | | | $ | 4,759,661 | |
| Other | | | 156,636 | | | | (80,934 | ) | | | 36,292 | |
| | | | 6,498,780 | | | | 5,188,740 | | | | 4,795,953 | |
| | | | | | | | | | | | | |
| Costs and expenses: | | | | | | | | | | | | |
| Raw material, freight and other costs | | | 5,950,782 | | | | 4,039,235 | | | | 3,850,937 | |
| Refinery operating expenses, excluding depreciation | | | 321,364 | | | | 300,542 | | | | 277,129 | |
| Selling and general expenses, excluding depreciation | | | 44,169 | | | | 55,343 | | | | 52,488 | |
| Depreciation, amortization and accretion | | | 65,756 | | | | 53,039 | | | | 41,213 | |
| Net gains on sales of assets | | | (44 | ) | | | (15,214 | ) | | | (8 | ) |
| | | | 6,382,027 | | | | 4,432,945 | | | | 4,221,759 | |
| | | | | | | | | | | | | |
| Operating income | | | 116,753 | | | | 755,795 | | | | 574,194 | |
| | | | | | | | | | | | | |
| Interest expense and other financing costs | | | 15,130 | | | | 8,773 | | | | 12,139 | |
| Interest and investment income | | | (5,425 | ) | | | (21,851 | ) | | | (18,059 | ) |
| | | | 9,705 | | | | (13,078 | ) | | | (5,920 | ) |
| | | | | | | | | | | | | |
| Income before income taxes | | | 107,048 | | | | 768,873 | | | | 580,114 | |
| Provision for income taxes | | | 26,814 | | | | 269,748 | | | | 200,837 | |
| Net income | | $ | 80,234 | | | $ | 499,125 | | | $ | 379,277 | |
| | | | | | | | | | | | | |
| Basic earnings per share of common stock | | $ | 0.78 | | | $ | 4.67 | | | $ | 3.40 | |
| | | | | | | | | | | | | |
| Diluted earnings per share of common stock | | $ | 0.77 | | | $ | 4.62 | | | $ | 3.37 | |
| | | | | | | | | | | | | |
| The accompanying notes are an integral part of these consolidated financial statements. |
|
| Consolidated Balance Sheets |
| | | | | | | |
| | | December 31, | |
| | | 2008 | | | 2007 | |
| | | (in thousands, except share data) | |
| ASSETS | | | | | | |
| Current assets: | | | | | | |
| Cash and cash equivalents | | $ | 483,532 | | | $ | 297,399 | |
| Trade receivables, net of allowance of $500 at both years | | | 84,110 | | | | 155,454 | |
| Income taxes receivable | | | 116,118 | | | | 24,056 | |
| Other receivables | | | 25,216 | | | | 5,236 | |
| Inventory of crude oil, products and other | | | 256,129 | | | | 501,927 | |
| Deferred income taxes | | | 8,841 | | | | 9,426 | |
| Commutation account | | | 6,319 | | | | 6,280 | |
| Other current assets | | | 37,038 | | | | 31,245 | |
| Total current assets | | | 1,017,303 | | | | 1,031,023 | |
| Property, plant and equipment, at cost: | | | | | | | | |
| Refineries, pipeline and terminal equipment | | | 1,291,106 | | | | 1,082,344 | |
| Furniture, fixtures and other equipment | | | 15,638 | | | | 13,099 | |
| | | | 1,306,744 | | | | 1,095,443 | |
| Accumulated depreciation and amortization | | | (373,301 | ) | | | (317,993 | ) |
| Property, plant and equipment, net | | | 933,443 | | | | 777,450 | |
| | | | | | | | | |
| Deferred turnaround costs | | | 47,465 | | | | 39,276 | |
| Deferred catalyst costs | | | 9,726 | | | | 6,540 | |
Deferred financing costs, net of accumulated amortization of $2,404 and $1,619 at 2008 and 2007, respectively | | | 6,201 | | | | 2,556 | |
Intangible assets, net of accumulated amortization of $492 and $370 at 2008 and 2007, respectively | | | 1,338 | | | | 1,460 | |
| Other assets | | | 2,993 | | | | 5,543 | |
| Total assets | | $ | 2,018,469 | | | $ | 1,863,848 | |
| | | | | | | | | |
| LIABILITIES AND SHAREHOLDERS' EQUITY | | | | | | | | |
| Current liabilities: | | | | | | | | |
| Accounts payable | | $ | 308,867 | | | $ | 417,395 | |
| Accrued liabilities and other | | | 57,084 | | | | 84,118 | |
| Total current liabilities | | | 365,951 | | | | 501,513 | |
| | | | | | | | | |
| Long-term debt | | | 347,220 | | | | 150,000 | |
| Contingent income tax liabilities | | | 28,057 | | | | 32,257 | |
| Post-retirement employee liabilities | | | 31,128 | | | | 27,549 | |
| Long-term capital lease obligation | | | 3,548 | | | | 8 | |
| Other long-term liabilities | | | 12,211 | | | | 13,597 | |
| Deferred income taxes | | | 179,214 | | | | 100,310 | |
| | | | | | | | | |
| Commitments and contingencies | | | | | | | | |
| | | | | | | | | |
| Shareholders' equity: | | | | | | | | |
Preferred stock, $100 par value, 500,000 shares authorized, no shares issued | | | - | | | | - | |
Common stock, no par value, 180,000,000 shares authorized, 131,850,356 shares issued at both periods | | | 57,736 | | | | 57,736 | |
| Paid-in capital | | | 236,183 | | | | 211,324 | |
| Retained earnings | | | 1,151,676 | | | | 1,095,540 | |
| Accumulated other comprehensive income (loss) | | | (723 | ) | | | 1,578 | |
Treasury stock, at cost, 27,945,884 and 26,893,939 shares at 2008 and 2007, respectively | | | (393,732 | ) | | | (327,564 | ) |
| Total shareholders' equity | | | 1,051,140 | | | | 1,038,614 | |
| Total liabilities and shareholders' equity | | $ | 2,018,469 | | | $ | 1,863,848 | |
| | | | | | | | | |
| The accompanying notes are an integral part of these consolidated financial statements. |
| |
| Consolidated Statements of Cash Flows | |
| | | | | | | | | | |
| | | Years Ended December 31, | |
| | | 2008 | | | 2007 | | | 2006 | |
| | | (in thousands) | |
| Cash flows from operating activities: | | | | | | | | | |
| Net income | | $ | 80,234 | | | $ | 499,125 | | | $ | 379,277 | |
Adjustments to reconcile net income to net cash from operating activities: | | | | | | | | | | | | |
| Depreciation, amortization and accretion | | | 83,571 | | | | 67,512 | | | | 54,388 | |
| Deferred income taxes | | | 80,894 | | | | (1,916 | ) | | | 6,073 | |
| Stock-based compensation expense | | | 20,014 | | | | 22,553 | | | | 18,029 | |
| Excess income tax benefits of stock-based compensation | | | (3,191 | ) | | | (6,962 | ) | | | (8,881 | ) |
| Amortization of debt issuance costs | | | 978 | | | | 769 | | | | 797 | |
| Senior Notes discount amortization | | | 60 | | | | - | | | | - | |
| Allowance for investment loss | | | 499 | | | | - | | | | - | |
| Net gains on sales of assets | | | (44 | ) | | | (15,214 | ) | | | (8 | ) |
| Decrease in long-term commutation account | | | - | | | | 1,009 | | | | 5,316 | |
| Amortization of long-term prepaid insurance | | | 909 | | | | 1,211 | | | | 1,211 | |
| (Decrease) increase in other long-term liabilities | | | (3,173 | ) | | | 27,365 | | | | 9,309 | |
Changes in deferred turnaround costs, deferred catalyst costs and other | | | (28,758 | ) | | | (29,287 | ) | | | (18,844 | ) |
| Changes in components of working capital from operations: | | | | | | | | | | | | |
| Increase in trade, income taxes and other receivables | | | (28,801 | ) | | | (45,018 | ) | | | (7,633 | ) |
| Decrease (increase) in inventory | | | 245,798 | | | | (127,351 | ) | | | (126,955 | ) |
| Increase in other current assets | | | (14,984 | ) | | | (12,724 | ) | | | (10,527 | ) |
| (Decrease) increase in accounts payable | | | (117,443 | ) | | | 30,312 | | | | 23,187 | |
| (Decrease) increase in accrued liabilities and other | | | (19,288 | ) | | | 17,629 | | | | 15,778 | |
| Net cash provided by operating activities | | | 297,275 | | | | 429,013 | | | | 340,517 | |
| | | | | | | | | | | | | |
| Cash flows from investing activities: | | | | | | | | | | | | |
| Additions to property, plant and equipment | | | (209,381 | ) | | | (291,174 | ) | | | (129,703 | ) |
| Proceeds from sales of assets | | | 46 | | | | 22,222 | | | | 8 | |
| El Dorado Refinery contingent earn-out payment | | | (7,500 | ) | | | (7,500 | ) | | | (7,500 | ) |
| Other acquisitions and leasehold improvements | | | - | | | | (3,561 | ) | | | - | |
| Net cash used in investing activities | | | (216,835 | ) | | | (280,013 | ) | | | (137,195 | ) |
| | | | | | | | | | | | | |
| Cash flows from financing activities: | | | | | | | | | | | | |
| Proceeds from issuance of 8.5% Senior Notes | | | 197,160 | | | | - | | | | - | |
| Purchase of treasury stock | | | (67,030 | ) | | | (248,486 | ) | | | (98,950 | ) |
| Proceeds from issuance of common stock | | | 405 | | | | 2,303 | | | | 3,672 | |
| Dividends paid | | | (23,144 | ) | | | (17,271 | ) | | | (67,498 | ) |
| Excess income tax benefits of stock-based compensation | | | 3,191 | | | | 6,962 | | | | 8,881 | |
| Debt issuance costs and other | | | (4,889 | ) | | | (588 | ) | | | (13 | ) |
| Net cash provided by (used in) financing activities | | | 105,693 | | | | (257,080 | ) | | | (153,908 | ) |
| Increase (decrease) in cash and cash equivalents | | | 186,133 | | | | (108,080 | ) | | | 49,414 | |
| Cash and cash equivalents, beginning of period | | | 297,399 | | | | 405,479 | | | | 356,065 | |
| Cash and cash equivalents, end of period | | $ | 483,532 | | | $ | 297,399 | | | $ | 405,479 | |
| | | | | | | | | | | | | |
| The accompanying notes are an integral part of these consolidated financial statements. | |
| |
| Consolidated Statements of Changes in Shareholders' Equity and Statements of Comprehensive Income | |
| (in thousands, except share data) | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Common Stock | | | | | | | | | | | | Treasury Stock | | | | | | | | | Total | |
| | | Number of Shares Issued | | | Amount | | | Paid-in-Capital | | Comprehensive Income | | | Retained Earnings | | | Number of Shares | | | Amount | | | Deferred Compensation | | | Accumulated Other Comprehensive Income (Loss) | | | Number of Shares | | | Amount | |
| December 31, 2005 | | | 133,629,396 | | | $ | 57,780 | | | $ | 157,910 | | | | | | $ | 352,783 | | | | (20,930,828 | ) | | $ | (86,870 | ) | | $ | (2,938 | ) | | $ | 27 | | | | 112,698,568 | | | $ | 478,692 | |
| Adoption of FAS No. 123(R) | | | - | | | | - | | | | (2,938 | ) | | | | | | - | | | | - | | | | - | | | | 2,938 | | | | - | | | | - | | | | - | |
Shares issued under stock-based compensation plans | | | 879,860 | | | | 22 | | | | 3,134 | | | | | | | - | | | | 389,846 | | | | 516 | | | | - | | | | - | | | | 1,269,706 | | | | 3,672 | |
| Shares received under: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | - | | | | - | |
| Stock repurchase plan | | | - | | | | - | | | | - | | | | | | | - | | | | (3,482,088 | ) | | | (92,273 | ) | | | - | | | | - | | | | (3,482,088 | ) | | | (92,273 | ) |
| Stock-based compensation plans | | | - | | | | - | | | | - | | | | | | | - | | | | (141,738 | ) | | | (4,765 | ) | | | - | | | | - | | | | (141,738 | ) | | | (4,765 | ) |
| Net income and comprehensive income | | | - | | | | - | | | | - | | | $ | 379,277 | | | | 379,277 | | | | - | | | | - | | | | - | | | | - | | | | - | | | | 379,277 | |
Adjustment to initially apply FAS No. 158, net of tax of $141 | | | - | | | | - | | | | - | | | | | | | | - | | | | - | | | | - | | | | - | | | | 229 | | | | - | | | | 229 | |
Income tax benefits of stock-based compensation, net of contingency | | | - | | | | - | | | | 5,251 | | | | | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | 5,251 | |
| Stock-based compensation expense | | | - | | | | - | | | | 18,029 | | | | | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | 18,029 | |
| Dividends declared | | | - | | | | - | | | | - | | | | | | | | (12,258 | ) | | | - | | | | - | | | | - | | | | - | | | | - | | | | (12,258 | ) |
| December 31, 2006 | | | 134,509,256 | | | $ | 57,802 | | | $ | 181,386 | | | | | | | $ | 719,802 | | | | (24,164,808 | ) | | $ | (183,392 | ) | | $ | - | | | $ | 256 | | | | 110,344,448 | | | $ | 775,854 | |
| Adoption of FIN 48 | | | - | | | | - | | | | - | | | | | | | | (1,016 | ) | | | - | | | | - | | | | - | | | | - | | | | - | | | | (1,016 | ) |
Shares issued under stock-based compensation plans | | | - | | | | - | | | | 951 | | | | | | | | - | | | | 1,188,168 | | | | 1,574 | | | | - | | | | - | | | | 1,188,168 | | | | 2,525 | |
| Shares received under: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Stock repurchase plan | | | - | | | | - | | | | - | | | | | | | | - | | | | (6,443,700 | ) | | | (243,568 | ) | | | - | | | | - | | | | (6,443,700 | ) | | | (243,568 | ) |
| Stock-based compensation plans | | | - | | | | - | | | | - | | | | | | | | - | | | | (132,499 | ) | | | (5,139 | ) | | | - | | | | - | | | | (132,499 | ) | | | (5,139 | ) |
| Comprehensive income: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Net income | | | - | | | | - | | | | - | | | $ | 499,125 | | | | 499,125 | | | | - | | | | - | | | | - | | | | - | | | | - | | | | 499,125 | |
| Other comprehensive income: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Defined benefit plans, net of tax of $805 | | | - | | | | - | | | | - | | | | 1,322 | | | | - | | | | - | | | | - | | | | - | | | | 1,322 | | | | - | | | | 1,322 | |
| Other comprehensive income | | | | | | | | | | | | | | | 1,322 | | | | | | | | | | | | | | | | | | | | | | | | - | | | | - | |
| Comprehensive income | | | | | | | | | | | | | | $ | 500,447 | | | | | | | | | | | | | | | | | | | | | | | | - | | | | - | |
Income tax benefits of stock-based compensation, net of contingency | | | - | | | | - | | | | 6,434 | | | | | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | 6,434 | |
| Treasury stock retirements | | | (2,658,900 | ) | | | (66 | ) | | | - | | | | | | | | (102,895 | ) | | | 2,658,900 | | | | 102,961 | | | | - | | | | - | | | | - | | | | - | |
| Stock-based compensation expense | | | - | | | | - | | | | 22,553 | | | | | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | 22,553 | |
| Dividends declared | | | - | | | | - | | | | - | | | | | | | | (19,476 | ) | | | - | | | | - | | | | - | | | | - | | | | - | | | | (19,476 | ) |
| December 31, 2007 | | | 131,850,356 | | | $ | 57,736 | | | $ | 211,324 | | | | | | | $ | 1,095,540 | | | | (26,893,939 | ) | | $ | (327,564 | ) | | $ | - | | | $ | 1,578 | | | | 104,956,417 | | | $ | 1,038,614 | |
Shares issued under stock-based compensation plans | | | | | | | | (457 | ) | | | | | | | | | | | 904,996 | | | | 1,168 | | | | | | | | | | | | 904,996 | | | | 711 | |
| Shares received under: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Stock repurchase plan | | | | | | | | | | | | | | | | | | | | | | | (1,561,367 | ) | | | (56,260 | ) | | | | | | | | | | | (1,561,367 | ) | | | (56,260 | ) |
| Stock-based compensation plans | | | | | | | | | | | | | | | | | | | | | | | (395,574 | ) | | | (11,076 | ) | | | | | | | | | | | (395,574 | ) | | | (11,076 | ) |
| Comprehensive income: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Net income | | | | | | | | | | | | | | $ | 80,234 | | | | 80,234 | | | | | | | | | | | | | | | | | | | | - | | | | 80,234 | |
| Other comprehensive income (loss): | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Defined benefit plans, net of tax of $1,405 | | | | | | | | | | | | | | | (2,301 | ) | | | | | | | | | | | | | | | | | | | (2,301 | ) | | | - | | | | (2,301 | ) |
| Other comprehensive income (loss) | | | | | | | | | | | | | | | (2,301 | ) | | | | | | | | | | | | | | | | | | | | | | | - | | | | - | |
| Comprehensive income | | | | | | | | | | | | | | $ | 77,933 | | | | | | | | | | | | | | | | | | | | | | | | - | | | | - | |
Income tax benefits of stock-based compensation, net of contingency | | | | | | | | 5,302 | | | | | | | | | | | | | | | | | | | | | | | | | | | | - | | | | 5,302 | |
| Stock-based compensation expense | | | | | | | | | | | 20,014 | | | | | | | | | | | | | | | | | | | | | | | | | | | | - | | | | 20,014 | |
| Dividends declared | | | | | | | | | | | | | | | | | | | (24,098 | ) | | | | | | | | | | | | | | | | | | | - | | | | (24,098 | ) |
| December 31, 2008 | | | 131,850,356 | | | $ | 57,736 | | | $ | 236,183 | | | | | | | $ | 1,151,676 | | | | (27,945,884 | ) | | $ | (393,732 | ) | | $ | - | | | $ | (723 | ) | | | 103,904,472 | | | $ | 1,051,140 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| The accompanying notes are an integral part of these consolidated financial statements. |
Notes To Consolidated Financial Statements
For The Years Ended December 31, 2008, 2007 and 2006
The financial statements include the accounts of Frontier Oil Corporation (“FOC”), a Wyoming corporation, and its wholly-owned subsidiaries, collectively referred to as “Frontier” or “the Company.” The Company is an energy company engaged in crude oil refining and wholesale marketing of refined petroleum products (the “refining operations”).
The Company operates refineries (“the Refineries”) in Cheyenne, Wyoming and El Dorado, Kansas. The Company also owns Ethanol Management Company (“EMC”), a products terminal and blending facility located near Denver, Colorado. The Company also owned, until their sale in September 2007, a 34.72% interest in a crude oil pipeline in Wyoming and a 50% interest in two crude oil tanks in Guernsey, Wyoming, both of which were accounted for as undivided interests. Each of these assets and the associated liabilities, revenues and expenses were reported on a proportionate gross basis until their disposition. In addition, the equity method of accounting is utilized for the Company’s 25% interest in 8901 Hangar, Inc., a company which leases and operates a private airplane hangar. The Company’s investment in 8901 Hangar, Inc. was $89,000 and $100,000 at December 31, 2008 and 2007, respectively, and is included in “Other assets” on the Consolidated Balance Sheets. All of the operations of the Company are in the United States, with its marketing efforts focused in the Rocky Mountain and Plains States regions of the United States. The Rocky Mountain region includes the states of Colorado, Wyoming, western Nebraska, Montana and Utah, and the Plains States include the states of Kansas, Oklahoma, eastern Nebraska, Iowa, Missouri, North Dakota and South Dakota. The Company purchases crude oil to be refined and markets the refined petroleum products produced, including various grades of gasoline, diesel fuel, jet fuel, asphalt, chemicals and petroleum coke. The operations of refining and marketing of petroleum products are considered part of one reporting segment.
| 2. | Significant Accounting Policies |
Revenue Recognition
Revenues from sales of refined products are earned and realized upon transfer of title to the customer based on the contractual terms of delivery (including payment terms and prices). Title primarily transfers at the refinery or terminal when the refined product is loaded into the common carrier pipelines, trucks or railcars (free on board origin). In some situations, title transfers at the customer’s destination (free on board destination). Nonmonetary product exchanges and certain buy/sell crude oil transactions which are entered into in the normal course of business are included on a net cost basis in “Raw material, freight and other costs” on the Consolidated Statements of Income. Taxes collected from customers and remitted to governmental authorities are not included in reported revenues.
Property, Plant and Equipment
Property, plant and equipment additions are recorded at cost and depreciated using the straight-line method over the estimated useful lives, which range as follows:
| | Refineries, pipeline and terminal equipment | | 2 to 50 years |
| | Furniture, fixtures and other equipment | | 2 to 20 years |
The costs of components of property, net of salvage value, retired or abandoned are charged or credited to accumulated depreciation. Gains or losses on sales or other dispositions of property are recorded in operating income and are reported in “Gains on sales of assets” in the Consolidated Statements of Income.
The Company reviews long-lived assets for impairments under the Financial Accounting Standards Board (“FASB”) Statement of Financial Accounting Standards (“FAS”) No. 144, “Accounting for the Impairment or Disposal of Long-lived Assets” whenever events or changes in circumstances indicate that the carrying value of an asset may not be recoverable. If the undiscounted future cash flow of an asset to be held and used in operations is less than the carrying value, the Company would recognize a loss for the difference between the carrying value and fair value. When fair values are not available, the Company estimates fair value based on a discounted cash flow analysis.
The Company capitalizes interest on the long-term construction of significant assets. Interest capitalized for the years ended December 31, 2008, 2007 and 2006 was $6.6 million, $8.1 million and $3.8 million, respectively.
Turnarounds
Normal maintenance and repairs are expensed as incurred. Planned major maintenance is the scheduled and required shutdowns of refinery processing units for significant overhaul and refurbishment (“turnarounds”). Turnaround costs include contract services, materials and rental equipment. The costs of turnarounds are deferred when incurred and amortized on a straight-line basis over the period of time estimated to lapse until the next turnaround occurs. These deferred charges are included in the Company’s Consolidated Balance Sheets in “Deferred turnaround costs.” Also included in the Consolidated Balance Sheets, in “Deferred catalyst costs,” are the costs of the catalyst that is replaced at periodic intervals when the quality of the catalyst has deteriorated beyond its prescribed function. The catalyst costs are deferred when incurred and amortized on a straight-line basis over the estimated useful life of the specific catalyst. The amortization expenses resulting from the turnaround and catalyst costs are included in “Refinery operating expenses, excluding depreciation” in the Company’s Consolidated Statements of Income.
Inventories
Inventories of crude oil, unfinished products and all finished products are recorded at the lower of cost on a first-in, first-out (“FIFO”) basis or market. Crude oil includes both domestic and foreign crude oil volumes at its cost and associated freight and other costs. Unfinished products (work in process) include any crude oil that has entered into the refining process, and other feedstocks that are not finished as far as refining operations are concerned. These include unfinished gasoline and diesel, blendstocks and other feedstocks. Finished product inventory includes saleable gasoline, diesel, jet fuel, chemicals, asphalt and other finished products. Unfinished and finished products inventory values have components of raw material, the associated raw material freight and other costs, and direct refinery operating expense allocated when refining begins relative to their proportionate market values. Refined product exchange transactions are considered asset exchanges with deliveries offset against receipts. The net exchange balance is included in inventory. Inventories of materials and supplies and process chemicals are recorded at the lower of average cost or market. Crude oil inventories, unfinished product inventories and finished product inventories are used to secure financing for operations under the Company’s revolving credit facility. (See Note 7 “Revolving Credit Facility.”) Inventory as of December 31, 2008 has been reduced by $19.8 million in lower of cost or market adjustments. The components of inventory as of December 31, 2008 and 2007 were as follows:
| | | December 31, | |
| | | 2008 | | | 2007 | |
| | | (in thousands) | |
| | | | | | | |
| Crude oil | | $ | 121,973 | | | $ | 223,715 | |
| Unfinished products | | | 55,915 | | | | 152,572 | |
| Finished products | | | 54,332 | | | | 104,820 | |
| Process chemicals | | | 1,385 | | | | 1,300 | |
| Repairs and maintenance supplies and other | | | 22,524 | | | | 19,520 | |
| | | $ | 256,129 | | | $ | 501,927 | |
Prepaid Insurance
The Company charges the amounts paid for insurance policies to expense over the term of the policy. Prepaid insurance related to policies with terms of one year or less are included in “Other current assets” on the Consolidated Balance Sheets.
Income Taxes
The Company accounts for income taxes under the provisions of FAS No. 109, “Accounting for Income Taxes.” FAS No. 109 requires the asset and liability approach for accounting for income taxes. Under this approach, deferred tax assets and liabilities are recognized based on anticipated future tax consequences attributable to differences between the financial statement carrying amounts of assets and liabilities and their respective tax basis. The Company recognizes liabilities, interest and penalties for potential tax issues based on its estimate of whether, and the extent to which, additional taxes may be due as determined under FASB Interpretation No. 48, “Accounting for Uncertain Tax Positions – An Interpretation of FAS No. 109, Accounting for Income Taxes” (“FIN 48”). See Note 8 “Income Taxes” for further information.
Environmental Expenditures
Environmental expenditures are expensed or capitalized based upon their future economic benefit. Costs that improve a property’s pre-existing condition, and costs that prevent future environmental contamination, are capitalized. Remediation costs related to environmental damage resulting from operating activities subsequent to acquisition are expensed. Liabilities for these expenditures are recorded when it is probable that obligations have been incurred and the amounts can be reasonably estimated.
Price Risk Management Activities
The Company, at times, enters into commodity derivative contracts to manage its price exposure to its inventory positions and purchases of foreign crude oil and to fix margins on certain future production. See Note 13, “Price Risk Management Activities” for detailed information on the Company’s price risk management activities.
Stock-based Compensation
Effective January 1, 2006, the Company accounts for stock-based compensation in accordance with FAS No. 123(R), “Share-Based Payment,” which requires companies to recognize the fair value of stock options and other stock-based compensation in the financial statements. See Note 9, under “Stock-based Compensation” for detailed information on the Company’s stock-based compensation.
Asset Retirement Obligations
The Company accounts for asset retirement obligations as required under FAS No. 143, “Accounting for Asset Retirement Obligations.” FAS No. 143 requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred, with the associated asset retirement costs being capitalized as a part of the carrying amount of the long-lived asset.
In March 2005, the FASB issued FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations” (“FIN 47”). FIN 47 clarified that the term “conditional asset retirement obligation” as used in FAS No. 143 refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. Because the obligation to perform the asset retirement activity is unconditional, FIN 47 provides that a liability for the fair value of a conditional asset obligation should be recognized if that fair value can be reasonably estimated, although uncertainty exists about the timing and/or method of settlement. FIN 47 also clarifies when an entity would have sufficient information to reasonably estimate the fair value of a conditional asset retirement obligation under FAS No. 143.
The Company’s Consolidated Balance Sheets as of December 31, 2008 and 2007 recognized a net asset retirement obligation of $6.3 million and $6.0 million, respectively. At December 31, 2008, $1.7 million of the $6.3 million was classified as current in “Accrued liabilities and other” and $4.6 million was included in “Other long-term liabilities.” Changes in the Company’s asset retirement obligations for the year ended December 31, 2008 were as follows (in thousands):
| Balance as of December 31, 2007 | | $ | 6,040 | |
| Liabilities incurred | | | - | |
| Liabilities settled | | | (515 | ) |
| Accretion expense | | | 340 | |
| Revisions to timing of estimated cash flows | | | 416 | |
| Balance as of December 31, 2008 | | $ | 6,281 | |
The Company has asset retirement obligations related to its Refineries and certain other assets as a result of environmental and other legal requirements. The Company is not required to perform such work in some circumstances until it permanently ceases operations of the long-lived assets. Because the Company considers the operational life of the Refineries and certain other assets indeterminable, an associated asset retirement obligation cannot be calculated at this time. The Company has recorded an asset retirement obligation for the handling and disposal of hazardous substances that the Company is legally obligated to incur in connection with maintaining and improving the Refineries and certain other assets.
Principles of Consolidation
The Consolidated Financial Statements include the accounts of FOC and all 100% owned subsidiaries, as well as the Company’s undivided interests in a crude oil pipeline and crude oil tanks up until their sale in September 2007. The Company utilizes the equity method of accounting for investments in entities in which it does not have the ability to exercise control. Entities in which the Company has the ability to exercise significant influence and control are consolidated. All intercompany transactions and balances are eliminated in consolidation.
Use of Estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America (“GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Cash Equivalents
Highly liquid investments with maturity, when purchased, of three months or less are considered to be cash equivalents. Cash equivalents were $482.4 million and $278.3 million at December 31, 2008 and 2007, respectively.
Supplemental Cash Flow Information
Cash payments for interest, net of capitalized interest, during 2008, 2007 and 2006 were $5.1 million, $5.5 million and $8.4 million, respectively. Cash payments for income taxes during 2008, 2007 and 2006 were $59.7 million, $294.1 million and $183.6 million, respectively. Cash refunds of income taxes during 2008, 2007 and 2006 were $24.9 million, none and $1.4 million, respectively. Noncash investing activities include accrued capital expenditures of $26.9 million, $27.1 million and $30.2 million as of December 31, 2008, 2007 and 2006, respectively.
Reclassifications
Certain prior year amounts have been reclassified to conform to the current period financial statement presentation. The Company has combined certain long-term assets from 2007 into “Other assets” on the Consolidated Balance Sheet. These reclassifications have no effect on previously reported net income.
New Accounting Pronouncements
On January 1, 2008, the Company adopted The Emerging Issues Task Force (“EITF”) Issue 06-11, “Accounting for Income Tax Benefits of Dividends on Share-Based Payment Awards” (“EITF 06-11”). In a stock-based compensation arrangement, employees may be entitled to dividends during the vesting period for nonvested shares or share units and until the exercise date for stock options. These dividend payments generally can be treated as a deductible compensation expense for income tax purposes, thereby generating an income tax benefit for the employer. At issue was how such a realized benefit should be recognized in the financial statements. The EITF concluded that an entity should recognize the realized tax benefit as an increase in additional paid-in capital (“APIC”) and that the amount recognized in APIC should be included in the pool of excess tax benefits available to absorb tax deficiencies on stock-based payment awards. EITF 06-11 was effective prospectively for income tax benefits that result from dividends on equity-classified employee share-based payment awards declared in fiscal years beginning after December 15, 2007. This EITF did not have a material effect on the Company’s financial statements.
In September 2006, the Financial Accounting Standards Board (“FASB”) issued FAS No. 157, “Fair Value Measurements.” FAS No. 157 defines fair value, establishes a framework for measuring fair value and expands disclosure requirements regarding fair value measurement. Where applicable, this statement simplifies and codifies fair value related guidance previously issued within GAAP. FAS No. 157 was effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. The Company partially adopted FAS No. 157 as of January 1, 2008, pursuant to FASB Staff Position (“FSP”) FAS No. 157-2, “Effective Date of FASB Statement No. 157,” which delayed the effective date of FAS No. 157 for all nonrecurring fair value measurements of non-financial assets and non-financial liabilities until fiscal years beginning after November 15, 2008. FSP FAS No. 157-2 states that a measurement is recurring if it happens at least annually and defines non-financial assets and non-financial liabilities as all assets and liabilities other than those meeting the definition of a financial asset or financial liability in FAS No. 159. The statement also notes that if FAS No. 157 is not applied in its entirety, the Company must disclose (1) that it has only partially adopted FAS No. 157 and (2) the categories of assets and liabilities recorded or disclosed at fair value to which the statement was not applied. The Company chose to adopt FSP FAS No. 157-2 as of January 1, 2008, which did not have a material impact on the Company’s financial statements, and delay the application of FAS No. 157 in its entirety. Therefore, the Company did not apply FAS No. 157 to nonrecurring fair value measurements of non-financial assets and non-financial liabilities, including non-financial long-lived assets measured at fair value for an impairment assessment under FAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” and asset retirement obligations initially measured at fair value under FAS No. 143, “Accounting for Asset Retirement Obligations.” The Company is still required to apply FAS No. 157 to recurring financial and non-financial instruments effective January 1, 2009, which affects the fair value disclosure of its financial derivatives within the scope of FAS No. 133, “Accounting for Derivative Instruments and Hedging Activities.” See Note 11 “Fair Value Measurement.” The full adoption of FAS No. 157 is not expected to have a material effect on the Company’s financial statements.
On January 1, 2008 the Company adopted FAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities – Including an amendment of FAS No. 115, Accounting for Certain Investments in Debt and Equity Securities,” which expands the use of fair value accounting but does not affect existing standards which require assets or liabilities to be carried at fair value. Under FAS No. 159, a company may elect to use fair value to measure many financial instruments and certain other assets and liabilities at fair value. As of December 31, 2008, the Company decided not to elect fair value accounting for any of its eligible items. The adoption of FAS No. 159 therefore did not have any impact on the Company’s financial position, cash flows or results of operations.
FSP No. FIN 39-1, an amendment of FASB Interpretation No. 39, was adopted by the Company on January 1, 2008. This FSP amends paragraph 3 of Interpretation 39 to replace the terms “conditional contracts” and “exchange contracts” with the term “derivative instruments” as defined in FASB Statement No. 133, “Accounting for Derivative Instruments and Hedging Activities.” It also amended paragraph 10 of Interpretation 39 to permit a reporting entity to offset fair value amounts recognized for the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a payable) against fair value amounts recognized for derivative instruments executed with the same counterparty under the same master netting arrangement that have been offset in accordance with the paragraph. The adoption of this FSP did not have any impact on the Company’s financial statements.
In March 2008, the FASB released FAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities – an amendment of FASB Statement No. 133.” FAS No. 161 expands the disclosure requirements in FAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” about an entity’s derivative instruments and hedging activities. FAS No. 161’s disclosure provisions apply to all entities with derivative instruments subject to FAS No. 133 and its related interpretations. The provisions also apply to related hedged items, bifurcated derivatives, and nonderivative instruments that are designated and qualify as hedging instruments. Entities with instruments subject to FAS No. 161 must provide more robust qualitative disclosures and expanded quantitative disclosures. The statement is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008. The Company is currently evaluating the effect that this statement will have on the Company’s financial statement disclosures.
In December 2008, the FASB released FSP No. FAS 132(R)-1, “Employers' Disclosures about Postretirement Benefit Plan Assets”, which amends FAS No. 132(R), “Employers' Disclosures about Pensions and Other Postretirement Benefits” (FASB ASC 715), to require disclosure of additional information about assets held in a defined benefit pension or other postretirement plan. Specifically, the additional disclosures cover (1) investment policies and strategies, (2) categories of plan assets, (3) fair value measurements of plan assets, and (4) significant concentrations of risk. In addition, SFAS No. 132(R) (FASB ASC 715) has been amended to re-instate the provision, which was inadvertently removed by SFAS No. 158, Employers' Accounting for Defined Benefit Pension and Other Postretirement Plans (FASB ASC 715), requiring non-public entities to disclose net periodic benefit cost. The additional disclosure requirements are effective for fiscal years ending after December 15, 2009, with earlier application permitted. The Company is evaluating the effect that this statement will have on the Company’s financial statement disclosures.
| | | December 31, | |
| | | 2008 | | | 2007 | |
| | | (in thousands) | |
| | | | | | | |
| Investment fund receivable, net of allowance | | $ | 6,418 | | | $ | - | |
| Realized futures trading receivable | | | 11,854 | | | | - | |
| Other | | | 6,944 | | | | 5,236 | |
| | | $ | 25,216 | | | $ | 5,236 | |
The Company had a $32.7 million money market investment in a J.P. Morgan money market fund called the Reserve Primary Fund (“Fund”) that was deemed illiquid in September 2008. The Fund is currently overseen by the SEC, which is determining the amount and timing of liquidation. Prior to the freeze on the Fund’s assets, the Company requested its funds in their entirety and reclassed the $32.7 million investment out of “Cash and cash equivalents” to “Other receivables” on the Consolidated Balance Sheet. In addition, it is currently estimated that approximately 1.5% of the Company’s original investment is at-risk for recoverability, primarily due to the bankruptcy of Lehman Brothers, as the Fund had an investment in Lehman Brothers Holdings, Inc. commercial paper. Therefore, an allowance of $499,000 has been recorded as of December 31, 2008. In addition, the Company had received partial distributions through December 31, 2008 from the Fund totaling $25.8 million, resulting in a net investment fund receivable of $6.4 million. The Company received another $2.2 million partial distribution from the fund in February 2009. The $499,000 investment loss is included in “Interest and investment income” on the 2008 Consolidated Statement of Income.
| | | December 31, | |
| | | 2008 | | | 2007 | |
| | | (in thousands) | |
| | | | | | | |
| Margin deposits | | $ | 18,323 | | | $ | 11,997 | |
| Derivative assets | | | 8,584 | | | | - | |
| Prepaid insurance | | | 8,374 | | | | 7,312 | |
| Prepaid income taxes | | | - | | | | 9,152 | |
| Other | | | 1,757 | | | | 2,784 | |
| | | $ | 37,038 | | | $ | 31,245 | |
| 5. | Accrued Liabilities and Other |
| | | December 31, | |
| | | 2008 | | | 2007 | |
| | | (in thousands) | |
| | | | | | | |
| Accrued compensation | | $ | 12,606 | | | $ | 16,119 | |
| Accrued Beverly Hills litigation settlement | | | 10,000 | | | | 10,000 | |
| Accrued environmental costs | | | 10,040 | | | | 8,750 | |
| Accrued dividends | | | 6,779 | | | | 5,825 | |
| Accrued property taxes | | | 5,295 | | | | 4,998 | |
| Accrued interest | | | 7,363 | | | | 2,541 | |
| Income taxes payable | | | 326 | | | | - | |
| Derivative liabilities | | | - | | | | 15,089 | |
| Accrued income taxes | | | - | | | | 6,819 | |
| Accrued El Dorado Refinery contingent earn-out payment | | | - | | | | 7,500 | |
| Accrued refinery incidents costs | | | - | | | | 2,800 | |
| Other | | | 4,675 | | | | 3,677 | |
| | | $ | 57,084 | | | $ | 84,118 | |
| | | December 31, | |
| | | 2008 | | | 2007 | |
| | | (in thousands) | |
| | | | | | | |
| 6.625% Senior Notes (Due October 1, 2011) | | $ | 150,000 | | | $ | 150,000 | |
| | | | | | | | | |
| 8.5% Senior Notes (Due September 15, 2016) | | | 200,000 | | | | - | |
| Less discount | | | (2,780 | ) | | | - | |
| 8.5% Senior Notes, net | | | 197,220 | | | | - | |
| | | | | | | | | |
| | | $ | 347,220 | | | $ | 150,000 | |
On September 15, 2008, the Company issued $200.0 million aggregate principal amount of 8.5% Senior Notes. The 8.5% Senior Notes, which mature on September 15, 2016, were issued at a 1.42% discount ($2.8 million) resulting in total Senior Notes, net of discount, of $197.2 million. The Company received net proceeds (after underwriting fees) of $195.3 million. Interest is paid semi-annually on March 15 and September 15. The 8.5% Senior Notes are redeemable, at the option of the Company, at 104.25% after September 15, 2012, declining to 100.00% in 2014. Prior to September 15, 2012, the Company may at its option redeem the 8.5% Senior Notes at a make-whole price comprised of 104.25% of the principal amount plus a make-whole amount. The make-whole amount is the excess, if any, of the present value of the remaining interest and principal payments due on the 8.5% Senior Notes as if such notes were redeemed on September 15, 2012 computed using a discount rate equal to the Treasury Rate plus 50 basis points, over the principal amount of the notes. The 8.5% Senior Notes may restrict payments, including dividends, and limit the incurrence of additional indebtedness based on covenants related to interest coverage and restricted payments. Frontier Holdings Inc. and its material subsidiaries are full and unconditional guarantors of the 8.5% Senior Notes (see Note 14 “Consolidating Financial Statements”).
On October 1, 2004, the Company issued $150.0 million principal amount of 6.625% Senior Notes. The 6.625% Senior Notes, which mature on October 1, 2011, were issued at par, and the Company received net proceeds (after underwriting fees) of $147.2 million. Interest is paid semi-annually. The 6.625% Senior Notes are redeemable, at the option of the Company, at 103.313% after October 1, 2007, declining to 100% in 2010. The 6.625% Senior Notes may restrict payments, including dividends, and limit the incurrence of additional indebtedness based on covenants related to interest coverage and restricted payments. Frontier Holdings Inc. and its subsidiaries are full and unconditional guarantors of the 6.625% Senior Notes (see Note 14 “Consolidating Financial Statements”).
| 7. | Revolving Credit Facility |
The refining operations have a working capital credit facility with a group of banks led by Union Bank of California and BNP Paribas (“Facility”). The Facility, collateralized by inventory, accounts receivable and related contracts and intangibles, and certain deposit accounts, provides working capital financing for operations, generally the financing of crude oil and product supply. On June 23, 2008, the Company entered into an amendment which increased the maximum amount available under this agreement from $250 million to $350 million. On August 19, 2008, the Company entered into a Fourth Amended and Restated Revolving Credit Agreement expiring August 17, 2012. This agreement increases the maximum commitment from $350 million to $500 million and established the margin at a range from 1.5% to 2% plus the base rate or LIBOR rate, as applicable. The Facility provides for a quarterly commitment fee from 0.30% to .375% per annum plus standard issuance and renewal fees. The Company had average daily borrowings of $4.8 million during 2008 under the Facility, with interest expense incurred of $193,000 at an average interest rate of 4.041%. No funds were borrowed at any time during 2007 under the Facility, and thus the Company did not incur any interest expense under the Facility in 2007. The Facility is subject to compliance with financial covenants relating to cash coverage, debt leverage and current ratios and permitted consolidated long-term funded indebtedness. The Company was in compliance with these covenants at December 31, 2008. No borrowings were outstanding at December 31, 2008 or 2007, under the Facility. Standby letters of credit outstanding were $12.5 million and $33.2 million at December 31, 2008 and 2007, respectively. As of December 31, 2008, the Company had borrowing base availability of $283.0 million under the Facility.
The Facility restricts payments to FOC from its subsidiaries and thus, as required by Regulation 210.5-04 of Regulation S-X of the Securities Exchange Act of 1934, as amended, the Condensed Financial Information of FOC is included in Schedule I of this Form 10-K.
The provision for income taxes is comprised of the following:
| | | Years ended December 31, | |
| | | 2008 | | | 2007 | | | 2006 | |
| | | (in thousands) | |
| Current: | | | | | | | | | |
| Federal | | $ | (51,136 | ) | | $ | 238,555 | | | $ | 168,950 | |
| State | | | (2,944 | ) | | | 33,109 | | | | 25,814 | |
| Total current provision | | | (54,080 | ) | | | 271,664 | | | | 194,764 | |
| Deferred: | | | | | | | | | | | | |
| Federal | | | 95,920 | | | | (1,567 | ) | | | 5,269 | |
| State | | | (15,026 | ) | | | (349 | ) | | | 804 | |
| Total deferred provision | | | 80,894 | | | | (1,916 | ) | | | 6,073 | |
| Total provision | | $ | 26,814 | | | $ | 269,748 | | | $ | 200,837 | |
The following is a reconciliation of the provision for income taxes computed at the statutory United States income tax rates on pretax income and the provision for income taxes as reported:
| | | Years ended December 31, | |
| | | 2008 | | | 2007 | | | 2006 | |
| | | (in thousands) | |
| | | | | | | | | | |
| Provision based on statutory rates | | $ | 37,467 | | | $ | 269,106 | | | $ | 203,040 | |
| Increase (decrease) resulting from: | | | | | | | | | | | | |
| State income taxes | | | (17,970 | ) | | | 32,760 | | | | 26,618 | |
| Federal tax effect of state income taxes | | | 6,290 | | | | (11,466 | ) | | | (9,316 | ) |
| FIN 48 federal tax contingency reversals and adjustments | | | (2,856 | ) | | | - | | | | - | |
Increase (benefit) from the Section 199 manufacturers deduction (1) | | | 3,052 | | | | (15,387 | ) | | | (5,666 | ) |
| Benefit of ultra-low sulfur diesel tax credit | | | - | | | | (5,525 | ) | | | (14,546 | ) |
| Other, including permanent book-tax differences | | | 831 | | | | 260 | | | | 707 | |
| Provision as reported | | $ | 26,814 | | | $ | 269,748 | | | $ | 200,837 | |
| | | | | | | | | | | | | |
(1) 2008 does not have a benefit from the Section 199 deduction due to having a taxable loss. The 2008 amounts reflect a decrease in the Section 199 manufacturers deduction due to the true-up of the 2007 tax return filed in 2008, the planned carryback of the 2008 net operating loss into prior years and the filing of an amended 2006 return in 2008. | |
Significant components of deferred tax assets and liabilities are shown below:
| | | December 31, 2008 | | | December 31, 2007 | |
| | | State | | | Federal | | | Total | | | State | | | Federal | | | Total | |
| | | (in thousands) | |
| Current deferred tax assets: | | | | | | | | | | | | | | | | | | |
| Gross current assets: | | | | | | | | | | | | | | | | | | |
| Accrued bonuses | | $ | 292 | | | $ | 2,203 | | | $ | 2,495 | | | $ | 474 | | | $ | 3,734 | | | $ | 4,208 | |
| Stock-based compensation | | | 932 | | | | 7,035 | | | | 7,967 | | | | 148 | | | | 1,173 | | | | 1,321 | |
| Accrued legal settlement | | | 293 | | | | 2,212 | | | | 2,505 | | | | - | | | | - | | | | - | |
| Environmental liability accruals | | | 337 | | | | 2,546 | | | | 2,883 | | | | 13 | | | | 105 | | | | 118 | |
| State net operating losses | | | 4,034 | | | | - | | | | 4,034 | | | | - | | | | - | | | | - | |
| Kansas income tax credits | | | 2,332 | | | | - | | | | 2,332 | | | | - | | | | - | | | | - | |
| Unrealized loss on derivative contracts | | | - | | | | - | | | | - | | | | 668 | | | | 5,281 | | | | 5,949 | |
| Current state income tax liabilities | | | - | | | | 97 | | | | 97 | | | | - | | | | 2,334 | | | | 2,334 | |
| Other | | | 198 | | | | 1,491 | | | | 1,689 | | | | 157 | | | | 1,241 | | | | 1,398 | |
| Total gross current assets | | | 8,418 | | | | 15,584 | | | | 24,002 | | | | 1,460 | | | | 13,868 | | | | 15,328 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Gross current liabilities: | | | | | | | | | | | | | | | | | | | | | | | | |
| Prepaid expenses | | | (418 | ) | | | (3,153 | ) | | | (3,571 | ) | | | (341 | ) | | | (2,698 | ) | | | (3,039 | ) |
| State income tax receivable or prepaid | | | - | | | | (5,527 | ) | | | (5,527 | ) | | | - | | | | (2,472 | ) | | | (2,472 | ) |
| State deferred taxes | | | | | | | (2,661 | ) | | | (2,661 | ) | | | - | | | | (391 | ) | | | (391 | ) |
| Unrealized gain on derivative contracts | | | (398 | ) | | | (3,004 | ) | | | (3,402 | ) | | | - | | | | - | | | | - | |
| Total gross current liabilities | | | (816 | ) | | | (14,345 | ) | | | (15,161 | ) | | | (341 | ) | | | (5,561 | ) | | | (5,902 | ) |
| Total current net deferred tax assets | | $ | 7,602 | | | $ | 1,239 | | | $ | 8,841 | | | $ | 1,119 | | | $ | 8,307 | | | $ | 9,426 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Long-term deferred tax liabilities: | | | | | | | | | | | | | | | | | | | | | | | | |
| Gross long-term assets: | | | | | | | | | | | | | | | | | | | | | | | | |
| Pension and other post-retirement benefits | | $ | 1,446 | | | $ | 10,906 | | | $ | 12,352 | | | $ | 1,185 | | | $ | 9,366 | | | $ | 10,551 | |
| Kansas income tax credits | | | 20,556 | | | | - | | | | 20,556 | | | | - | | | | - | | | | - | |
| Stock-based compensation | | | - | | | | - | | | | - | | | | 1,095 | | | | 8,650 | | | | 9,745 | |
| Environmental liability accruals | | | 211 | | | | 1,593 | | | | 1,804 | | | | 301 | | | | 2,375 | | | | 2,676 | |
| Asset retirement obligations | | | 214 | | | | 1,617 | | | | 1,831 | | | | 208 | | | | 1,646 | | | | 1,854 | |
| Other | | | 347 | | | | 3,189 | | | | 3,536 | | | | 433 | | | | 3,421 | | | | 3,854 | |
| State deferred taxes | | | - | | | | 1,045 | | | | 1,045 | | | | - | | | | 4,094 | | | | 4,094 | |
| Total gross long-term assets | | | 22,774 | | | | 18,350 | | | | 41,124 | | | | 3,222 | | | | 29,552 | | | | 32,774 | |
| Gross long-term liabilities | | | | | | | | | | | | | | | | | | | | | | | | |
| Depreciation | | | (23,558 | ) | | | (177,964 | ) | | | (201,522 | ) | | | (13,178 | ) | | | (104,419 | ) | | | (117,597 | ) |
| Deferred turnaround costs | | | (2,203 | ) | | | (16,613 | ) | | | (18,816 | ) | | | (1,740 | ) | | | (13,747 | ) | | | (15,487 | ) |
| Total long-term net deferred tax liabilities | | $ | (2,987 | ) | | $ | (176,227 | ) | | $ | (179,214 | ) | | $ | (11,696 | ) | | $ | (88,614 | ) | | $ | (100,310 | ) |
As of December 31, 2008, the Company had a federal income tax receivable of $100.3 million and state income taxes receivable of $15.8 million, which are included in “Income taxes receivable” on the Consolidated Balance Sheet. The federal income tax receivable results from the Company having a taxable loss for the year ended December 31, 2008, which will enable the Company to receive a refund for all of its 2008 estimated income tax payments of $47.0 million as well as carryback the net operating loss (“NOL”) generated in 2008 to claim an additional estimated $34.0 million tax refund from prior years. In addition the Company has a refund receivable for the $18.4 million overpayment on its federal income tax return for the year ended December 31, 2007 and has filed an amended federal income tax return for the year ended December 31, 2006, which will result in a refund of $516,000 primarily related to the Energy Policy Act of 2005 which added Section 179C to the Internal Revenue Code and provides an accelerated deduction for qualified capital costs incurred to expand an existing refinery. This accelerated deduction allows an expense deduction of 50% of such costs in the year the qualified projects are placed in service with the remaining costs depreciable under regular tax depreciation rules. This Section 179C deduction has benefited the Company’s cash flow by reducing its taxable income for 2006 and 2007 and is a primary factor in the Company’s 2008 taxable loss. The American Jobs Creation Act of 2004 created Internal Revenue Code Section 199, which provides an income tax benefit to domestic manufacturers, and for which the Company did record income tax benefits of approximately $15.4 million and $5.7 million, in its 2007 and 2006 income tax provisions, respectively. The Company recognized the benefit of a $23.3 million in Kansas income tax credits in 2008 related to expansion projects completed in the years 2006 through 2008 at its El Dorado Refinery. Of these $23.3 million Kansas income tax credits, the Company has taken $217,000 on the Company’s amended 2006 Kansas income tax return and $217,000 on the Company’s 2007 Kansas income tax return, both filed in 2008. The remaining $22.9 million of Kansas income tax credits (reflected as deferred tax assets as of December 31, 2008), are scheduled to be taken approximately evenly over the years 2009 thru 2017. The income tax provision for the year ended December 31, 2007 was reduced $5.5 million because of an $8.5 million credit for production of ultra low sulfur diesel fuel. The income tax provision for the year ended December 31, 2006 was reduced $14.5 million because of a $22.4 million credit for production of ultra low sulfur diesel fuel (see “Environmental” under Note 12 “Commitments and Contingencies”).
The Company generated an estimated federal NOL in 2008 of nearly $105.0 million, which as indicated above the Company plans to carryback, enabling it to receive a refund of taxes paid in prior years. The Company also generated state net operating losses in 2008 of approximately $44.8 million in Kansas, $11.6 million in Colorado and $4.1 million in Nebraska, which will be carried forward to reduce income taxes payable in future years.
The Company recognizes the amount of taxes payable or refundable for the current year and recognizes deferred tax liabilities and assets for the expected future tax consequences of events and transactions that have been recognized in the Company’s financial statements or tax returns. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some or all of its deferred tax assets will not be realized. Realization of the deferred income tax assets is dependent on generating sufficient taxable income in future years. Although realization is not assured, management believes that it is more likely than not that all of the deferred income tax assets will be realized and thus, no valuation allowance was provided as of December 31, 2008 and 2007.
The Company recognized income tax benefits related to the deductibility of stock-based compensation, net of contingencies, in the amounts of $5.3 million, $6.4 million, and $5.3 million for the years ended December 31, 2008, 2007 and 2006, respectively. Such benefits were recorded as an increase in additional paid-in capital, a reduction of income taxes payable and an increase in “Contingent income tax liabilities.” The Company also recognized an income tax (asset) liability related to the minimum defined benefit liability reflected in “Accumulated other comprehensive income (loss)” in the amounts of ($1.4 million), $805,000 and $141,000 for the years ended December 31, 2008, 2007 and 2006, respectively.
The Company is currently under a U.S. Federal income tax examination for 2006 and 2005. The Company has received a Notice of Proposed Adjustment (“NOPA”) from the Internal Revenue service for approximately $14.4 million of 2005 taxes and approximately $4.7 million of 2006 taxes both related to the deductibility for income tax purposes of certain stock-based compensation for executives. The Company has submitted a protest of these amounts and has requested an appeals conference. As discussed below, the Company has provided income tax contingencies for these amounts in the event it is unsuccessful in its appeal.
The Company adopted the provisions of FIN 48 on January 1, 2007. The Company reviewed all open tax years for all jurisdictions, primarily U.S. Federal and the states of Kansas, Colorado and Nebraska for the years 2003 through 2006. As a result of the implementation of FIN 48, the Company recognized approximately a $940,000 increase in the liability for unrecognized tax benefits and $76,000 in accrued interest, which were accounted for as reductions to the January 1, 2007 balance of retained earnings. In connection with the adoption of FIN 48, previously recognized contingent income tax liabilities under FAS No. 5, “Accounting for Contingencies” ($28.3 million, including accrued interest, at December 31, 2006) were reclassified from a current liability to a long-term liability. A reconciliation of the beginning and ending amount of unrecognized tax benefits, excluding accrued interest and the federal income tax benefit of state contingencies, for the years ended December 31, 2008 and 2007 is as follows (in thousands):
| | | Years ended December 31, | |
| | | 2008 | | | 2007 | |
| | | | | | | |
| Balance beginning of year | | $ | 28,324 | | | $ | 27,710 | |
| Additions based on tax positions related to the current year | | | 521 | | | | 692 | |
| Additions for tax positions of prior years | | | 1,294 | | | | - | |
| Reductions for tax positions of prior years | | | (120 | ) | | | - | |
| Settlements | | | - | | | | - | |
| Reductions due to lapse of applicable statutes of limitations | | | (5,741 | ) | | | (78 | ) |
| Balance end of year | | $ | 24,278 | | | $ | 28,324 | |
The Company recognizes penalties and interest accrued related to unrecognized tax benefits in “Interest expense and other financing costs” on the Consolidated Statements of Income. During the years ended December 31, 2008, 2007 and 2006, the Company recognized approximately $530,000 (net of reversals of $1.2 million), $2.4 million and $1.5 million, respectively, of interest expense on contingent income tax liabilities. During the years ended December 31, 2008, 2007 and 2006, the Company recorded $52,000, $59,000 and $33,000, respectively, in tax penalties. The Company had approximately $4.7 million and $4.1 million in accrued interest on income tax contingencies at December 31, 2008 and 2007, respectively.
The total contingent income tax liabilities and accrued interest of $28.1 million and $32.3 million are reflected in the Consolidated Balance Sheet at December 31, 2008 and 2007 in “Contingent income tax liabilities.” These contingencies relate to the deductibility for income tax purposes of certain stock-based compensation for executives and the treatment of certain items for state income tax purposes. The Company has no tax positions for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility. Total unrecognized tax benefits at December 31, 2008 that, if recognized, would affect the effective tax rate were $1.6 million.
The regular statutes of limitations for contingencies related to the Company’s 2004 and 2005 income tax returns (totaling $19.6 million as of December 31, 2008) will expire in the third and fourth quarters of 2009; however, the statute of limitations for the Company’s 2005 federal return has been extended to March 2010 to allow for the appeals process related to the NOPA discussed above. These contingencies primarily relate to the deductibility for income tax purposes of certain stock-based compensation for executives. Any income tax benefit related to these contingencies will be recorded as a reduction to the income tax provision ($379,000), an increase to paid-in capital ($15.5 million) and a reduction of interest expense ($3.8 million as of December 31, 2008).
As of December 31, 2008, the Company is generally open to examination in the United States and various individual states for tax years ended December 31, 2005 through December 31, 2008.
Dividends
The Company declared a quarterly cash dividend of $0.05 per share of common stock for the quarter ended March 31, 2008. The quarterly cash dividend was $0.06 per share of common stock for the quarters ended June 30, 2008 through December 31, 2008.
All outstanding common shareholders at the declaration date are eligible to participate in dividends. The payment of dividends is prohibited under the Company’s revolving credit facility only if a default has occurred and is continuing or such payment would cause a default. The 6.625% and 8.5% Senior Notes may restrict dividend payments based on covenants related to interest coverage and a restricted payments calculation.
Treasury stock
The Company accounts for its treasury stock under the cost method on a FIFO basis. Through December 31, 2007, the Company’s Board of Directors had approved a total of $300.0 million for share repurchases, of which $243.6 million had been utilized as of December 31, 2007. On February 28, 2008, the Company’s Board of Directors authorized another $100.0 million for share repurchases. During the year ended December 31, 2008, the Company purchased 1,561,367 shares ($56.3 million) in open market transactions, leaving remaining authorization of $100.2 million for future repurchases of shares. A rollforward of treasury stock for the year ended December 31, 2008 is as follows:
| | | Number of shares | | | Amount | |
| | | (in thousands except share amounts) | |
| | | | | | | |
| Balance as of December 31, 2007 | | | 26,893,939 | | | $ | 327,564 | |
| Shares repurchased under stock repurchase plans | | | 1,561,367 | | | | 56,260 | |
| Shares received to fund minimum statutory withholding taxes | | | 386,350 | | | | 10,770 | |
| Shares received to fund stock option exercises | | | 9,224 | | | | 306 | |
| Shares issued for stock option exercises | | | (160,000 | ) | | | (212 | ) |
| Shares issued for restricted stock unit vestings | | | (122,250 | ) | | | (143 | ) |
| Shares issued for restricted stock grants, net of forfeits | | | (622,746 | ) | | | (813 | ) |
| Balance as of December 31, 2008 | | | 27,945,884 | | | $ | 393,732 | |
Earnings per Share
The following sets forth the computation of diluted earnings per share (“EPS”) for the years ended December 31, 2008, 2007 and 2006.
| | | 2008 | | | 2007 | | | 2006 | |
| | | Income (Numerator) | | | Shares (Denominator) | | | Per Share Amount | | | Income (Numerator) | | | Shares (Denominator) | | | Per Share Amount | | | Income (Numerator) | | | Shares (Denominator) | | | Per Share Amount | |
| | | (in thousands except per share amounts) | |
| Basic EPS: | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Net income | | $ | 80,234 | | | | 103,139 | | | $ | 0.78 | | | $ | 499,125 | | | | 106,804 | | | $ | 4.67 | | | $ | 379,277 | | | | 111,408 | | | $ | 3.40 | |
| Dilutive securities: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Stock options | | | | | | | 40 | | | | | | | | | | | | 291 | | | | | | | | | | | | 565 | | | | | |
Restricted stock and stock unit awards | | | | | | | 428 | | | | | | | | | | | | 875 | | | | | | | | | | | | 539 | | | | | |
| Diluted EPS: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Net income | | $ | 80,234 | | | | 103,607 | | | $ | 0.77 | | | $ | 499,125 | | | | 107,970 | | | $ | 4.62 | | | $ | 379,277 | | | | 112,512 | | | $ | 3.37 | |
For the year ended December 31, 2008, 449,591 outstanding stock options that could potentially dilute EPS in future years were not included in the computation of diluted EPS as they were anti-dilutive. For the year ended December 31, 2007, there were no outstanding stock options that could potentially dilute EPS in future years that were not included in the computation of diluted EPS. For the year ended December 31, 2006, 493,226 outstanding stock options that could potentially dilute EPS in future years were not included in the computation of diluted EPS.
Stock-based Compensation
Effective January 1, 2006, the Company adopted FAS No. 123(R), “Share-Based Payment,” which requires companies to recognize the fair value of stock options and other stock-based compensation in the financial statements. The Company adopted FAS No. 123(R) using the modified prospective application method, and accordingly, prior period amounts have not been retrospectively adjusted. Upon adoption of FAS No. 123(R), deferred compensation recorded as contra-equity in prior periods was eliminated against the appropriate equity accounts. The Company evaluated the need for a cumulative effect of a change in accounting principle as of January 1, 2006, related to previously recognized compensation expense for previously forfeited awards or in recognition of an assumption for future forfeits, and determined that none was necessary.
The Company also elected to use the FSP No. 123(R)-3’s simplified method of calculating the adoption-date additional paid-in capital pool. This relates to the method of calculating the pool of excess income tax benefits available to absorb tax deficiencies subsequent to the adoption of FAS No. 123(R).
Stock-based compensation costs and income tax benefits recognized in the Consolidated Statements of Income for the years ended December 31, 2008, 2007 and 2006 are as follows:
| | | Years Ended December 31, | |
| | | 2008 | | | 2007 | | | 2006 |
| | (in thousands) | | | | |
| | | | | | | | | | |
| Restricted shares and units | | $ | 5,398 | | | $ | 6,879 | | | $ | 8,539 | |
| Stock options | | | 1,004 | | | | 1,515 | | | | 2,110 | |
| Contingently issuable stock unit awards | | | 13,612 | | | | 14,159 | | | | 7,290 | |
| Stock grant to retiring executive | | | - | | | | - | | | | 90 | |
| Total stock-based compensation expense | | $ | 20,014 | | | $ | 22,553 | | | $ | 18,029 | |
| | | | | | | | | | | | | |
| Income tax benefit recognized in the income statement | | $ | 6,730 | | | $ | 8,570 | | | $ | 6,851 | |
Omnibus Incentive Compensation Plan. The shareholders of the Company approved the Frontier Oil Corporation Omnibus Incentive Compensation Plan (the “Plan”) at the Annual Meeting of Shareholders held on April 26, 2006. The Plan is a broad-based incentive plan that provides for granting stock options, stock appreciation rights (“SAR”), restricted stock awards, performance awards, stock units, bonus shares, dividend equivalent rights, other stock-based awards and substitute awards (“Awards”) to employees, consultants and non-employee directors of the Company. The Plan amends and restates the Company’s previously approved 1999 Stock Plan and the Company’s Restricted Stock Plan, both of which were merged into the Omnibus Plan. The maximum number of shares of the Company’s common stock that may be issued under the Plan with respect to Awards is 12,000,000 shares, subject to certain adjustments as provided by the Plan. Awards issued under the prior plans between December 31, 2005 and April 26, 2006 reduced the number of shares available for Awards as though the awards had been issued after April 26, 2006. The number of shares available for Awards will be reduced by 1.7 times the number of shares for each stock-denominated award granted, other than an option or a SAR under the Plan, and will be reduced by 1.0 times the number of option shares or SARs granted. As of December 31, 2008, 5,141,656 shares were available to be awarded under the Plan based on expected payout of the performance awards made in 2008 for which restricted stock will be issued in 2009 and in 2011 if the performance criteria are met (see “Contingently Issuable Awards” below). For purposes of determining compensation expense, forfeitures are estimated at the time Awards are granted based on historical average forfeiture rates and the group of individuals receiving those Awards. The Plan provides that the source of shares for Awards may be either newly issued shares or treasury shares. The Company does not plan to repurchase additional treasury shares in 2009 strictly for issuing share Awards; however, treasury shares that are repurchased or are currently in treasury may be issued as share Awards in 2009. As of December 31, 2008, there was $22.5 million of total unrecognized compensation cost related to the Plan including costs for stock options, restricted stock, restricted stock units and performance-based awards, which is expected to be recognized over a weighted-average period of 1.72 years.
Stock Options. Stock options are issued at the current market price of the Company’s common stock on the date of grant and generally vest ratably over three years and expire after five years. The grant date fair value is calculated using the Black-Scholes option pricing model. The Company uses historical employee exercise data, including post-vesting termination behavior, to estimate the expected life of the options. Expected volatility is calculated using the historical volatility of the price of the Company’s common stock. The risk-free interest rate is based on the U.S. Treasury yield curve in effect at the time of the grant. No stock options were granted during the years ended December 31, 2008 or 2007. The $9.615 per share fair value of the options granted during the year ended December 31, 2006 was estimated with the following assumptions: risk-free interest rate of 4.89%, expected volatility of 37.3%, expected life of 3.33 years and no dividend yield.
For the stock options granted in 2006, when common stock dividends are declared by the Company’s Board of Directors, dividend equivalents are accrued but not paid until the options are vested. After vesting, dividend equivalents will be paid concurrently with common stock dividends until the options are exercised or expire. Stock options issued prior to 2006 do not have any dividend equivalent rights.
Stock option changes during the years ended December 31, 2008, 2007 and 2006 are presented below:
| | | 2008 | | | 2007 | | | 2006 | |
| | | Number of awards | | | Weighted-Average Exercise Price | | | Aggregate Intrinsic Value of Options (in thousands) | | | Number of awards | | | Weighted-Average Exercise Price | | | Number of awards | | | Weighted-Average Exercise Price | |
| | | | | | | | | | | | | | | | | | | | | | |
Outstanding at beginning of year | | | 624,591 | | | $ | 22.4021 | | | | | | | 1,032,126 | | | $ | 16.3104 | | | | 1,381,700 | | | $ | 4.3515 | |
| Granted | | | - | | | | - | | | | | | | - | | | | - | | | | 493,226 | | | | 29.3850 | |
| Exercised or issued | | | (160,000 | ) | | | 4.4438 | | | | | | | (396,761 | ) | | | 6.3655 | | | | (842,800 | ) | | | 4.3560 | |
| Expired or forfeited | | | - | | | | - | | | | | | | (10,774 | ) | | | 29.3850 | | | | - | | | | - | |
Outstanding at end of year | | | 464,591 | | | $ | 28.5868 | | | $ | 120 | | | | 624,591 | | | $ | 22.4021 | | | | 1,032,126 | | | $ | 16.3104 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Vested or expected to vest at end of year | | | 462,489 | | | $ | 28.5832 | | | $ | 120 | | | | 613,672 | | | $ | 22.2779 | | | | 1,021,207 | | | $ | 16.1706 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Exercisable at end of period | | | 235,039 | | | $ | 27.8072 | | | $ | 120 | | | | 280,249 | | | $ | 13.8223 | | | | 501,400 | | | $ | 4.3200 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Weighted-average fair value of options granted during the year | | | | n/a | | | | | | | | | | | | n/a | | | | | | | | 9.6150 | |
The Company received $405,000, $2.3 million and $3.7 million of cash for stock options exercised during the years ended December 31, 2008, 2007 and 2006, respectively. The total intrinsic value of stock options exercised during the years ended December 31, 2008, 2007 and 2006 was $3.7 million, $13.6 million and $22.4 million, respectively. The Company realized $1.4 million, $5.1 million and $8.5 million of income tax benefits during the years ended December 31, 2008, 2007 and 2006, respectively, substantially all of which were excess income tax benefits, related to the exercises of stock options. Excess income tax benefits are the benefits from additional deductions allowed for income tax purposes in excess of expenses recorded in the financial statements. These excess income tax benefits are recorded as an increase to paid-in capital, and the majority of these amounts are reflected as cash flows from financing activities in the Consolidated Statements of Cash Flows (as provided for in FAS No. 123(R)).
The following table summarizes information about stock options outstanding at December 31, 2008:
| Stock Options Outstanding at December 31, 2008 | |
Number Outstanding | | Weighted-Average Remaining Contractual Life (Years) | | Exercise Price | | Exercisable | | | Vested or Expected to Vest | |
| | 449,591 | | | | 2.32 | | | $ | 29.3850 | | | | 220,039 | | | | 447,489 | |
| | 15,000 | | | | 0.15 | | | $ | 4.6625 | | | | 15,000 | | | | 15,000 | |
Restricted Shares and Restricted Stock Units. Restricted shares and restricted stock units, when granted, are valued at the closing market value of the Company’s common stock on the date of issuance and amortized to compensation expense on a straight-line basis over the nominal vesting period of the stock, and for awards issued subsequent to the adoption of FAS No. 123(R), adjusted for retirement-eligible employees, as required. For awards granted prior to the adoption of FAS No. 123(R), the final $153,000 of compensation costs were recognized during the year ended December 31, 2008. The restricted shares and restricted stock units have vesting dates up to three years from the issue date. When common stock dividends are declared by the Company’s Board of Directors, dividends are accrued on the issued restricted shares but are not paid until the shares vest. When common stock dividends are declared by the Company’s Board of Directors, dividend equivalents are accrued on the restricted stock units and paid when the common stock dividends are paid.
The following table summarizes the changes in the Company’s restricted shares and restricted stock units during the years ended December 31, 2008, 2007 and 2006.
| | | 2008 | | | 2007 | | | 2006 | |
| | | Shares / Units | | | Weighted-Average Grant-Date Market Value | | | Shares / Units | | | Weighted-Average Grant-Date Market Value | | | Shares / Units | | | Weighted-Average Grant-Date Market Value | |
| Nonvested at beginning of year | | | 1,053,083 | | | $ | 24.0234 | | | | 713,026 | | | $ | 18.5465 | | | | 415,692 | | | $ | 8.8870 | |
| Conversion of stock unit awards | | | 459,171 | | | | 29.5867 | | | | 657,232 | | | | 29.3850 | | | | - | | | | - | |
| Granted | | | 191,603 | | | | 29.2920 | | | | 127,762 | | | | 30.3280 | | | | 459,956 | | | | 26.4773 | |
| Vested | | | (1,130,600 | ) | | | 24.5279 | | | | (415,266 | ) | | | 25.0136 | | | | (162,622 | ) | | | 16.2865 | |
| Forfeited | | | (1,778 | ) | | | 28.6345 | | | | (29,671 | ) | | | 24.4588 | | | | - | | | | - | |
| Nonvested at end of year | | | 571,479 | | | | 29.2473 | | | | 1,053,083 | | | | 24.0234 | | | | 713,026 | | | | 18.5465 | |
The total grant date fair value of restricted shares and restricted stock units which vested during the years ended December 31, 2008, 2007 and 2006 was $27.7 million, $10.4 million and $2.6 million, respectively. The total intrinsic value of restricted shares and restricted stock units vested during the years ended December 31, 2008, 2007 and 2006 was $33.3 million, $16.0 million and $4.5 million, respectively. The vesting for the year ended December 31, 2008 in the table above includes 1,008,350 shares of previously issued restricted stock and 122,250 restricted stock units (for which common stock was issued upon vesting). The vesting for the year ended December 31, 2007 in the table above includes 348,382 shares of previously issued restricted stock and 66,884 restricted stock units (for which common stock was issued upon vesting). The vesting for the year ended December 31, 2006 in the table above includes 128,596 shares of previously issued restricted stock and 34,026 restricted stock units (for which common stock was issued upon vesting). The Company realized $11.6 million, $5.8 million and $1.7 million of income tax benefits related to these vestings, of which $1.7 million, $2.1 million, and $712,000 was excess income tax benefits, for 2008, 2007 and 2006, respectively.
In March 2008, following certification by the Compensation Committee of the Company’s Board of Directors that specified performance criteria had been achieved for the year ended December 31, 2007, the Company issued 459,171 shares of restricted stock in connection with the February 2007 grant of contingently issuable stock unit awards. One-third of this restricted stock vested on June 30, 2008, one-third will vest on June 30, 2009 and the final one-third will vest on June 30, 2010. Due to a retirement of an employee, 116,666 shares of the 459,171 shares fully vested during the year ended December 31, 2008. The Company issued 26,250 restricted stock units to its Board of Directors on January 24, 2008, that fully vested during the year ended December 31, 2008. During the year ended December 31, 2008, an additional 99,755 shares (net of forfeits) of restricted stock were issued to employees and will vest 25% in March 2009, 25% in March 2010, and the final 50% in March 2011. A grant of 62,129 shares of restricted stock were also issued to an employee, of which all of the shares were early vested during the year ended December 31, 2008 due to the retirement of the employee. The Company also granted 2,865 shares of restricted stock to an employee, one-third of which vested on June 30, 2008, one-third will vest on June 30, 2009 and the final one-third will vest on June 30, 2010. On April 26, 2006, the Company granted performance-based stock unit awards. Because performance goals were achieved for 2006, the stock unit awards were converted into 657,232 shares of restricted stock in early 2007 following certification of performance by the Compensation Committee of the Company’s Board of Directors, one-third vested on June 30, 2007, one-third vested on June 30, 2008 and the final one-third will vest on June 30, 2009.
Contingently Issuable Awards. During the year ended December 31, 2008, the Company granted up to 242,680 (net of forfeitures thru December 31, 2008) contingently issuable stock unit awards to be earned if a certain net income goal was met for 2008. As the net income goal was not met, stock-based compensation expense recorded for these awards during the first two quarters of 2008 was reversed during the third quarter of 2008.
During the year ended December 31, 2008, the Company granted up to 242,669 (net of forfeitures thru December 31, 2008) contingently issuable stock unit awards to be earned based on the Company’s return of capital employed versus that of a defined peer group. Depending on achievement of the performance goals, awards earned could be between 0% and 125% of the base number of contingently issuable stock units. As of December 31, 2008, the Company estimated that the target (100%) level award (194,148 stock units) would be earned for purposes of stock-based compensation expense for the awards granted in 2008. If any of the performance goals are achieved for 2008 and certified by the Compensation Committee, these stock unit awards (or a portion thereof) will be converted into restricted stock during the first quarter of 2009. One-third of these restricted shares will vest on June 30, 2009, one-third on June 30, 2010 and the final one-third on June 30, 2011.
The Company also granted during the year ended December 31, 2008, up to 242,671 (net of forfeitures thru December 31, 2008) stock unit awards contingent upon certain share price criteria being met over a three-year period ending on December 31, 2010. As of December 31, 2008, the Company assumed that the target (100%) level award (194,125 stock units) would be earned for purposes of stock-based compensation expense for the awards granted in 2008.
As of December 31, 2008, the Company also had outstanding up to 229,605 (net of forfeitures thru December 31, 2008) contingently issuable stock unit awards that were issued during the quarter ended March 31, 2007, to be earned should certain share price criteria be met over a three-year period ending December 31, 2009. Depending on achievement of the goals, awards earned could be between 0% and 125% of the base number of contingently issuable stock units. As of December 31, 2008, the company assumed the maximum (125%) level award (229,605 stock units) would be earned for purposes of stock-based compensation expense for the awards granted in 2007.
When common stock dividends are declared by the Company’s Board of Directors, dividend equivalents (on the stock unit awards) and dividends (once the stock unit awards are converted to restricted stock) are accrued on the contingently issuable stock units and restricted stock but are not paid until the restricted stock vests. The stock unit awards were valued at the market value on the date of grant and amortized to compensation expense on a straight-line basis over the nominal vesting period, adjusted for retirement-eligible employees, as required under FAS No. 123(R).
| 10. | Employee Benefit Plans |
Defined Contribution Plans
The Company sponsors defined contribution plans for its employees. All employees may participate by contributing a portion of their annual earnings to the plans. The Company makes pension and/or matching contributions on behalf of participating employees. The cost of the defined contribution plans for the years ended December 31, 2008, 2007 and 2006 was $7.9 million, $7.5 million and $6.4 million, respectively.
Deferred Compensation Plan
The Company sponsors a deferred compensation plan for certain employees and directors whose eligibility to participate in the plan is determined by the Compensation Committee of the Company’s Board of Directors. Participants may contribute a portion of their earnings to the plan, and the Company makes pension and/or matching contributions on behalf of eligible employees. The contributions and any earnings are held in an irrevocable trust known as a “rabbi trust” by an independent trustee. The trust account balance and related liability, both of which were $2.6 million at December 31, 2008 ($3.2 million at December 31, 2007) are reflected in “Other assets” and “Other long-term liabilities,” respectively, in the Consolidated Balance Sheets.
Executive Retiree Medical Benefit Plan
On February 22, 2006, the Compensation Committee of the Company’s Board of Directors approved the Executive Retiree Medical Benefit Plan. The Executive Retiree Medical Benefit Plan provided a post-retirement medical benefit for certain of the Company’s executive officers. Due to the plan design, the amount to be contributed by the retirees was expected to cover approximately the full cost of the plan. The Company incurred net costs of approximately $8,000 and $2,000 for the years ended December 31, 2008 and 2007, respectively. In November 2008, the Compensation Committee of the Board of Directors discontinued the Executive Retiree Medical Plan, effective immediately. One individual who is already participating in the plan will be allowed to continue as a covered participant.
Defined Benefit Plans
The Company established a defined benefit cash balance pension plan, effective January 1, 2000, for eligible El Dorado Refinery employees to supplement retirement benefits that those employees lost upon the sale of the El Dorado Refinery to Frontier. No other current or future employees will be eligible to participate in the plan and its funding status is in compliance with ERISA.
In April 2008, the Company’s Board of Directors approved the termination of the pension plan. Because of the required regulatory review, the Company estimates that the termination will not be completed until the third quarter of 2009. Plan participants will receive 100% of their account balance, including interest, upon termination.
The Company provides post-retirement healthcare and other benefits to certain employees of the El Dorado Refinery. Eligible employees are employees hired by the Refinery before certain defined dates and who satisfy certain age and service requirements. Employees hired on or before November 16, 1999 qualify for retirement healthcare insurance until eligible for Medicare. Employees hired on or before January 1, 1995 are also eligible for Medicare supplemental insurance. These plans were unfunded as of December 31, 2008 and 2007. The post-retirement health care plan requires retirees to pay between 20% and 40% of total health care costs based on age and length of service. The plan’s prescription drug benefits are at least equivalent to Medicare Part D benefits. The plan was changed in the first quarter of 2008 to limit the employees’ pre-Medicare insurance premium to 125% of the active employee rate. Post-retirement healthcare benefits provided for Medicare eligible retirees were reduced effective December 31, 2006 to levels stipulated at the time of the El Dorado Refinery acquisition.
In accordance with FAS No. 158, which the Company adopted as of December 31, 2006, Frontier is required to 1) recognize the funded status of a benefit plan (measured as the difference between plan assets at fair value and the benefit obligation) in its statement of financial position, 2) recognize as a component of other comprehensive income, net of tax, the gains or losses and prior service costs or credits that arise during the period but are not recognized as components of net period benefit cost, 3) measure defined benefit plan assets and obligations as of the date of the employer’s fiscal year-end statement of financial position, and 4) disclose in the notes to the financial statements additional information about certain effects on net periodic benefit cost for the next fiscal year that arise from delayed recognition of the gains or losses, prior service costs or credits, and transition assets or obligations.
The tables on the following pages set forth the funded status of the pension plan and post-retirement healthcare and other benefit plans change in benefit obligation, items not yet recognized as a component of net periodic benefit costs and reflected as a component of the ending balance of accumulated Other Comprehensive Income (“OCI”), net of tax, and the measurement of defined benefit plan assets and obligations for the years ended December 31, 2008, 2007 and 2006. Also included in the tables on the following pages are weighted average key assumptions, healthcare cost trend rates and sensitivity analysis for the years ended December 31, 2008, 2007 and 2006.
| | | Pension Benefits | | | Post-retirement and Other Benefits (1) | |
| | | 2008 | | | 2007 | | | 2008 | | | 2007 | |
| | | (in thousands) | |
| Change in benefit obligation: | | | | | | | | | | | | |
| Benefit obligation at January 1 | | $ | 9,941 | | | $ | 9,971 | | | $ | 28,156 | | | $ | 28,223 | |
| Service cost | | | - | | | | - | | | | 628 | | | | 752 | |
| Interest cost | | | 508 | | | | 562 | | | | 1,788 | | | | 1,612 | |
| Plan participant contributions | | | - | | | | - | | | | 62 | | | | 66 | |
| Actuarial loss (gain) | | | 158 | | | | (428 | ) | | | 1,556 | | | | (2,269 | ) |
| Amendments | | | 994 | | | | - | | | | - | | | | - | |
| Benefits paid | | | (264 | ) | | | (164 | ) | | | (332 | ) | | | (228 | ) |
| Benefit obligation at December 31 | | $ | 11,337 | | | $ | 9,941 | | | $ | 31,858 | | | $ | 28,156 | |
| | | | | | | | | | | | | | | | | |
| Change in plan assets: | | | | | | | | | | | | | | | | |
| Fair value of plan assets at January 1 | | | 10,731 | | | | 9,668 | | | | - | | | | - | |
| Actual (loss) return on plan assets | | | (150 | ) | | | 883 | | | | - | | | | - | |
| Employer contributions | | | 800 | | | | 344 | | | | 270 | | | | 162 | |
| Plan participant contributions | | | - | | | | - | | | | 62 | | | | 66 | |
| Benefits paid | | | (265 | ) | | | (164 | ) | | | (332 | ) | | | (228 | ) |
| Fair value of plan assets at December 31 | | $ | 11,116 | | | $ | 10,731 | | | $ | - | | | $ | - | |
| | | | | | | | | | | | | | | | | |
| Funded status at December 31 | | $ | (221 | ) | | $ | 790 | | | $ | (31,858 | ) | | $ | (28,156 | ) |
| | | | | | | | | | | | | | | | | |
| Amounts recognized in the balance sheets: | | | | | | | | | | | | | | | | |
| Other assets | | $ | - | | | $ | 790 | | | $ | - | | | $ | - | |
| Accrued liabilities and other | | | (221 | ) | | | - | | | | (730 | ) | | | (607 | ) |
| Post-retirement employee liabilities | | | - | | | | - | | | | (31,128 | ) | | | (27,549 | ) |
| Net amount recognized | | $ | (221 | ) | | $ | 790 | | | $ | (31,858 | ) | | $ | (28,156 | ) |
| | | | | | | | | | | | | | | | | |
Amounts recognized in accumulated OCI (2) | | | | | | | | | | | | | | | | |
| (Gain) loss | | $ | (397 | ) | | $ | (1,209 | ) | | $ | 10,499 | | | $ | 9,908 | |
| Prior service credit | | | 426 | | | | - | | | | (9,363 | ) | | | (11,239 | ) |
| | | $ | 29 | | | $ | (1,209 | ) | | $ | 1,136 | | | $ | (1,331 | ) |
(1) The disclosed post-retirement healthcare obligations and net periodic cost for 2008 and 2007 reflect government subsidies for prescription drugs as allowed under the Medicare Prescription Drug, Improvement and Modernization Act. The subsidy reduced the benefit obligation at December 31, 2008 and 2007, by approximately $4.3 million and $5.1 million, respectively. The Company did not recognize any benefits of the subsidy during the years ended December 31, 2008 and 2007. | |
(2) The pension loss of $29,000 will be recognized in the pension benefit cost in 2009. For the post-retirement healthcare and other benefits, $1.0 of the $10.5 million net loss and $1.9 million of the $9.4 million of prior service cost credit will be recognized in the benefit cost in 2009. | |
| | | Pension Benefits | | | Post-retirement Healthcare and Other Benefits | |
| | | 2008 | | | 2007 | | | 2006 | | | 2008 | | | 2007 | | | 2006 | |
| | | (in thousands) | |
Components of net periodic benefit cost and other amounts recognized in other comprehensive income for the year ended December 31: | |
| Service cost | | $ | - | | | $ | - | | | $ | - | | | $ | 627 | | | $ | 752 | | | $ | 1,011 | |
| Interest cost | | | 508 | | | | 562 | | | | 541 | | | | 1,788 | | | | 1,611 | | | | 2,075 | |
| Expected return on plan assets | | | (501 | ) | | | (714 | ) | | | (640 | ) | | | - | | | | - | | | | - | |
| Amortization of prior service cost | | | 568 | | | | - | | | | - | | | | (1,876 | ) | | | (1,876 | ) | | | - | |
| Amortized net actuarial loss | | | (3 | ) | | | - | | | | - | | | | 966 | | | | 1,137 | | | | 1,087 | |
| Net periodic benefit cost | | | 572 | | | | (152 | ) | | | (99 | ) | | | 1,505 | | | | 1,624 | | | | 4,173 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
Changes in assets and benefit obligations recognized in other comprehensive income: | | | | | | | | | |
Increase in benefit obligation for plan amendment | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | |
| Net loss (gain) | | | 810 | | | | (598 | ) | | | - | | | | 1,557 | | | | (2,269 | ) | | | - | |
| Amortization of prior service cost | | | 3 | | | | - | | | | - | | | | 1,876 | | | | 1,876 | | | | - | |
| Prior service cost | | | 994 | | | | - | | | | - | | | | - | | | | - | | | | - | |
| Amortization of loss | | | (568 | ) | | | - | | | | - | | | | (966 | ) | | | (1,137 | ) | | | - | |
| Adoption of SFAS 158 | | | - | | | | - | | | | (611 | ) | | | - | | | | - | | | | 199 | |
Total recognized in other comprehensive income | | | 1,239 | | | | (598 | ) | | | (611 | ) | | | 2,467 | | | | (1,530 | ) | | | 199 | |
Total recognized in net periodic benefit cost and other comprehensive income | | $ | 1,811 | | | $ | (750 | ) | | $ | (710 | ) | | $ | 3,972 | | | $ | 94 | | | $ | 4,372 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Weighted average assumptions: | | | | | | | | | | | | | | | | | | | | | | | | |
Benefit obligation discount rate as of December 31 (1) | | | 4.72 | % | | | 6.25 | % | | | 5.75 | % | | | 6.00 | % | | | 6.25 | % | | | 5.75 | % |
Net periodic benefit cost discount rate for the year ended December 31 (1) | | | 4.16 | % | | | 5.75 | % | | | 5.50 | % | | | 6.25 | % | | | 5.75 | % | | | 5.50 | % |
Expected return on plan assets (1) | | | 3.20 | % | | | 7.50 | % | | | 7.50 | % | | | - | | | | - | | | | - | |
| Salary increases | | | n/a | | | | n/a | | | | n/a | | | | n/a | | | | n/a | | | | n/a | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
(1) 2008 reflects revised rates based on the April 2008 approval to terminate the plan which is expected to occur by the third quarter of 2009. | |
| | | Post-retirement Healthcare and Other Benefits | |
| | | 2008 | | | 2007 | | | 2006 | |
| | | (dollars in thousands) | |
| | | | | | | | | | |
| Healthcare cost-trend rate: | | | 9.00 | % | | | 10.00 | % | | | 11.00 | % |
| | | ratable to | | | ratable to | | | ratable to | |
| | | | 5.00 | % | | | 5.00 | % | | | 5.00 | % |
| | | from | | | from | | | from | |
| | | 2012 | | | 2012 | | | 2008 | |
| | | | | | | | | | | | | |
| Sensitivity Analysis: | | | | | | | | | | | | |
| Effect of 1% (-1%) change in healthcare cost-trend rate: | | | | | | | | | | | | |
| Year-end benefit obligation | | $ | 4,932 | | | $ | 4,761 | | | $ | 8,641 | |
| | | | (4,030 | ) | | | (3,852 | ) | | | (6,784 | ) |
| Total service and interest cost | | | 388 | | | | 662 | | | | 720 | |
| | | | (316 | ) | | | (519 | ) | | | (560 | ) |
At December 31, 2008, the estimated future benefit payments to be paid over the next ten years are as follows:
| Estimated future benefit payments for years ending December 31, | | Pension Benefits | | | Post-retirement Healthcare and Other Benefits | |
| | | Payment | | | Payment | | | Subsidy Receipts | |
| | | (in thousands) | |
| | | | | | | | | | |
| 2009 | | $ | 11,601 | | | $ | 731 | | | $ | - | |
| 2010 | | | - | | | | 1,019 | | | | - | |
| 2011 | | | - | | | | 1,351 | | | | - | |
| 2012 | | | - | | | | 1,632 | | | | - | |
| 2013 | | | - | | | | 1,939 | | | | - | |
| Next 5 fiscal years thereafter | | | - | | | | 12,694 | | | | 654 | |
Plan Assets. The pension plan assets are held in a Trust Fund (the “Fund”) whose trustee is Frost National Bank (“trustee”). The Company contributed $800,000 to the Fund during 2008. Frontier’s pension plan weighted-average asset allocations in the Fund at December 31, 2008 and 2007, by asset category are as follows:
| | | Percentage of Plan Assets at December 31, | |
| Asset Category: | | 2008 | | | 2007 | |
| | | | | | | |
| Cash and cash equivalents | | | 89 | % | | | 9 | % |
| Equity common trust funds | | | - | | | | 65 | % |
| Fixed income common trust funds | | | 11 | % | | | 25 | % |
| Real estate | | | - | | | | 1 | % |
| Total | | | 100 | % | | | 100 | % |
The Company does not have a definitive target for the percentage allocation of assets within the plan. Management reviews the earnings on plan assets each year and assesses portfolio asset allocation along with risk and expected returns. After this review, and in connection with terminating the plan, management directed the trustee to revise the asset allocation as shown above. The trustee has the following investment powers:
| · | except for limitations on investing Fund assets in Company securities or real property, the trustee may invest and reinvest in any property, real, personal or mixed, wherever situated, including, without limitation, common and preferred stocks, bonds, notes, debentures, mutual funds, leaseholds, mortgages, certificates of deposit, and oil, mineral or gas properties, royalties, interests or rights; |
| · | to make commingled, collective or common investments and to invest or reinvest all or any portion of the pension plan assets with funds of other pension and profit sharing trusts exempt from tax under section 501(a) of the Internal Revenue Code; and |
| · | to deposit or invest all or a part of the Fund in savings accounts, certificates of deposit or other deposits which bear a reasonable rate of interest in a bank or similar financial institution, including the commercial department of the trustee. |
| 11. | Fair Value Measurement |
FAS No. 157 establishes a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy is based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date. The three levels are defined as follows:
Level 1 – inputs to the valuation methodology are quoted prices (unadjusted) for identical assets or liabilities in active markets.
Level 2 – inputs to the valuation methodology include quoted prices for similar assets and liabilities in active markets, and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial instrument.
Level 3 – inputs to the valuation methodology are unobservable and significant to the fair value measurement.
A financial instrument’s categorization within the valuation hierarchy is based upon the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the asset or liability.
The following table presents information about the Company’s assets and liabilities measured at fair value on a recurring basis as of December 31, 2008, and indicates the fair value hierarchy of the valuation techniques utilized by the Company to determine such fair value (in thousands):
| Description | | Level 1 | | | Level 2 | | | Level 3 | | | Total | |
| Derivative assets | | $ | 8,584 | | | $ | - | | | $ | - | | | $ | 8,584 | |
As of December 31, 2008, the Company’s derivative contracts giving rise to the assets measured under Level 1 are NYMEX crude oil contracts and thus are valued using quoted market prices at the end of each period. The Company’s crude call options that relate to lease crude purchases, which at December 31, 2008, had no value, are measured under Level 3, meaning that it provides a reconciliation of the beginning and ending balances of the Company’s Level 3 derivative asset crude call options for the year ended December 31, 2008 (in thousands):
| | | | |
| Derivative asset balance as of January 1, 2008 | | $ | - | |
| Net increase in derivative assets | | | 437 | |
| Net settlements | | | (437 | ) |
| Transfers in (out) of Level 3 | | | - | |
| Derivative asset balance as of December 31, 2008 | | $ | - | |
The fair value of the Company’s Senior Notes was estimated based on quotations obtained from broker-dealers who make markets in these and similar securities. At December 31, 2008 and 2007, the carrying amounts of the Company’s 6.625% Senior Notes were $150.0 million and $150.0 million, and the estimated fair values were $135.8 million and $150.0 million, respectively. At December 31, 2008, the carrying amount of the Company’s 8.5% Senior Notes, issued September 17, 2008, was $197.2 million ($200.0 million less the unamortized discount of $2.8 million) and the estimated fair value was $176.5 million. For cash and cash equivalents, trade receivables, inventory and accounts payable, the carrying amount is a reasonable estimate of fair value.
| 12. | Commitments and Contingencies |
Lease and Other Commitments
In connection with the acquisition of the El Dorado Refinery, the Company entered into an operating sublease agreement with Shell for the use of the cogeneration facility at the El Dorado Refinery. The non-cancelable operating sublease, which has both a fixed and a variable component, expires in 2016, although the Company has the option to renew the sublease for an additional eight years. At the end of the renewal period, the Company has the option to purchase the cogeneration facility for the greater of fair value or $22.3 million. The Company also has building, equipment, aircraft and vehicle operating leases that expire from 2009 through 2017. Operating lease rental expense was approximately $13.2 million, $13.6 million and $13.8 million for the years ended December 31, 2008, 2007 and 2006, respectively. The approximate future minimum lease payments for operating leases as of December 31, 2008 were $13.0 million for 2009, $12.3 million for 2010, $9.9 million for 2011, $6.5 million for 2012, $6.3 million for 2013 and $17.0 million thereafter.
The Company has commitments for crude oil pipeline capacity on four pipelines (see below) totaling approximately $34.0 million in 2009, an average of $33.6 million for each of the years 2010 through 2012, an average of $27.6 million for each of the years 2013 through 2015, and an average of $10.2 million for each of the years 2016 and 2017. The Company incurred expenses under these commitments of $41.1 million, $16.0 million and $9.8 million for the years ended December 31, 2008, 2007 and 2006, respectively.
The Company has two contracts for crude oil pipeline capacity on the Express Pipeline. The first contract, which began in 1997, is for 15 years and for an average of 13,800 barrels per day (“bpd”) over that 15-year period. In December 2003, the Company entered into an expansion capacity agreement on the Express Pipeline for an additional 10,000 bpd from April 2005 through 2015.
The Company has a Transportation Services Agreement (“Agreement”) to transport 38,000 bpd of crude oil based on filed tariffs on the Spearhead Pipeline from Griffith, Indiana to Cushing, Oklahoma (“Cushing”). This pipeline enables the Company to transport Canadian crude oil to the El Dorado Refinery. The initial term of this Agreement is until 2016, although the Company has the right to extend the Agreement for an additional ten-year term and increase the volume transported.
The Company entered into a definitive agreement with Rocky Mountain Pipeline System LLC, now owned by Plains All American Pipeline, L.P. (“Plains All American”), on March 31, 2006 to support construction of a new crude pipeline from Guernsey, Wyoming to Rocky Mountain’s Fort Laramie, Wyoming tank farm and then to the Cheyenne Refinery. The Company made a ten-year commitment to ship 35,000 bpd based on a filed tariff on the new pipeline and will concurrently lease approximately 300,000 barrels of dedicated storage capacity in the Plains All American tank farm. The pipeline, which is designed to transport 55,000 bpd of heavy crude and is expandable to 90,000 bpd, first transported crude oil in October 2007.
The Company entered into an agreement with Osage Pipeline in 2007 to ship additional crude oil volumes from Cushing, Oklahoma to its El Dorado Refinery. The annual average increased commitment of 7,500 bpd commenced in July 2008 with a term of five years.
In 2006, the Company’s subsidiary, Frontier Oil and Refining Company (“FORC”), entered into a Master Crude Oil Purchase and Sale Contract (“Contract”) with Utexam Limited (“Utexam”), a wholly-owned subsidiary of BNP Paribas Ireland. Under this $250.0 million Contract, Utexam purchases, transports and subsequently sells crude oil to FORC at locations near Guernsey, Wyoming and Cushing, Oklahoma or other locations as agreed. Under this agreement, Utexam is the owner of record of the crude oil as it is transported from the point of injection, typically Hardisty, Alberta, Canada, to the point of ultimate sale to FORC. The Company has provided a guarantee of FORC’s obligations under this Contract, primarily to receive crude oil and make payment for crude oil purchases arranged under this Contract. The Company accounts for the transactions under this Contract as a financing arrangement, whereby the inventory and the associated liability are recorded in the Company’s financial statements when the crude oil is injected into the pipeline in Canada. As of December 31, 2008, FORC and Utexam had entered into certain commitments to purchase and sell crude oil in January 2009 under this Contract; however, neither party has a continuing commitment to purchase or sell crude oil in the future.
Litigation
Beverly Hills Lawsuits. Following summary judgment rulings by the Los Angeles Superior Court in favor of Frontier Oil Corporation and Wainoco Oil & Gas Company in 2006, the Company announced in October 2007 that it had reached agreement in principle on the terms of a settlement with the attorneys for the plaintiffs in the Beverly Hills lawsuits. The Beverly Hills lawsuits were initiated in April 2003 when a law firm began filing claims against the Beverly Hills Unified School District and the City of Beverly Hills on behalf of former students, school employees, area residents and others alleging that emissions from an oil field and a heating and cooling production facility caused cancers or various other health problems in those individuals. Wainoco Oil & Gas Company, the Frontier subsidiary that owned and operated the production facilities from 1985 to 1995, and Frontier were named in seven such suits: Moss et al. v. Venoco, Inc. et al., filed in June 2003; Ibraham et al. v. City of Beverly Hills et al., filed in July 2003; Yeshoua et al. v. Venoco, Inc. et al., filed in August 2003; Jacobs v. Wainoco Oil & Gas Company et al., filed in December 2003; Bussel et al. v. Venoco, Inc. et al., filed in January 2004; Steiner et al. v. Venoco, Inc. et al., filed in May 2004; and Kalcic et al. v. Venoco, Inc. et al., filed in April 2005. Under the terms of the settlement, which was approved by the Los Angeles Superior Court in December 2008, all of the plaintiffs, except one, who named Frontier Oil Corporation and/or Wainoco Oil & Gas Company as defendants will receive a total of $10.0 million from the Company, its subsidiary and its insurance provider in exchange for either a dismissal with prejudice and/or a complete release from all of their existing and future claims. The attorneys for the plaintiffs received the $10.0 million on January 15, 2009. Frontier’s share of the cost of the settlement was approximately $6.3 million, which was funded from the Company’s commutation account that had previously been established with an insurance provider. Frontier had accrued the $10.0 million settlement as of December 31, 2008 and 2007, (“Accrued liabilities and other” on the Consolidated Balance Sheets) and a receivable from insurance providers of $3.7 million (included in “Other receivables” on the Consolidated Balance Sheets). As a result of the court’s orders, only one claim against Wainoco Oil & Gas Company is pending, and the orders do not affect unresolved indemnity claims asserted by or against Frontier Oil Corporation.
The loss mitigation insurance policy purchased in October 2003 covers the settled claims described above and any similar claims asserted during the five-year period following the policy’s commencement date, whether asserted directly against the insured parties or as a result of contractual indemnity. The Company is continuing to pursue coverage efforts and settlements from the insurance companies that provided policies to Frontier during the 1985 to 1995 period.
Frontier does not believe that any potential future claims or litigation, by which similar or related claims may be asserted against the Company or its subsidiary, will result in any material liability or have any material adverse effect upon the Company.
Other. The Company is also involved in various other lawsuits and Occupational Safety and Health Administration (“OSHA”) regulatory actions which are incidental to its business. In management’s opinion, the adverse determination of such lawsuits would not have a material adverse effect on the Company’s liquidity, financial position or results of operations. The Company paid a penalty in January 2009 of $102,000 (which was accrued at December 31, 2008) in connection with citations issued by OSHA alleging violations of applicable process safety management standards at the El Dorado Refinery.
Concentration of Credit Risk
The Company has concentrations of credit risk with respect to sales within the same or related industries and within limited geographic areas. The Company sells its Cheyenne Refinery products exclusively at wholesale, principally to independent retailers and major oil companies located primarily in the Denver, Colorado, western Nebraska and eastern Wyoming regions. The Company sells a majority of its El Dorado Refinery gasoline, diesel and jet fuel to Shell at market-based prices under a 15-year offtake agreement executed in conjunction with the purchase of the El Dorado Refinery in 1999. Beginning in 2000, the Company retained and marketed 5,000 bpd of the El Dorado Refinery’s gasoline and diesel production. The retained portion is scheduled to increase by 5,000 bpd each year for ten years. In 2008, the Company entered into an amendment to the offtake agreement that allowed the Company to retain an additional 10,000 bpd of diesel production due to the Coker expansion project and improved Refinery efficiencies. In 2008, Frontier retained and marketed 55,000 bpd of the El Dorado Refinery’s gasoline and diesel production. Shell has also agreed to purchase all jet fuel production from the El Dorado Refinery through the offtake agreement term. The Company retains and markets all by-products produced from the El Dorado Refinery. The Company made sales to Shell of approximately $2.3 billion, $2.2 billion and $2.1 billion in the years 2008, 2007 and 2006, respectively, which accounted for 37%, 42% and 44% of consolidated refined products revenues in 2008, 2007 and 2006, respectively.
The Company extends credit to its customers based on ongoing credit evaluations. An allowance for doubtful accounts is provided based on the current evaluation of each customer’s credit risk, past experience and other factors. No bad debts were recorded in the year ended December 31, 2008. For the year ended December 31, 2007, $198,000 of previously written off bad debts was collected. A bad debt loss of $26,000 was recorded in the year ended December 31, 2006.
Environmental
The Company’s operations and many of its manufactured products are specifically subject to certain requirements of the Clean Air Act (“CAA”) and related state and local regulations. The 1990 amendments to the CAA contain provisions that will require capital expenditures for the production of cleaner transportation fuels and the installation of certain air pollution control devices at the Refineries during the next several years.
The Environmental Protection Agency (“EPA”) has promulgated regulations requiring the phase-in of gasoline sulfur standards, which began January 1, 2004 and continue through 2008, with special provisions for small business refiners such as Frontier. As allowed by subsequent regulation, Frontier elected to extend its small refinery interim gasoline sulfur standard at each of the Refineries until January 1, 2011 by complying with the highway ultra low sulfur diesel standard by June 2006. The Cheyenne Refinery has spent approximately $28.9 million (including capitalized interest) to meet the interim gasoline sulfur standard, which was required by January 1, 2004. To meet final federal gasoline sulfur standards, the Company expects to spend $22.0 million for new process unit capacity and intermediate inventory handling equipment at the Cheyenne Refinery. In addition, new federal benzene regulations and anticipated state requirements for reduction in gasoline Reid Vapor Pressure (“RVP”) suggest that additional capital expenditures may be required for environmental compliance projects. The Company is presently estimating the total cost in connection with an overall compliance strategy for the Cheyenne Refinery. Total capital expenditures estimated as of December 31, 2008 for the El Dorado Refinery to comply with the final gasoline sulfur standard are approximately $91.0 million, including capitalized interest, and are expected to be incurred by the end of 2009. As of December 31, 2008, $36.6 million of the estimated $91.0 million had been incurred. Substantially all of the estimated $91.0 million of expenditures relates to the El Dorado Refinery’s gasoil hydrotreater revamp project. The gasoil hydrotreater revamp project will address most of the El Dorado Refinery’s modifications needed to achieve gasoline sulfur compliance.
The Company is a significant holder of gasoline sulfur credits; some retained from prior generation years and others generated from operations during 2008 at both the Cheyenne and the El Dorado Refineries. During the year ended December 31, 2008, Frontier sold 38.9 billion (ppm-gallons) sulfur credits for total proceeds of $4.6 million, which was recorded in “Other revenues” on the Consolidated Statements of Income. During the years ended December 31, 2007 and 2006, the Company sold $4.8 million (34.7 billion (ppm-gallons)) and $1.5 million (10.0 billion (ppm-gallons)) of sulfur credits, respectively, also included in “Other revenues” on the Consolidated Statements of Income.
The EPA has embarked on a Petroleum Refining Initiative (“Initiative”) alleging industry-wide noncompliance with certain longstanding regulatory programs. These programs are:
| | • | New Source Review (“NSR”) – a program requiring permitting of certain facility modifications, |
| | • | New Source Performance Standards – a program establishing emission standards for new emission sources as defined in the regulations, |
| | • | Benzene Waste National Elimination System for Hazardous Air Pollutants (“NESHAPS”) – a program limiting the amount of benzene allowable in industrial wastewaters, and |
| | • | Leak Detection and Repair (“LDAR”) – a program designed to control hydrocarbon emissions from refinery pipes, pumps and valves. |
The Initiative has caused many refiners to enter into consent decrees typically requiring substantial expenditures for penalties and the installation of additional pollution control equipment. The Company’s settlement negotiations with the EPA and state regulatory agencies regarding the Initiative were completed in December 2008. Final settlement agreements have been signed by each Refinery and forwarded to the Department of Justice for signature by the EPA, the Kansas Department of Health and Environment and the Wyoming Department of Environmental Quality. The Company expects the final settlement agreement to be filed with the Court during the first quarter of 2009, absent adverse public comment. The Company now estimates that, in addition to the flare gas recovery systems previously installed at each facility in anticipation of the finalization of the agreement, capital expenditures totaling approximately $57.0 million at the Cheyenne Refinery and $10.0 million at the El Dorado Refinery will need to be incurred prior to 2017. The Company may also choose to incur additional costs at the Cheyenne Refinery and at the El Dorado Refinery to comply with certain requirements of the agreement if such projects are determined to be the most cost effective compliance strategy. Notwithstanding these anticipated regulatory settlements, many of these same expenditures would be required for the Company to comply with preexisting regulatory requirements or to implement its planned facility expansions. As an example, a preexisting regulation known as Maximum Achievable Control Technology II (“MACT II”) will require the installation of a particulate scrubber at the El Dorado facility at an estimated cost of $34.0 million. Consequently, the costs associated with this project and other more minor projects are not included in the totals above. In addition to the capital costs described above, the EPA has proposed a civil penalty in the amount of $1.9 million, to be discounted for a related $96,000 penalty and associated supplemental environment project (“SEP”) paid to the State of Wyoming in 2005 and further offset by $902,000 for the completion of additional mutually agreed SEPs. The EPA has also attached to this settlement resolution an enforcement action against the Company’s El Dorado Refinery related to allegations of violation of certain requirements of the EPA Risk Management Program (“RMP”). Negotiated civil penalties regarding resolution of this issue will total approximately $484,000 to be reduced to $358,000 by completion of an approved SEP. The Company has made accruals for the balance of these estimated penalties at December 31, 2008 and December 31, 2007.
The EPA has promulgated regulations to enact the provisions of the Energy Policy Act of 2005 regarding mandated blending of renewable fuels in gasoline. The Energy Independence and Security Act of 2007 significantly increases the amount of renewable fuels that had been required by the 2005 legislation. The Company, as a small refiner, will be exempt until 2012 from these requirements. The Company does have blending facilities and purchases ethanol with Renewable Identification Numbers (RINs) credits attached. Ethanol RINs were created to assist in tracking the compliance with these EPA regulations for the blending of renewable fuels. In 2008, the Company sold approximately 70.5 million RIN gallons for $4.5 million, which was recorded in “Other revenues” on the Consolidated Statements of Income. The Company had available to sell approximately 10.8 million RIN gallons at December 31, 2008.
While not yet enacted or promulgated, other pending legislation or regulation regarding the mandated use of alternative or renewable fuels and/or the reduction of greenhouse gas emissions from either transportation fuels or manufacturing processes is under consideration by the U.S. Congress and certain federal regulatory agencies. If enacted or promulgated, these requirements may impact the operations of the Company.
On February 26, 2007, the EPA promulgated regulations limiting the amount of benzene in gasoline. These regulations take effect for large refiners on January 1, 2011 and for small refiners, such as Frontier, on January 1, 2015. While not yet estimated, the Company anticipates that potentially material capital expenditures may be necessary to achieve compliance with the new regulation at its Cheyenne Refinery as discussed above. Gasoline manufactured at the El Dorado Refinery typically contains benzene concentrations near the new standard. The Company therefore believes that necessary benzene compliance expenditures at the El Dorado Refinery will be substantially less than those at its Cheyenne Refinery.
As is the case with companies engaged in similar industries, the Company faces potential exposure from future claims and lawsuits involving environmental matters, including soil and water contamination, air pollution, personal injury and property damage allegedly caused by substances that the Company may have manufactured, handled, used, released or disposed.
Cheyenne Refinery. The Company is party to an agreement with the State of Wyoming requiring investigation and interim remediation actions at the Cheyenne Refinery’s property that may have been impacted by past operational activities. As a result of past and ongoing investigative efforts, capital expenditures and remediation of conditions found to exist have already taken place, including the completion of surface impoundment closures, waste stabilization activities and other site remediation projects. In addition, the Company estimates that an ongoing groundwater remediation program will be required for approximately ten more years. As of December 31, 2008 and 2007, the Company had a $5.0 million accrual included on the Consolidated Balance Sheets related to the remediation program, reflecting the estimated present value of a $450,000 cost in 2009 and $700,000 in annual costs for 2010 through 2018, assuming a 3% inflation rate and discounted at a rate of 7.5%. The Company also had accrued a total of $4.7 million, as of December 31, 2008, and $4.8 million, as of December 31, 2007, for the cleanup of a waste water treatment pond located on land adjacent to the Cheyenne Refinery which the Company had historically leased from the landowner. The lease expired, and the Company ceased use of the pond on June 30, 2006. The waste water pond will be cleaned up pursuant to the aforementioned agreement with the State of Wyoming. Depending upon the results of the ongoing investigation, or by a subsequent administrative order or permit, additional remedial action and costs could be required. Pursuant to this agreement, the Company has also committed to the installation of a groundwater boundary control system to be constructed in 2009. The Company has estimated the capital cost of the boundary control system at approximately $10.0 million.
The Company has completed the negotiation of a settlement of a Notice of Violation (“NOV”) from the Wyoming Department of Environmental Quality alleging non-compliance with certain refinery waste management requirements. A negotiated penalty in the amount of $631,000 was paid in 2007 as part of the settlement of this NOV. The Company has estimated that the minimum capital cost for required corrective measures will be approximately $2.7 million. In addition, the Company had accruals of $995,000 at December 31, 2008 and $1.2 million at December 31, 2007 for additional work related to the corrective measures. The Company has also negotiated settlements regarding various NOVs from the Wyoming Department of Environmental Quality for certain alleged solid and hazardous waste violations noted during site inspection. The administrative settlement agreement to satisfy alleged solid and hazardous waste violations specifies a civil penalty of approximately $460,000. Negotiation of a settlement agreement regarding alleged wastewater discharge violations has been completed and was signed in January 2009. The agreement will require payment of $650,000 as a civil penalty and completion of certain Supplemental Environment Projects (“SEPs”) at a cost of $200,000, which were accrued as of December 31, 2008.
Pursuant to an agreement with the City of Cheyenne, the Company will contribute $1.5 million toward a project (estimated to be completed in 2009) to relocate a city storm water conveyance pipe, which is presently located on Refinery property and therefore is potentially subject to contaminants from Refinery operations.
El Dorado Refinery. The El Dorado Refinery is subject to a 1988 consent order with the Kansas Department of Health and Environment (“KDHE”). Subject to the terms of the purchase and sale agreement for the El Dorado Refinery entered into between the Company and Shell Oil Products US (“Shell”), Shell is responsible for the costs of continued compliance with this order. This order, including various subsequent modifications, requires the El Dorado Refinery to continue the implementation of a groundwater management program with oversight provided by the KDHE Bureau of Environmental Remediation. More specifically, the El Dorado Refinery must continue to operate the hydrocarbon recovery well systems and containment barriers at the site and conduct sampling from monitoring wells and surface water stations. Quarterly and annual reports must also be submitted to the KDHE. The order requires that remediation activities continue until KDHE-established groundwater criteria or other criteria agreed to by the KDHE and the Refinery are met.
Other Future Environmental Considerations. Recent scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases” and including carbon dioxide and methane, may be contributing to warming of the Earth’s atmosphere. In response to such studies, the U.S. Congress has been actively considering legislation to reduce emissions of greenhouse gases, primarily through the development of greenhouse gas cap and trade programs that would require obtaining and surrendering emission allowances. It is possible that the Company could be required to purchase and surrender allowances, either for greenhouse gas emissions resulting from its operations or from combustion of fuels that it produces. In addition, more than one-third of the states already have begun implementing legal measures to reduce emissions of greenhouse gases. On April 2, 2007, the U.S. Supreme Court in Massachusetts, et al. v. EPA held that carbon dioxide may be regulated as an “air pollutant” under the federal Clean Air Act and that the EPA must consider whether it is required to regulate greenhouse gas emissions from mobile sources such as cars and trucks. In July 2008, the EPA released an Advance Notice of Proposed Rulemaking regarding possible future regulation of greenhouse gas emissions under the Clean Air Act, in response to the Supreme Court’s decision in Massachusetts. In the notice, the EPA evaluated the potential regulation of greenhouse gases under the Clean Air Act and other potential methods of regulating greenhouse gases. Although the notice did not propose any specific, new regulatory requirements for greenhouse gases, it indicates that federal regulation of greenhouse gas emissions could occur in the near future. Thus, there may be restrictions imposed on the emission of greenhouse gases even if the U.S. Congress does not adopt new legislation specifically addressing emissions of greenhouse gases. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address greenhouse gas emissions would impact the Company’s business, any such future laws and regulations could result in increased compliance costs or additional operating restrictions, and could have a material adverse effect on its business, financial condition and results of operations, including demand for the refined petroleum products that it produces.
Collective Bargaining Agreements
The union members at the Cheyenne and El Dorado Refineries, comprising 56% of the Company’s workforce, are represented by seven bargaining units, the largest being the United Steel, Paper and Forestry, Rubber, Manufacturing, Energy, Allied Industrial and Service Workers International Union (“USW”) and the others being affiliated with the AFL-CIO. The El Dorado Refinery current union contract expire in 2012 and the Cheyenne Refinery contracts expire by July 2009.
| 13. | Price Risk Management Activities |
The Company, at times, enters into commodity derivative contracts to manage its price exposure to its inventory positions, purchases of foreign crude oil and consumption of natural gas in the refining process or to fix margins on certain future production. The commodity derivative contracts used by the Company may take the form of futures contracts, collars or price swaps. The Company believes that there is minimal credit risk with respect to its counterparties. The Company accounts for its commodity derivative contracts that do not qualify for hedge accounting under mark-to-market accounting and gains and losses on transactions are reflected in “Other revenues” on the Consolidated Statements of Income for each period. When the derivative contracts are designated as fair value hedges for accounting purposes, under FAS No. 133, “Accounting for Derivative Instruments and Hedging Activities”, the gains or losses are recognized in the related inventory in “Inventory of crude oil, products and other” on the Consolidated Balance Sheets and ultimately, when the inventory is charged or sold, in “Raw material, freight and other costs” on the Consolidated Statements of Income. The Company has derivative contracts which it holds directly and also derivative contracts held on Frontier’s behalf by Utexam, in connection with the Master Crude Oil Purchase and Sale Contract (see Note 12 “Lease and Other Commitments”). The market value of open derivative contracts is included on the Consolidated Balance Sheets in “Other current assets” when the unrealized value is a gain ($8.6 million at December 31, 2008), or in “Accrued liabilities and other” when the unrealized value is a loss ($15.1 million at December 31, 2007).
Trading Activities
During 2008, 2007 and 2006, the Company had the following derivative activities which, while economic hedges, were not accounted for as hedges and whose gains or losses are reflected in “Other revenues” on the Consolidated Statements of Income:
Crude Purchases. As of December 31, 2008, the Company had no open derivative contracts held on Frontier’s behalf by Utexam on barrels of crude oil to hedge in-transit Canadian crude oil costs for the El Dorado Refinery. During the year ended December 31, 2008, the Company reported in “Other revenues” an $18.8 million net realized and unrealized gain on positions to hedge in-transit crude oil, mainly Canadian crude oil for the El Dorado Refinery. During the years ended December 31, 2007 and 2006, the Company reported in “Other revenues” an $18.0 million net loss and a $14.6 million net gain, respectively, on positions to hedge in-transit Canadian crude oil for the El Dorado Refinery.
Derivative contracts on barrels of crude oil to hedge excess intermediate, finished product and crude oil inventory for both the Cheyenne and El Dorado Refineries. As of December 31, 2008, the Company had open derivative contracts on 2,795,000 barrels of crude oil to hedge crude oil, intermediate or finished product inventory. At December 31, 2008, these positions had unrealized gains of $8.5 million. During the year ended December 31, 2008, the Company reported in “Other revenues” $127.7 million in net realized and unrealized gains on these types of positions. During the years ended December 31, 2007 and 2006, the Company recorded a $68.4 million loss and a $15.9 million gain, respectively, on these types of positions.
Hedging Activities
During the years ended December 31, 2008 and 2007, the Company had no derivatives which were accounted for as hedges. During the year ended December 31, 2006, the Company had the following derivatives which were appropriately designated and accounted for as fair value hedges.
Crude purchases in-transit. During the year ended December 31, 2006, the Company recorded $10.9 million in net losses on derivative contracts to hedge in-transit Canadian crude oil, primarily for the El Dorado Refinery, of which $15.0 million increased crude costs (“Raw material, freight and other costs”) and $4.1 million increased income, which was reflected in “Other revenues” in the Consolidated Statements of Income for the ineffective portion of these hedges.
| 14. | Consolidating Financial Statements |
Frontier Holdings Inc. and its subsidiaries (“FHI”) are full and unconditional guarantors of the Company’s 6.625% Senior Notes. In addition, on September 15, 2008 the Company issued 8.5% Senior Notes in which Frontier Holdings Inc. and its material subsidiaries are full and unconditional guarantors. Presented on the following pages are the Company’s consolidating balance sheets, statements of operations, and cash flows as required by Rule 3-10 of Regulation S-X of the Securities Exchange Act of 1934, as amended. As specified in Rule 3-10, the condensed consolidating balance sheets, statement of operations, and cash flows presented below meet the requirements for financial statements of the issuer and each guarantor of the notes because the guarantors are all direct or indirect 100% owned subsidiaries of Frontier, and all of the guarantees are full and unconditional on a joint and several basis. The Company files a consolidated U.S. federal income tax return and consolidated state income tax returns in the majority of states in which it does business. Accordingly, the equity in earnings of subsidiaries recorded for Frontier Oil Corporation is equal to the subsidiaries’ net income adjusted for consolidating pre-tax adjustments and for the portion of the subsidiaries’ income tax provision which is eliminated in consolidation.
The presentation of intercompany dividends and income taxes received by FOC (parent) from subsidiaries in the 2006 and 2007 consolidating statements of cash flows has been changed from a financing activity to an operating activity. The presentation of intercompany income taxes paid by subsidiaries to parent in the 2006 and 2007 consolidating statements of cash flows has been changed from a financing activity to an operating activity. Additionally, other intercompany transactions between parent and subsidiaries has been changed from a financing activity to an operating activity in the 2006 and 2007 consolidating statements of cash flows.
| CONSOLIDATING FINANCIAL STATEMENTS | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
| FRONTIER OIL CORPORATION | |
| Condensed Consolidating Statement of Income | |
| For the Year Ended December 31, 2008 | |
| (in thousands) | |
| | | FOC (Parent) | | | FHI (Guarantor Subsidiaries) | | | Other Non-Guarantor Subsidiaries | | | Eliminations | | | Consolidated | |
| Revenues: | | | | | | | | | | | | | | | |
| Refined products | | $ | - | | | $ | 6,342,144 | | | $ | - | | | $ | - | | | $ | 6,342,144 | |
| Other | | | (7 | ) | | | 156,287 | | | | 356 | | | | - | | | | 156,636 | |
| | | | (7 | ) | | | 6,498,431 | | | | 356 | | | | - | | | | 6,498,780 | |
| | | | | | | | | | | | | | | | | | | | | |
| Costs and expenses: | | | | | | | | | | | | | | | | | | | | |
Raw material, freight and other costs | | | - | | | | 5,950,782 | | | | - | | | | - | | | | 5,950,782 | |
Refinery operating expenses, excluding depreciation | | | - | | | | 321,364 | | | | - | | | | - | | | | 321,364 | |
Selling and general expenses, excluding depreciation | | | 17,677 | | | | 26,492 | | | | - | | | | - | | | | 44,169 | |
Depreciation, amortization and accretion | | | 55 | | | | 65,409 | | | | - | | | | 292 | | | | 65,756 | |
| Gains on sales of assets | | | (37 | ) | | | (7 | ) | | | - | | | | - | | | | (44 | ) |
| | | | 17,695 | | | | 6,364,040 | | | | - | | | | 292 | | | | 6,382,027 | |
| | | | | | | | | | | | | | | | | | | | | |
| Operating income (loss) | | | (17,702 | ) | | | 134,391 | | | | 356 | | | | (292 | ) | | | 116,753 | |
| | | | | | | | | | | | | | | | | | | | | |
Interest expense and other financing costs | | | 15,939 | | | | 5,570 | | | | - | | | | (6,379 | ) | | | 15,130 | |
| Interest and investment income | | | (2,868 | ) | | | (2,557 | ) | | | - | | | | - | | | | (5,425 | ) |
Equity in earnings of subsidiaries | | | (137,139 | ) | | | - | | | | - | | | | 137,139 | | | | - | |
| | | | (124,068 | ) | | | 3,013 | | | | - | | | | 130,760 | | | | 9,705 | |
| | | | | | | | | | | | | | | | | | | | | |
| Income before income taxes | | | 106,366 | | | | 131,378 | | | | 356 | | | | (131,052 | ) | | | 107,048 | |
| Provision for income taxes | | | 26,132 | | | | 38,407 | | | | 139 | | | | (37,864 | ) | | | 26,814 | |
| Net income | | $ | 80,234 | | | $ | 92,971 | | | $ | 217 | | | $ | (93,188 | ) | | $ | 80,234 | |
| FRONTIER OIL CORPORATION | |
| Condensed Consolidating Statement of Income | |
| For the Year Ended December 31, 2007 | |
| (in thousands) | |
| | | FOC (Parent) | | | FHI (Guarantor Subsidiaries) | | | Other Non-Guarantor Subsidiaries | | | Eliminations | | | Consolidated | |
| Revenues: | | | | | | | | | | | | | | | |
| Refined products | | $ | - | | | $ | 5,269,674 | | | $ | - | | | $ | - | | | $ | 5,269,674 | |
| Other | | | 2 | | | | (80,981 | ) | | | 45 | | | | - | | | | (80,934 | ) |
| | | | 2 | | | | 5,188,693 | | | | 45 | | | | - | | | | 5,188,740 | |
| | | | | | | | | | | | | | | | | | | | | |
| Costs and expenses: | | | | | | | | | | | | | | | | | | | | |
Raw material, freight and other costs | | | - | | | | 4,039,235 | | | | - | | | | - | | | | 4,039,235 | |
Refinery operating expenses, excluding depreciation | | | - | | | | 300,542 | | | | - | | | | - | | | | 300,542 | |
Selling and general expenses, excluding depreciation | | | 30,593 | | | | 24,750 | | | | - | | | | - | | | | 55,343 | |
Depreciation, amortization and accretion | | | 61 | | | | 53,299 | | | | - | | | | (321 | ) | | | 53,039 | |
| Loss (gain) on sales of assets | | | 2,028 | | | | (17,242 | ) | | | - | | | | - | | | | (15,214 | ) |
| | | | 32,682 | | | | 4,400,584 | | | | - | | | | (321 | ) | | | 4,432,945 | |
| | | | | | | | | | | | | | | | | | | | | |
| Operating income (loss) | | | (32,680 | ) | | | 788,109 | | | | 45 | | | | 321 | | | | 755,795 | |
| | | | | | | | | | | | | | | | | | | | | |
Interest expense and other financing costs | | | 12,723 | | | | 4,122 | | | | - | | | | (8,072 | ) | | | 8,773 | |
| Interest and investment income | | | (11,202 | ) | | | (10,649 | ) | | | - | | | | - | | | | (21,851 | ) |
Equity in earnings of subsidiaries | | | (802,362 | ) | | | - | | | | - | | | | 802,362 | | | | - | |
| | | | (800,841 | ) | | | (6,527 | ) | | | - | | | | 794,290 | | | | (13,078 | ) |
| | | | | | | | | | | | | | | | | | | | | |
| Income before income taxes | | | 768,161 | | | | 794,636 | | | | 45 | | | | (793,969 | ) | | | 768,873 | |
| Provision for income taxes | | | 269,036 | | | | 279,174 | | | | 15 | | | | (278,477 | ) | | | 269,748 | |
| Net income | | $ | 499,125 | | | $ | 515,462 | | | $ | 30 | | | $ | (515,492 | ) | | $ | 499,125 | |
| FRONTIER OIL CORPORATION | |
| Condensed Consolidating Statement of Income | |
| For the Year Ended December 31, 2006 | |
| (in thousands) | |
| | | FOC (Parent) | | | FHI (Guarantor Subsidiaries) | | | Other Non-Guarantor Subsidiaries | | | Eliminations | | | Consolidated | |
| Revenues: | | | | | | | | | | | | | | | |
| Refined products | | $ | - | | | $ | 4,759,661 | | | $ | - | | | $ | - | | | $ | 4,759,661 | |
| Other | | | 4 | | | | 36,146 | | | | 142 | | | | - | | | | 36,292 | |
| | | | 4 | | | | 4,795,807 | | | | 142 | | | | - | | | | 4,795,953 | |
| | | | | | | | | | | | | | | | | | | | | |
| Costs and expenses: | | | | | | | | | | | | | | | | | | | | |
| Raw material, freight and other costs | | | - | | | | 3,850,937 | | | | - | | | | - | | | | 3,850,937 | |
Refinery operating expenses, excluding depreciation | | | - | | | | 277,129 | | | | - | | | | - | | | | 277,129 | |
Selling and general expenses, excluding depreciation | | | 30,194 | | | | 22,294 | | | | - | | | | - | | | | 52,488 | |
Depreciation, amortization and accretion | | | 88 | | | | 41,502 | | | | - | | | | (377 | ) | | | 41,213 | |
| Gain on sales of assets | | | (8 | ) | | | - | | | | - | | | | - | | | | (8 | ) |
| | | | 30,274 | | | | 4,191,862 | | | | - | | | | (377 | ) | | | 4,221,759 | |
| | | | | | | | | | | | | | | | | | | | | |
| Operating income (loss) | | | (30,270 | ) | | | 603,945 | | | | 142 | | | | 377 | | | | 574,194 | |
| | | | | | | | | | | | | | | | | | | | | |
Interest expense and other financing costs | | | 11,978 | | | | 3,835 | | | | - | | | | (3,674 | ) | | | 12,139 | |
| Interest and investment income | | | (12,102 | ) | | | (5,957 | ) | | | - | | | | - | | | | (18,059 | ) |
| Equity in earnings of subsidiaries | | | (609,265 | ) | | | - | | | | - | | | | 609,265 | | | | - | |
| | | | (609,389 | ) | | | (2,122 | ) | | | - | | | | 605,591 | | | | (5,920 | ) |
| | | | | | | | | | | | | | | | | | | | | |
| Income before income taxes | | | 579,119 | | | | 606,067 | | | | 142 | | | | (605,214 | ) | | | 580,114 | |
| Provision for income taxes | | | 199,842 | | | | 209,951 | | | | 55 | | | | (209,011 | ) | | | 200,837 | |
| Net income | | $ | 379,277 | | | $ | 396,116 | | | $ | 87 | | | $ | (396,203 | ) | | $ | 379,277 | |
| FRONTIER OIL CORPORATION | |
| Condensed Consolidating Balance Sheet | |
| As of December 31, 2008 | |
| (in thousands) | |
| | | FOC (Parent) | | | FHI (Guarantor Subsidiaries) | | | Other Non-Guarantor Subsidiaries | | | Eliminations | | | Consolidated | |
| ASSETS | | | | | | | | | | | | | | | |
| Current assets: | | | | | | | | | | | | | | | |
| Cash and cash equivalents | | $ | 254,548 | | | $ | 228,984 | | | $ | - | | | $ | - | | | $ | 483,532 | |
| Trade and other receivables, net | | | 120,265 | | | | 105,169 | | | | 10 | | | | - | | | | 225,444 | |
| Inventory of crude oil, products and other | | | - | | | | 256,129 | | | | - | | | | - | | | | 256,129 | |
| Deferred tax assets | | | 8,841 | | | | 9,034 | | | | - | | | | (9,034 | ) | | | 8,841 | |
| Commutation account | | | 6,319 | | | | - | | | | - | | | | - | | | | 6,319 | |
| Other current assets | | | 643 | | | | 36,395 | | | | | | | | | | | | 37,038 | |
| Total current assets | | | 390,616 | | | | 635,711 | | | | 10 | | | | (9,034 | ) | | | 1,017,303 | |
| | | | | | | | | | | | | | | | | | | | | |
| Property, plant and equipment, at cost | | | 1,248 | | | | 1,295,420 | | | | - | | | | 10,076 | | | | 1,306,744 | |
Accumulated depreciation and amortization | | | (998 | ) | | | (379,967 | ) | | | - | | | | 7,664 | | | | (373,301 | ) |
| Property, plant and equipment, net | | | 250 | | | | 915,453 | | | | - | | | | 17,740 | | | | 933,443 | |
| | | | | | | | | | | | | | | | | | | | | |
| Deferred turnaround costs | | | - | | | | 47,465 | | | | - | | | | - | | | | 47,465 | |
| Deferred catalyst costs | | | - | | | | 9,726 | | | | - | | | | - | | | | 9,726 | |
| Deferred financing costs, net | | | 3,642 | | | | 2,559 | | | | - | | | | - | | | | 6,201 | |
| Intangible assets, net | | | - | | | | 1,338 | | | | - | | | | - | | | | 1,338 | |
| Other assets | | | 2,600 | | | | 393 | | | | - | | | | - | | | | 2,993 | |
Receivable from affiliated companies (1) | | | 646 | | | | 25,733 | | | | 468 | | | | (26,847 | ) | | | - | |
| Investment in subsidiaries | | | 1,235,678 | | | | - | | | | - | | | | (1,235,678 | ) | | | - | |
| Total assets | | $ | 1,633,432 | | | $ | 1,638,378 | | | $ | 478 | | | $ | (1,253,819 | ) | | $ | 2,018,469 | |
| | | | | | | | | | | | | | | | | | | | | |
| LIABILITIES AND SHAREHOLDERS' EQUITY | | | | | | | | | | | | | | | | | |
| Current liabilities: | | | | | | | | | | | | | | | | | | | | |
| Accounts payable | | $ | 1,168 | | | $ | 307,684 | | | $ | 15 | | | $ | - | | | $ | 308,867 | |
| Accrued liabilities and other | | | 26,071 | | | | 31,013 | | | | - | | | | - | | | | 57,084 | |
| Total current liabilities | | | 27,239 | | | | 338,697 | | | | 15 | | | | - | | | | 365,951 | |
| | | | | | | | | | | | | | | | | | | | | |
| Long-term debt | | | 347,220 | | | | - | | | | - | | | | - | | | | 347,220 | |
| Contingent income tax liabilities | | | 26,112 | | | | 1,945 | | | | - | | | | - | | | | 28,057 | |
| Long-term capital lease obligations | | | - | | | | 3,548 | | | | - | | | | - | | | | 3,548 | |
| Other long-term liabilities | | | 2,507 | | | | 40,832 | | | | - | | | | - | | | | 43,339 | |
| Deferred income taxes | | | 179,214 | | | | 174,597 | | | | - | | | | (174,597 | ) | | | 179,214 | |
| Payable to affiliated companies | | | - | | | | 1,114 | | | | 209 | | | | (1,323 | ) | | | - | |
| | | | | | | | | | | | | | | | | | | | | |
| Shareholders' equity | | | 1,051,140 | | | | 1,077,645 | | | | 254 | | | | (1,077,899 | ) | | | 1,051,140 | |
| Total liabilities and shareholders' equity | | $ | 1,633,432 | | | $ | 1,638,378 | | | $ | 478 | | | $ | (1,253,819 | ) | | $ | 2,018,469 | |
| | | | | | | | | | | | | | | | | | | | | |
(1) FHI receivable from affiliated companies balance relates to income taxes receivable from parent under a tax sharing agreement. | |
| FRONTIER OIL CORPORATION | |
| Condensed Consolidating Balance Sheet | |
| As of December 31, 2007 | |
| (in thousands) | |
| | | FOC (Parent) | | | FHI (Guarantor Subsidiaries) | | | Other Non-Guarantor Subsidiaries | | | Eliminations | | | Consolidated | |
| ASSETS | | | | | | | | | | | | | | | |
| Current assets: | | | | | | | | | | | | | | | |
| Cash and cash equivalents | | $ | 186,368 | | | $ | 111,031 | | | $ | - | | | $ | - | | | $ | 297,399 | |
| Trade and other receivables, net | | | 27,948 | | | | 156,798 | | | | - | | | | - | | | | 184,746 | |
| Receivable from affiliated companies | | | - | | | | 2,319 | | | | 296 | | | | (2,615 | ) | | | - | |
| Inventory of crude oil, products and other | | | - | | | | 501,927 | | | | - | | | | - | | | | 501,927 | |
| Deferred tax assets | | | 9,426 | | | | 13,507 | | | | - | | | | (13,507 | ) | | | 9,426 | |
| Commutation account | | | 6,280 | | | | - | | | | - | | | | - | | | | 6,280 | |
| Other current assets | | | 9,646 | | | | 21,599 | | | | - | | | | - | | | | 31,245 | |
| Total current assets | | | 239,668 | | | | 807,181 | | | | 296 | | | | (16,122 | ) | | | 1,031,023 | |
| | | | | | | | | | | | | | | | | | | | | |
| Property, plant and equipment, at cost | | | 1,121 | | | | 1,090,695 | | | | - | | | | 3,627 | | | | 1,095,443 | |
Accumulated depreciation and amortization | | | (943 | ) | | | (325,076 | ) | | | - | | | | 8,026 | | | | (317,993 | ) |
| Property, plant and equipment, net | | | 178 | | | | 765,619 | | | | - | | | | 11,653 | | | | 777,450 | |
| | | | | | | | | | | | | | | | | | | | | |
| Deferred turnaround costs | | | - | | | | 39,276 | | | | - | | | | - | | | | 39,276 | |
| Deferred catalyst costs | | | - | | | | 6,540 | | | | - | | | | - | | | | 6,540 | |
| Deferred financing costs, net | | | 1,810 | | | | 746 | | | | - | | | | - | | | | 2,556 | |
| Intangible assets, net | | | - | | | | 1,460 | | | | - | | | | - | | | | 1,460 | |
| Other assets | | | 4,222 | | | | 1,321 | | | | - | | | | - | | | | 5,543 | |
| Investment in subsidiaries | | | 1,106,243 | | | | - | | | | - | | | | (1,106,243 | ) | | | - | |
| Total assets | | $ | 1,352,121 | | | $ | 1,622,143 | | | $ | 296 | | | $ | (1,110,712 | ) | | $ | 1,863,848 | |
| | | | | | | | | | | | | | | | | | | | | |
| LIABILITIES AND SHAREHOLDERS' EQUITY | | | | | | | | | | | | | | | | | |
| Current liabilities: | | | | | | | | | | | | | | | | | | | | |
| Accounts payable | | $ | 242 | | | $ | 417,153 | | | $ | - | | | $ | - | | | $ | 417,395 | |
| Accrued liabilities and other | | | 25,947 | | | | 57,982 | | | | 189 | | | | - | | | | 84,118 | |
| Total current liabilities | | | 26,189 | | | | 475,135 | | | | 189 | | | | - | | | | 501,513 | |
| | | | | | | | | | | | | | | | | | | | | |
| Long-term debt | | | 150,000 | | | | - | | | | - | | | | - | | | | 150,000 | |
| Contingent income tax liabilities | | | 31,185 | | | | 1,072 | | | | - | | | | - | | | | 32,257 | |
| Long-term capital lease obligations | | | - | | | | 8 | | | | - | | | | - | | | | 8 | |
| Other long-term liabilities | | | 3,208 | | | | 37,938 | | | | - | | | | - | | | | 41,146 | |
| Deferred income taxes | | | 100,310 | | | | 107,652 | | | | - | | | | (107,652 | ) | | | 100,310 | |
| Payable to affiliated companies | | | 2,615 | | | | 3,365 | | | | 70 | | | | (6,050 | ) | | | - | |
| | | | | | | | | | | | | | | | | | | | | |
| Shareholders' equity | | | 1,038,614 | | | | 996,973 | | | | 37 | | | | (997,010 | ) | | | 1,038,614 | |
| Total liabilities and shareholders' equity | | $ | 1,352,121 | | | $ | 1,622,143 | | | $ | 296 | | | $ | (1,110,712 | ) | | $ | 1,863,848 | |
| FRONTIER OIL CORPORATION | |
| Condensed Consolidating Statement of Cash Flows | |
| For the Year Ended December 31, 2008 | |
| (in thousands) | |
| | | | | | | | | | | | | | | | |
| | | FOC (Parent) | | | FHI (Guarantor Subsidiaries) | | | Other Non-Guarantor Subsidiaries | | | Eliminations | | | Consolidated | |
| Cash flows from operating activities: | | | | | | | | | | | | | | | |
| Net income | | $ | 80,234 | | | $ | 92,971 | | | $ | 217 | | | $ | (93,188 | ) | | $ | 80,234 | |
Adjustments to reconcile net income to net cash from operating activities: | | | | | | | | | | | | | |
| Equity in earnings of subsidiaries | | | (137,139 | ) | | | - | | | | - | | | | 137,139 | | | | - | |
| Depreciation, amortization and accretion | | | 55 | | | | 83,224 | | | | - | | | | 292 | | | | 83,571 | |
| Deferred income taxes | | | 80,894 | | | | - | | | | - | | | | - | | | | 80,894 | |
| Stock-based compensation expense | | | 20,014 | | | | - | | | | - | | | | - | | | | 20,014 | |
Excess income tax benefits of stock-based compensation | | | (3,191 | ) | | | - | | | | - | | | | - | | | | (3,191 | ) |
| Intercompany income taxes | | | (6,000 | ) | | | 43,725 | | | | 139 | | | | (37,864 | ) | | | - | |
| Intercompany dividends | | | 10,000 | | | | - | | | | - | | | | (10,000 | ) | | | - | |
| Other intercompany transactions | | | (3,261 | ) | | | 3,433 | | | | (172 | ) | | | - | | | | - | |
| Amortization of debt issuance costs | | | 570 | | | | 408 | | | | - | | | | - | | | | 978 | |
| Senior notes discount amortization | | | 60 | | | | - | | | | - | | | | - | | | | 60 | |
| Allowance for investment loss | | | 41 | | | | 458 | | | | - | | | | - | | | | 499 | |
| Gains on sales of assets | | | (37 | ) | | | (7 | ) | | | - | | | | - | | | | (44 | ) |
Amortization of long-term prepaid insurance | | | 909 | | | | - | | | | - | | | | - | | | | 909 | |
(Decrease) increase in other long- term liabilities | | | (3,716 | ) | | | 543 | | | | - | | | | - | | | | (3,173 | ) |
Changes in deferred turnaround costs, deferred catalyst costs and other | | | 713 | | | | (29,471 | ) | | | - | | | | - | | | | (28,758 | ) |
Changes in components of working capital from operations | | | (80,054 | ) | | | 143,933 | | | | (184 | ) | | | 1,587 | | | | 65,282 | |
Net cash (used in) provided by operating activities | | | (39,908 | ) | | | 339,217 | | | | - | | | | (2,034 | ) | | | 297,275 | |
| | | | | | | | | | | | | | | | | | | | | |
| Cash flows from investing activities: | | | | | | | | | | | | | | | | | | | | |
Additions to property, plant and equipment | | | (129 | ) | | | (201,286 | ) | | | - | | | | (7,966 | ) | | | (209,381 | ) |
| Proceeds from sales of assets | | | 37 | | | | 9 | | | | - | | | | - | | | | 46 | |
El Dorado Refinery contingent earn- out payment | | | - | | | | (7,500 | ) | | | - | | | | - | | | | (7,500 | ) |
| Net cash used in investing activities | | | (92 | ) | | | (208,777 | ) | | | - | | | | (7,966 | ) | | | (216,835 | ) |
| | | | | | | | | | | | | | | | | | | | | |
| Cash flows from financing activities: | | | | | | | | | | | | | | | | | | | | |
Proceeds from issuance of 8.5% Senior Notes | | | 197,160 | | | | - | | | | - | | | | - | | | | 197,160 | |
| Purchase of treasury stock | | | (67,030 | ) | | | - | | | | - | | | | - | | | | (67,030 | ) |
Proceeds from issuance of common stock | | | 405 | | | | - | | | | - | | | | - | | | | 405 | |
| Dividends paid | | | (23,144 | ) | | | - | | | | - | | | | - | | | | (23,144 | ) |
Excess income tax benefits of stock-based compensation | | | 3,191 | | | | - | | | | - | | | | - | | | | 3,191 | |
| Debt issuance costs and other | | | (2,402 | ) | | | (2,487 | ) | | | - | | | | - | | | | (4,889 | ) |
| Intercompany dividends | | | - | | | | (10,000 | ) | | | - | | | | 10,000 | | | | - | |
Net cash provided by (used in) financing activities | | | 108,180 | | | | (12,487 | ) | | | - | | | | 10,000 | | | | 105,693 | |
| Increase in cash and cash equivalents | | | 68,180 | | | | 117,953 | | | | - | | | | - | | | | 186,133 | |
Cash and cash equivalents, beginning of period | | | 186,368 | | | | 111,031 | | | | - | | | | - | | | | 297,399 | |
Cash and cash equivalents, end of period | | $ | 254,548 | | | $ | 228,984 | | | $ | - | | | $ | - | | | $ | 483,532 | |
| FRONTIER OIL CORPORATION | |
| Condensed Consolidating Statement of Cash Flows | |
| For the Year Ended December 31, 2007 | |
| (in thousands) | |
| | | | | | | | | | | | | | | | |
| | | FOC (Parent) | | | FHI (Guarantor Subsidiaries) | | | Other Non-Guarantor Subsidiaries | | | Eliminations | | | Consolidated | |
| Cash flows from operating activities: | | | | | | | | | | | | | | | |
| Net income | | $ | 499,125 | | | $ | 515,462 | | | $ | 30 | | | $ | (515,492 | ) | | $ | 499,125 | |
Adjustments to reconcile net income to net cash from operating activities: | | | | | | | | | | | | | |
| Equity in earnings of subsidiaries | | | (802,362 | ) | | | - | | | | - | | | | 802,362 | | | | - | |
| Depreciation, amortization and accretion | | | 61 | | | | 67,772 | | | | - | | | | (321 | ) | | | 67,512 | |
| Deferred income taxes | | | (1,916 | ) | | | - | | | | - | | | | - | | | | (1,916 | ) |
| Stock-based compensation expense | | | 22,553 | | | | - | | | | - | | | | - | | | | 22,553 | |
Excess income tax benefits of stock-based compensation | | | (6,962 | ) | | | - | | | | - | | | | - | | | | (6,962 | ) |
| Intercompany income taxes | | | 317,500 | | | | (39,038 | ) | | | 15 | | | | (278,477 | ) | | | - | |
| Intercompany dividends | | | 212,150 | | | | - | | | | - | | | | (212,150 | ) | | | - | |
| Other intercompany transactions | | | 1,110 | | | | (1,065 | ) | | | (45 | ) | | | - | | | | - | |
| Amortization of debt issuance costs | | | 483 | | | | 286 | | | | - | | | | - | | | | 769 | |
| Loss (gain) on sales of assets | | | 2,028 | | | | (17,242 | ) | | | - | | | | - | | | | (15,214 | ) |
Decrease in long-term commutation account | | | 1,009 | | | | - | | | | - | | | | - | | | | 1,009 | |
Amortization of long-term prepaid insurance | | | 1,211 | | | | - | | | | - | | | | - | | | | 1,211 | |
Increase (decrease) in other long- term liabilities | | | 31,058 | | | | (3,693 | ) | | | - | | | | - | | | | 27,365 | |
Changes in deferred turnaround costs, deferred catalyst costs and other | | | (578 | ) | | | (28,709 | ) | | | - | | | | - | | | | (29,287 | ) |
Changes in components of working capital from operations | | | (46,639 | ) | | | (88,900 | ) | | | - | | | | (1,613 | ) | | | (137,152 | ) |
Net cash (used in) provided by operating activities | | | 229,831 | | | | 404,873 | | | | - | | | | (205,691 | ) | | | 429,013 | |
| | | | | | | | | | | | | | | | | | | | | |
| Cash flows from investing activities: | | | | | | | | | | | | | | | | | | | | |
Additions to property, plant and equipment | | | (4,310 | ) | | | (280,405 | ) | | | - | | | | (6,459 | ) | | | (291,174 | ) |
| Proceeds from sale of assets | | | 2,290 | | | | 19,932 | | | | - | | | | - | | | | 22,222 | |
El Dorado Refinery contingent earn- out payment | | | - | | | | (7,500 | ) | | | - | | | | - | | | | (7,500 | ) |
Other acquisitions and leasehold improvements | | | - | | | | (3,561 | ) | | | - | | | | - | | | | (3,561 | ) |
| Net cash used in investing activities | | | (2,020 | ) | | | (271,534 | ) | | | - | | | | (6,459 | ) | | | (280,013 | ) |
| | | | | | | | | | | | | | | | | | | | | |
| Cash flows from financing activities: | | | | | | | | | | | | | | | | | | | | |
| Purchase of treasury stock | | | (248,486 | ) | | | - | | | | - | | | | - | | | | (248,486 | ) |
Proceeds from issuance of common stock | | | 2,303 | | | | - | | | | - | | | | - | | | | 2,303 | |
| Dividends paid | | | (17,271 | ) | | | - | | | | - | | | | - | | | | (17,271 | ) |
Excess income tax benefits of stock-based compensation | | | 6,962 | | | | - | | | | - | | | | - | | | | 6,962 | |
| Debt issuance costs and other | | | - | | | | (588 | ) | | | - | | | | - | | | | (588 | ) |
| Intercompany dividends | | | - | | | | (212,150 | ) | | | - | | | | 212,150 | | | | - | |
Net cash provided by (used in) financing activities | | | (256,492 | ) | | | (212,738 | ) | | | - | | | | 212,150 | | | | (257,080 | ) |
| Decrease in cash and cash equivalents | | | (28,681 | ) | | | (79,399 | ) | | | - | | | | - | | | | (108,080 | ) |
Cash and cash equivalents, beginning of period | | | 215,049 | | | | 190,430 | | | | - | | | | - | | | | 405,479 | |
Cash and cash equivalents, end of period | | $ | 186,368 | | | $ | 111,031 | | | $ | - | | | $ | - | | | $ | 297,399 | |
| FRONTIER OIL CORPORATION | |
| Condensed Consolidating Statement of Cash Flows | |
| For the Year Ended December 31, 2006 | |
| (in thousands) | |
| | | | | | | | | | | | | | | | |
| | | FOC (Parent) | | | FHI (Guarantor Subsidiaries) | | | Other Non-Guarantor Subsidiaries | | | Eliminations | | | Consolidated | |
| Cash flows from operating activities: | | | | | | | | | | | | | | | |
| Net income | | $ | 379,277 | | | $ | 396,116 | | | $ | 87 | | | $ | (396,203 | ) | | $ | 379,277 | |
Adjustments to reconcile net income to net cash from operating activities: | | | | | | | | | | | | | |
| Equity in earnings of subsidiaries | | | (609,265 | ) | | | - | | | | - | | | | 609,265 | | | | - | |
| Depreciation, amortization and accretion | | | 88 | | | | 54,677 | | | | - | | | | (377 | ) | | | 54,388 | |
| Deferred income taxes | | | 6,073 | | | | - | | | | - | | | | - | | | | 6,073 | |
| Stock-based compensation expense | | | 18,029 | | | | - | | | | - | | | | - | | | | 18,029 | |
Excess income tax benefits of stock-based compensation | | | (8,881 | ) | | | - | | | | - | | | | - | | | | (8,881 | ) |
| Intercompany income taxes | | | 166,500 | | | | 42,456 | | | | 55 | | | | (209,011 | ) | | | - | |
| Intercompany dividends | | | 150,000 | | | | - | | | | - | | | | (150,000 | ) | | | - | |
| Other intercompany transactions | | | (3,240 | ) | | | 3,302 | | | | (62 | ) | | | - | | | | - | |
| Amortization of debt issuance costs | | | 482 | | | | 315 | | | | - | | | | - | | | | 797 | |
| Gains on sales of assets | | | (8 | ) | | | - | | | | - | | | | - | | | | (8 | ) |
Decrease in long-term commutation account | | | 5,316 | | | | - | | | | - | | | | - | | | | 5,316 | |
Amortization of long-term prepaid insurance | | | 1,211 | | | | - | | | | - | | | | - | | | | 1,211 | |
Increase in other long-term liabilities | | | 416 | | | | 8,893 | | | | - | | | | - | | | | 9,309 | |
Changes in deferred turnaround costs, deferred catalyst costs and other | | | (420 | ) | | | (18,424 | ) | | | - | | | | - | | | | (18,844 | ) |
Changes in components of working capital from operations | | | 19,089 | | | | (124,306 | ) | | | (80 | ) | | | (853 | ) | | | (106,150 | ) |
Net cash (used in) provided by operating activities | | | 124,667 | | | | 363,029 | | | | - | | | | (147,179 | ) | | | 340,517 | |
| | | | | | | | | | | | | | | | | | | | | |
| Cash flows from investing activities: | | | | | | | | | | | | | | | | | | | | |
Additions to property, plant and equipment | | | (88 | ) | | | (126,794 | ) | | | - | | | | (2,821 | ) | | | (129,703 | ) |
| Proceeds from sale of assets | | | 8 | | | | - | | | | - | | | | - | | | | 8 | |
El Dorado Refinery contingent earn- out payment | | | - | | | | (7,500 | ) | | | - | | | | - | | | | (7,500 | ) |
| Net cash used in investing activities | | | (80 | ) | | | (134,294 | ) | | | - | | | | (2,821 | ) | | | (137,195 | ) |
| | | | | | | | | | | | | | | | | | | | | |
| Cash flows from financing activities: | | | | | | | | | | | | | | | | | | | | |
| Purchase of treasury stock | | | (98,950 | ) | | | - | | | | - | | | | - | | | | (98,950 | ) |
Proceeds from issuance of common stock | | | 3,672 | | | | - | | | | - | | | | - | | | | 3,672 | |
| Dividends paid | | | (67,498 | ) | | | - | | | | - | | | | - | | | | (67,498 | ) |
Excess income tax benefits of stock-based compensation | | | 8,881 | | | | - | | | | - | | | | - | | | | 8,881 | |
| Debt issuance costs and other | | | - | | | | (13 | ) | | | - | | | | - | | | | (13 | ) |
| Intercompany dividends | | | - | | | | (150,000 | ) | | | - | | | | 150,000 | | | | - | |
Net cash provided by (used in) financing activities | | | (153,895 | ) | | | (150,013 | ) | | | - | | | | 150,000 | | | | (153,908 | ) |
(Decrease) increase in cash and cash equivalents | | | (29,308 | ) | | | 78,722 | | | | - | | | | - | | | | 49,414 | |
Cash and cash equivalents, beginning of period | | | 244,357 | | | | 111,708 | | | | - | | | | - | | | | 356,065 | |
Cash and cash equivalents, end of period | | $ | 215,049 | | | $ | 190,430 | | | $ | - | | | $ | - | | | $ | 405,479 | |
| 15. | Selected Quarterly Financial and Operating Data (Unaudited) |
| (Dollars in thousands, except per share and per bbl) | | | | | | | | | | | | | | | | | | | | | | |
| | | 2008 | | | 2007 | |
| | | Fourth | | | Third | | | Second | | | First | | | Fourth | | | Third | | | Second | | | First | |
| Revenues | | $ | 1,348,139 | | | $ | 2,198,302 | | | $ | 1,766,556 | | | $ | 1,185,783 | | | $ | 1,319,637 | | | $ | 1,386,520 | | | $ | 1,434,700 | | | $ | 1,047,883 | |
Operating income (1) | | | (142,628 | ) | | | 103,558 | | | | 81,986 | | | | 73,837 | | | | 61,806 | | | | 207,024 | | | | 374,293 | | | | 112,672 | |
| Net income | | | (97,374 | ) | | | 72,323 | | | | 59,316 | | | | 45,969 | | | | 43,417 | | | | 137,225 | | | | 243,763 | | | | 74,720 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Basic net income per share | | | (0.94 | ) | | | 0.70 | | | | 0.58 | | | | 0.45 | | | | 0.42 | | | | 1.30 | | | | 2.26 | | | | 0.68 | |
| Diluted net income per share | | | (0.94 | ) | | | 0.70 | | | | 0.57 | | | | 0.44 | | | | 0.41 | | | | 1.28 | | | | 2.23 | | | | 0.68 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Refining operations: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Total charges (bpd) (2) | | | 185,599 | | | | 173,954 | | | | 161,380 | | | | 126,018 | | | | 157,772 | | | | 171,243 | | | | 163,991 | | | | 166,529 | |
Gasoline yields (bpd) (3) | | | 88,680 | | | | 78,755 | | | | 73,203 | | | | 65,498 | | | | 72,173 | | | | 78,302 | | | | 79,221 | | | | 77,545 | |
Diesel and jet fuel yields (bpd) (3) | | | 75,256 | | | | 66,424 | | | | 54,220 | | | | 38,824 | | | | 51,475 | | | | 55,389 | | | | 55,437 | | | | 61,367 | |
| Total product sales (bpd) | | | 191,952 | | | | 177,219 | | | | 158,766 | | | | 137,129 | | | | 161,899 | | | | 174,116 | | | | 173,888 | | | | 170,744 | |
Average gasoline crack spread (per bbl) (4) | | $ | (0.95 | ) | | $ | 9.42 | | | $ | 5.85 | | | $ | 4.24 | | | $ | 4.72 | | | $ | 20.39 | | | $ | 34.86 | | | $ | 11.86 | |
Average diesel crack spread (per bbl) (4) | | | 21.81 | | | | 26.76 | | | | 28.70 | | | | 20.92 | | | | 17.51 | | | | 23.32 | | | | 27.22 | | | | 20.60 | |
Cheyenne average light/heavy crude oil differential (per bbl) (4) | | | 15.68 | | | | 14.02 | | | | 20.54 | | | | 18.36 | | | | 26.95 | | | | 18.51 | | | | 16.04 | | | | 14.30 | |
El Dorado average light/heavy crude oil differential (per bbl) (4) | | | 14.40 | | | | 14.33 | | | | 22.44 | | | | 21.45 | | | | 29.20 | | | | 20.71 | | | | 20.65 | | | | 13.45 | |
Average WTI/WTS crude oil differential (per bbl) | | | 3.30 | | | | 2.77 | | | | 4.98 | | | | 4.64 | | | | 6.95 | | | | 4.20 | | | | 4.59 | | | | 4.34 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
(1) Fourth quarter 2008 operating income includes $19.8 million of lower of cost or market inventory adjustments in December. | |
(2) Charges are the quantity of crude oil and other feedstock processed through refinery units. | |
(3) Manufactured product yields are the volumes of specific materials that are obtained through the distilling of crude oil and the operations of other refinery process units. | |
(4) Prior quarter and prior year amounts are restated to reflect current year presentation measurement under NYMEX WTI. The following presents prior period presentation as previously disclosed: | |
Average gasoline crack spread (per bbl) | | | n/a | | | $ | 9.52 | | | $ | 5.03 | | | $ | 4.04 | | | $ | 3.27 | | | $ | 20.51 | | | $ | 36.73 | | | $ | 12.92 | |
Average diesel crack spread (per bbl) | | | n/a | | | | 26.86 | | | | 27.88 | | | | 20.71 | | | | 16.06 | | | | 23.43 | | | | 29.08 | | | | 21.66 | |
Cheyenne average light/heavy crude oil differential (per bbl) | | | n/a | | | | 13.92 | | | | 21.36 | | | | 18.56 | | | | 28.40 | | | | 18.40 | | | | 14.17 | | | | 13.24 | |
El Dorado average light/heavy crude oil differential (per bbl) | | | n/a | | | | 14.23 | | | | 23.26 | | | | 21.68 | | | | 30.64 | | | | 20.60 | | | | 18.78 | | | | 12.46 | |
Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure
None.
The information contained in this Form 10-K, as well as the financial and operational data we present concerning the Company, is prepared by management. Our financial statements are fairly presented in all material respects in conformity with generally accepted accounting principles. It has always been our intent to apply proper and prudent accounting guidelines in the presentation of our financial statements, and we are committed to full and accurate representation of our condition through complete and clear disclosures. We maintain a set of disclosure controls and procedures that are designed to ensure that information required to be disclosed by us in the reports filed by us under the Securities Exchange Act of 1934, as amended (“Exchange Act”), is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to management, including the Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. Management necessarily applies its judgment in assessing the costs and benefits of such controls and procedures, which, by their nature, can provide only reasonable assurance regarding management's control objectives.
As of the end of the period covered by this report, we evaluated, under the supervision and with the participation of our management, including our President and Chief Executive Officer, our Executive Vice President and Chief Financial Officer and our Vice-President and Chief Accounting Officer, the effectiveness of our disclosure controls and procedures pursuant to Rule 13a-15 of the Exchange Act. Based on that evaluation, our President and Chief Executive Officer, our Executive Vice President and Chief Financial Officer and our Vice-President and Chief Accounting Officer concluded that our disclosure controls and procedures are effective.
During the most recent fiscal quarter, there have been no changes in our internal control over financial reporting that have materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
Our “Management’s Report on Internal Control Over Financial Reporting” and the related “Report of Independent Registered Public Accounting Firm” on our report are include on pages 25 and 26.
The information required by Part III of this Form is incorporated by reference from the Company’s definitive proxy statement to be filed with the SEC pursuant to Regulation 14A within 120 days after the close of its last fiscal year.
Item 15. Exhibits and Financial Statement Schedules
| (a)1.Financial Statements and Supplemental Data |
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| (a)2.Financial Statements Schedules |
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| Other Schedules are omitted because of the absence of the conditions under which they are required or because the required information is included in the financial statements or notes thereto. |
| * | 2.1 | Asset Purchase and Sale Agreement, dated as of October 19, 1999, among Frontier El Dorado Refining Company, as buyer, the Company, as Guarantor, and Equilon Enterprises LLC, as seller (Exhibit 10.1 to Form 8-K, File Number 1-07627, filed December 1, 1999). |
| * | 3.1 | Restated Articles of Incorporation of Wainoco Oil Corporation (now Frontier Oil Corporation) dated August 5, 1987 (Exhibit 3.1.1 to Registration Statement No. 333-120643, filed November 19, 2004). |
| * | 3.2 | Articles of Amendment to the Restated Articles of Incorporation of Wainoco Oil Corporation (now Frontier Oil Corporation) dated June 14, 1988 (Exhibit 3.1.2 to Registration Statement Number 333-120643, filed November 19, 2004). |
| * | 3.3 | Articles of Amendment to the Restated Articles of Incorporation of Wainoco Oil Corporation (now Frontier Oil Corporation) dated April 24, 1992 (Exhibit 3.1.3 to Registration Statement Number 333-120643, filed November 19, 2004). |
| * | 3.4 | Articles of Amendment to the Restated Articles of Incorporation of Wainoco Oil Corporation (now Frontier Oil Corporation) dated April 27, 1998 (Exhibit 3.1.4 to Registration Statement Number 333-120643, filed November 19, 2004). |
| * | 3.5 | Articles of Amendment to the Restated Articles of Incorporation of Frontier Oil Corporation dated May 23, 2005 (Exhibit 3.1 to Form 8-K, File Number 1-07627, filed May 24, 2005). |
| * | 3.6 | Articles of Amendment to the Restated Articles of Incorporation of Frontier Oil Corporation dated June 12, 2006 (Exhibit 3.1 to Form 8-K, File Number 1-07627, filed June 15, 2006). |
| * | 3.7 | Fifth Restated Bylaws of Wainoco Oil Corporation (now Frontier Oil Corporation), effective November 12, 2008 (Exhibit 2.1 to Form 8-K, File Number 1-07627, filed November 14, 2008). |
| * | 4.1 | Indenture, dated as of October 1, 2004, among the Company, as issuer, the guarantors party thereto and Wells Fargo Bank, N.A., as trustee relating to the Company’s 6.625% Senior Notes due 2011 (Exhibit 4.1 to Form 8-K, File Number 1-07627, filed October 4, 2004). |
| * | 4.2 | Indenture, dated as of September 17, 2008, among Frontier Oil Corporation, the guarantors named therein and Wells Fargo Bank, N.A., as trustee relating to the Company’s 8.5% Senior Notes due 2016 (Exhibit 4.1 to Form 8-K, File Number 1-07627, filed September 17, 2008). |
| * | 4.3 | First Supplemental Indenture, dated as of September 17, 2008, among Frontier Oil Corporation, the guarantors named therein and Wells Fargo Bank, N.A., as trustee relating to the Company’s 8.5% Senior Notes due 2016 (Exhibit 4.2 to Form 8-K, File Number 1-07627, filed September 17, 2008). |
| * | 4.4 | Form of the Company’s global note for 8.5% Senior Notes due 2016 (Exhibit 4.3 to Form 8-K, File Number1-07627, filed September 17, 2008). |
*² | 10.1 | Frontier Deferred Compensation Plan (previously named Wainoco Deferred Compensation Plan dated October 29, 1993 and filed as Exhibit 10.19 to Form 10-K, File Number 1-07627, filed March 17, 1995). |
*² | 10.2 | Frontier Deferred Compensation Plan for Directors (previously named Wainoco Deferred Compensation Plan for Directors dated May 1, 1994 and filed as Exhibit 10.20 to Form 10-K, File Number 1-07627, filed March 17, 1995). |
| * | 10.3 | Master Crude Oil Purchase and Sale Contract, dated March 10, 2006, among Utexam Limited, Frontier Oil and Refining Company and the Company (Exhibit 10.1 to Form 8-K, File Number 1-07627, filed March 14, 2006). |
| | | |
| * | 10.5 | Second Amendment to Master Crude Oil Purchase and Sale Contract, dated March 12, 2008, among Utexam Limited, Frontier Oil and Refining Company and the Company (Exhibit 10.1 to Form 8-K, File Number 1-07627, filed March 17, 2008). |
| * | 10.6 | Guaranty, dated March 10, 2006, by the Company in favor of Utexam Limited (Exhibit 10.2 to Form 8-K, File Number 1-07627, filed March 14, 2006). |
| | | Consent of Frontier Oil and Refining Company to the Second Amendment to the Revolving Credit Agreement (Uncommitted) dated as of March 8, 2007, among Utexam Limited, as borrower, BNP Paribas, as administrative agent and the lenders party thereto, and Consent of Frontier Oil and Refining Company to the Third Amendment to the Revolving Credit Agreement (Uncommitted) dated as of May 16, 2007, among Utexam Limited, as borrower, BNP Paribas, as administrative agent and the lenders party thereto, and Consent of Frontier Oil and Refining Company to the Sixth Amendment to the Revolving Credit Agreement (Uncommitted) dated as of January 20, 2009, among Utexam Limited, as borrower, BNP Paribas, as administrative agent and the lenders party thereto. |
| * | 10.8 | Third Amended and Restated Revolving Credit Agreement dated October 1, 2007, among the Company, Frontier Oil and Refining Company, as borrower, the lenders named therein, Union Bank of California, N.A., as administrative agent, and BNP Paribas, as syndication agent (Exhibit 10.1 to Form 8-K, File Number 1-07627, filed October 4, 2007). |
| | | |
| * | 10.10 | Second Amendment to Third Amended and Restated Revolving Credit Agreement dated as of June 23, 2008, among Frontier Oil and Refining Company, Frontier Oil Corporation, Union Bank of California, N.A., as administrative agent, and BNP Paribas, as syndication agent and the other lenders specified therein (Exhibit 10.1 to Form 8-K, File Number 1-07627, filed June 24, 2008). |
| * | 10.11 | Fourth Amended and Restated Revolving Credit Agreement dated as of August 19, 2008, among Frontier Oil and Refining Company, Frontier Oil Corporation, Union Bank of California, N.A., as administrative agent, and BNP Paribas, as syndication agent and the other lenders specified therein (Exhibit 10.1 to Form 8-K, File Number 1-07627, filed August 20, 2008). |
| * | 10.12 | First Amendment to Fourth Amended and Restated Revolving Credit Agreement dated December 15, 2008, among Frontier Oil and Refining Company, Frontier Oil Corporation, Union Bank of California, N.A., as administrative agent, and BNP Paribas, as syndication agent and the other lenders specified therein (Exhibit 10.1 to Form 8-K, File Number 1-07627, filed December 16, 2008). |
| * | 10.13 | Frontier Products Offtake Agreement El Dorado Refinery, dated as of October 19, 1999 by and between Frontier Oil and Refining Company and Equiva Trading Company (now Shell Oil Products US, assignee of Equiva Trading Company) (“the Agreement”), and First Amendment to the Agreement dated September 18, 2000, Second Amendment to the Agreement dated September 21, 2000, Third Amendment to the Agreement dated December 19, 2000, Fourth Amendment to the Agreement dated February 22, 2001, Fifth Amendment to the Agreement dated August 14, 2001, Sixth Amendment to the Agreement dated November 5, 2001, Seventh Amendment to the Agreement dated April 22, 2002, Eight Amendment to the Agreement dated May 30, 2003, Ninth Amendment to the Agreement dated May 25, 2004, Tenth Amendment to the Agreement dated May 3, 2005, Eleventh Amendment to the Agreement dated March 31, 2006, Twelfth Amendment to the Agreement dated May 11, 2006, Thirteenth Amendment to the Agreement dated September 30, 2007, Fourteenth Amendment to the Agreeme |
*² | 10.14 | Frontier Oil Corporation Omnibus Incentive Compensation Plan (Annex A to Proxy Statement, File Number 1-07627, filed March 21, 2006). |
*² | 10.15 | Form of Frontier Oil Corporation Omnibus Incentive Compensation Plan Stock Unit/Restricted Stock Agreement (Exhibit 4.8 to Form S-8, File Number 333-133595, filed April 27, 2006). |
*² | 10.16 | Form of Frontier Oil Corporation Omnibus Incentive Compensation Plan Nonqualified Stock Option Agreement (Exhibit 4.9 to Form S-8, File Number 333-133595, filed April 27, 2006). |
*² | 10.17 | Form of Non-Employee Director Restricted Stock Unit Grant Agreement (Exhibit 10.1 to Form 8-K, File Number 1-07627, filed April 7, 2006). |
*² | 10.18 | Form of First Amendment to Restricted Stock Unit Grant (Exhibit 10.1 to Form 10-Q, File Number 1-07627, filed August 7, 2006). |
*² | 10.19 | Form of Restricted Stock Agreement (Exhibit 10.2 to Form 8-K, File Number 1-07627, filed April 7, 2006). |
*² | 10.20 | Form of Indemnification Agreement by and between the Company and each of its officers and directors (Exhibit 10.41 to Form 10-K, File Number 1-07627, filed February 28, 2007). |
*² | 10.21 | Management Incentive Compensation Plan for Fiscal 2007 (Exhibit 10.1 to Form 8-K, File Number 1-07627, filed March 2, 2007). |
*² | 10.22 | Management Incentive Compensation Plan for Fiscal 2008 (Exhibit 10.1 to Form 8-K, File Number 1-07627, filed February 29, 2008). |
*² | 10.23 | Form of 2007 Stock Unit / Restricted Stock Agreement (Exhibit 10.1 to Form 10-Q, File Number 1-07627, filed May 9, 2007). |
*² | 10.24 | Form of Stock Unit / Restricted Stock Agreement for James R. Gibbs (Exhibit 10.1 to Form 10-Q, File Number 1-07627, filed May 8, 2008). |
*² | 10.25 | Form of Stock Unit / Restricted Stock Agreement for other employees (Exhibit 10.2 to Form 10-Q, File Number 1-07627, filed May 8, 2008). |
*² | 10.26 | Executive Change in Control Severance Agreement, effective as of December 30, 2008 by and between Frontier Oil Corporation and James R. Gibbs (Exhibit 10.1 to Form 8-K, File Number 1-07627, filed January 2, 2009). |
*² | 10.27 | Executive Change in Control Severance Agreement, effective as of December 30, 2008 by and between Frontier Oil Corporation and Michael C. Jennings (Exhibit 10.2 to Form 8-K, File Number 1-07627, filed January 2, 2009). |
*² | 10.28 | Executive Change in Control Severance Agreement, effective as of December 30, 2008 by and between Frontier Oil Corporation and W. Paul Eisman (Exhibit 10.3 to Form 8-K, File Number 1-07627, filed January 2, 2009). |
*² | 10.29 | Executive Change in Control Severance Agreement, effective as of December 30, 2008 by and between Frontier Oil Corporation and Doug S. Aron (Exhibit 10.4 to Form 8-K, File Number 1-07627, filed January 2, 2009). |
*² | 10.30 | Executive Change in Control Severance Agreement, effective as of December 30, 2008 by and between Frontier Oil Corporation and J. Currie Bechtol (Exhibit 10.5 to Form 8-K, File Number 1-07627, filed January 2, 2009). |
*² | 10.31 | Executive Change in Control Severance Agreement, effective as of December 30, 2008 by and between Frontier Oil Corporation and Gerald B. Faudel (Exhibit 10.6 to Form 8-K, File Number 1-07627, filed January 2, 2009). |
*² | 10.32 | Executive Change in Control Severance Agreement, effective as of December 30, 2008 by and between Frontier Oil Corporation and Jon D. Galvin (Exhibit 10.7 to Form 8-K, File Number 1-07627, filed January 2, 2009). |
*² | 10.33 | Executive Change in Control Severance Agreement, effective as of December 30, 2008 by and between Frontier Oil Corporation and Nancy J. Zupan (Exhibit 10.8 to Form 8-K, File Number 1-07627, filed January 2, 2009). |
*² | 10.34 | Executive Change in Control Severance Agreement, effective as of December 30, 2008 by and between Frontier Oil Corporation and Leo J. Hoonakker (Exhibit 10.9 to Form 8-K, File Number 1-07627, filed January 2, 2009). |
*² | 10.35 | Executive Change in Control Severance Agreement, effective as of December 30, 2008 by and between Frontier Oil Corporation and Penny S. Newmark (Exhibit 10.10 to Form 8-K, File Number 1-07627, filed January 2, 2009). |
*² | 10.36 | Executive Change in Control Severance Agreement, effective as of December 30, 2008 by and between Frontier Oil Corporation and Michael F. Milam (Exhibit 10.11 to Form 8-K, File Number 1-07627, filed January 2, 2009). |
*² | 10.37 | Executive Change in Control Severance Agreement, effective as of December 30, 2008 by and between Frontier Oil Corporation and Kent A. Olsen (Exhibit 10.12 to Form 8-K, File Number 1-07627, filed January 2, 2009). |
*² | 10.38 | Executive Change in Control Severance Agreement, effective as of December 30, 2008 by and between Frontier Oil Corporation and Joel W. Purdy (Exhibit 10.13 to Form 8-K, File Number 1-07627, filed January 2, 2009). |
*² | 10.39 | Executive Change in Control Severance Agreement, effective as of December 30, 2008 by and between Frontier Oil Corporation and Billy N. Rigby (Exhibit 10.14 to Form 8-K, File Number 1-07627, filed January 2, 2009). |
*² | 10.40 | Executive Change in Control Severance Agreement, effective as of December 30, 2008 by and between Frontier Oil Corporation and James M. Stump (Exhibit 10.15 to Form 8-K, File Number 1-07627, filed January 2, 2009). |
*² | 10.41 | Executive Severance Agreement, effective as of December 30, 2008 by and between Frontier Oil Corporation and Michael C. Jennings (Exhibit 10.16 to Form 8-K, File Number 1-07627, filed January 2, 2009). |
*² | 10.42 | Executive Severance Agreement, effective as of December 30, 2008 by and between Frontier Oil Corporation and W. Paul Eisman (Exhibit 10.17 to Form 8-K, File Number 1-07627, filed January 2, 2009). |
*² | 10.43 | Executive Severance Agreement, effective as of December 30, 2008 by and between Frontier Oil Corporation and Doug S. Aron (Exhibit 10.18 to Form 8-K, File Number 1-07627, filed January 2, 2009). |
*² | 10.44 | Executive Severance Agreement, effective as of December 30, 2008 by and between Frontier Oil Corporation and J. Currie Bechtol (Exhibit 10.19 to Form 8-K, File Number 1-07627, filed January 2, 2009). |
*² | 10.45 | Executive Severance Agreement, effective as of December 30, 2008 by and between Frontier Oil Corporation and Gerald B. Faudel (Exhibit 10.20 to Form 8-K, File Number 1-07627, filed January 2, 2009). |
*² | 10.46 | Executive Severance Agreement, effective as of December 30, 2008 by and between Frontier Oil Corporation and Jon D. Galvin (Exhibit 10.21 to Form 8-K, File Number 1-07627, filed January 2, 2009). |
*² | 10.47 | Executive Severance Agreement, effective as of December 30, 2008 by and between Frontier Oil Corporation and Nancy J. Zupan (Exhibit 10.22 to Form 8-K, File Number 1-07627, filed January 2, 2009). |
*² | 10.48 | Executive Severance Agreement, effective as of December 30, 2008 by and between Frontier Oil Corporation and Leo J. Hoonakker (Exhibit 10.23 to Form 8-K, File Number 1-07627, filed January 2, 2009). |
*² | 10.49 | Executive Severance Agreement, effective as of December 30, 2008 by and between Frontier Oil Corporation and Penny S. Newmark (Exhibit 10.24 to Form 8-K, File Number 1-07627, filed January 2, 2009). |
*² | 10.50 | Executive Severance Agreement, effective as of December 30, 2008 by and between Frontier Oil Corporation and Michael F. Milam (Exhibit 10.25 to Form 8-K, File Number 1-07627, filed January 2, 2009). |
*² | 10.51 | Executive Severance Agreement, effective as of December 30, 2008 by and between Frontier Oil Corporation and Kent A. Olsen (Exhibit 10.26 to Form 8-K, File Number 1-07627, filed January 2, 2009). |
*² | 10.52 | Executive Severance Agreement, effective as of December 30, 2008 by and between Frontier Oil Corporation and Joel W. Purdy (Exhibit 10.27 to Form 8-K, File Number 1-07627, filed January 2, 2009). |
*² | 10.53 | Executive Severance Agreement, effective as of December 30, 2008 by and between Frontier Oil Corporation and Billy N. Rigby (Exhibit 10.28 to Form 8-K, File Number 1-07627, filed January 2, 2009). |
*² | 10.54 | Executive Severance Agreement, effective as of December 30, 2008 by and between Frontier Oil Corporation and James M. Stump (Exhibit 10.29 to Form 8-K, File Number 1-07627, filed January 2, 2009). |
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* Asterisk indicates exhibits incorporated by reference as shown.
² Diamond indicates management contract or compensatory plan or arrangement.
The Company’s 2008 Annual Report is available upon request. Shareholders of the Company may obtain a copy of any exhibits to this Form 10-K at a charge of $0.05 per page. Requests should be directed to:
Investor Relations
Frontier Oil Corporation
10000 Memorial Drive, Suite 600
Houston, Texas 77024-3411
| | | | | | |
| Condensed Financial Information of Registrant | | | | | | |
| Balance Sheets | | | | | | |
| Schedule I | |
| | | | | | | |
| | | | | | | |
| | | December 31, | |
| | | 2008 | | | 2007 | |
| | | (in thousands) | |
| ASSETS | | | | | | |
| Current assets: | | | | | | |
| Cash and cash equivalents | | $ | 254,548 | | | $ | 186,368 | |
| Trade and other receivables | | | 120,265 | | | | 27,948 | |
| Deferred income taxes | | | 8,841 | | | | 9,426 | |
| Commutation account | | | 6,319 | | | | 6,280 | |
| Other current assets | | | 643 | | | | 9,646 | |
| Total current assets | | | 390,616 | | | | 239,668 | |
| Property, plant and equipment, at cost: | | | | | | | | |
| Furniture, fixtures and other | | | 1,248 | | | | 1,121 | |
| Accumulated depreciation | | | (998 | ) | | | (943 | ) |
| Property, plant and equipment, net | | | 250 | | | | 178 | |
| Deferred financing costs, net | | | 3,642 | | | | 1,810 | |
| Other assets | | | 2,600 | | | | 4,222 | |
| Receivable from affiliated companies | | | 646 | | | | - | |
| Investment in subsidiaries | | | 1,235,678 | | | | 1,106,243 | |
| Total assets | | $ | 1,633,432 | | | $ | 1,352,121 | |
| | | | | | | | | |
| LIABILITIES AND SHAREHOLDERS' EQUITY | | | | | | | | |
| Current liabilities: | | | | | | | | |
| Accounts payable | | $ | 1,168 | | | $ | 242 | |
| Accrued liabilities and other | | | 26,071 | | | | 25,947 | |
| Total current liabilities | | | 27,239 | | | | 26,189 | |
| Long-term debt | | | 347,220 | | | | 150,000 | |
| Contingent income tax liabilities | | | 26,112 | | | | 31,185 | |
| Other long-term liabilities | | | 2,507 | | | | 3,208 | |
| Deferred income taxes | | | 179,214 | | | | 100,310 | |
| Payable to affiliated companies | | | - | | | | 2,615 | |
| | | | | | | | | |
| Shareholders' equity | | | 1,051,140 | | | | 1,038,614 | |
| | | | | | | | | |
| Total liabilities and shareholders' equity | | $ | 1,633,432 | | | $ | 1,352,121 | |
| | | | | | | | | |
| The "Notes to Consolidated Financial Statements" in Item 8 of this Form 10-K are an integral part of these financial statements. | |
| Frontier Oil Corporation | | | | | | | | | |
| Condensed Financial Information of Registrant | | | | | | | | | |
| Statements of Income | | | | | | | | | |
| Schedule I | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | December 31, | |
| | | 2008 | | | 2007 | | | 2006 | |
| | | (in thousands) | |
| | | | | | | | | | |
| Revenues | | $ | (7 | ) | | $ | 2 | | | $ | 4 | |
| | | | | | | | | | | | | |
| Costs and expenses: | | | | | | | | | | | | |
| Selling and general expenses, excluding depreciation | | | 17,677 | | | | 30,593 | | | | 30,194 | |
| Depreciation | | | 55 | | | | 61 | | | | 88 | |
| Loss (gain) on sales of assets | | | (37 | ) | | | 2,028 | | | | (8 | ) |
| | | | 17,695 | | | | 32,682 | | | | 30,274 | |
| | | | | | | | | | | | | |
| Operating income | | | (17,702 | ) | | | (32,680 | ) | | | (30,270 | ) |
| | | | | | | | | | | | | |
| Interest expense and other financing costs | | | 15,939 | | | | 12,723 | | | | 11,978 | |
| Interest and investment income | | | (2,868 | ) | | | (11,202 | ) | | | (12,102 | ) |
| Equity in earnings of subsidiaries | | | (137,139 | ) | | | (802,362 | ) | | | (609,265 | ) |
| | | | (124,068 | ) | | | (800,841 | ) | | | (609,389 | ) |
| | | | | | | | | | | | | |
| Income before income taxes | | | 106,366 | | | | 768,161 | | | | 579,119 | |
| Provision for income taxes | | | 26,132 | | | | 269,036 | | | | 199,842 | |
| | | | | | | | | | | | | |
| Net income | | $ | 80,234 | | | $ | 499,125 | | | $ | 379,277 | |
| | | | | | | | | | | | | |
| The "Notes to Consolidated Financial Statements" in Item 8 of this Form 10-K are an integral part of these financial statements. | |
| Frontier Oil Corporation | | | | | | | | | |
| Condensed Financial Information of Registrant | | | | | | | | | |
| Statements of Cash Flows | | | | | | | | | |
| Schedule I | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | December 31, | |
| | | 2008 | | | 2007 | | | 2006 | |
| | | (in thousands) | |
| Cash flows from operating activities: | | | | | | | | | |
| Net income | | $ | 80,234 | | | $ | 499,125 | | | $ | 379,277 | |
| Equity in earnings of subsidiaries | | | (137,139 | ) | | | (802,362 | ) | | | (609,265 | ) |
| Intercompany transactions, net | | | (9,261 | ) | | | 1,110 | | | | (3,240 | ) |
| Dividends and income taxes received from subsidiaries | | | 10,000 | | | | 529,650 | | | | 316,500 | |
| Depreciation | | | 55 | | | | 61 | | | | 88 | |
| Deferred income taxes | | | 80,894 | | | | (1,916 | ) | | | 6,073 | |
| Stock-based compensation expense | | | 20,014 | | | | 22,553 | | | | 18,029 | |
| Excess income tax benefits of stock-based compensation | | | (3,191 | ) | | | (6,962 | ) | | | (8,881 | ) |
| Amortization of debt issuance costs | | | 570 | | | | 483 | | | | 482 | |
| Senior notes discount amortization | | | 60 | | | | - | | | | - | |
| Allowance for investment loss | | | 41 | | | | - | | | | - | |
| Loss (gain) on sales of assets | | | (37 | ) | | | 2,028 | | | | (8 | ) |
| Decrease in commutation account | | | - | | | | 1,009 | | | | 5,316 | |
| Amortization of long-term prepaid insurance | | | 909 | | | | 1,211 | | | | 1,211 | |
| Increase (decrease) in other long-term liabilities | | | (3,716 | ) | | | 31,058 | | | | 416 | |
| Other | | | 713 | | | | (578 | ) | | | (420 | ) |
| Changes in components of working capital from operations | | | (80,054 | ) | | | (46,639 | ) | | | 19,089 | |
| Net cash (used in) provided by operating activities | | | (39,908 | ) | | | 229,831 | | | | 124,667 | |
| | | | | | | | | | | | | |
| Cash flows from investing activities: | | | | | | | | | | | | |
| Additions to property, plant and equipment | | | (129 | ) | | | (4,310 | ) | | | (88 | ) |
| Proceeds from sale of assets | | | 37 | | | | 2,290 | | | | 8 | |
| Net cash used in investing activities | | | (92 | ) | | | (2,020 | ) | | | (80 | ) |
| | | | | | | | | | | | | |
| Cash flows from financing activities: | | | | | | | | | | | | |
Proceeds from issuance of 8.5% Senior Notes, net of discount | | | 197,160 | | | | - | | | | - | |
| Purchase of treasury stock | | | (67,030 | ) | | | (248,486 | ) | | | (98,950 | ) |
| Proceeds from issuance of common stock | | | 405 | | | | 2,303 | | | | 3,672 | |
| Dividends paid to shareholders | | | (23,144 | ) | | | (17,271 | ) | | | (67,498 | ) |
| Excess income tax benefits of stock-based compensation | | | 3,191 | | | | 6,962 | | | | 8,881 | |
| Debt issuance costs and other | | | (2,402 | ) | | | - | | | | - | |
| Net cash provided by (used in) financing activities | | | 108,180 | | | | (256,492 | ) | | | (153,895 | ) |
| | | | | | | | | | | | | |
| Increase (decrease) in cash and cash equivalents | | | 68,180 | | | | (28,681 | ) | | | (29,308 | ) |
| Cash and cash equivalents, beginning of period | | | 186,368 | | | | 215,049 | | | | 244,357 | |
| | | | | | | | | | | | | |
| Cash and cash equivalents, end of period | | $ | 254,548 | | | $ | 186,368 | | | $ | 215,049 | |
| | | | | | | | | | | | | |
| The "Notes to Consolidated Financial Statements" in Item 8 of this Form 10-K are an integral part of these financial statements. | |
| | | | | | | | | | | | | |
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| Valuation and Qualifying Accounts | | | | | | | | | | | | |
| For the three years ended December 31, | | | | | | | | | | |
| Schedule II | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| Description | | Balance at beginning of period | | Additions | | | Deductions | | | Balance at end of period | |
| | | (in thousands) | |
| 2008 | | | | | | | | | | | | |
| Allowance for doubtful accounts | | $ | 500 | | | $ | - | | | $ | - | | | $ | 500 | |
| Allowance for investment loss | | | - | | | | 499 | | | | - | | | | 499 | |
| | | | | | | | | | | | | | | | | |
| 2007 | | | | | | | | | | | | | | | | |
| Allowance for doubtful accounts | | | 500 | | | | 198 | | | | 198 | | | | 500 | |
| | | | | | | | | | | | | | | | | |
| 2006 | | | | | | | | | | | | | | | | |
| Allowance for doubtful accounts | | | 500 | | | | 26 | | | | 26 | | | | 500 | |
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 on the date indicated.
| | FRONTIER OIL CORPORATION | |
| | | | |
| | By: | /s/ Michael C. Jennings | |
| | | Michael C. Jennings | |
| | | President and Chief Executive Officer (chief executive officer) | |
| | | | |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of Frontier Oil Corporation and in the capacities and on the date indicated.
| | | | | |
| /s/ James R. Gibbs | | | /s/ G. Clyde Buck | |
| James R. Gibbs | | | G. Clyde Buck | |
| Director and Chairman of the Board | | | Director | |
| | | | | |
| /s/ Michael C. Jennings | | | /s/ T. Michael Dossey | |
| Michael C. Jennings | | | T. Michael Dossey | |
President and Chief Executive Officer and Director (chief executive officer) | | | Director | |
| | | | | |
| /s/ Doug S. Aron | | | /s/ James H. Lee | |
| Doug S. Aron | | | James H. Lee | |
Executive Vice President and Chief Financial Officer (principal financial officer) | | | Director | |
| | | | | |
| /s/ Nancy J. Zupan | | | /s/ Paul B. Loyd, Jr. | |
| Nancy J. Zupan | | | Paul B. Loyd, Jr. | |
Vice President and Chief Accounting Officer (principal accounting officer) | | | Director | |
| | | | | |
| /s/ Douglas Y. Bech | | | /s/ Michael E. Rose | |
| Douglas Y. Bech | | | Michael E. Rose | |
| Director | | | Director | |
