UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
| [X] | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the Fiscal Year Ended: December 31, 2002 |
| OR | |
| [ ] | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from . . . .to . . . . |
Commission File Number: 1-7627
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 | ||
| 9-1/8% Senior Notes, due 2006 | New York Stock Exchange | ||
| 11¾% Senior Notes, due 2009 |
Securities registered pursuant to Section 12(g) of the Act:
None
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 [X] 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.{X}
Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act)
Yes [X] No . . .
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, or the average bid and asked price of such common equity, as of the last business day of the registrant’s most recently completed second fiscal quarter: $343.5 million.
The number of shares of common stock outstanding as of February 28, 2003 was 26,144,115.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Annual Proxy Statement for the registrant’s 2003 annual meeting of shareholders are incorporated by reference into Items 10 through 13 of Part III.
Table of Contents
Frontier Oil Corporation is filing this amendment to its Annual Report on Form 10-K for the fiscal year ended December 31, 2002, originally filed on March 4, 2003, in response to comments received from the Securities and Exchange Commission. This amendment to the original Form 10-K amends and restates the original Form 10-K in its entirety, but continues to speak as of the date of the original filing of the original Form 10-K. Frontier Oil Corporation has not updated the disclosure in this amendment to speak as of a later date. All information contained in this amendment and the original Form 10-K is subject to updating and supplementing as provided in the periodic reports filed subsequent to the original filing date with the Securities and Exchange Commission.
This Form 10-K/A contains forward-looking statements, which include, among other things, statements regarding (1) projections of revenues, earnings, earnings per share, capital expenditures or other financial items, (2) statements of plans and objectives for future operations, including acquisitions, (3) statements of future economic performance, or (4) statements of assumptions or estimates underlying or supporting the foregoing are forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995 and Section 21E of the Exchange Act. These forward-looking statements can generally be identified by the words “anticipate,” “believe,” “expect,” “plan,” “intend,” “estimate,” “project,” “budget,” “forecast,” “will,” “could,” “should,” “may,” and similar expressions.
Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this document 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.
We undertake no obligation to publicly release the result of 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/A, or to reflect the occurrence of unanticipated events.
The terms “Frontier” and “we” as used in this Form 10-K/A 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, Montana and Utah, and when we use the term “Plains States,” we refer to the states of Kansas, Nebraska, Iowa, Missouri, North Dakota and South Dakota.
We are an independent energy company engaged in crude oil refining and the wholesale marketing of refined petroleum products. We operate refineries in Cheyenne, Wyoming and in El Dorado, Kansas with a total crude oil capacity of over 156,000 barrels per day. 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 margin 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 capacity of 46,000 barrels per day. 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 Cheyenne refinery has a coking unit, which allows the refinery to process up to 100% heavy crude oil for use as a feedstock. This ability to process heavy crude oil lowers our crude oil supply costs because heavy crude oil is generally less expensive than lighter types of crude oil. For the year ended December 31, 2002, heavy crude oil constituted approximately 90% of the Cheyenne refinery’s total crude oil charge. For the year ended December 31, 2002, the Cheyenne refinery’s product mix included gasoline (40%), diesel fuel (30%) and asphalt and other refined petroleum products (30%).
El Dorado Refinery. The El Dorado refinery, acquired on November 16, 1999 from Equilon Enterprises LLC, now known as Shell Oil Products US (“Shell”), is one of the largest refineries in the Plains States and the Rocky Mountain region, with a crude capacity of 110,000 barrels per day. The El Dorado refinery can select from many different types of crude oil because of its direct access to the Cushing, Oklahoma hub which is connected by pipeline to the Gulf Coast. This access, combined with the El Dorado refinery’s complexity, gives it the flexibility to refine a wide variety of crude oils. In connection with our acquisition of the El Dorado refinery in late 1999, we entered into a 15-year refined product offtake agreement for gasoline and diesel production at this refinery with Equiva Trading Company (“Equiva”), an affiliate of Shell Oil Company. In 2002 Equiva assigned this offtake agreement to Shell. The offtake agreement also provides for Shell to purchase all jet fuel production from the El Dorado refinery for five years through 2004. The offtake agreement will allow us to maximize the operating efficiency of the El Dorado refinery during the initial years of our ownership. As our commitments to Shell under the refined product offtake agreement decline over the first ten years, we intend to market an increasing portion of the El Dorado refinery’s gasoline and diesel in the same markets in which Shell currently sells the El Dorado refinery’s production, primarily the Denver and Kansas City metropolitan areas. For the year ended December 31, 2002, the El Dorado refinery’s product mix included gasoline (57%), diesel and jet fuel (35%) and chemicals and other refined petroleum products (8%).
Varieties of Crude Oil. Traditionally, crude oil has been classified as (1) sweet (if sulfur content is low) or sour (if sulfur content is high), (2) light (if gravity is high) or heavy (if gravity is low) and (3) 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 yield of higher margin 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 margin by-products and heavy residual oils. The discount at which heavy crude oil sells compared to the sales price of light crude oil is known in the industry as the light/heavy spread. Coking units, such as the ones used by our refineries, can process certain by-products and heavy residual oils to produce additional volumes of gasoline and diesel, thus increasing the aggregate yield of higher margin refined products from the same initial volume of crude oil.
Products. The Cheyenne and El Dorado refineries are both complex refineries. 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. Upgrading capacity refers to the ability of a refinery to produce high yields of high margin refined products such as gasoline and diesel despite processing significant volumes of heavy and intermediate crude oil. In contrast, in order to produce high yields of gasoline and diesel, refineries with low upgrading capacity must process primarily sweet crude oil. Some low complexity refineries may be capable of processing heavy and intermediate crude oil, but they will produce large volumes of by-products and heavy residual oils. The Cheyenne and El Dorado refineries have high upgrading capacity relative to other refineries in the Plains States and Rocky Mountain region. 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 bulk of our production.
In addition to its petroleum refining operations, the El Dorado refinery includes a small petro-chemical complex. The primary products of the petro-chemical processes are phenol and acetone, the chemical building blocks for sandpaper adhesive, rubber belts, fiberglass insulation, high-impact plastics, plywood adhesive, medicines, cosmetics and other useful everyday items. Demand for petro-chemical products has been on a decline. Due to reduced demand and weak prices, we shut down certain aspects of the petro-chemical complex in 2002, discontinued the production of phenol and acetone, and began producing and selling benzene. The remaining hydrocarbon streams are being used as feed in other process units.
Marketing and Distribution.
Cheyenne Refinery. The primary market for the Cheyenne refinery’s refined products is the eastern slope area of the Rocky Mountain region, which includes Colorado and Wyoming. For the year ended December 31, 2002, we sold approximately 82% of the Cheyenne refinery’s gasoline sales volumes in Colorado and 8% in Wyoming. For the year ended December 31, 2002, we sold approximately 37% of the Cheyenne refinery’s diesel sales volumes in Colorado and 45% in Wyoming. Because of the location of the Cheyenne refinery, we are able to sell a significant portion of its diesel product from a truck rack at the refinery, eliminating any 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 Kaneb pipeline, serving Denver and Colorado Springs, Colorado, and the Continental 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.” The customer at a terminal rack typically supplies his own truck transportation. Prices at the terminal rack are posted daily by sellers. In the year ended December 31, 2002, approximately 72% of the Cheyenne refinery’s sales were made to its 25 largest customers. Occasionally, marketing volumes exceed the refinery’s production capabilities and in those instances, 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. Pipeline shipments from the El Dorado refinery are handled mainly by the Kaneb pipeline serving the northern Plains States, the Chase pipeline serving Denver, Colorado; the Williams pipeline serving Kansas City, Carthage, Missouri and Des Moines, Iowa, and the KCPL pipeline, serving Kansas City.
In connection with our late 1999 refinery acquisition we entered into a 15-year refined product offtake agreement with Shell, as previously discussed. For the year ended December 31, 2002, Shell was the El Dorado refinery’s largest customer. Under the agreement, Shell will purchase 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 a portion of the refinery’s gasoline and diesel production. This portion will increase 5,000 barrels per day each year for ten years, beginning at 5,000 barrels per day in 2000 rising to 50,000 barrels per day in 2009 and remaining at that level through the term of the agreement. Shell will continue to purchase all jet fuel production for the first five years of the agreement through 2004, but thereafter, we can market all of the El Dorado refinery’s jet fuel production. The agreement will allow us to focus on maximizing the operating efficiency of our El Dorado refinery during the initial years of our ownership. 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 markets as Shell currently does, as described above.
Competition.
Cheyenne Refinery. The most competitive market for the Cheyenne refinery is the Denver metropolitan area. Other than the Cheyenne refinery, four principal refineries serve the Denver market: a 65,000 barrel per day refinery near Rawlins, Wyoming and a 22,000 barrel per day refinery in Casper, Wyoming, both owned by Sinclair Oil Company, a 28,000 barrel per day refinery in Denver owned by Valero; and a 58,000 barrel per day refinery in Denver owned by Conoco Phillips. 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 bear the burden of higher transportation costs.
The Valero and Conoco Phillips refineries located in Denver have lower product transportation costs in servicing 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, and our ownership interest in the Centennial pipeline, which runs from Guernsey to the Cheyenne refinery. Moreover, unlike Sinclair, Valero and Conoco Phillips, we only sell our products to the wholesale market. We believe that this commitment to the wholesale market gives us a customer relations advantage over our principal competitors in the Eastern Slope area, all of which also have retail outlets, because we are not in direct competition 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 than the El Dorado refinery, we believe that their higher refined product transportation costs allow the El Dorado refinery to compete effectively with these refineries in the Plains States and Rocky Mountain region. The Plains States and mid continent region are also supplied by three product pipelines that originate from the Gulf Coast.
Crude Oil Supply.
Cheyenne Refinery. In the year ended December 31, 2002, we obtained approximately 37% of the Cheyenne refinery’s crude oil charge from Wyoming, 54% from Canada and 9% from Colorado. During the same period, heavy crude oil constituted approximately 90% of the Cheyenne refinery’s total crude oil charge. Cheyenne is 88 miles southwest of Guernsey, Wyoming, the main hub and crude oil trading center for the Rocky Mountain region. During 2001, an additional tank was added at Guernsey for heavy crude oil storage, with another expected to be completed in 2003. We transport up to 25,000 barrels per day of crude oil from Guernsey to the Cheyenne refinery through the Centennial pipeline. Additional crude oil volumes are transported on an alternative common carrier pipeline. 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/Platte and the eastern corridor pipeline system including the Wascana, Poplar and Butte pipelines. The Cheyenne refinery’s ability to process up to 100% heavy crude oil feedstocks gives us a distinct advantage over the four other Eastern Slope refineries, none of which has the necessary upgrading capacity to process high volumes of heavy crude oil. Upgrading capacity is the ability to produce a higher yield of higher margin refined products, such as gasoline and diesel, than would otherwise be possible using heavy crude oil feedstock.
We purchase crude oil for the Cheyenne refinery from a number of suppliers, including major oil companies, marketing companies and large and small independent producers, under arrangements which contain market-responsive pricing provisions. Many 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. In October 2002, we entered into a five-year crude oil supply agreement with Baytex Energy Ltd., a Canadian crude oil producer. On November 28, 2002 Baytex Energy Ltd. assigned this agreement to its wholly owned subsidiary, Baytex Marketing Ltd. This agreement, effective January 1, 2003, provides for the purchase of up to 20,000 barrels per day of a Lloydminster crude oil blend, a heavy Canadian crude. Initially, we will receive 9,000 barrels per day, increasing up to 20,000 barrels per day by October 2003. This type of crude oil typically sells at a discount to lighter crude oils. Our price for the crude oil under the agreement will be equal to 71% of the simple average of the near month settlement prices of the NYMEX light sweet crude oil contracts during the month of delivery, plus the cost of transportation based on the pipeline tariff from Hardisty, Alberta to Guernsey, Wyoming, less $0.25 per barrel. The initial term of the agreement is through December 31, 2007. This agreement provides a firm source of heavy Canadian crude and also assigns most of our dedicated capacity through the Express Pipeline.
El Dorado Refinery. In the year ended December 31, 2002, we obtained approximately 59% of the El Dorado refinery’s crude oil charge from Texas, 20% from Kansas, 8% from Latin America, 7% from the Middle East and 6% from the North Sea. El Dorado is 125 miles north of Cushing, Oklahoma, the location of 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 from West Texas; and the Mobil pipeline, which originates at the Gulf Coast and connects to the Basin pipeline at Wichita Falls. The Osage pipeline runs from Cushing to El Dorado and transported approximately 80% of our crude oil charge during the year ended December 31, 2002. The remainder of our crude oil charge is transported to the El Dorado refinery through Kansas gathering system pipelines.
We have a foreign crude oil supply agreement with Shell that expires July 2003, which may be renewed. Under this agreement, we may purchase crude oil for the El Dorado Refinery from Shell, although we are not obligated to do so. We are obligated to pay monthly installments towards an annualized commitment fee to Shell for making foreign crude volumes available to us under this agreement based on a per barrel fee for crude purchased under this agreement. This agreement allows us to use Shell’s worldwide network to acquire foreign crude oil. In the event that the crude supply agreement is not renewed, we will purchase all of our crude oil charge from various third parties and will continue to rely primarily on the Cushing hub and the Osage pipeline to supply crude oil to the El Dorado refinery.
Refinery Maintenance. Each of the operating units at our refineries requires regular 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 plan to coordinate operations by staggering turnarounds at the two refineries. Maintenance turnarounds are implemented using our regular personnel as well as some additional contract labor. Turnaround work typically proceeds on a continuous 24-hour basis to minimize unit downtime. We accrue for our turnaround costs. We normally schedule our maintenance turnaround work during the spring or fall of each year. When we perform a turnaround, we build product inventories prior to the turnaround to minimize the impact of the turnaround on our sales of refined products. We have major turnaround work scheduled at our El Dorado refinery during March and April 2003. Turnaround work is scheduled at our Cheyenne Refinery in the fall of 2003.
Safety and Lost Time Accidents. We are subject to the requirements of the federal Occupational Safety and Health Act (OSHA) and comparable state occupational safety statutes. We believe that we have operated in substantial compliance with OSHA requirements, including general industry standards, record keeping and reporting, hazard communication and process safety management. The nature of our business may result from time to time in industrial accidents. It is possible that changes in safety and health regulations or a finding of non-compliance with current regulations could result in additional capital expenditures or operating expenses.
Both refineries continued to experience OSHA recordable rates during 2002 that are greater than the national average for petroleum refineries. The behavioral safety program initiated in 2000 at the Cheyenne refinery has reversed the negative trend that had developed, but the results have not been as successful as expected. Frontier is very appreciative of the many employees at all levels of the organization who have made the behavioral safety program a personal success. Frontier continues to be committed to our behavioral safety program at Cheyenne because an individual behavioral approach changes the safety culture of the entire workforce, but will initiate in 2003 a more robust and aggressive management driven safety program to run parallel with the behavioral safety program. Frontier is determined to improve the safety record at the Cheyenne refinery and plans to devote additional resources to operate both safety programs.
While the safety record of the El Dorado refinery improved last year and is much better than the Cheyenne refinery, it is also above the national average for similar facilities. The employees and management dedicated their efforts to a balanced safety program that combines individual behavioral elements in a safety-coaching environment with very structured management driven programs to improve the safety of the facility and the operating procedures. The objective is a safe working environment for employees who know how to work safely. Frontier is determined to develop a culture based on safety. The operating plans and budgets for 2003 reflect our continued push for safety.
Environmental Matters. Our refining and marketing operations are subject to a variety of federal, state and local health and environmental laws and regulations governing product specifications, the discharge of pollutants into the air and water, and the generation, treatment, storage, transportation and disposal of solid and hazardous waste and materials. Numerous permits with varying terms of duration are required for the operation of our refineries, and these permits are subject to revocation, expiration, modification and renewal. Timely application for new permits and/or renewal of existing permits is undertaken as necessary to maintain compliance with applicable permitting requirements. Governmental authorities have the power to enforce compliance with these regulations and permits, and violators are subject to injunctions, civil fines and even criminal penalties. We believe that each of our refineries has obtained all necessary permits and is in substantial compliance with such permits, and other applicable existing environmental laws and regulations.
Rules and regulations implementing federal, state and local laws relating to health and the environment will continue to affect our operations, and we cannot predict what additional environmental legislation or regulations will be enacted or become effective in the future or how existing or future laws or regulations will be administered or interpreted with respect to products or activities to which they have not been applied previously. Compliance with more stringent laws or regulations, as well as more vigorous enforcement policies of regulatory agencies, could have a materially adverse effect on our financial position and results of operations as well as the refining industry in general, and may result in substantial expenditures for the installation and operation of pollution control or other environmental systems and equipment.
Our operations and many of the products we manufacture 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 installation of certain air pollution control devices at our refineries during the next several years. Subsequent rule making authorized by the CAA or similar laws or new agency interpretations of existing rules, may necessitate additional expenditures in future years. The Environmental Protection Agency (“EPA”) recently embarked on a Petroleum Refining Initiative (“Initiative”) alleging industry-wide noncompliance with certain rules. The Initiative has resulted in many refiners entering into consent decrees typically requiring substantial expenditures for penalties and additional pollution control equipment. We have been contacted by the EPA and invited to meet with them to hear more about the Initiative. At this time, we do not know how or if the Initiative will affect the Company. We have, however, recently determined that over the next three years, expenditures totaling approximately $10 million may be necessary to further reduce emissions from our refineries’ flare systems. Because other refineries will likely be required to make similar expenditures, we do not expect such expenditures to materially adversely impact our competitive position.
The CAA may authorize the EPA to require modifications in the formulation of the refined transportation fuel products we manufacture in order to limit the emissions associated with their final use. For example, on December 21, 1999, the EPA promulgated national regulations limiting the amount of sulfur that is to be allowed in gasoline. The EPA believes such limits are necessary to protect new automobile emission control systems that may be inhibited by sulfur in the fuel. The new regulations require the phase-in of gasoline sulfur standards beginning in 2004 and continuing through 2008, with special provisions for refiners serving those Western states exhibiting lesser air quality problems and for small business refiners, such as Frontier. Since we qualify as a small business refiner by having 1,500 or fewer employees and a capacity of less than 155,000 barrels per day during the specified pre-2001 baseline years, the Cheyenne and El Dorado refineries may comply with an interim gasoline sulfur standard in 2004 that is based on historic gasoline sulfur levels rather than having to meet the much stricter standard that will be applied to the general industry. Depending on the deadline we choose to comply with the new diesel sulfur limit (see discussion below), we will then have between four and seven additional years to reduce our gasoline sulfur content to the national standard. The total capital expenditures estimated, as of December 31, 2002, to achieve the final gasoline sulfur standard, are approximately $35 million at the Cheyenne refinery and approximately $45 million at the El Dorado refinery. Approximately $7.2 million of the Cheyenne Refinery expenditures had been incurred as of December 31, 2002, an additional $20.8 million is expected to be incurred by early 2004 with the remaining $7 million in 2009 and 2010. The expenditures for the El Dorado refinery are expected to be incurred beginning in 2008 and completed in 2010.
The EPA recently promulgated regulations that will limit the sulfur content of highway diesel fuel beginning in 2006 to 15 parts per million. The current standard is 500 parts-per-million. As a small business refiner, Frontier may choose to comply with the 2006 program and extend our interim gasoline standard by three years (until 2011) or delay the diesel standard by four years (until 2010) and keep our original gasoline sulfur program timing. Although still under deliberation, it is now likely that Frontier will choose to comply with 15 part-per-million highway diesel sulfur standard by June 2006 and extend our small refiner interim gasoline sulfur standards at each of our facilities until 2011. To satisfy a regulatory requirement necessary for the preservation of this compliance option, which is not the same compliance option we anticipated last year, we recently submitted an application for a highway diesel volumetric baseline to the EPA. As of December 31, 2002, capital costs for diesel desulfurization are estimated to be approximately $5 million for Cheyenne and $56 million for El Dorado. The Cheyenne Refinery expenditures are currently expected to be committed beginning in 2005, with the majority to be committed in 2006. Approximately $6 million of the El Dorado Refinery expenditures are currently expected to be committed in 2004 with the remaining $50 million in 2005 and 2006.
The EPA has recently stated their intent to propose new regulations that will limit emissions from diesel fuel powered engines used in off-road activities such as mining, construction and agriculture. The EPA has also stated their intent to simultaneously limit the sulfur content of diesel fuel used in these engines to facilitate compliance with the new emission standards. The EPA expects to propose the new off-road diesel engine emissions and related fuel sulfur standards early in 2003. It is likely that the new rules will require the off-road diesel fuel sulfur content to be reduced to 500 parts-per-million or less from the current limit of 5000 parts-per-million by 2007. Since a minor portion of the diesel fuel we manufacture at our El Dorado Refinery is sold to the off-road market, these regulations, when promulgated, will likely require certain modifications to the Refinery. The cost associated with such modifications cannot be estimated until the final regulatory limits are known.
We are aware of public concern regarding possible groundwater contamination resulting from the use of MTBE (methyl tertiary butyl ether) as a source of required oxygen in gasolines sold in specified areas of the country. Gasoline containing a specified amount of oxygen is required by the EPA to be used in those regions that exceed the National Ambient Air Quality Standards for either ozone or carbon monoxide. That oxygen requirement may be satisfied by adding to gasoline any one of many oxygen-containing materials including, among others, MTBE and also ethanol, an oxygen containing compound that is manufactured primarily from “renewable” agricultural products and that has not been shown to exhibit the environmental concerns associated with MTBE. Ethanol serves as an oxygenate, an octane booster and as an extender of gasoline. Through a blending terminal, Frontier currently supplies ethanol “oxygenated” gasoline to the Denver metropolitan area, a region that has historically exceeded the National Ambient Air Quality Standard for carbon monoxide during the winter months, from both our Cheyenne and our El Dorado refineries. Both refineries use only ethanol as the oxygen-containing additive. Under Texaco ownership, the El Dorado refinery used MTBE from 1988 until 1991. In the past, MTBE was occasionally added to a small percentage of gasoline from our Cheyenne refinery at the request of certain customers. Frontier is not aware of any environmental concerns or claims related to the supply, distribution or use of its oxygen additives or oxygenated products.
Our operations are also subject to the Clean Water Act (“CWA”) and comparable state and local requirements. The CWA and analogous laws prohibit any discharge into surface waters and ground waters except in strict conformance with permits, such as National Pollutant Discharge Elimination System (“NPDES”) permits, issued by federal and state governmental agencies. NPDES permits and analogous water discharge permits are valid for a maximum of five years and must be renewed. In addition, changes in our operations may require us to modify our permits. When permits are modified or renewed, we may be required to update our wastewater treatment facilities to comply with potentially stricter discharge limits. No material capital expenditures are currently anticipated to be necessary to maintain our compliance with CWA requirements.
We generate wastes that may be subject to the Resource Conservation and Recovery Act (“RCRA”) and comparable state and local requirements. The EPA and various state agencies have limited the approved methods of disposal for certain hazardous and nonhazardous wastes. Some of the disposal methods we used in the past are no longer allowed or are substantially limited. This may cause us to incur additional costs for the disposal of wastes and the maintenance or closure of waste disposal areas. Because other refineries will be required to make similar expenditures, we do not expect such expenditures to materially adversely impact our competitive position. No capital expenditures other than those potential cleanup and remediation matters identified in the discussion of the Cheyenne Refinery are currently anticipated to be necessary to maintain our compliance with RCRA requirements.
The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as “Superfund,” imposes liability, without regard to fault or the legality of the original conduct, on certain classes of persons, including past owners and operators, who are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include the current and/or former owner(s) or operator(s) of the disposal site or sites where the release occurred and the current and/or former owners or operators of companies or facilities that disposed or arranged for the disposal of the hazardous substances. Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment. Analogous state laws impose similar responsibilities and liabilities on responsible parties. In the course of our historical operations, as well as in our current ordinary operations, we have generated waste, some of which falls within the statutory definition of a “hazardous substance” and some of which may have been disposed of at sites that may require cleanup under Superfund. We are not aware of any existing or potential CERCLA liability that would result in capital costs material to the Company.
In 1997, we completed the divestiture of our former oil and gas properties and assets. While the transactions that conveyed these properties and assets to new owners were intended to transfer any attendant environmental liabilities to the new owners, we cannot assure you that we will never be subject to liability for any former activity respecting the divested oil and gas properties. Prior to the divestiture, we were named as a potentially responsible party (“PRP”) under CERCLA at the Gulf Coast Vacuum Services Superfund Site located in Vermilion Parish, Louisiana. We have entered into a consent decree resolving our liabilities as a PRP at this Superfund site. The site has since been cleaned up to the satisfaction of the EPA and the State of Louisiana and was subsequently removed from the National Priority List (“NPL”) by EPA direct final rule on May 22, 2001 (28093 – 28096 Federal Register / Vol. 66, No. 99 / Tuesday, May 22, 2001 / Rules and Regulations). In accordance with the decree, Frontier was assessed and has paid in full a 1.2717% share of the final site cleanup cost of $179,490 equaling $2,284. We believe that any future liabilities related to this site will not have a material adverse effect on our financial condition. We also believe that any liability relating to our historical practices respecting the oil and gas properties will not have a material adverse effect on our financial condition, results of operations or business.
As is the case with all companies engaged in similar industries, we face potential exposure from future claims and lawsuits involving environmental matters. The matters include soil and water contamination, air pollution, personal injury and property damage allegedly caused by substances which we manufactured, handled, used, released or disposed of.
Cheyenne Refinery. We are party to an agreement with the State of Wyoming requiring the investigation and possible eventual remediation of certain areas of the Cheyenne refinery’s property which may have been impacted by past operational activities. Prior to this agreement, we addressed tasks required under a consent decree entered by the Wyoming State District Court on November 28, 1984 and involving the State of Wyoming, the Wyoming Department of Environmental Quality (“WDEQ”) and the predecessor owners of the Cheyenne refinery. This action primarily addressed the threat of groundwater and surface water contamination at the Cheyenne refinery. As a result of these investigative efforts, substantial capital expenditures and remediation of conditions found to exist have already taken place or are in progress, including the completion of surface impoundment closures, waste stabilization activities and other site remediation projects totaling approximately $4 million and an ongoing groundwater remediation program averaging $150,000 in annual operation and maintenance costs. Additionally, the EPA issued an administrative consent order with respect to the Cheyenne refinery on September 24, 1990 pursuant to RCRA. Among other things, this order required a technical investigation of the Cheyenne refinery to determine if certain areas have been adversely impacted by past operational activities. Based upon the results of the investigation, additional remedial action could be required by a subsequent administrative order or permit.
On March 21, 1995, we entered into an administrative consent order with the WDEQ that generally parallels the federal order and replaces the 1984 Wyoming consent decree. Accordingly, the earlier consent decree was dismissed in an order entered March 21, 1995. The new consent decree eliminates some of the earlier consent decree’s requirements, unifies state and federal regulatory expectations regarding site investigation and remediation and, consequently, helps to streamline certain of our current environmental obligations. The EPA withdrew the September 24, 1990 federal order on March 19, 1997 in recognition of Wyoming’s assumption of RCRA corrective action authority. In 1999, a scope of work for the site investigation was agreed upon with the WDEQ and work was initiated to determine the existence and extent of any historic soils contamination. At the same time, an understanding was reached with the WDEQ that any non-safety related on-site remedial activities identified could be scheduled subsequent to eventual facility closure. The ultimate cost of any environmental remediation projects that may be identified by the site investigation required by the new consent order cannot be reasonably estimated at this time.
On October 10, 2001, the First Judicial District Court of the State of Wyoming terminated a consent decree previously entered into by Frontier Refining Inc. (Cheyenne Refinery) and the WDEQ in recognition of the completion by Frontier of the requirements of the decree. Completion of the terms of the decree, which combined resolution of two separate notices of violation alleging non-compliance with certain administrative requirements related to the facility’s air emission permit, included, in part, payment by the Company of a penalty in the amount of $105,000 and completion of certain supplemental environmental projects.
El Dorado Refinery. The El Dorado refinery is subject to a 1988 consent order with the Kansas Department of Health and the Environment (“KDHE”). This order, including various subsequent modifications, requires the refinery to continue the implementation of a groundwater management program with oversight provided by the KDHE Bureau of Environmental Remediation. More specifically, the 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. Subject to the terms of the purchase and sale agreement, Shell will be responsible for the costs of continued compliance with this order.
The most recent National Pollutant Discharge Elimination System (“NPDES”) permit issued to the El Dorado refinery requires, in part, the preparation and submittal of an engineering report identifying certain refinery wastewater treatment plant upgrades necessary to allow routine compliance with applicable discharge permit limits. In accordance with the provisions of the purchase and sale agreement, Shell will be responsible for the first $2 million of any required wastewater treatment system upgrades. If required system upgrade costs exceed this amount, Shell and Frontier will share, based on a sliding scale percentage, up to another $3 million in upgrade costs. Subject to the terms of the purchase and sale agreement, Shell will be responsible for up to $5 million in costs, in addition to Shell’s obligation for the wastewater treatment system upgrade, relating to safety, health and environmental conditions after closing arising from Shell’s operation of the El Dorado refinery that are not covered under a ten-year insurance policy. This insurance policy has $25 million coverage through November 17, 2009 for environmental liabilities, with a $500,000 deductible, and will reimburse us for losses related to all known and some unknown conditions existing prior to our acquisition of the El Dorado refinery. The first phase of wastewater treatment system upgrades was completed in 2001 at a cost of $2.6 million with payment apportioned as described above.
On August 18, 2000, we entered into a Consent Agreement and Final Order of the Secretary with the KDHE that required the initiation of a wastewater toxicity testing program to commence upon the completion of the wastewater treatment upgrades described above. The Company further agreed to undertake a program designed to identify and remedy any wastewater toxicity non-compliance issues remaining after the first phase of wastewater treatment system upgrades were completed. Wastewater toxicity testing subsequent to the commissioning of the upgrades did not confirm satisfactory, routine compliance with permit limits. As a result, we submitted,and the KDHE approved, a Toxicity Identification and Elimination plan that we believe will facilitate resolution of the remaining wastewater quality concerns. Good progress has since been made toward satisfying the provisions of the Agreement and we expect to meet all applicable requirements.
Centennial Pipeline Regulation. We have a 34.72% undivided ownership interest in the Centennial pipeline. Conoco Pipe Line Company is the sole operator of the Centennial pipeline as well as the holder of the remaining ownership interest. The Centennial pipeline runs approximately 80 miles from Guernsey to Cheyenne, Wyoming. The Cheyenne refinery receives up to 25,000 barrels per day of crude oil feedstock through the Centennial pipeline. Under the terms of the operating agreement for the Centennial pipeline, the costs and expenses incurred to operate and maintain the Centennial pipeline are allocated to us on a combined basis, based on our throughput and our ownership interest. The Centennial pipeline is subject to numerous federal, state and local laws and regulations relating to the protection of health, safety and the environment. We believe that the Centennial pipeline is operated in accordance with all applicable laws and regulations. We are not aware of any material pending legal proceedings to which the Centennial pipeline is a party.
At December 31, 2002, we employed approximately 736 full-time employees in the refining operations, 66 of whom were in the Houston and Denver offices, 266 at the Cheyenne refinery, 399 at the El Dorado refinery and 5 at our 50% owned asphalt terminal in Grand Island, Nebraska. The Cheyenne refinery employees include 94 administrative and technical personnel and 172 union members. The El Dorado refinery employees include 126 administrative and technical personnel and 273 union members. The union members at our Cheyenne refinery are represented by seven bargaining units, the largest being the Paper, Allied-Industrial, Chemical and Energy Workers International Union (PACE) and the others being affiliated with the AFL-CIO. At the Cheyenne refinery, our current contract with PACE expires in July 2006 while our current contract with the AFL-CIO affiliated unions expires in June 2009. At the El Dorado refinery, all union members are represented by PACE and our current contract with PACE expires in January 2006.
We depend upon our subsidiaries for cash to meet our debt obligations. Our ability to obtain cash from our subsidiaries may be restricted by our banks.
We are a holding company. Our subsidiaries conduct all of our consolidated operations and own substantially all of our consolidated assets. Consequently, our cash flow and our ability to meet our debt service obligations depend upon the cash flow of our subsidiaries and the payment of funds by our subsidiaries to us in the form of dividends, tax sharing payments or otherwise. Their ability to make any payments will depend on their earnings, the terms of their indebtedness, tax considerations and legal restrictions. We have no special purpose entities (SPE’s).
Specifically, our subsidiaries are prohibited from transferring cash in the form of dividends, loans or advances when there are any cash advances outstanding under the credit facility or when there is a default or event of default under the credit facility. The credit facility includes certain financial covenant requirements relating to our working capital, tangible net worth and earnings before interest, taxes, depreciation and amortization. Borrowing under the credit facility also must be reduced to zero for at least five consecutive business days during each calendar year. If we do not do this, an event of default occurs under our credit facility. Accordingly, the existence of borrowing or a default or event of default under our credit facility could adversely affect our ability to have sufficient cash to pay our obligations.
We have significant indebtedness that may affect our ability to operate our business.
As of December 31, 2002, we had $208 million principal amount of total consolidated debt, and we may incur other indebtedness in the future, including borrowing under our $175 million credit facility.
Our high level of indebtedness could have important consequences, such as:
| • | limiting our ability to obtain additional financing to fund our working capital, expenditures, debt service requirements or for other purposes; |
| • | limiting our ability to use operating cash flow in other areas of our business because we must dedicate a substantial portion of these funds to service debt; |
| • | limiting our ability to compete with other companies who are not as highly leveraged; and |
| • | limiting our ability to react to changing market conditions, in our industry and in our customers' industries and economic downturns. |
Our ability to satisfy our debt obligations will depend upon our future operating performance. Prevailing economic conditions and financial, business and other factors, many of which are beyond our control, will affect our ability to make payments on our debt obligations. If we cannot generate sufficient cash from operations to meet our other obligations, we may need to refinance or sell assets. Our business may not generate sufficient cash flow, or we may not be able to obtain sufficient funding, to make the payments required by all of our debt.
Crude oil prices and refining margins significantly impact our cash flow and have fluctuated significantly in the past.
Our cash flow from operations is primarily dependent upon producing and selling quantities of refined products at margins that are high enough to cover our fixed and variable expenses. In recent years, crude oil costs and crack spreads 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; and |
| • | the extent of government regulation. |
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 prices we receive for our refined products are affected by:
| • | global market dynamics; |
| • | product pipeline capacity; |
| • | local market conditions, and |
| • | the level of operations of other refineries in the Plains States and the Rocky Mountain region. |
The price at which we can sell gasoline and other refined products is strongly influenced by the commodity 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. From time to time, we purchase forward crude oil supply contracts, have entered into forward product agreements to hedge excess inventories and for the El Dorado refinery, we have hedged our refined product margins.
In addition, our refineries maintain inventories of crude oil, intermediate products and refined products, the value of each being subject to rapid fluctuations in market prices. We record our inventories at the lower of cost (as determined on a FIFO basis) or market price. 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 linked to the light/heavy crude oil price spread, which declined during the first quarter of 2002 and remained low for three quarters in 2002, but began to widen during the fourth quarter. Light/heavy spreads for 2002 were significantly lower than in 2001.
Our profitability, particularly at the Cheyenne refinery, is linked to the price spread between light and heavy crude oil. We prefer to refine heavy crude oil because it provides a wider refining margin than light crude does. Accordingly, any tightening of the light/heavy spread will reduce our profitability. Crude prices were low at the beginning of 2002 making it uneconomical for companies to produce heavy crude oil, which sells at a discount to light crude. Although crude prices rose gradually during 2002, the light/heavy spread only began to widen again in the fourth quarter. Crude oil prices may not remain at their current levels and the light/heavy spread may decline again.
External factors beyond our control can cause fluctuations in demand for our products and in our prices and margins, which may negatively affect income and cash flow.
External factors can also cause significant fluctuations in demand for our products and volatility in the prices for our products and other operating costs and can magnify the impact of economic cycles on our business. Examples of external factors include:
| • | general economic conditions; |
| • | competitor actions; |
| • | availability of raw materials; |
| • | international events and circumstances; and |
| • | governmental regulation in the United States and abroad, including changes in policies of the Organization of Petroleum Exporting Countries. |
Demand for our products is influenced by general economic conditions. For example, refined product margins and crude oil differentials in 2001 were at near record levels. After experiencing such record levels, refined product margins and crude oil differentials declined substantially in 2002. This decline was attributed to unusually high prices for oil, reduced market demand for refined products and greater imports of competitive products, all of which adversely affected our results of operations in 2002. The existence of similar economic and market conditions in the future may have a negative impact on our business and financial results.
Our refineries face operating hazardsand the potential limits on insurance coverage could expose us to potentially significant liability costs.
Our operations are subject to significant interruption and our profitability is impacted if any of our refineries experiences a major accident or fire, is damaged by severe weather or other natural disaster, or otherwise is forced to curtail its operations or shut down. If a pipeline becomes inoperative, crude oil would have to be supplied to these refineries through an alternative pipeline or from additional tank trucks to the refinery, which could hurt our business and profitability. In addition, a major accident, fire or other event could damage a refinery or the environment or cause personal injuries. If a refinery 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 a long time. One or more of the units may require additional, unscheduled down time, or “turnaround”, for unanticipated maintenance or repairs that is more frequent than our scheduled turnaround for each unit every one to five years. Scheduled and unscheduled turnarounds could reduce our revenues during the period of time that our units are not operating.
As our commitment to Shell under the refined product offtake agreement declines, we will have to find new customers for the gasoline and diesel fuel produced at the El Dorado refinery. Wemay not be able to do this successfully.
In connection with the purchase of the El Dorado refinery in 1999, we entered into a 15-year refined product offtake agreement with Shell. Under this agreement, Shell purchases most of the gasoline and diesel production of the of the El Dorado refinery at market-based prices. Initially, Shell purchased substantially all of the El Dorado refinery’s production of these products. Beginning in 2000, we retained and marketed a portion of the refinery’s gasoline and diesel production. This portion has increased and will continue to increase by 5,000 barrels per day each year for ten years, beginning at 5,000 barrels per day in 2000, rising to 50,000 barrels per day by 2009 and remaining at this level through the term of this agreement. Shell will purchase substantially all gasoline and diesel production in excess of these amounts. The offtake agreement also provides for Shell to purchase all jet fuel production from the El Dorado refinery for five years (through most of 2004). Since we will have to market an increasing portion of the El Dorado refinery’s gasoline and diesel production over the next ten years, as well as jet fuel after 2004, we will have to find new customers for these refined products. These customers may be in markets that we have not previously sold to, and it may be difficult for us to find customers for these products. If we cannot find customers in locations convenient to the El Dorado refinery, our revenues and profits may be reduced.
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 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.
Our operating results are seasonal and generally lower in the first and fourth quarters of the year.
Demand for gasoline and asphalt products is generally higher during the summer months than during the winter months due to seasonal increases in highway traffic and road construction work. As a result, our operating results for the first and fourth calendar quarters are generally lower than for those for the second and third quarters. Diesel demand has historically been more stable because two major east-west truck routes and two major railroads cross one of our principal marketing areas. However, reduced road construction and agricultural work during the winter months does somewhat depress demand for diesel in the winter months.
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 resulting from compliance 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 a variety of federal, state and local environmental 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 and 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. For the amount of potential costs associated with such compliance, see “Business-Government Regulation-Environmental Matters.”
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, may 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 may involve contamination associated with facilities we currently own or operate, facilities 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 maybe 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 some 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. For the amount of potential clean-up costs, see “Business-Government Regulation-Environmental Matters.”
We may have labor relations difficulties with some of our employees represented by unions.
Approximately 59 percent of our employees were covered by collective bargaining agreements at December 31, 2002. We believe that our current relations with our employees are good. However, employees may conduct a strike at some time in the future, which may adversely affect our operations. See “Business-Employees.”
Terrorist attacks and threats or actual war may negatively impact our business.
Terrorist attacks in the United States, 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, may adversely impact our 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 extension for time for payment of accounts receivable from our customers.
We file reports with the Securities and Exchange Commission (“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 we file with the SEC at the SEC’s Public Reference Room at 450 Fifth Street, NW, 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 maintains an Internet site athttp://www.sec.gov that contains the reports, proxy and information statements, and other information filed electronically.
Our website address is:http://www.frontieroil.com.
We make available free of charge through our web site, the annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and all amendments to those report as soon as reasonably practicable after such material is electronically filed with or furnished to the SEC.
We own the 125 acre site of the Cheyenne refinery in Cheyenne, Wyoming and the 1,100 acre site of the El Dorado refinery in El Dorado, Kansas. The following tables sets forth the refining operating statistical information on a consolidated basis and for each refinery for 2002, 2001 and 2000.
Year Ended December 31, 2002 2001 2000
- -------------------------------------------------------------------------------------------------------------------
Charges (bpd) (1)
Light crude 35,684 31,456 35,605
Heavy and intermediate crude 110,372 111,061 105,529
Other feed and blend stocks 17,760 15,538 14,884
----------- ----------- -----------
Total 163,816 158,055 156,018
Manufactured product yields (bpd) (2)
Gasoline 84,645 78,126 76,795
Diesel and jet fuel 53,436 51,210 50,924
Asphalt 7,437 6,067 7,407
Chemicals (3) 369 1,370 1,804
Other 14,915 18,416 15,956
----------- ----------- -----------
Total 160,802 155,189 152,886
Total product sales (bpd)
Gasoline 91,989 83,737 83,070
Diesel and jet fuel 53,378 51,539 51,568
Asphalt 7,490 6,875 6,490
Chemicals (3) 439 1,413 1,964
Other 13,236 15,536 15,066
----------- ----------- -----------
Total 166,532 159,100 158,158
Refinery operating margin information (per sales bbl)
Refined product revenue $ 29.82 $ 32.53 $ 35.20
Raw material, freight and other costs (FIFO inventory accounting) 25.71 25.69 30.41
Refinery operating expenses, excluding depreciation 2.93 3.27 3.07
Refinery depreciation .44 .42 .39
----------- ---------- -----------
Operating margin $ .74 $ 3.15 $ 1.33
Average West Texas Intermediate crude oil price at Cushing, OK $ 26.17 $ 26.09 $ 31.25
Average sales price (per sales bbl)
Gasoline $ 33.08 $ 35.85 $ 38.09
Diesel and jet fuel 30.35 34.12 37.19
Asphalt 21.64 22.81 25.39
Chemicals (3) 41.68 70.81 70.52
Other 9.24 10.21 12.16
| (1) | Charges are the quantity of crude oil and other feedstock processed through refinery units. |
| (2) | Manufactured product yields are the volumes of specification materials that are obtained through the distilling of crude oil and the operations of other refinery process units. |
| (3) | During 2002, the process of shutting down the phenol and cumene units at El Dorado began and by year-end we had discontinued the production of phenol and acetone and began producing and selling benzene. |
Year Ended December 31, 2002 2001 2000
- -------------------------------------------------------------------------------------------------------------------
Charges (bpd) (1)
Light crude 4,070 3,390 2,465
Heavy crude 37,231 32,790 36,568
Other feed and blend stocks 4,882 4,626 4,996
----------- ----------- -----------
Total 46,183 40,806 44,029
Manufactured product yields (bpd) (2)
Gasoline 18,196 15,956 17,441
Diesel 13,434 12,091 12,542
Asphalt 7,437 6,067 7,407
Other 5,855 5,590 5,425
----------- ----------- -----------
Total 44,922 39,704 42,815
Total product sales (bpd)
Gasoline 24,559 21,090 22,492
Diesel 13,361 12,031 12,583
Asphalt 7,490 6,875 6,490
Other 4,243 3,877 4,804
----------- ----------- -----------
Total 49,653 43,873 46,369
Refinery operating margin information (per sales bbl)
Refined product revenue $ 29.91 $ 32.88 $ 34.19
Raw material, freight and other costs (FIFO inventory accounting) 25.18 24.85 28.51
Refinery operating expenses, excluding depreciation 3.02 3.39 2.83
Refinery depreciation .83 .85 .73
Average light/heavy crude spread based on delivered
crude costs (per bbl) (3) $ 4.24 $ 7.07 $ 5.09
Average sales price (per sales bbl)
Gasoline $ 35.22 $ 38.81 $ 40.03
Diesel 32.16 36.40 39.22
Asphalt 21.64 22.81 25.39
Other 6.68 7.58 5.61
| (1) | Charges are the quantity of crude oil and other feedstock processed through refinery units. |
| (2) | Manufactured product yields are the volumes of specification materials that are obtained through the distilling of crude oil and the operations of other refinery process units. |
| (3) | Average light/heavy spread is the discount at which heavy crude oil (gravity is low) sells compared to the sales price of light crude oil (gravity is high). |
Year Ended December 31, 2002 2001 2000
- -------------------------------------------------------------------------------------------------------------------
Charges (bpd) (1)
Light crude 31,614 28,066 33,140
Heavy and intermediate crude 73,141 78,272 68,961
Other feed and blend stocks 12,878 10,912 9,888
----------- ----------- -----------
Total 117,633 117,250 111,989
Manufactured product yields (bpd) (2)
Gasoline 66,449 62,170 59,354
Diesel and jet fuel 40,002 39,119 38,382
Chemicals (3) 369 1,370 1,804
Other 9,061 12,825 10,531
----------- ----------- -----------
Total 115,881 115,484 110,071
Total product sales (bpd)
Gasoline 67,430 62,646 60,579
Diesel and jet fuel 40,017 39,508 38,985
Chemicals (3) 439 1,413 1,964
Other 8,993 11,659 10,262
----------- ----------- -----------
Total 116,879 115,226 111,790
Refinery operating margin information (per sales bbl)
Refined product revenue $ 29.78 $ 32.40 $ 35.62
Raw material, freight and other costs (FIFO inventory accounting) 25.93 26.01 31.20
Refinery operating expenses, excluding depreciation 2.90 3.22 3.17
Refinery depreciation .28 .26 .25
WTI/WTS crude spread (per bbl) (4) $ 1.36 $ 3.10 $ 2.06
Average sales price (per sales bbl)
Gasoline $ 32.30 $ 34.85 $ 37.37
Diesel and jet fuel 29.75 33.43 36.53
Chemicals (3) 41.68 70.81 70.52
Other 10.45 11.08 15.22
| (1) | Charges are the quantity of crude oil and other feedstock processed through refinery units. |
| (2) | Manufactured product yields are the volumes of specification materials that are obtained through the distilling of crude oil and the operations of other refinery process units. |
| (3) | During 2002, the process of shutting down the phenol and cumene units at El Dorado began and by year-end we had discontinued the production of phenol and acetone and began producing and selling benzene. |
| (4) | Average differential between benchmark West Texas intermediate (sweet) and West Texas sour crude oil prices. |
We lease approximately 6,500 square feet of office space in Houston for our corporate headquarters under a six and one half year lease expiring in October 2004. For our refining operations headquarters, we lease approximately 25,000 square feet in Denver, Colorado under a four and a half year sublease expiring in December 2006.
We are not a party to any material pending legal proceedings. We are a party to ordinary routine litigation incidental to our business.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
The registrant’s common stock is listed on the New York Stock Exchange under the symbol FTO. The quarterly high and low sales prices as reported on the New York Stock Exchange, for 2002 and 2001 are shown in the following table:
- ------------------------ ---------------- ----------------
2002 High Low
- ------------------------ ---------------- ----------------
Fourth quarter $ 17.61 $ 10.68
Third quarter 17.50 11.47
Second quarter 22.75 14.66
First quarter 21.90 15.94
- ------------------------ ---------------- ----------------
2001 High Low
- ------------------------ ---------------- ----------------
Fourth quarter $ 20.25 $ 14.65
Third quarter 17.00 10.80
Second quarter 16.75 7.55
First quarter 8.99 6.38
- ------------------------ ---------------- ----------------
The approximate number of holders of record for Frontier Oil Corporation common stock as of February 28, 2003 was 1,196.
Quarterly cash dividends of $.05 per share have been declared on the registrant’s common stock for each quarter beginning with the quarter ended June 2001 and through the most recent quarter ended December 31, 2002.
Under certain conditions, the revolving credit facility at the subsidiary level restricts the transfer of cash in the form of dividends, loans or advances from the operating subsidiary to the parent holding company.
Equity Compensation Plan Information as of December 31, 2002
- -------------------------------- ----------------------------- ----------------------------- -----------------------------
Number of securities
remaining available
Number of securities for future issuance
to be issued upon Weighted-average under equity
exercise of exercise price of compensation plans
outstanding options outstanding options, (excluding securities
warrants and rights warrants and rights reflected in column (a))
Plan Category (a) (b) (c)
- -------------------------------- ----------------------------- ----------------------------- -----------------------------
Equity compensation
plans approved by 2,581,250 $11.18 985,650
security holders
- -------------------------------- ----------------------------- ----------------------------- -----------------------------
Equity compensation
plans not approved 0 (1) n/a 681,303 (2)
by security holders
- -------------------------------- ----------------------------- ----------------------------- -----------------------------
Total 2,581,250 $11.18 1,666,953
- -------------------------------- ----------------------------- ----------------------------- -----------------------------
| (1) | Does not include an aggregate of 294,697 shares of restricted stock granted under the Frontier Oil Corporation Restricted Stock Plan which will vest in the years 2003 through 2005. |
| (2) | Represents 639,303 shares of treasury stock reserved for issuance with respect to grants of restricted stock which may be made to employees under the Frontier Oil Corporation Restricted Stock Plan and 42,000 shares of treasury stock reserved for issuance with respect to grants of stock which may be made under the 1995 Stock Grant Plan for Non-employee Directors. |
The Frontier Oil Corporation Restricted Stock Plan (the “Restricted Stock Plan”) is administered by the Compensation Committee of the Board of Directors. Any key employee, as determined by the Compensation Committee, is eligible to be granted shares of restricted stock under the Restricted Stock Plan. Upon delivery of shares of restricted stock, the participant generally has, subject to the restrictions contained in his or her award agreement, all rights of a shareholder, including the right to vote and receive dividends, if any. Shares granted under the Restricted Stock Plan vest as provided in his or her award agreement, except that the shares automatically vest upon a change in control of the Company. Subject to certain exceptions, shares of restricted stock may not be transferred unless and until the shares have been issued and all restrictions on the shares have lapsed. The Restricted Stock Plan provides for the grant of restricted stock to acquire up to 1,000,000 shares.
The Company’s 1995 Stock Grant Plan for Non-Employee Directors (the “1995 Plan”) is administered by a committee consisting of directors who are not eligible to participate in the 1995 Plan. All active members of the Company’s Board of Directors who are not employees of the Company or any of its subsidiaries or affiliates as of the date of any stock grant are eligible to receive stock under the 1995 Plan. Under the 1995 Plan, each eligible director is automatically granted 500 shares of Company common stock, as adjusted for dilutive effects, on the first day of every fifteenth month commencing April 1, 1995. The 1995 Plan provides for the grant of up to 60,000 shares of stock and will terminate on December 31, 2004, if not terminated earlier.
ITEM 6. SELECTED FINANCIAL DATA
(in thousands except per share) 2002 2001 2000 1999 (1) 1998
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Revenues $1,813,750 $1,888,401 $2,045,157 $503,600 $299,368
Operating income (loss) 27,899 164,100 70,655 (5,249) 25,700
Income (loss) before extraordinary item 1,028 107,653 37,206 (17,061) 18,818
Extraordinary loss, net of taxes - - - - 3,013
Net income (loss) 1,028 107,653 37,206 (17,061) 15,805
Basic earnings (loss) per share:
Before extraordinary item 0.04 4.12 1.36 (0.62) 0.67
Net income (loss) 0.04 4.12 1.36 (0.62) 0.56
Diluted earnings (loss) per share:
Before extraordinary item 0.04 4.00 1.34 (0.62) 0.65
Net income (loss) 0.04 4.00 1.34 (0.62) 0.55
Net cash (used in) provided by operating activities 50,822 138,575 66,346 (11,332) 31,263
Net cash used in investing activities (37,117) (22,824) (12,688) (181,703) (16,763)
Net cash provided by (used in) financing activities (5,336) (76,202) (27,557) 197,791 (2,646)
Working capital 108,253 109,064 43,610 24,832 30,125
Total assets 628,877 581,746 588,213 521,493 182,026
Long-term debt 207,966 208,880 239,583 257,286 70,000
Shareholders' equity 168,258 169,204 81,424 50,681 70,353
Capital expenditures 37,117 22,824 12,688 181,703 16,763
Dividends declared per common share 0.20 0.15 - - -
EBITDA (2) 55,231 189,110 93,662 7,799 33,397
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| (1) | Includes El Dorado Refinery financial data from November 17, 1999. Capital expenditures in 1999 included the purchase of the El Dorado Refinery. |
| (2) | EBITDA represents income before interest expense, interest income, income tax, and depreciation and amortization. EBITDA is not a calculation based upon generally accepted accounting principles; however, the amounts included in the EBITDA calculation are derived from amounts included in the consolidated financial statements of the Company. EBITDA should not be considered as an alternative to net income or operating income, as an indication of operating performance of the Company or as an alternative to operating cash flow as a measure of liquidity. EBITDA is not necessarily comparable to similarly titled measures of other companies. EBITDA is presented here because it enhances an investor's understanding of Frontier's ability to satisfy principal and interest obligations with respect to Frontier's indebtedness and to use cash for other purposes, including capital expenditures. EBITDA is also used for internal analysis and as a basis for financial covenants. Frontier's EBITDA for each of the years in the five-year period ended December 31, 2002 is reconciled to net income as follows: |
2002 2001 2000 1999 1998
----------- ------------- ------------ ------------ -----------
(in thousands)
Net income (loss) $1,028 $107,653 $37,206 ($17,061) $15,805
Add provision for income taxes 1,060 28,073 2,075 1,865 150
Add interest expense and other financing costs 27,613 31,146 34,738 11,447 8,232
Subtract interest income (1,802) (2,772) (3,364) (1,500) (1,500)
Add depreciation and amortization 27,332 25,010 23,007 13,048 10,710
----------- ------------- ------------ ------------ -----------
EBITDA $55,231 $189,110 $93,662 $7,799 $33,397
=========== ============= ============ ============ ===========
2002 2001 2000 1999 (1) 1998
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Charges (bpd) (2)
Light crude 35,684 31,456 35,605 10,250 2,174
Heavy crude (3) 110,372 111,061 105,529 39,315 32,303
Other feed and blend stocks 17,760 15,538 14,884 7,589 5,909
------ ------ ------ ----- -----
Total charges 163,816 158,055 156,018 57,154 40,386
Manufactured product yields (bpd) (4)
Gasoline 84,645 78,126 76,795 24,923 15,738
Diesel and jet fuel 53,436 51,210 50,924 17,340 13,097
Chemicals (5) 369 1,370 1,804 232 -
Asphalt and other 22,352 24,483 23,363 12,982 10,236
------ ------ ------ ------ ------
Total manufactured product yields 160,802 155,189 152,886 55,477 39,071
Product sales (bpd)
Gasoline 91,989 83,737 83,070 29,728 21,421
Diesel and jet fuel 53,378 51,539 51,568 17,156 12,484
Chemicals (5) 439 1,413 1,964 44 -
Asphalt and other 20,726 22,411 21,556 10,965 8,797
------ ------ ------ ------ -----
Total product sales 166,532 159,100 158,158 57,893 42,702
Average sales price (per bbl)
Gasoline $33.08 $35.85 $38.09 $26.61 $21.52
Diesel and jet fuel 30.35 34.12 37.19 25.92 19.90
Chemicals (5) 41.68 70.81 70.52 57.50 -
Asphalt and other 13.72 14.07 16.14 12.36 12.07
Refinery operating margin information (per sales bbl)
Refined product revenue $29.82 $32.53 $35.20 $23.73 $19.10
Raw material, freight and other costs 25.71 25.69 30.41 20.31 13.33
Operating expenses excluding depreciation 2.93 3.27 3.07 2.71 3.02
Refinery depreciation 0.44 0.42 0.39 0.61 0.68
Average light/heavy spread based on delivered crude
costs for the Cheyenne Refinery (per bbl) (6) $4.24 $7.07 $5.09 $2.17 $4.15
Average WTI/WTS crude oil spread (per bbl) (7) $1.36 $3.10 $2.06 n/a n/a
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| (1) | Includes El Dorado Refinery operating data from the date of acquisition, November 17, 1999. |
| (2) | Charges are the quantity of crude oil and other feedstock processed through refinery units. |
| (3) | Includes intermediate varieties of crude oil used by the El Dorado Refinery. |
| (4) | Manufactured product yields are the volumes of specification materials that are obtained through the distilling of crude oil and the operations of other refinery process units. |
| (5) | During 2002, the process of shutting down the phenol and cumene units at El Dorado began and by year-end Frontier had discontinued the production of phenol and acetone, and began producing and selling benzene. |
| (6) | Average light/heavy spread is the discount at which heavy crude oil (gravity is low) sells compared to the sales price of light crude oil (gravity is high). |
| (7) | Average differential between benchmark West Texas intermediate (sweet) and West Texas sour crude oil prices. |
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The terms “Frontier” and “we” refer to Frontier Oil Corporation and its subsidiaries. Frontier operates refineries (the “Refineries”) in Cheyenne, Wyoming and El Dorado, Kansas with a combined crude oil capacity of 156,000 barrels per day. The Company focuses its marketing efforts in the Rocky Mountain and Plains States regions of the United States. The Company purchases the crude oil to be refined and markets the refined petroleum products produced, including various grades of gasoline, diesel fuel, jet fuel, asphalt and chemicals.
2002 Compared with 2001. We had net income for the year ended December 31, 2002 of $1.0 million, or $.04 per diluted share, compared to net income of $107.7 million, or $4.00 per diluted share, for 2001. The 2002 decrease in net income of $106.7 million is primarily the result of a combined decrease in revenue, while raw material, freight and other costs increased.
Operating income decreased $136.2 million from $164.1 million for the year ended December 31, 2001 to $27.9 million for the year ended December 31, 2002 due to decreases in refined product revenues of $76.6 million, increases in raw material, freight and other costs of $70.8 million, an increase in depreciation of $2.3 million and a $.4 million impairment loss on asset held for sale in 2002 offset by an increase in other income of $2.0 million and decreases in refinery operating expenses, excluding depreciation, of $11.6 million and selling and general, excluding depreciation, costs of $.3 million. The major factors affecting operating income were lower light product margins in 2002 compared to 2001 and decreases in both the light/heavy (the discount at which heavy crude oil sells compared to the sales price of light crude oil) and WTI/WTS (the difference between West Texas Intermediate and West Texas Sour crude oil prices) crude spreads, offset by a positive inventory valuation impact during the year ended December 31, 2002 as a result of rising crude oil and product prices.
Refined product revenues decreased $76.6 million or 4% for the year ended December 31, 2002 compared to 2001 due to decreased sales prices and lower light product margins. Average gasoline prices decreased from $35.85 per sales barrel in 2001 to $33.08 per sales barrel in 2002. Sales volumes of gasoline increased 8,252 barrels per day from 83,737 barrels per day during 2001 to 91,989 barrels per day in 2002. Average diesel and jet fuel prices decreased from $34.12 per sales barrel in 2001 to $30.35 per sales barrel during 2002. Sales volumes of diesel and jet fuel increased 1,839 barrels per day from 51,539 barrels per day during 2001 to 53,378 barrels per day in 2002. Total product sales volumes overall increased 5% from 159,100 barrels per day in 2001 to 166,532 barrels per day in 2002. Manufactured product yields (“yields”) are the volumes of specification materials that are obtained through the distilling of crude oil and the operations of other refinery process units. Yields of gasoline increased 6,519 barrels per day or 8% from 78,126 barrels per day in 2001 to 84,645 barrels per day in 2002 while yields of diesel and jet fuel increased 2,226 barrels per day or 4% from 51,210 barrels per day in 2001 compared to 53,436 barrels per day in 2002. El Dorado gasoline yields improved in 2002 due to diverting feedstocks previously used in the phenol and cumene units. The primary reason for the lower volumes in sales and yields in 2001 was the major turnaround, or planned maintenance, at the El Dorado Refinery which commenced in mid-March 2001 and was completed in mid-April 2001. Despite a major turnaround at the Cheyenne Refinery during March and April 2002, refinery yields and sales for the year ended December 31, 2002 increased from the same period in 2001 due to the benefit of the increased crude capacity from 41,000 barrels per day to 46,000 barrels per day which was completed during latter 2001 and early 2002. The Cheyenne Refinery throughput and resulting yields in the early part of 2001 was constrained by asphalt inventory storage availability.
Other revenues increased $2.0 million to income of $1.1 million for the year ended December 31, 2002 compared to a loss of $832,000 for the same period in 2001 due to $108,000 in futures trading net gains in 2002 compared to $2.0 million futures trading net losses in 2001 (see“Price Risk Management Activities”).
Raw material, freight and other costs include crude oil and other raw materials utilized in the refining process, purchased products and blendstocks, freight costs for FOB destination sales, as well as the impact of changes in inventory under FIFO inventory accounting. Raw material, freight and other costs increased $70.8 million or $.02 per sales barrel from 2001 due to higher average crude oil prices offset by inventory gains from rising prices during the year. For the year ended December 31, 2002, we realized a decrease in raw material, freight and other costs as a result of inventory gains of approximately $19.0 million after tax ($30.6 million pretax, comprised of $10.7 million at the Cheyenne refinery and $19.9 million at the El Dorado refinery) because of the increasing crude oil prices. The price of crude oil on the New York Mercantile Exchange increased through 2002 from $19.84 per barrel to $31.20 per barrel. For the year ended December 31, 2001, we realized an increase in raw material, freight and other costs as a result of inventory losses of approximately $28.9 million after tax ($41.4 million pretax, comprised of $8.9 million at the Cheyenne refinery and $32.5 million at the El Dorado refinery) because of decreasing crude oil prices. The Cheyenne refinery raw material, freight and other costs of $25.18 per sales barrel increased from $24.85 per sales barrel in 2001 due to higher crude oil prices and a reduced light/heavy spread offset by a positive inventory valuation impact as a result of increasing crude oil and product prices. The heavy crude oil utilization rate at the Cheyenne Refinery expressed as a percentage of the total crude oil charge decreased to 90% in the year ended December 31, 2002 from 91% in 2001 as we utilized slightly more light crude oil due to the depressed light/heavy crude oil spread. The light/heavy spread for the Cheyenne Refinery averaged $4.24 per barrel compared to $7.07 per barrel in 2001. The El Dorado Refinery raw material, freight and other costs of $25.93 per sales barrel decreased from $26.01 per sales barrel in 2001 due to slightly higher average crude oil prices more than offset by the inventory gains from rising prices during the year. The WTI/WTS crude spread decreased from an average of $3.10 per barrel in 2001 to $1.36 per barrel in 2002.
Refinery operating expenses, excluding depreciation, includes both the variable costs (including energy and utilities) and the fixed costs (salaries, taxes, maintenance costs and other) of operating the refineries. Refinery operating expense, excluding depreciation, was $178.3 million or $2.93 per sales barrel in 2002 compared to $189.9 million or $3.27 per sales barrel in 2001. The Cheyenne Refinery operating expense, excluding depreciation, per sales barrel decreased $.37 to $3.02 per sales barrel in 2002 due to more sales volumes. The El Dorado Refinery operating expense, excluding depreciation, was $2.90 per sales barrel in 2002 decreasing from $3.22 per sales barrel in 2001 due to lower natural gas costs and more sales volumes.
Selling and general expenses, excluding depreciation, decreased $.3 million or 2% for the year ended December 31, 2002 because of decreased salaries and benefits due to bonuses not being accrued this year partially offset by increased engineering consulting services and travel costs.
Depreciation increased $2.3 million or 9% for the year ended December 31, 2002 as compared to 2001 because of increases in capital investment.
The interest expense decrease of $3.5 million or 11% for the year ended December 31, 2002 was attributable to repurchases of 9-1/8% Senior Notes and 11¾% Senior Notes during 2001, less interest expense on the revolving credit facility due to lower borrowing rates and capitalized interest in 2002. Interest income decreased by $.9 million or 35% for the year ended December 31, 2002 compared to 2001 due to lower available investing interest rates offset by more cash available to invest. Average debt decreased to $246.1 million for the year ended December 31, 2002 from $255.3 million for the year ended December 31, 2001.
Our effective income tax rate for the book provision of income taxes for the year ended December 31, 2002, of 50.8% is greater than our current estimated statutory rate of 38.25% primarily due to one-time adjustments for permanent book versus tax differences and an increase in the state deferred income tax provision due to a revised estimate of state apportionment factors based on actual 2002 allocation factor data. An $83,000 Canadian income tax payment for an audit settlement related to our Canadian oil and gas operations (sold in June 1997) also increased our income tax provision in 2002.
2001 Compared with 2000. We had net income for the year ended December 31, 2001 of $107.7 million, or $4.00 per diluted share, compared to net income of $37.2 million, or $1.34 per diluted share, for 2000. The 2001 increase in net income of $70.5 million is primarily the result of reduced raw material, freight and other costs due to lower crude oil prices, offset somewhat by a corresponding reduction in the average sales price.
Operating income increased $93.4 million in 2001 versus 2000 due to a decrease in raw material, freight and other costs of $268.5 million offset by a decrease in refined product revenues of $148.6 million, a decrease in other income of $8.2 million and increases in refinery operating expenses, excluding depreciation, of $12.1 million, selling and general costs, excluding depreciation, of $4.2 million and depreciation of $2.0 million. The major factors affecting operating income were improved light product margins offset by a negative inventory valuation impact from declining crude oil prices.
Refined product revenues decreased $148.6 million or 7% for the year ended December 31, 2001 compared to 2000 due to decreased sales prices. Average gasoline prices decreased $2.24 per sales barrel from $38.09 per sales barrel in 2000 to $35.85 per sales barrel in 2001. Gasoline sales volumes increased to 83,737 barrels per day during 2001 from 83,070 barrels per day during 2000. Average diesel and jet fuel prices decreased from $37.19 per sales barrel in 2000 to $34.12 per sales barrel in 2001. Sales volumes for diesel and jet fuel decreased only slightly from 51,568 barrels per day in 2000 to 51,539 barrels per day in 2001.Yields of gasoline increased 1,331 barrels per day or 2% from 76,795 barrels per day in 2000 to 78,126 barrels per day in 2001 while yields of diesel and jet fuel increased 286 barrels per day or 1% from 50,924 barrels per day in 2000 to 51,210 barrels per day in 2001.
Other revenues decreased $8.2 million to a loss of $832,000 for the year ended December 31, 2001 compared to the same period in 2000 due to a $1.9 million realized futures trading net losses in 2001 compared to a $4.6 million futures trading net gain in 2000. Other revenues in 2000 also included $1.1 million proceeds from the sale of excess catalyst platinum from the El Dorado Refinery, insurance proceeds of $300,000, which was related to a business interruption at the El Dorado Refinery in 2000, and sulfur credit sales of $230,000.
Raw material, freight and other costs include crude oil and other raw materials utilized in the refining process, purchased products and blendstocks, freight costs for FOB destination sales, as well as the impact of changes in inventory under FIFO inventory accounting. Raw material, freight and other costs of $1,491.8 million in 2001 decreased 16% per sales barrel or $4.72 per sales barrel in 2001 primarily due to lower crude oil prices. The price of crude oil on the New York Mercantile Exchange declined through 2001 from $26.80 per barrel to $19.84 per barrel. For the year ended December 31, 2001, we realized an increase in raw material, freight and other costs as a result of inventory losses of approximately $28.9 million after tax ($41.4 million pretax.comprised of $8.9 million at the Cheyenne refinery and $32.5 million at the El Dorado refinery) because of decreasing crude oil prices. For the year ended December 31, 2000, we realized a decrease in raw material, freight and other costs from inventory gains of approximately $18.7 million after tax ($19.2 million pretax comprised of $2.3 million at the Cheyenne refinery and $16.9 million at the El Dorado refinery) from rising crude oil prices. The Cheyenne Refinery raw material, freight and other costs of $24.85 per sales barrel decreased from $28.51 per sales barrel in 2000 due to lower crude oil prices and an increased light/heavy spread. The heavy crude oil utilization rate at the Cheyenne Refinery expressed as a percentage of the total crude oil charge decreased to 91% in the year ended December 31, 2001 from 94% in 2000 due to fulfilling light crude oil purchase contracts while reducing spot purchases of heavy crude oil during the fall 2001 crude unit turnaround. The light/heavy spread for the Cheyenne Refinery averaged $7.07 per barrel compared to $5.09 per barrel in 2000. The El Dorado Refinery raw material, freight and other costs of $26.01 per sales barrel decreased from $31.20 per sales barrel in 2000 due to lower crude oil prices. The WTI/WTS crude spread increased from an average of $2.06 per barrel in 2000 to $3.10 per barrel in 2001.
Refinery operating expenses, excluding depreciation, include both the variable costs (including energy and utilities) and the fixed costs (salaries, taxes, maintenance costs and other) of operating the refineries. Refinery operating expense, excluding depreciation, was $189.9 million or $3.27 per sales barrel in 2001 compared to $177.9 million or $3.07 per sales barrel in 2000. The Cheyenne Refinery operating expense, excluding depreciation, per sales barrel increased $.56 to $3.39 per sales barrel in 2001 due to higher maintenance and turnaround costs and reduced yields and sales volumes due to the fall crude unit turnaround and higher natural gas costs early in the year. The El Dorado Refinery operating expense, excluding depreciation, was $3.22 per sales barrel in 2001 increasing from $3.17 per sales barrel in 2000 due to higher natural gas costs early in the year, electrical costs, and chemical and additive costs offset by more yields and sales volumes.
Selling and general expenses, excluding depreciation, increased $4.2 million or 32% for the year ended December 31, 2001 because of increased compensation, mainly bonuses, personnel, and other costs, particularly travel, relating to the operation of multiple locations.
Depreciation increased $2.0 million or 9% for the year ended December 31, 2001 as compared to 2000 because of increases in capital investment.
The interest expense decrease of $3.6 million or 10% for the year ended December 31, 2001 was attributable to the reduction of debt including repurchases of 9-1/8% Senior Notes and 11¾% Senior Notes during 2001 and 2000 and lower borrowing rates, balances and fees on the revolving credit facility. Interest income decreased by $.6 million or 18% for the year ended December 31, 2001 compared to 2000 due to lower available investing interest rates offset by more available cash to invest. Average debt decreased to $255.3 million for the year ended December 31, 2001 from $295.7 million for the year ended December 31, 2000.
Our effective income tax rate for the book provision of income taxes for the year ended December 31, 2001 of approximately 21% was greater than the effective tax rate for the year ended December 31, 2000 of 5% due to the unanticipated increase in pretax income in 2001 which resulted in the utilization of our deferred tax assets (primarily federal net operating loss carryforwards) in mid-2001 for which we had previously provided a valuation allowance.
Net cash provided by operating activities was $50.8 million for the year ended December 31, 2002 while $138.6 million cash was provided by operating activities for the year ended December 31, 2001. The most significant decrease from cash provided by operating activities was the decrease in operating income due to the lower product margins and decreases in the crude spreads discussed above. Working capital changes provided $17.8 million of cash flows in 2002 while using $6.5 million of cash flows in 2001.
At December 31, 2002, we had $112.4 million of cash and cash equivalents, working capital of $108.3 million and an $88.2 million borrowing base availability for additional borrowings under our revolving credit facility.
On November 5, 1999, we issued $190 million principal amount of 11¾% Senior Notes due 2009. The Notes were issued at a price of 98.562%. Net proceeds of the offering were approximately $181.0 million. We used the net proceeds to fund the $170 million purchase price of the El Dorado Refinery and for general corporate purposes. During 2001 and 2000, we purchased $6.5 million and $13.0 million principal amount, respectively, of the 11¾% Senior Notes and are holding them as treasury notes, the accounting for which reduced debt.
During 2002, 2001 and 2000, we purchased $1.1 million, $24.4 million and $5.0 million principal amount, respectively, of the 9-1/8% Senior Notes and are holding them as treasury notes. The accounting for which reduced debt. The 9-1/8% Senior Notes were issued in 1998.
On September 1, 1998, we announced that the Board of Directors had approved a stock repurchase program of up to three million shares of common stock. In late 2000, the Board of Directors increased this amount to a total of four million shares and in June 2001 authorized an additional two million shares to bring the total authorization to six million shares, which may be purchased and held as treasury shares. In 1998, 469,700 shares of common stock were purchased for $2.3 million and in 1999, 627,700 shares of common stock were purchased for $3.4 million. In 2000, 1,393,696 shares of common stock were purchased for approximately $9.2 million, of which 1,248,500 shares were purchased on the open market. In 2001, 1,850,970 shares were purchased for approximately $22.6 million, of which 1,774,400 were purchased on the open market. In 2002, we completed the purchase, committed to at December 31, 2001, of another 25,300 shares for $416,000. During the year ended 2002, we did not initiate any additional purchases of common stock under the stock repurchase programs, however we did acquire 19,041 shares of stock from employees to cover their withholding taxes on shares of restricted stock which vested during the year.
Capital expenditures for 2002 were $37.1 million, which included the $7.5 million El Dorado earn-out payment accrued as of December 31, 2001. We reduced our originally planned total capital expenditures in 2002 due to reevaluating the economics of the previously announced heavy crude oil expansion at the El Dorado Refinery. Due to anticipated cost and market conditions, we reached a decision in the fourth quarter of 2002 to cancel this project and $2.4 million previously recorded as capital expenditures was expensed.
Capital expenditures for 2001 were $22.8 million. Capital expenditures of approximately $41.0 million are planned for 2003, which includes nearly $14.0 million for the low sulfur gasoline project at Cheyenne. The additional $27.0 million of capital expenditures consists of $13.6 million of sustaining capital (including safety, environmental and operational projects), $6.9 million of growth, strategic and profitability projects, $3.3 million of information technology projects and $3.2 million of small capital and other projects at both the Cheyenne and El Dorado refineries. The $41.0 million expenditures planned for 2003 does not include any amount for an El Dorado earn-out payment, as none was earned in 2002. The planned capital expenditures in excess of $35.0 million will be subject to bank approval under our revolving credit facility or we have the option to lease a portion of the equipment required for the low sulfur gasoline project.
Under the provisions of the purchase agreement for our El Dorado Refinery, we have made, or may be required to make, contingent earn-out payments for each of the years 2000 through 2007 equal to one-half of the excess over $60 million per year of the El Dorado Refinery’s revenues less its material costs and operating costs, other than depreciation. The total amount of these contingent payments is capped at $40 million, with an annual cap of $7.5 million. Any contingency payment will be recorded when determinable. Such contingency payments, if any, will be recorded as additional acquisition cost. No contingent earn-out payment will be required based on 2002 results. A contingent earn-out payment of $7.5 million was required based on 2001 results and was accrued as of December 31, 2001 and paid in early 2002. No contingent earn-out payment was required based on 2000 results.
As of December 31, 2002, we have $208.0 million of total consolidated debt and shareholders’ equity of $168.3 million. For 2003, we anticipate that cash generated from operating activities may have to be supplemented with a portion of our current cash balance to meet our 2003 capital investment plans and debt obligations. Operating cash flows are affected by crude oil and refined product prices and other risks as discussed in Market Risks below.
Under certain conditions, the revolving credit facility, which is at the subsidiary level, restricts the transfer of cash in the form of dividends, loans or advances from the operating subsidiary to the parent holding company. We do not believe these restrictions limit our current operating plans. Our refining revolving credit facility was amended, effective September 23, 2002 to allow for capital expenditures of up to $35.0 million cash in any calendar year, in addition to any El Dorado earn-out payments required. We are in compliance with the financial covenants as of December 31, 2002.
Our Board of Directors declared quarterly cash dividends in December 2001, March 2002, June 2002 and September 2002 of $.05 per share which were paid in January 2002, April 2002, July 2002 and October 2002, respectively. The total paid out for dividends in 2002 was $5.2 million. In addition, our Board of Directors declared a quarterly cash dividend of $.05 per share in December 2002, to be paid on January 13, 2003 to shareholders of record on December 27, 2002. The total cash required for this dividend is approximately $1.3 million and was accrued at year-end.
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 and our commitment for crude oil pipeline capacity. We have contracted for pipeline capacity into 2012 on the Express Pipeline from Hardisty, Alberta to Guernsey, Wyoming at which we then have pipeline access to take the crude oil to our Cheyenne, Wyoming Refinery. Our 15-year contract, which began in 1997, is for an average 13,800 barrels per day, however we were allowed to assign a portion of our capacity in earlier years for additional capacity in later years, thus our remaining commitments range from 16,600 barrels per day in 2003, increasing to a high of 22,600 barrels per day in 2006 and then are reduced back down to 13,800 barrels per day through the remainder of the contract. Our crude oil supply agreement with Baytex Marketing Ltd. (“Baytex”) includes an assignment of a portion of our pipeline capacity obligation to them. The amounts shown below for pipeline capacity contractual obligations are net of $37.0 million, the approximate cost of the pipeline capacity assigned to Baytex for the initial term of that agreement. Our operating leases include building, equipment, aircraft and vehicle leases which expire from 2002 through 2008, as well as an operating sublease for the use of the cogeneration facility at our El Dorado Refinery. The noncancellable sublease, entered into in connection with the acquisition of our El Dorado Refinery in 1999, expires in 2016 with an option to allow us to renew the sublease for an additional eight years. At the end of the renewal sublease term we have the option to purchase the cogeneration facility for the greater of fair value or $22.3 million.
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Contractual Obligation Payments due by Period (in thousands)
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Total Within 1 year Within 2 - 3 years Within 4 -5 years After 5 years
- ----------------------------- ------------ ---------------- ---------------------- ------------------- --------------
Long-term Debt $ 209,924 $ - $ - $ 39,475 $ 170,449
- ----------------------------- ------------ ---------------- ---------------------- ------------------- --------------
Operating Leases 103,262 10,430 19,482 16,444 56,906
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Pipeline Capacity 28,923 1,560 1,111 284 25,968
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Total Contractual Cash $ 342,109 $ 11,990 $ 20,593 $ 56,203 $ 253,323
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See “Government Regulation–Environmental Matters” in Part I, Item 1.
Refined Product Revenues. Revenues from sales of refined products are earned and realized upon transfer of title to the customer based on the contractual terms of delivery. 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).
Property, Plant and Equipment. We record property, plant and equipment at cost and depreciate the asset or groups of assets using the straight-line method over the estimated useful lives. The estimated useful lives are:
Refinery plant and equipment.................... 5 to 20 years
Pipeline and pumps.............................. 10 to 20 years
Furniture, fixtures and other................... 3 to 10 years
We review long-lived assets for impairments whenever events or changes in circumstances indicate that the carrying value of an asset may not be recoverable. If the undiscounted future cash flows of an asset to be held and used in operations is less than the carrying value, we 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. We capitalize interest on debt incurred to fund the construction of significant assets.
Turnarounds. Normal maintenance and repairs are expensed as incurred. The costs for turnarounds (scheduled and required shutdown of refinery operating units for significant overhaul and refurbishment) are ratably accrued over the period from the prior turnaround to the next scheduled turnaround. These accruals are included in our consolidated balance sheet in the “Accrued turnaround cost” and “Long-term accrued turnaround cost.” The turnaround accrual expenses are included in "Refining operating costs" in our consolidated statements of operations. Turnaround costs include contract services, materials and rental equipment. Major improvements are capitalized and the assets replaced are retired.
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 cost. Unfinished products (work in process) include any crude oil which 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 both 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.
Income Taxes. We account for income taxes under the provisions of Statement of Financial Accounting Standards (“SFAS”) No. 109, Accounting for Income Taxes. SFAS 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 financial statement carrying amounts of assets and liabilities and their respective tax bases.
Environmental Expenditures. Environmental expenditures are expensed or capitalized based upon their future economic benefit. Costs which improve a property’s pre-existing condition and costs which 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.
In June 2001, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 142, “Goodwill and Other Intangible Assets”. SFAS No. 142 addresses financial accounting and reporting for acquired goodwill and other intangible assets and supersedes Accounting Principles Board (“APB”) Opinion No. 17, “Intangible Assets”. SFAS No. 142 addresses how intangible assets that are acquired should be accounted for in financial statements upon their acquisition and also addresses how goodwill and other intangible assets should be accounted for after they have been initially recognized in the financial statements. We adopted SFAS No. 142 effective January 1, 2002. The adoption did not have any impact on our financial condition or results of operations.
In June 2001, the FASB issued SFAS No. 143, “Accounting for Asset Retirement Obligations”. This statement provides accounting and disclosure requirements for retirement obligations associated with long-lived assets and is effective January 1, 2003. SFAS 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. SFAS No. 143 also includes disclosure requirements that provide a description of asset retirement obligations and reconciliation of changes in the components of those obligations. We have potential asset retirement obligation (“ARO”) liabilities related to our Refineries as a result of environmental and other legal requirements. Any ARO liability is not currently estimatable as to amount and timing, but we will continue to monitor and evaluate our potential AROs. In the event that we decide to cease the use of a particular refinery, an ARO liability would be recorded at that time. We do not expect the adoption of SFAS No. 143 to have a material impact on our current financial condition or results of operations.
In August 2001, the FASB issued SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets”. SFAS No. 144 addresses the accounting and reporting for the impairment or disposal of long-lived assets and supersedes SFAS No. 121, “Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of ” and APB Opinion No. 30, “Reporting the Results of Operations - Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions.” SFAS No. 144 establishes one accounting model for long-lived assets to be disposed of by sale as well as resolve implementation issues related to SFAS No. 121. We adopted SFAS No. 144 effective January 1, 2002. The adoption did not have any impact on our financial condition or results of operations.
The Accounting Standards Executive Committee of the American Institute of Certified Public Accountants has issued an exposure draft of a proposed Statement of Position (“SOP”) entitled “Accounting for Certain Costs and Activities Related to Property, Plant and Equipment.” If adopted as proposed, this SOP would require companies to expense as incurred turnaround costs, defined as “the non-capital portion of major maintenance costs.” Adoption of the proposed SOP would also require that any existing turnaround accruals be reversed to income immediately. If this proposed change were in effect at December 31, 2002, we would have been required to reverse the turnaround accruals and recognize pretax income totaling $26.9 million. The total accrued turnaround costs will change throughout the year as turnarounds are incurred and accruals are made for future turnarounds. If adopted in its present form, income related to this proposed change would be reported as a cumulative effect of an accounting change, net of tax, in the consolidated statements of operations.
In April 2002, the FASB issued SFAS No. 145, “Rescission of FASB Statements No. 4, 44 and 64, Amendment of FASB Statement No. 13, and Technical Corrections.” It is probable that the rescission of SFAS No. 4 is the only portion of SFAS No. 145 that may have an impact on us in the future. Under SFAS No. 4, all gains and losses from extinguishment of debt were required to be aggregated and, if material, classified as an extraordinary item, net of related income tax effect. SFAS No. 145 eliminates SFAS No. 4. As a result, gains and losses from extinguishment of debt should be classified as extraordinary items only if they meet the criteria in Opinion 30. We adopted SFAS No. 145 effective January 1, 2003 and it did not have any impact on our financial condition or results of operations.
In June 2002, the FASB issued SFAS No. 146, “Accounting for Costs Associated with Exit or Disposal Activities.” SFAS No. 146 addresses financial accounting and reporting for costs associated with exit or disposal activities. SFAS No. 146 is effective for exit or disposal activities that are initiated after December 31, 2002.
In December 2002, the FASB issued SFAS No. 148, “Accounting for Stock-Based Compensation – Transition and Disclosure, an amendment of FASB Statement No. 123.” SFAS No. 148 amends SFAS No. 123, “Accounting for Stock-Based Compensation”, to provide alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation. In addition, SFAS No. 148 amends the disclosure requirements of SFAS No. 123 to require prominent disclosures in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on reported results. SFAS No. 148 is effective for the December 31, 2002 financial statements and all required disclosures have been made in the notes to the 2002 financial statements.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK
Impact of Changing Prices. Our revenues and cash flows, as well as estimates of future cash flows, are very sensitive to changes in energy prices. Major shifts in the cost of crude oil, and the prices of refined products and natural gas can result in large changes in the operating margin from refining operations. These prices also determine the carrying value of the Refineries’ inventories.
Price Risk Management Activities. At times, we enter into commodity derivative contracts to manage our price exposure to our inventory positions, our purchases of foreign crude oil and consumption of natural gas in the refining process as well as fix margins on certain future production. The commodity derivative contracts we use may take the form of futures contracts or price swaps and are entered into with reputable counterparties. We use futures transactions to price foreign crude oil cargos at the time when the crude oil is processed by the El Dorado Refinery instead of the price when purchased. Foreign crude oil delivery times can exceed one month from when the purchase is made. In addition, we may engage in futures transactions for the purchase of natural gas at fixed prices. The Refineries consume natural gas for energy purposes. We account for our commodity derivative contracts under 1) the hedge (or deferral) method of accounting when the derivative contracts qualify and are designated as hedges for accounting purposes, or 2) mark-to-market accounting if we elect not to designate derivative contracts as accounting hedges or if such derivative contracts do not qualify for hedge accounting. As such, gains or losses on commodity derivative contracts accounted for as hedges are recognized in refining operating costs when the associated transactions are consummated while gains and losses on transactions accounted for using mark-to-market accounting are reflected in other revenues at each period end.
Other revenues for the year ended December 31, 2002 includes $878,000 realized net gains on the ineffective portion of fair value hedges on crude oil cargos and $740,000 realized net losses on derivative contracts accounted for using mark-to-market accounting. The ineffective portion of foreign crude oil hedges arises primarily from changes in the shape of the forward futures price curve.
During the year ended December 31, 2002, we had the following derivative activities which were appropriately designated and accounted for as hedges:
| • | At December 31, 2002 we had no open derivative contracts to hedge against price changes on foreign crude oil purchase commitments. During the year ended December 31, 2002, we closed out contracts to hedge foreign crude purchases and realized net losses of $9.8 million, of which $10.7 million increased crude costs and $878,000 income was reflected in other revenues for the ineffective portion of those hedges. These contracts were accounted for as fair value hedges. |
| • | In March 2002, we entered into price swaps on natural gas for the purpose of hedging approximately 50% of the Refineries’ anticipated usage against natural gas price increases for April 2002 through December 2002. These contracts were accounted for as cash flow hedges. One group of contracts to hedge natural gas costs at our El Dorado Refinery averaged 300,000 MMBTU per month at an average price of $3.34 per MMBTU (Panhandle). A second group of contracts to hedge natural gas costs at our Cheyenne Refinery averaged 112,222 MMBTU per month at an average price of $2.84 per MMBTU (CIG). The April and May contracts resulted in net realized gains totaling $41,000 and were recorded into refining operating costs. Due to natural gas market conditions, we made a decision in May to close out the remaining June through December contracts resulting in a net gain of $393,000. The realized gains or losses were recorded in other comprehensive income (equity account), net of tax. The pretax realized gains or losses were reclassified into refining operating costs and out of other comprehensive income based on the month when the corresponding natural gas was purchased. As of December 31, 2002, all these gains and losses had been reclassified into earnings. |
During the year ended December 31, 2002, we had the following derivative activities which, while economic hedges, did not qualify for hedge accounting treatment and whose gains or losses are reflected in other revenues:
| • | We had derivative contracts on barrels of crude oil to hedge butane inventory builds at the El Dorado Refinery and recorded $903,000 in realized losses on these positions. |
| • | We had derivative contracts on barrels of crude oil to hedge excess gas oil inventory at our Cheyenne Refinery and had realized losses of $202,000 on these positions. |
| • | Derivative contracts on barrels of crude oil to hedge excess gas oil inventory at our El Dorado Refinery resulted in gains of $896,000. |
| • | We also hedged excess naptha inventory at our El Dorado Refinery by having derivative contracts on barrels of crude oil which resulted in losses of $579,000. |
| • | Contracts to hedge crude oil resulted in a gain of $48,000. |
Interest Rate Risk. Borrowings under our revolving credit facility bear a current market rate of interest. Our approximately $39.5 million of outstanding 9-1/8% Senior Notes, due 2006, have a fixed interest rate. Our approximately $170.5 million principal of 11¾% Senior Notes outstanding, due 2009, also have a fixed interest rate. Accordingly, our long-term debt is not exposed to cash flow risk from interest rate changes, however, our long-term debt is exposed to fair value risk. The estimated fair value of the 9-1/8% Senior Notes at December 31, 2002 was $37.9 million and the estimated fair value of the 11¾% Senior Notes was $174.7 million.
FRONTIER OIL CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands except per share amounts)
Years Ended December 31,
----------------------------------------------
2002 2001 2000
------------- ------------- -----------
Revenues:
Refined products $ 1,812,613 $ 1,889,233 $ 2,037,840
Other 1,137 (832) 7,317
------------- ------------- -----------
1,813,750 1,888,401 2,045,157
------------- ------------- -----------
Costs and Expenses:
Raw material, freight and other costs 1,562,613 1,491,772 1,760,289
Refinery operating expenses, excluding depreciation 178,295 189,948 177,873
Selling and general expenses, excluding depreciation 17,248 17,571 13,333
Impairment loss on asset held for sale 363 - -
Depreciation 27,332 25,010 23,007
------------- ------------- -----------
1,785,851 1,724,301 1,974,502
------------- ------------- -----------
Operating income 27,899 164,100 70,655
Interest expense and other financing costs 27,613 31,146 34,738
Interest income (1,802) (2,772) (3,364)
------------- ------------- -----------
25,811 28,374 31,374
------------- ------------- -----------
Income before income taxes 2,088 135,726 39,281
Provision for income taxes 1,060 28,073 2,075
------------- ------------- -----------
Net income $ 1,028 $ 107,653 $ 37,206
============= ============= ===========
Basic earnings per share of common stock $ .04 $ 4.12 $ 1.36
============= ============= ===========
Diluted earnings per share of common stock $ .04 $ 4.00 $ 1.34
============= ============= ===========
The accompanying notes are an integral part of these financial statements.
FRONTIER OIL CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(in thousands except share data)
December 31,
-------------------------------
2002 2001
------------- -------------
ASSETS
Current assets:
Cash and cash equivalents (Note 2) $ 112,364 $ 103,995
Trade receivables, net of allowance of $500 in both years 81,154 55,848
Note receivable, net of allowance of $800 1,449 -
Other receivables 987 6,469
Inventory of crude oil, products and other 105,160 87,970
Deferred tax assets 5,346 4,845
Other current assets 2,510 2,243
------------- -------------
Total current assets 308,970 261,370
------------- -------------
Property, plant and equipment, at cost:
Refineries and pipelines 447,948 419,962
Furniture, fixtures and other equipment 5,119 5,853
------------- -------------
453,067 425,815
Less - accumulated depreciation 144,127 117,252
------------- -------------
308,940 308,563
Asset held for sale 472 -
Other assets 10,495 11,813
------------- -------------
Total assets $ 628,877 $ 581,746
============= =============
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable $ 174,917 $ 112,303
Accrued turnaround cost 12,849 10,394
Accrued liabilities and other 9,095 25,714
Accrued interest 3,856 3,895
------------- -------------
Total current liabilities 200,717 152,306
------------- -------------
Long-term debt 207,966 208,880
Long-term accrued turnaround cost 14,013 15,443
Postretirement employee liabilities 18,784 16,734
Deferred credits and other 3,963 4,099
Deferred income taxes 15,176 15,080
Commitments and contingencies (Note 7)
Shareholders' equity:
Preferred stock, $100 par value, 500,000 shares authorized,
no shares issued - -
Common stock, no par, 50,000,000 shares authorized,
30,290,324 and 30,059,574 shares
issued in 2002 and 2001, respectively 57,469 57,446
Paid-in capital 102,557 98,046
Retained earnings 49,621 53,764
Accumulated other comprehensive loss (598) (255)
Treasury stock, at cost, 4,151,210 and 4,240,937
shares at December 31, 2002 and 2001, respectively (37,959) (38,163)
Deferred employee compensation (2,832) (1,634)
------------- -------------
Total shareholders' equity 168,258 169,204
------------- -------------
Total liabilities and shareholders' equity $ 628,877 $ 581,746
============= =============
The accompanying notes are an integral part of these financial statements.
FRONTIER OIL CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
Years Ended December 31,
----------------------------------------------
2002 2001 2000
----------- ----------- -----------
Cash flows from operating activities:
Net income $ 1,028 $ 107,653 $ 37,206
Depreciation 27,332 25,010 23,007
Deferred finance cost and bond discount amortization 2,033 2,168 2,190
Deferred employee compensation amortization 907 380 -
Allowance for doubtful trade and note receivables 800 - 533
Impairment loss on asset to be sold 363 - -
Deferred income taxes 1,149 9,463 130
Other (562) 381 (285)
Changes in components of working capital from operations:
Decrease (increase) in trade, note and other receivables (22,178) 15,912 (25,583)
Decrease (increase) in inventory (17,190) 37,511 (25,122)
Decrease (increase) in other current assets (267) 1,569 (2,927)
(Decrease) increase in accounts payable 64,004 (60,013) 49,551
(Decrease) increase in accrued liabilities and other (6,597) (1,459) 7,646
----------- ----------- -----------
Net cash provided by operating activities 50,822 138,575 66,346
Cash flows from investing activities:
Additions to property, plant and equipment & other (29,617) (22,824) (12,688)
El Dorado Refinery acquisition-contingent earn-out payment (7,500) - -
------------ ----------- -----------
Net cash used in investing activities (37,117) (22,824) (12,688)
Cash flows from financing activities:
Repurchase of debt:
9-1/8% Senior Notes (1,090) (24,410) (5,025)
11-3/4% Senior Notes - (6,541) (13,010)
Repayments of revolving credit facility, net - (23,000) (3,000)
Proceeds from issuance of common stock 1,702 3,271 2,743
Purchase of treasury stock (787) (22,600) (9,215)
Dividends paid (5,161) (2,629) -
Other - (293) (50)
----------- ----------- -----------
Net cash used in financing activities (5,336) (76,202) (27,557)
----------- ----------- -----------
Increase in cash and cash equivalents 8,369 39,549 26,101
Cash and cash equivalents, beginning of period 103,995 64,446 38,345
----------- ----------- -----------
Cash and cash equivalents, end of period $ 112,364 $ 103,995 $ 64,446
=========== =========== ===========
The accompanying notes are an integral part of these financial statements.
FRONTIER OIL CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY
(in thousands except shares)
Common Stock Treasury Stock Total
-------------------------- ---------------------- Accumulated -----------------------
Compre- Retained Deferred Other
Number of Paid-In hensive Earnings Number of Employee Comprehensive Number of
Shares Issued Amount Capital Income (Deficit) Shares Amount Compensation Income (Loss) Shares Amount
------------- ------------ ------------ --------- ------------ ----------- ---------- ------------ ------------- ---------- ----------
December 31, 1999 28,542,330 $ 57,294 $ 87,028 $ (87,122) (1,230,900) $ (6,519) $ - $ - 27,311,430 $ 50,681
Net income - - - $ 37,206 37,206 - - - - 37,206
========
Shares issued under:
Stock option plan 647,674 65 2,678 - (145,196) (1,013) - - 502,478 1,730
Directors stock plan - - - - 2,000 9 - - 2,000 9
Shares repurchased under:
Stock repurchase plans - - - - (1,248,500) (8,202) - - (1,248,500) (8,202)
December 31, 2000 29,190,004 57,359 89,706 (49,916) (2,622,596) (15,725) - - 26,567,408 81,424
Shares issued under:
Stock option plan 869,570 87 3,987 - (101,870) (785) - - 767,700 3,289
Directors stock plan - - - - 3,000 13 - - 3,000 13
Restricted stock issuances, net - - 663 - 254,929 1,351 (2,014) - 254,929 -
Shares repurchased under:
Stock repurchase plans - - - - (1,774,400) (23,017) - - (1,774,400) (23,017)
Comprehensive income:
Net income - - - $107,653 107,653 - - - - - 107,653
Other comprehensive income:
Cumulative effect of accounting change on fair
value of derivative instruments, net of tax of $206 3,910
Change in fair value of derivatives, net of tax of $160 (1,626)
Derivative value reclassed to income, net of tax of $46 (2,284)
Minimum pension liability, net of tax of $158 (255)
--------
Other comprehensive income (255) (255) - (255)
--------
Comprehensive income $107,398
========
Income tax benefits of stock options - - 3,690 - - - - - - 3,690
Deferred employee compensation:
Amortization/vested shares - - - - - - 380 - - 380
Dividends declared - - - (3,973) - - - - - (3,973)
December 31, 2001 30,059,574 57,466 98,046 53,764 (4,240,937) (38,163) (1,634) (255) 25,818,637 169,204
Shares issued under:
Stock option plan 230,750 23 1,543 - - - - - 230,750 1,566
Directors stock plan - - - - 3,000 13 - - 3,000 13
Restricted stock issuances, net - - 1,544 - 105,768 561 (2,105) - 105,768 -
Shares repurchased under:
Restricted stock plan - - - - (19,041) (370) - - (19,041) (370)
Comprehensive income:
Net income - - - $ 1,028 1,028 - - - - - 1,028
Other comprehensive income:
Deferred net loss on derivative contracts, net of tax of $21 (33)
Derivative value reclassed to income, net of tax of $21 33
Minimum pension liability, net of tax of $214 (343)
--------
Other comprehensive income (343) (343) (343)
--------
Comprehensive income $ 685
========
Income tax benefits of stock compensation - - 1,424 - - - - - - 1,424
Deferred employee compensation:
Amortization/vested shares - - - - - - 907 - - 907
Dividends declared - - - (5,171) - - - - - (5,171)
------------- ----------- --------- ------------ ----------- ---------- ----------- ------------ ---------- ---------
December 31, 2002 30,290,324 $ 57,469 $ 102,557 $ 49,621 (4,151,210) $ (37,959) $ (2,832) $ (598) 26,139,114 $ 168,258
============= =========== ========= ============ =========== ========== =========== ============ ========== =========
The accompanying notes are an integral part of these financial statements.
The financial statements include the accounts of Frontier Oil Corporation, a Wyoming corporation, and its wholly owned subsidiaries, including Frontier Holdings Inc., 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 with a combined crude oil capacity of 156,000 barrels per day. The Company also owns a 34.72% interest in a crude oil pipeline in Wyoming and a 50% interest in one crude oil tank and another under construction in Guernsey, Wyoming, both of which are accounted for as undivided interests. Each asset, liability, revenue and expense is reported on a proportionate gross basis. The Company also has a 50% interest in FGI, LLC, an asphalt terminal and storage facility in Grand Island, Nebraska, which is accounted for using the equity method of accounting. In addition, the equity method of accounting is also utilized for the Company’s 25% interest in 8901 Hangar, Inc., a company, which leases and operates a private airplane hangar.
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 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.
Revenues from sales of refined products are earned and realized upon transfer of title to the customer based on the contractual terms of delivery. 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).
Property, plant and equipment additions are recorded at cost and depreciated using the straight-line method over the estimated useful lives. The estimated useful lives are:
Refinery plant and equipment................................ 5 to 20 years
Pipeline and pumps.......................................... 10 to 20 years
Furniture, fixtures and other............................... 3 to 10 years
The Company reviews long-lived assets for impairments whenever events or changes in circumstances indicate that the carrying value of an asset may not be recoverable. If the undiscounted future cash flows 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 value s are not available, the Company estimates fair value based on a discounted cash flow analysis. The Company capitalizes interest on debt incurred to fund the constructions of significant assets. Interest capitalized for the year ended December 31, 2002 was $342,000. There was no interest capitalized for the years 2001 and 2000.
Normal maintenance and repairs are expensed as incurred. The costs for turnarounds (scheduled and required shutdown of refinery operating units for significant overhaul and refurbishment) are ratably accrued over the period from the prior turnaround to the next scheduled turnaround. These accruals are included in the Company’s consolidated balance sheet in the “Accrued turnaround cost” and “Long-term accrued turnaround cost.” The turnaround accrual expenses are included in “Refining operating costs” in the Company’s consolidated statements of operations. Turnaround costs include contract services, materials and rental equipment. Major improvements are capitalized, and the assets replaced are retired.
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 cost. Unfinished products (work in process) include any crude oil which 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 both 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.
Components of Inventory
(in thousands)
December 31,
-----------------------------
2002 2001
------------- -------------
Crude oil $ 33,765 $ 24,787
Unfinished products 24,806 24,406
Finished products 29,836 21,607
Process chemicals 3,308 4,103
Repairs and maintenance supplies and other 13,445 13,067
------------- -------------
$ 105,160 $ 87,970
============= =============
The Company accounts for income taxes under the provisions of Statement of Financial Accounting Standards (“SFAS”) No. 109, Accounting for Income Taxes. SFAS 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 financial statement carrying amounts of assets and liabilities and their respective tax bases.
Environmental expenditures are expensed or capitalized based upon their future economic benefit. Costs which improve a property’s pre-existing condition and costs which 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.
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 and are entered into with credit-worthy counterparties. The Company believes there is minimal credit risk with respect to its counterparties. The Company accounts for its commodity derivative contracts under the hedge (or deferral) method of accounting when the derivative contracts are designated as hedges for accounting purposes, or mark-to-market accounting if the Company elects not to designate derivative contracts as accounting hedges or if such derivative contracts do not qualify for hedge accounting. As such, gains or losses on commodity derivative contracts accounted for as hedges are recognized in refining operating costs when the associated transactions are consummated while gains and losses on transactions accounted for using mark-to-market accounting are reflected in other revenues at each period end.
Stock-based compensation is measured in accordance with Accounting Principles Board (“APB”) No. 25. Under this intrinsic value method, compensation cost is the excess, if any, of the quoted market value of the Company’s common stock at the grant date over the amount the employee must pay to acquire the stock. Compensation costs of $907,000 and $380,000 related to restricted stock awards was recognized for the years ended December 31, 2002 and 2001, respectively. No compensation cost was recognized for the year ended December 31, 2000.
Intercompany transactions are eliminated in consolidation.
The preparation of financial statements in conformity with accounting principles generally accepted in the United States 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.
In June 2001, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 142, “Goodwill and Other Intangible Assets”. SFAS No. 142 addresses financial accounting and reporting for acquired goodwill and other intangible assets and supersedes APB Opinion No. 17, “Intangible Assets”. SFAS No. 142 addresses how intangible assets that are acquired should be accounted for in financial statements upon their acquisition and also addresses how goodwill and other intangible assets should be accounted for after they have been initially recognized in the financial statements. The Company adopted SFAS No. 142 effective January 1, 2002. The adoption did not have any impact on the Company's financial condition or results of operations.
In June 2001, the FASB issued SFAS No. 143, “Accounting for Asset Retirement Obligations”. This statement provides accounting and disclosure requirements for retirement obligations associated with long-lived assets and is effective January 1, 2003. SFAS 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. SFAS No. 143 also includes disclosure requirements that provide a description of asset retirement obligations and reconciliation of changes in the components of those obligations. The Company has potential asset retirement obligation (“ARO”) liabilities related to its Refineries as a result of environmental and other legal requirements. Any ARO liability is not currently estimatable as to amount and timing, but the Company will continue to monitor and evaluate its potential AROs. In the event that the Company decides to cease the use of a particular refinery, an ARO liability would be recorded at that time. The Company does not expect the adoption of SFAS No. 143 to have a material impact on the Company’s current financial condition or results of operations.
In August 2001, the FASB issued SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets”. SFAS No. 144 addresses the accounting and reporting for the impairment or disposal of long-lived assets and supersedes SFAS No. 121, “Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of ” and APB Opinion No. 30, “Reporting the Results of Operations - Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions.” SFAS No. 144 establishes one accounting model for long-lived assets to be disposed of by sale as well as resolves implementation issues related to SFAS No. 121. The Company adopted SFAS No. 144 effective January 1, 2002. The adoption did not have any impact on the Company’s financial condition or results of operations.
The Accounting Standards Executive Committee of the American Institute of Certified Public Accountants has issued an exposure draft of a proposed Statement of Position (“SOP”) entitled “Accounting for Certain Costs and Activities Related to Property, Plant and Equipment.” If adopted as proposed, this SOP would require companies to expense as incurred turnaround costs, defined as “the non-capital portion of major maintenance costs.” Adoption of the proposed SOP would also require that any existing turnaround accruals be reversed to income immediately. If this proposed change were in effect at December 31, 2002, the Company would have been required to reverse the turnaround accruals and recognize pretax income totaling $26.9 million. The total accrued turnaround costs will change throughout the year as turnarounds are incurred and accruals are made for future turnarounds. If adopted in its present form, income related to this proposed change would be reported as a cumulative effect of an accounting change, net of tax, in the consolidated statements of operations.
In April 2002, the FASB issued SFAS No. 145, “Rescission of FASB Statements No. 4, 44 and 64, Amendment of FASB Statement No. 13, and Technical Corrections.” It is probable that the rescission of SFAS No. 4 is the only portion of SFAS No. 145 that may have an impact on the Company in the future. Under SFAS No. 4, all gains and losses from extinguishment of debt were required to be aggregated and, if material, classified as an extraordinary item, net of related income tax effect. SFAS No. 145 eliminates SFAS No. 4. As a result, gains and losses from extinguishment of debt should be classified as extraordinary items only if they meet the criteria in Opinion 30. The Company adopted SFAS No. 145 effective January 1, 2003 and it did not expected have any impact on the Company’s financial condition or results of operations for the periods presented herein.
In June 2002, the FASB issued SFAS No. 146, “Accounting for Costs Associated with Exit or Disposal Activities.” SFAS No. 146 addresses financial accounting and reporting for costs associated with exit or disposal activities. SFAS No. 146 is effective for exit or disposal activities that are initiated after December 31, 2002.
In December 2002, the FASB issued SFAS No. 148, “Accounting for Stock-Based Compensation – Transition and Disclosure, an amendment of FASB Statement No. 123.” SFAS No. 148 amends SFAS No. 123, “Accounting for Stock-Based Compensation”, to provide alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation. In addition, SFAS No. 148 amends the disclosure requirements of SFAS No. 123 to require prominent disclosures in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on reported results. SFAS No. 148 is effective for the December 31, 2002 financial statements and all required disclosures have been made in the notes to the 2002 financial statements.
Highly liquid investments with a maturity, when purchased, of three months or less are considered to be cash equivalents. Cash equivalents were $109.8 million and $102.3 million at December 31, 2002 and 2001, respectively.
Cash payments for interest, excluding capitalized interest, during 2002, 2001 and 2000 were $24.5 million, $27.8 million and $31.7 million, respectively. Cash payments for income taxes during 2002, 2001 and 2000 were $83,000, $21.2 million and $2.4 million, respectively.
Certain prior year amounts have been reclassified to conform with the current year presentation.
Schedule of Long-term Debt
(in thousands)
December 31,
-----------------------------------
2002 2001
---------------- ----------------
11-3/4% Senior Notes, net of unamortized discount $ 168,491 $ 168,315
9-1/8% Senior Notes 39,475 40,565
---------------- ----------------
$ 207,966 $ 208,880
================ ================
On November 5, 1999, the Company issued $190 million principal amount of 11¾% Senior Notes due 2009. The 11¾% Notes were issued at a price of 98.562%. The net proceeds were utilized to acquire the El Dorado Refinery. The 11¾% Notes are redeemable, at the option of the Company, at 105.875% after November 15, 2004, declining to 100% in 2007. Prior to November 15, 2004, the Company may at its option redeem the 11¾% Notes at a defined make-whole amount, plus accrued and unpaid interest. During 2001 and 2000, the Company purchased and is holding as treasury notes $6.5 million and $13.0 million, respectively, principal amount of the 11¾% Senior Notes, the accounting for which was a reduction of debt. Interest is paid semiannually.
On February 9, 1998, the Company issued $70 million of 9-1/8% Senior Notes due 2006. The 9-1/8% Notes are redeemable, at the option of the Company, at 104.563% after February 15, 2002, declining to 100% in 2005. Interest is paid semiannually. During 2002, 2001 and 2000, the Company purchased and is holding as treasury notes $1.1 million, $24.4 million and $5.0 million, respectively, principal amount of the 9-1/8% Senior Notes, the accounting for which was a reduction of debt.
The refining operations have a working capital credit facility with a group of nine banks. The revolving credit facility has a current expiration date of June 15, 2004. The facility is a collateral-based facility with total capacity of up to $175 million, of which maximum cash borrowings are $125 million, subject to borrowing base amounts. Any unutilized capacity after cash borrowings is available for letters of credit. No debt was outstanding at December 31, 2002 or 2001. Standby letters of credit outstanding were $48.0 million and $175,000 at December 31, 2002 and 2001, respectively. As of December 31, 2002, the Company had borrowing base availability of $88.2 million under the facility.
The facility provides working capital financing for operations, generally the financing of crude and product supply. It is generally secured by the Refineries’ current assets. The agreement provides for a quarterly commitment fee of 0.375 of 1% to 0.500 of 1% per annum. Interest rates are based, at the Company’s option, on the agent bank’s prime rate plus 0.25% to 1%, the prevailing Federal Funds Rate plus 2% to 2.75%, or the reserve-adjusted LIBOR plus 1.5% to 2.25%. Standby letters of credit issued bear a fee of 1.125% to 1.875% annually, plus standard issuance and renewal fees. In all cases, the rate and fees discussed above increase from the lower to higher levels as the ratio of funded debt to earnings, as defined, increases. The average interest rate on funds borrowed under the revolving credit facility during 2002 was 3.7%. The agreement includes certain financial covenant requirements relating to the Refineries’ working capital, cash earnings, tangible net worth and capital expenditure limits. The Company was in compliance with these covenants at December 31, 2002.
The revolving credit facility restricts the Refineries as to the distribution of capital assets and the transfer of cash in the form of dividends, loans or advances when there are any outstanding borrowings under the facility or when a default exists or would occur. The Company is currently in compliance with the provisions of its credit agreement.
The 9-1/8% Senior Notes are due 2006 and the 11¾% Notes are due 2009; until then there are no maturities of long-term debt.
The following is the provision for income taxes for the three years ended December 31, 2002, 2001 and 2000.
Provision for Income Taxes
(in thousands)
2002 2001 2000
----------- ----------- -----------
Current:
State $ 32 $ 6,231 $ 615
Canadian 83 - 751
Federal (204) 12,379 579
----------- ----------- -----------
Total current (benefit) provision (89) 18,610 1,945
----------- ----------- -----------
Deferred:
State 303 457 1,277
Federal 846 9,006 (1,147)
----------- ----------- -----------
Total deferred provision 1,149 9,463 130
----------- ----------- -----------
$ 1,060 $ 28,073 $ 2,075
=========== =========== ===========
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 for the three years ended December 31, 2002, 2001 and 2000.
Reconciliation of Tax Provision
(in thousands)
2002 2001 2000
----------- ----------- -----------
Provision based on statutory rates $ 731 $ 47,504 $ 13,748
Increase (decrease) resulting from:
Release of valuation allowance - (24,603) (13,574)
Federal tax effect of state and
other income taxes (146) (2,341) (925)
State and other income taxes 418 6,688 2,643
Other 57 825 183
----------- ----------- -----------
Provision as reported $ 1,060 $ 28,073 $ 2,075
=========== =========== ===========
Significant components of deferred tax assets and liabilities are shown below:
Components of Deferred Taxes
(in thousands)
December 31,
------------------------------
2002 2001
------------- -------------
Current deferred tax assets:
State gross current assets $ 808 $ 765
State net operating losses 287 -
State gross current liabilities (132) (149)
------------- -------------
Total state current net deferred tax assets 963 616
------------- -------------
Federal gross current assets 5,651 5,304
Federal gross current liabilities (1,268) (1,075)
------------- -------------
Total federal current net deferred tax assets 4,383 4,229
------------- -------------
Total current deferred tax assets $ 5,346 $ 4,845
============= =============
Long-term deferred tax liabilities:
State gross long-term liabilities $ 6,242 $ 5,700
State gross long-term assets (1,767) (1,660)
------------- -------------
Total state long-term net deferred tax liabilities 4,475 4,040
------------- -------------
Federal gross long-term liabilities 39,460 41,071
Federal gross long-term assets:
Accrued liabilities and other (13,923) (13,372)
Federal alternative minimum tax credits (13,434) (13,614)
Federal net operating loss carryforwards and other (1,402) (3,045)
------------- -------------
Total federal gross long-term assets (28,759) (30,031)
------------- -------------
Total federal long-term net deferred tax liabilities 10,701 11,040
------------- -------------
Total long-term deferred tax liabilities $ 15,176 $ 15,080
============= =============
The accrued liabilities and other deferred tax assets primarily include turnaround and postretirement employee benefit expenses. The major component of the deferred tax liabilities is depreciation.
At December 31, 2002, the Company had alternative minimum tax carryforwards of approximately $13.4 million which are indefinitely available to reduce future United States income taxes payable, of which $644,000 represents alternative minimum tax carryforwards generated by the Cheyenne refining operations prior to its 1991 acquisition by the Company which may be subject to certain limitations. The Company had an estimated federal net operating loss carryforward of $6.7 million as of December 31, 2002, the majority of which will not expire until 2022.
The Company has estimated state net operating losses generated during 2002 to reduce future state taxable income of $3.3 million for Kansas, $690,000 for Colorado and $174,000 for Nebraska. Carryforward periods for the state net operating losses are ten years for Kansas, twenty years for Colorado and five years for Nebraska. State deferred tax liabilities were $3.5 million and $3.4 million at December 31, 2002 and 2001, respectively, reflecting the estimated state tax effect of temporary differences, primarily for differences in depreciation for property, plant and equipment.
The Company declared quarterly dividends of $.05 per share of common stock for each quarter during 2002 and quarterly dividends of $.05 per share for the second, third and fourth quarters of 2001. No dividends were declared for the year ended December 31, 2000.
The following sets forth the computation of diluted earnings per share (“EPS”) for the years ended December 31, 2002, 2001 and 2000.
2002 2001 2000
----------------------------------- ---------------------------------- -----------------------------------
Per Per Per
Income Shares Share Income Shares Share Income Shares Share
(Numerator) (Denominator) Amount (Numerator) (Denominator) Amount (Numerator) (Denominator) Amount
----------- ------------- -------- ----------- ------------- -------- ----------- ------------- --------
(in thousands except per share amounts)
Basic EPS:
Net income $ 1,028 25,780 .04 $ 107,653 26,113 $ 4.12 $ 37,206 27,374 $ 1.36
Dilutive securities:
Stock options and
restricted stock - 1,154 - 772 - 415
--------- ------- --------- --------- -------- -------- --------- ------- -------
Dilutive EPS:
Net income $ 1,028 26,934 $ .04 $ 107,653 26,885 $ 4.00 $ 37,206 27,789 $ 1.34
========= ======= ========= ========= ======== ======== ========= ======= =======
The number of shares of the Company’s restricted stock that could potentially dilute basic EPS in the future but were not included in the computation of diluted EPS for the years ended 2002, 2001 and 2000 were 242,880, 155,575 and 0 shares, respectively, because to do so would have been antidilutive for those periods presented.
During 1995, the Company established a stock grant plan for non-employee directors. The purpose of the plan is to provide a part of non-employee directors’ compensation in Company stock. The plan will be beneficial to the Company and its stockholders by allowing non-employee directors to have a personal financial stake in the Company through an ownership interest in the Company’s common stock. The plan may grant an aggregate of 60,000 shares of the Company’s common stock held in treasury. The Company made aggregate grants to directors under this plan of 3,000 shares each in 2002 and 2001 and 2,000 shares in 2000 and expensed compensation in the amount of $13,500, $13,500 and $9,000, respectively for each of these years. There were 42,000 shares available for grant as of December 31, 2002.
The Company has a stock option plan which authorizes the granting of options to employees to purchase shares. The plans through December 31, 2002 have reserved for issuance a total of 8,002,075 shares of common stock of which 4,435,175 shares were granted and exercised, 2,581,250 shares were granted and were outstanding and 985,650 shares were available to be granted. Options under the plan are granted at fair market value on the date of grant. No entries are made in the accounts until the options are exercised, at which time the proceeds are credited to common stock and paid-in capital. Generally, the options vest ratably throughout their one- to five-year terms.
Changes during 2002, 2001 and 2000 in outstanding options are presented below:
2002 2001 2000
------------------------------ ----------------------------- --------------------------
Weighted- Weighted- Weighted-
Number of Average Number of Average Number of Average
Options Exercise Price Options Exercise Price Options Exercise Price
------------- -------------- ------------- -------------- ------------ --------------
Outstanding at beginning of year 2,159,700 $ 7.22 2,451,220 $ 5.88 2,115,884 $ 4.68
Granted 702,400 21.85 623,500 8.88 1,218,000 7.13
Exercised (230,750) 6.79 (869,570) 4.68 (647,674) 4.24
Expired (50,100) 10.21 (45,450) 6.41 (234,990) 6.10
----------- ----------- -----------
Outstanding at end of year 2,581,250 11.18 2,159,700 7.22 2,451,220 5.88
=========== =========== ===========
Exercisable at end of year 1,512,325 8.63 1,022,826 6.72 1,326,570 5.17
=========== =========== ===========
Available for grant at end of year 985,650 765,230 1,343,280
=========== ============= ===========
Weighted-average fair value of
options granted during the year 9.34 4.39 3.58
The following table summarizes information about stock options outstanding at December 31, 2002:
Options Outstanding Options Exercisable
----------------------------------------- -------------------------
Weighted-
Average Weighted- Weighted-
Number Remaining Average Average
Outstanding Contractual Exercise Exercisable Exercise
Range of Exercise Prices At 12/31/02 Life (Years) Price at 12/31/02 Price
- ------------------------ -------------- ------------- ----------- ----------- ----------
$5.63 to $7.00 1,263,550 1.86 $ 6.48 1,039,650 $ 6.37
$8.50 to $8.75 595,000 3.04 8.58 284,500 8.57
$12.10 20,000 3.33 10.10 10,000 12.10
$19.07 to 21.85 702,700 4.29 21.81 178,175 21.77
Had compensation costs been determined based on the fair value at the grant dates for awards made in 2002, 2001, and prior years for the vested portions of the awards in each of the years 2002, 2001 and 2000, the Company’s net income (loss) and EPS would have been the pro forma amounts indicated in the following table for the years ended December 31, 2002, 2001 and 2000:
2002 2001 2000
----------- ----------- -----------
(in thousands except per share amounts)
Net income as reported $ 1,028 $ 107,653 $ 37,206
Pro forma compensation expense, net of tax (4,002) (1,670) (2,156)
---------- ----------- -----------
Pro forma net income (loss) (2,974) 105,983 35,050
Basic EPS:
As reported $ .04 $ 4.12 $ 1.36
Pro forma (.12) 4.06 1.28
Diluted EPS:
As reported $ .04 $ 4.00 $ 1.34
Pro forma (.12) 3.94 1.26
The fair value of grants was estimated on the date of grant using the Black-Scholes option pricing model with the following weighted-average assumptions used for 2002, 2001 and 2000, respectively: risk-free interest rates of 2.76%, 4.80% and 6.58%, expected volatilities of 55.6%, 50.20% and 47.40%, expected lives of 5.0 years, 5.0 years, and 3.50 years and 1.27% dividend yield in 2002, 0.5% dividend yield in 2001 and no dividend yield in 2000.
On March 13, 2001, the Company established the Frontier Oil Corporation Restricted Stock Plan (the “Plan”) covering 1,000,000 shares of common stock held as treasury stock by the Company. The Plan’s purpose is to permit grants of shares, subject to restrictions, to key employees of the Company and is intended to promote the interests of the Company by encouraging those employees to acquire or increase their equity interest in the Company. The Plan is also intended to enhance the ability of the Company to attract and retain the services of key employees who are important to the growth and profitability of the Company. The Plan is designed to work in conjunction with the Company’s annual bonus program for employees whereby all or a portion of a bonus awarded shall be paid in the form of restricted stock granted under the Plan. Shares awarded under the Plan entitle the shareholder to all rights of common stock ownership except that the shares may not be sold, transferred or pledged during the restriction period except as provided for in the Plan and any dividends are held by the Company and paid to the employee when the stock vests.
As of December 31, 2002, there are 294,697 shares of unvested restricted stock which represents the total of both the 2001 and 2002 grants less the portion of the 2001 grant which has now vested and reduced by shares forfeited from employee departures prior to vesting. Of the remaining 181,638 shares from the 2001 grants, 60,540 shares vest in March 2003 and the remaining 121,098 shares will vest in March 2004. The Company granted an additional 113,059 restricted shares on March 13, 2002 and recorded an additional $2.2 million to deferred employee compensation. These restricted shares of common stock granted in 2002 vest 25% in March 2003, 25% in March 2004 and 50% in March 2005. The shares for both the 2002 and 2001 grants were recorded at the market value on the date of issuance (March 13, 2002 and 2001 respectively) as deferred employee compensation (equity account) and is being amortized to compensation expense over the respective vesting periods of the stock. Compensation expense for the years ended December 31, 2002 and 2001 was $907,000 and $380,000, respectively.
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 basic and/or matching contributions on behalf of participating employees. The cost of the plans for the three years ended December 31, 2002, 2001 and 2000 was $5.1 million, $4.6 million and $4.8 million, respectively.
The Company established a defined cash balance pension plan, effective January 1, 2000, for eligible El Dorado employees to supplement retirement benefits 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. This plan has assets of $3.8 million at December 31, 2002 and its funding status is in compliance with ERISA.
The Company provides postretirement 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 have no assets as of December 31, 2002 and 2001.
The following tables set forth the change in benefit obligation, the change in plan assets, the funded status of the pension plan and postretirement healthcare and other benefit plans, amounts recognized in the Company’s financial statements, and the principal weighted-average assumptions used:
Postretirement
Healthcare and
Pension Benefits Other Benefits
---------------------- --------------------
2002 2001 2002 2001
-------- -------- -------- --------
(in thousands)
Change in benefit obligation
Benefit obligation at January 1 $ 8,816 $ 8,409 $ 15,075 $ 12,015
Service cost - - 691 599
Interest cost 582 563 1,071 901
Plan participant contributions - - 3 1
Actuarial (gains) losses 449 (95) 2,547 1,566
Benefits paid (53) (61) (7) (7)
-------- -------- --------- --------
Benefit obligation at December 31 $ 9,794 $ 8,816 $ 19,380 $ 15,075
======== ======== ========= ========
Change in plan assets
Fair value of plan assets at January 1 $ 925 $ - $ - $ -
Actual return on plan assets 54 13 - -
Employer contribution 2,851 973 4 6
Plan participant contributions - - 3 1
Benefits paid (53) (61) (7) (7)
-------- -------- -------- --------
Fair value of plan assets at December 31 $ 3,777 $ 925 $ - $ -
======== ======== ======== ========
Funded status $ (6,017) $ (7,891) $ (19,380) $(15,075)
Unrecognized net actuarial loss 970 413 4,941 2,530
-------- -------- --------- --------
Net amount recognized $ (5,047) $ (7,478) $ (14,439) $(12,545)
======== ======== ========= ========
Amounts recognized in the balance sheets:
Accrued benefit liability $ (6,017) $ (7,891) $ (14,439) $(12,545)
Accumulated other comprehensive loss 970 413 - -
-------- -------- -------- --------
Net amount recognized $ (5,047) $ (7,478) $ (14,439) $(12,545)
======== ======== ========= ========
Weighted-average assumptions as of December 31
Discount rate 6.25% 6.82% 6.25% 6.82%
Expected return on plan assets 8.00% 8.00% 8.00% 8.00%
Components of net periodic benefit cost are as follows:
Postretirement
Healthcare and
Pension Benefits Other Benefits
------------------------ -------------------------------
2002 2001 2000 2002 2001 2000
------ ------- ------- --------- --------- ---------
(in thousands)
Components of net periodic benefit cost:
Service cost $ - $ - $ - $ 691 $ 599 $ 537
Interest cost 582 563 401 1071 901 752
Expected return on plan assets (162) (25) - - - -
Amortization of prior service cost - - - - - -
Recognized net actuarial loss - - - 136 11 -
------ ------- ------- --------- --------- ---------
Net periodic benefit cost $ 420 $ 538 $ 401 $ 1,898 $ 1,511 $ 1,289
====== ====== ====== ======== ======== =========
Healthcare cost trend rate:
15.00% 15.00% 9.00%
ratable to ratable to ratable to
5.0% 5.0% 5.0%
from 2007 from 2007 from 2009
Sensitivity Analysis:
Effect of 1% (-1%) change in healthcare cost-trend rate:
Year-end benefit obligation $ 4,258 $ 3,322 $ 2,688
(3,313) (2,585) (2,088)
Total of service and interest cost 394 338 293
(307) (263) (228)
On November 16, 1999, Frontier acquired the 110,000 barrels per day crude oil refinery located in El Dorado, Kansas from Equilon Enterprises LLC, now known as Shell Oil Products US (“Shell”). Under the provisions of the purchase and sale agreement, the Company is required to make contingent earn-out payments for each of the years 2000 through 2007 equal to one-half of the excess over $60 million per year of the El Dorado Refinery’s revenues less its material costs and operating costs, other than depreciation. The total amount of these contingent payments is capped at $40 million, with an annual cap of $7.5 million. Any contingency payment will be recorded when determinable. Such contingency payments, if any, will be recorded as additional acquisition cost. No contingent earn-out payment will be required based on 2002 results. A contingent earn-out payment of $7.5 million was required based on 2001 results and was accrued as of December 31, 2001 and paid in early 2002. No contingent earn-out payment was required based on 2000 results.
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 noncancellable operating sublease expires in 2016 with the Company having the option to renew the sublease for an additional eight years. At the end of the renewal sublease term, 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 2003 through 2008. Operating lease rental expense was approximately $11.3 million, $11.9 million and $11.1 million for the three years ended December 31, 2002, 2001 and 2000, respectively. The approximate future minimum lease payments as of December 31, 2002 are $10.4 million for 2003, $10.0 million for 2004, $9.5 million for 2005, $9.0 million for 2006, $7.5 million for 2007 and $56.9 million thereafter.
The Company has a one-year foreign crude oil supply agreement with Shell which expires April 2003. Under this agreement, the Company may purchase crude oil for the El Dorado Refinery from Shell, although the Company is not obligated to do so. The Company is obligated to pay monthly installments towards an annualized commitment fee to Shell for making foreign crude volumes available to the Company under this agreement based on a per barrel fee for crude purchased under this agreement. This agreement allows the Company to use Shell’s worldwide network to acquire foreign crude oil.
In October 2002, the Company entered into a five-year crude oil supply agreement with Baytex Energy Ltd, a Canadian crude oil producer. On November 28, 2002, Baytex Energy Ltd. assigned this agreement to its wholly-owned subsidiary, Baytex Marketing Ltd. (“Baytex”). This agreement, which commences January 1, 2003, will provide for the Company to purchase up to 20,000 barrels per day of a Lloydminster crude oil blend, a heavy Canadian crude. Initially, the Company will receive 9,000 barrels per day, increasing up to 20,000 barrels per day by October 2003. The Company intends to process this crude oil at the Cheyenne Refinery, which is near Guernsey, Wyoming, the delivery point of the crude oil under this agreement. This type of crude oil typically sells at a discount to lighter crude oils. The Company’s price for the crude oil under the agreement will be equal to 71% of the simple average of the near month settlement prices of the NYMEX light sweet crude oil contracts during the month of delivery, plus the cost of transportation based on the pipeline tariff from Hardisty, Alberta to Guernsey, Wyoming, less $0.25 per barrel. The initial term of the agreement is through December 31, 2007. This agreement provides a firm source of heavy Canadian crude and also assigns most of the Company’s dedicated capacity through the Express Pipeline, a crude oil pipeline from Canada to Guernsey, Wyoming.
The Company contracted for pipeline capacity of approximately 13,800 bpd on the Express Pipeline from Hardisty, Alberta to Guernsey, Wyoming in 1997 for a period of 15 years. The agreement has allowed the Company to assign a portion of its capacity in early years for additional capacity in later years. As discussed above, the Company has assigned a portion of its contracted pipeline capacity to Baytex in connection with the crude supply agreement. The Company’s commitment for pipeline capacity, based on the current tariff, and after reducing for the commitment assigned to Baytex under the initial term of the agreement, is approximately $1.6 million for 2003, $178,000 for 2004, $934,000 for 2005, $284,000 for 2006, $0 for 2007, $6.1 million for each of the years 2008 though 2011, and $1.5 million for 2012. Should the Baytex agreement be extended, as provided for in the agreement, beyond the initial term which is through December 31, 2007, a significant portion of the Company’s commitment for pipeline capacity will continue to be assigned to Baytex in the years 2008 through 2012.
The Company has a Resid Processing Agreement, as amended, with Conoco Inc. (“Conoco”) which expires no later than December 2006. Conoco is entitled to process in the Cheyenne Refinery coker unit up to 3,300 barrels per day of resid. The Company earns a processing fee ranging from $.80 to $2.05 per barrel depending on the number of barrels of resid processed plus a pro rata share of the actual coker operating costs.
The Company owns a 25,000 bpd interest in a crude oil pipeline from Guernsey, Wyoming to the Cheyenne Refinery and a 50% interest in some crude oil tankage in Guernsey. The Company’s share of operating costs for the crude oil pipeline and the tanks are recorded as refining operating costs.
The Company has commitments to purchase crude oil from various suppliers on a one-month to one-year basis at daily market posted prices to meet its refineries’ throughput requirements.
The Company has concentrations of credit risk with respect to sales within the same or related industry and within limited geographic areas. The Company sells its Cheyenne products exclusively at wholesale, principally to independent retailers and major oil companies located primarily in the Denver, western Nebraska and eastern Wyoming regions. The Company sells a majority of its El Dorado gasoline, diesel and jet fuel to Shell at market-based prices, under a 15-year offtake agreement in conjunction with the purchase of the El Dorado Refinery previously discussed. Beginning in 2000, the Company retained and marketed a portion of the El Dorado Refinery’s gasoline and diesel production. This portion will increase 5,000 barrels per day each year for ten years. The amount of gasoline and diesel production retained by the Company began at 5,000 barrels per day in 2000, and will rise to 50,000 barrels in 2009 and remain at that level through the term of the agreement. Shell will purchase all jet fuel production from the El Dorado Refinery through 2004. The Company retains and markets all of the chemicals and heavy oils production from the El Dorado Refinery.
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 customers’ credit risk, past experience and other factors. During 2002, the Company provided an allowance of $800,000 against a $2.2 million note receivable from a customer which represents the estimated unsecured portion of the note. During 2000, doubtful accounts for two customers totaling $533,000 were written off. The Company made sales to Shell during 2002, 2001 and 2000 of approximately $1.1 billion, $1.1 billion and $1.2 billion, respectively, which accounted for 58% of consolidated sales revenues in 2002 and 59% of consolidated sales revenues in 2001 and 2000.
The Company accounts for environmental costs as indicated in Note 2. The Company’s refining and marketing operations are subject to a variety of federal, state and local health and environmental laws and regulations governing product specifications, the discharge of pollutants into the air and water, and the generation, treatment, storage, transportation and disposal of solid and hazardous waste and materials. Permits are required for the operation of the Refineries, and these permits are subject to revocation, modification and renewal. Governmental authorities have the power to enforce compliance with these regulations and permits, and violators are subject to injunctions, civil fines and even criminal penalties. The Company believes that each of our Refineries is in substantial compliance with existing environmental laws, regulations and permits.
The Company’s operations and many of the products manufactured 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 installation of certain air pollution control devices at our refineries during the next several years. The EPA recently embarked on a Petroleum Refining Initiative (“Initiative”) alleging industry-wide noncompliance with certain CAA rules. The Initiative has resulted in many refiners entering into consent decrees typically requiring substantial expenditures for penalties and additional pollution control equipment. Frontier has been contacted by the EPA and invited to meet with them to hear more about the Initiative. At this time, the Company does not know how or if the Initiative will affect Frontier. The Company has, however, recently determined that over the next three years, expenditures totaling approximately $10 million may be necessary to further reduce emissions from the Refineries’ flare systems. Because other refineries will be required to make similar expenditures, Frontier does not expect such expenditures to materially adversely impact the Company’s competitive position.
On December 21, 1999, the EPA promulgated national regulations limiting the amount of sulfur that is to be allowed in gasoline. The total capital expenditures estimated, as of December 31, 2002, to achieve the final gasoline sulfur standard, are approximately $35 million at the Cheyenne Refinery and approximately $44 million at the El Dorado Refinery. Approximately $7.2 million of the Cheyenne Refinery expenditures had been incurred as of December 31, 2002, an additional $20.8 million is expected to be incurred by early 2004 with the remaining $7 million in 2009 and 2010. The expenditures for the El Dorado Refinery are expected to be incurred beginning in 2008 and completed in 2010.
The EPA recently promulgated regulations that will limit the sulfur content of highway diesel fuel beginning in 2006 to 15 parts-per-million from the current standard of 500 parts-per-million. As of December 31, 2002, capital costs for diesel desulfurization are estimated to be approximately $5 million for Cheyenne and $56 million for El Dorado. The Cheyenne Refinery expenditures are currently expected to be committed beginning in 2005, with the majority to be committed in 2006. Approximately $6 million of the El Dorado Refinery expenditures are currently expected to be committed in 2004 with the remaining $50 million in 2005 and 2006.
The EPA has recently stated their intent to propose new regulations that will limit emissions from diesel fuel powered engines used in off-road activities such as mining, construction and agriculture. The EPA has also stated their intent to simultaneously limit the sulfur content of diesel fuel used in these engines to facilitate compliance with the new emission standards. The EPA expects to propose the new off-road diesel engine emissions and related fuel sulfur standards early in 2003. It is likely that the new rules will require the off-road diesel fuel sulfur content to be reduced to 500 parts-per-million or less from the current limit of 5,000 parts-per-million by 2007. Since a minor portion of the diesel fuel the Company manufactures at the El Dorado Refinery is sold to the off-road market, these regulations, when promulgated, will likely require certain modifications to the Refinery. The cost associated with such modifications cannot be estimated until the final regulatory limits are known.
As is the case with all companies engaged in similar industries, the Company faces potential exposure from future claims and lawsuits involving environmental matters. The matters include soil and water contamination, air pollution, personal injury and property damage allegedly caused by substances which the Company manufactured, handled, used, released or disposed of.
Cheyenne Refinery. The Company is party to an agreement with the State of Wyoming requiring the investigation and possible eventual remediation of certain areas of the Cheyenne Refinery’s property which may have been impacted by past operational activities. Among other things, this order required a technical investigation of the Cheyenne Refinery to determine if certain areas have been adversely impacted by past operational activities. Based upon the results of the investigation, additional remedial action could be required by a subsequent administrative order or permit. The ultimate cost of any environmental remediation projects that may be identified by the site investigation required by the agreement cannot be reasonably estimated at this time.
El Dorado Refinery. The El Dorado Refinery is subject to a 1988 consent order with the Kansas Department of Health and the Environment (“KDHE”). This order, including various subsequent modifications, requires the Refinery to continue the implementation of a groundwater management program with oversight provided by the KDHE Bureau of Environmental Remediation. 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. Subject to the terms of the purchase and sale agreement, Shell will be responsible for the costs of continued compliance with this order.
The most recent National Pollutant Discharge Elimination System permit issued to the El Dorado Refinery requires, in part, the preparation and submittal of an engineering report identifying certain refinery wastewater treatment plant upgrades necessary to allow routine compliance with applicable discharge permit limits. In accordance with the provisions of the purchase and sale agreement, Shell will be responsible for the first $2 million of any required wastewater treatment system upgrades. If required system upgrade costs exceed this amount, Shell and Frontier will share, based on a sliding scale percentage, up to another $3 million in upgrade costs. Subject to the terms of the purchase and sale agreement, Shell will be responsible for up to $5 million in costs, in addition to Shell’s obligation for the wastewater treatment system upgrade, relating to safety, health and environmental conditions after closing arising from Shell’s operation of the El Dorado Refinery that are not covered under a ten-year insurance policy. This insurance policy has $25 million coverage through November 17, 2009 for environmental liabilities, with a $500,000 deductible, and will reimburse the Company for losses related to all known and some unknown conditions existing prior to our acquisition of the El Dorado Refinery. The first phase of wastewater treatment system upgrades was completed in 2001 at a cost of $2.6 million with payment apportioned as described above.
On August 18, 2000, the Company entered into a Consent Agreement and Final Order of the Secretary (“Agreement”) with the KDHE that required the initiation of a wastewater toxicity testing program to commence upon the completion of the wastewater treatment upgrades described above. Good progress has since been made toward satisfying the provisions of the Agreement and Frontier expects to meet all applicable requirements.
The Company is involved in various lawsuits 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’s refining units hourly employees are represented by seven bargaining units, the largest being the Paper, Allied-Industrial, Chemical and Energy Workers International Union (“PACE”). Six AFL-CIO affiliated unions represent the Cheyenne Refinery craft workers. At the Cheyenne Refinery, the current contract with PACE expires in July 2006, while the current contract with the AFL-CIO affiliated unions expires in June 2009. The El Dorado Refinery’s hourly workers are all represented by PACE and the current contract with PACE expires January 2006. The union employees represent approximately 61% of the Company’s work force at December 31, 2002.
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, 2002 and 2001, the carrying amounts of long-term debt instruments were $208.0 million and $208.9 million, respectively, and the estimated fair values were $212.6 million and $222.3 million.
The Company, at times, enters into commodity derivative contracts for the purposes of managing price risk on foreign crude purchases, crude and other inventories, and natural gas purchases and to fix margins on certain future production.
| During 2002, 2001 and 2000, 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: |
| • | Derivative contracts on barrels of crude oil to hedge butane inventory builds at the El Dorado Refinery. During the year ended December 31, 2002, the Company recorded $903,000 in realized losses on these positions. |
| • | Derivative contracts during 2002 on barrels of crude oil to hedge excess gas oil inventory at the Cheyenne Refinery had $202,000 in realized losses. |
| • | Derivative contracts during 2002 on barrels of crude oil to hedge excess gas oil inventory at the El Dorado Refinery resulted in gains of $896,000. |
| • | Derivative contracts during 2002 on barrels of crude oil to hedge excess naptha inventory at the El Dorado Refinery resulted in losses of $579,000. |
| • | Derivative contracts during 2002 to hedge crude oil resulted in a gain of $48,000. |
| • | Derivative contracts to fix margins on sales of gasoline and diesel. During 2001, the Company recorded net gains on these positions totaling $2.5 million ($394,000 realized gain plus the reversal of the $2.1 million unrealized loss recorded in 2000). During 2000, the impact of these positions was $0 ($2.1 million realized gain and an unrealized loss of $2.1 million recorded at December 31, 2000 on open positions). |
| • | Derivative contracts on unleaded gasoline to hedge butylene inventory builds at the El Dorado Refinery which were drawn down in April and May 2001. During 2001, the Company recorded a net loss of $1.3 million on these positions ($769,000 realized loss plus the reversal of the unrealized gain recorded in 2000.) During 2000, the Company recorded net gains of $564,000, consisting of an unrealized gain recorded at December 31, 2000 on open positions. |
| • | Derivative contracts on barrels of crude oil to hedge excess inventory against price declines. During 2001, the Company recorded net losses of $1.5 million on these positions ($763,000 net realized losses plus the reversal of the unrealized gain recorded in 2000). During 2000, the Company recorded net gains of $115,000 on these positions ($622,000 realized losses plus an unrealized gain of $737,000 recorded on open positions at December 31, 2000). |
| • | Derivative contracts on barrels of crude oil to protect against price declines on foreign crude oil purchases. During 2001, the Company recorded a net loss of $2.2 million on these positions ($1.8 million realized gain less the unrealized gain recorded in 2000.) During 2000, the Company recorded net gains of $4.0 million, consisting of an unrealized gain recorded at December 31, 2000 on open positions. |
| • | Derivative contracts on natural gas to hedge natural gas costs. During 2001, the Company realized a $472,000 gain on positions to hedge natural gas. |
| • | Derivative contracts on barrels of unleaded gasoline and barrels of heating oil to hedge gas oil inventory builds at the Cheyenne Refinery. During 2001, the Company realized a $144,000 loss on these positions. |
As of December 31, 2002, the Company had no open derivative contracts.
During 2002, 2001 and 2000, the Company had the following derivatives which were appropriately designated and accounted for as hedges:
| • | Crude Purchases. At December 31, 2002, the Company had no open derivative contracts to hedge against price declines on foreign crude oil purchases. During the year ended December 31, 2002, the Company closed out contracts to hedge foreign crude purchases and realized net losses of $9.8 million, of which $10.7 million increased crude costs and $878,000 income was reflected in other revenues for the ineffective portion of those hedges. These contracts were accounted for as fair value hedges. At December 31, 2001, the Company had open derivative contracts on 422,000 barrels of crude oil to hedge against price declines on foreign crude oil purchases which were accounted for as fair value hedges under SFAS No. 133. The unrealized ineffective portion of this hedge recorded in other revenues during 2001 was a $30,000 gain. During 2001, the Company realized gains of $7.1 million on crude fair value hedges of which $229,000 was the ineffective portions recorded in other revenues and $6.8 million was recorded as a reduction of crude oil costs. During 2000, the Company recognized losses of $6.0 million on crude oil hedging derivative contracts. |
| • | Natural Gas Collars. In March 2002, the Company entered into price swaps on natural gas for the purpose of hedging approximately 50% of the Refineries’ anticipated usage against natural gas price increases for April 2002 through December 2002. These contracts were accounted for as cash flow hedges. One group of contracts to hedge natural gas costs at the El Dorado Refinery averaged 300,000 MMBTU per month at an average price of $3.34 per MMBTU (Panhandle). A second group of contracts to hedge natural gas costs at the Cheyenne Refinery averaged 112,222 MMBTU per month at an average price of $2.84 per MMBTU (CIG). The April and May contracts resulted in net realized gains totaling $41,000 and were recorded into refining operating costs. Due to natural gas market conditions, a decision was made in May to close out the remaining June through December contracts resulting in a net gain of $393,000. The realized gains or losses were recorded in other comprehensive income (equity account), net of tax. The pretax realized gains or losses were reclassified into refining operating costs and out of other comprehensive income based on the month when the corresponding natural gas was purchased. As of December 31, 2002, all these gains and losses and been reclassified into earnings. During September 2000, the Company purchased two costless collars for the purpose of hedging against natural gas price increases for the November 2000 through March 2001 period. The first collar covered an aggregate of 38,000 MMBTU with ceiling and floor prices of $6.50 and $4.29, respectively. The second collar covered an aggregate of 9,000 MMBTU with ceiling and floor prices of $6.50 and $4.00, respectively. Through December 31, 2000, no gains or losses had been recorded related to the collars. At December 31, 2000, these collars had a fair value of $4.1 million. In the first quarter of 2001, these positions were closed and the Company realized a $2.4 million gain. Beginning January 1, 2001, the Company began accounting for these contracts as cash flow hedges under the provisions of SFAS No. 133. |
| • | Natural Gas Purchases. During 2000, the Company recognized natural gas hedging gains of $195,000. |
INDEPENDENT AUDITORS’ REPORT
�� To the Board of Directors and Shareholders of Frontier Oil Corporation:
We have audited the accompanying consolidated balance sheet of Frontier Oil Corporation and subsidiaries as of December 31, 2002, and the related consolidated statements of operations, changes in shareholders’ equity and cash flows for the year then ended. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audit. The consolidated financial statements of Frontier Oil Corporation as of December 31, 2001, and for the years ended December 31, 2001 and 2000 were audited by other auditors who have ceased operations. Those auditors expressed an unqualified opinion on those consolidated financial statements in their report dated February 8, 2002.
We conducted our audit in accordance with auditing standards generally accepted in the United States of America. 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 audit provides 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, 2002 and the results of their operations and their cash flows for the year ended December 31, 2002, in conformity with accounting principles generally accepted in the United States of America.
DELOITTE & TOUCHE LLP
Houston, Texas
February 7, 2003
Frontier Oil Corporation dismissed Arthur Andersen LLP on March 28, 2002 and subsequently engaged Deloitte & Touche LLP as its independent auditors. The predecessor auditors’ report appearing below is a copy of Arthur Andersen LLP’s previously issued opinion dated February 8, 2002. Since Frontier Oil Corporation is unable to obtain a manually signed audit report, a copy of Arthur Andersen LLP’s most recent signed and dated report has been included to satisfy filing requirements, as permitted under Rule 2-02(e) of Regulation S-X.
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
We have audited the accompanying consolidated balance sheets of Frontier Oil Corporation (a Wyoming corporation) and subsidiaries as of December 31, 2001 and 2000, and the related consolidated statements of operations, changes in shareholders’ equity and cash flows for each of the three years in the period ended December 31, 2001. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Frontier Oil Corporation and subsidiaries as of December 31, 2001 and 2000, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2001, in conformity with accounting principles generally accepted in the United States.
ARTHUR ANDERSEN LLP
Houston, Texas
February 8, 2002
The information contained in this Annual Report, as well as all the financial and operational data we present concerning Frontier Oil Corporation, 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 stand behind this pledge as a matter of honor and integrity.
James R. Gibbs
Chairman of the Board, President and
Chief Executive Officer
Julie H. Edwards
Executive Vice President - Finance and Administration,
Chief Financial Officer
Nancy J. Zupan
Vice President - Controller
UNAUDITED SUPPLEMENTARY DATA
2002 2001
------------------------------------------ ---------------------------------------
(unaudited, dollars in thousands except per share) Fourth Third Second First Fourth Third Second First
- -----------------------------------------------------------------------------------------------------------------------------------
Revenues $531,558 $486,680 $459,162 $336,350 $365,560 $538,049 $553,649 $431,143
Operating income (loss) 11,110 8,487 1,631 6,671 (11,447) 62,473 100,916 12,158
Net income (loss) 2,965 809 (3,007) 261 (10,422) 34,662 78,901 4,512
Basic earnings (loss) per share: $0.11 $0.03 ($0.12) $0.01 ($0.41) $1.33 $2.99 $0.17
Diluted earnings (loss) per share: $0.11 $0.03 ($0.12) $0.01 ($0.41) $1.27 $2.86 $0.17
Net cash provided by (used in) operating
activities 43,749 20,237 (3,120) (10,044) (10,827) 73,812 109,164 (33,574)
Net cash used in investing activities (6,729) (4,193) (10,560) (15,635) (8,585) (5,272) (4,560) (4,407)
Net cash provided by (used in) financing
activities (31,339) (19,082) 15,494 29,591 (11,528) (17,639) (64,104) 17,069
EBITDA (1) 18,089 15,466 8,407 13,269 (5,056) 68,808 107,120 18,238
Refining operations
Total charges (bpd) (2) 162,361 170,391 165,074 157,310 153,649 169,878 161,854 146,632
Gasoline yields (bpd) (3) 94,564 79,779 82,050 82,104 82,310 83,506 77,283 69,201
Diesel and jet fuel yields (bpd) (3) 55,140 53,101 54,190 51,273 49,313 54,578 52,653 48,247
Total product sales (bpd) 175,888 166,750 169,366 153,880 163,375 174,281 159,531 138,770
Average light/heavy spread based on delivered
crude costs for the Cheyenne Refinery(per
bbl) (4) $5.73 $3.95 $3.52 $3.75 $6.13 $6.42 $7.55 $8.20
Average WTI/WTS crude oil spread (per bbl) (5) $1.73 $0.97 $1.22 $1.53 $2.22 $2.68 $3.77 $3.73
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| (1) | EBITDA represents income before interest expense, interest income, income tax, and depreciation and amortization. EBITDA is not a calculation based upon generally accepted accounting principles; however, the amounts included in the EBITDA calculation are derived from amounts included in the consolidated financial statements of the Company. EBITDA should not be considered as an alternative to net income or operating income, as an indication of operating performance of the Company or as an alternative to operating cash flow as a measure of liquidity. EBITDA is not necessarily comparable to similarly titled measures of other companies. EBITDA is presented here because it enhances an investor's understanding of Frontier's ability to satisfy principal and interest obligations with respect to Frontier's indebtedness and to use cash for other purposes, including capital expenditures. EBITDA is also used for internal analysis and as a basis for financial covenants. Frontier's EBITDA for the 2002 and 2001 quarters is reconciled to net income as follows (in thousands): |
2002 2001
---------------------------------------- -----------------------------------------
Fourth Third Second First Fourth Third Second First
---------------------------------------- -----------------------------------------
Net income (loss) $2,965 $809 ($3,007) $261 ($10,422) $34,662 $78,901 $4,512
Add provision (benefit) for income taxes 1,686 1,140 (1,864) 98 (7,456) 21,221 13,849 459
Add interest expense and other financing
costs 6,874 7,009 6,953 6,777 7,129 7,458 8,659 7,900
Subtract interest income (415) (471) (451) (465) (698) (868) (493) (713)
Add depreciation and amortization 6,979 6,979 6,776 6,598 6,391 6,335 6,204 6,080
----------------------------------------- ----------------------------------------
EBITDA $18,089 $15,466 $8,407 $13,269 ($5,056) $68,808 $107,120 $18,238
========================================= ========================================
| (2) | Charges are the quantity of crude oil and other feedstock processed through refinery units. |
| (3) | Manufactured product yields are the volumes of specification materials that are obtained through the distilling of crude oil and the operations of other refinery process units. |
| (4) | Average light/heavy spread is the discount at which heavy crude oil (gravity is low) sells compared to the sales price of light crude oil (gravity is high). |
| (5) | Average differential between benchmark West Texas intermediate (sweet) and West Texas sour crude oil prices. |
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
The Report on Form 8-K filed April 3, 2002 is incorporated herein by reference. This report included Item 4 for the reporting of Changes in Registrant's Certifying Accountant and Item 7(c)(16) Letter re: change in certifying accountant.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
Directors
Set forth below are the directors of the Company along with their ages as of March 3, 2003.
Mr. James R. Gibbs (58) joined the Company in February 1982 and has been President and Chief Operating Officer since January 1987. He assumed the additional position of Chief Executive Officer on April 1, 1992 and additionally became Chairman of the Board on April 29, 1999. Mr. Gibbs is a member of the Board of Directors of Smith International, Inc., an oil field service company; an advisory director of Frost National Bank, Houston; a director of Veritas DGC Inc., a seismic service company; and a director of Gundle/SLT Environmental, Inc., an environmental service company. Mr. Gibbs was elected a director of the Company in 1985.
Mr. Douglas Y. Bech (57) has been Chairman and Chief Executive Officer of Raintree Resorts International, Inc. (“Raintree”) since August 1997. Mr. Bech is also a director and executive officer of Raintree U.S. Holdings, LLC, which filed for protection under Chapter 11 of the Bankruptcy Code on June 28, 2002. Raintree U.S. Holdings, LLC is a non-operating wholly owned subsidiary of Raintree. From 1994 to 1997, Mr. Bech was a partner in the law firm of Akin, Gump, Strauss, Hauer & Feld, L.L.P. of Houston, Texas. Since 1994, he has also been a managing director of Raintree Capital Company, LLC, a merchant banking firm. From 1993 to 1994, Mr. Bech was a partner of Gardere & Wynne, L.L.P. of Houston, Texas. From 1970 until 1993, Mr. Bech was associated with and a senior partner of Andrews & Kurth L.L.P. of Houston, Texas. Mr. Bech is a member of the Board of Directors of Pride Refining, Inc., the general partner of Pride Companies, L.P., a products pipeline and crude gathering company and j2 Global Communications, Inc., an internet document communications company. He was appointed a director of the Company in 1993.
Mr. G. Clyde Buck (65) has been a Senior Vice President and Managing Director of the investment banking firm Sanders Morris Harris, Inc. (including predecessor firms) since 1998. From 1983 to 1998, he was a Managing Director of Dain Rauscher Corporation, also an investment banking firm. Mr. Buck is also a member of the Board of Directors of Smith International, Inc., an oilfield service company. He was appointed a director of the Company in 1999.
Mr. T. Michael Dossey (60) has been a management consultant located in Houston, Texas since April 2000. From April 2000 through August 2002, Mr. Dossey was a management consultant affiliated with the Adizes Institute of Santa Barbara, California. Prior to his retirement in April 2000, Mr. Dossey spent 35 years with the Shell Oil Company and its affiliates. His last assignment with Shell was General Manager-Mergers and Acquisitions for Equilon Enterprises LLC, an alliance between the domestic downstream operations of Shell and Texaco. He also had been Vice President and Business Manager for Shell Deer Park Refining Company, which was a joint venture operation with Pemex. Previously, he spent several years in Saudi Arabia where he was General Operations Manager for Saudi Petrochemical Company, a joint venture between Shell and the Saudi Arabian government. Earlier in his career, Mr. Dossey’s positions included various business and operational positions in Shell’s refining and petrochemical operations domestically and in Europe. Mr. Dossey is a member of the advisory board of Verticore Technologies, Inc. and the marketing advisory board of Management Vitality Company, management consulting companies. He was appointed a director of the Company in 2000.
Mr. James H. Lee (54) is Managing General Partner and principal owner of Lee, Hite & Wisda Ltd., an oil and gas consulting firm, which he founded in 1984. From 1981 to 1984, Mr. Lee was a Principal with the oil and gas advisory firm of Schroder Energy Associates. He had prior experience in investment management, corporate finance and mergers and acquisitions at Cooper Industries Inc. and at White, Weld & Co. Incorporated. Mr. Lee is a member of the Board of Directors of Forest Oil Corporation, an oil and gas exploration and production company. He was appointed a director of the Company in 2000.
Mr. Paul B. Loyd, Jr. (56) served as Chairman of the Board and Chief Executive Officer of R&B Falcon Corporation, the world’s largest offshore drilling company, from December 1997 until its merger in January 2001, with Transocean Sedco Forex, after which time he retired. From April 1991 until December 1997 Mr. Loyd was Chairman of the Board and Chief Executive Officer of Reading and Bates, and prior to that time he had served as Assistant to the president of Atwood Oceanics International, President of Griffin-Alexander Company, and Chief Executive Officer of Chiles-Alexander International, Inc., all of which are companies in the offshore drilling industry. He has served as consultant to the Government of Saudi Arabia, and was a founder and principal of Loyd & Associates, Inc., an investment company focusing on the energy industry. Mr. Loyd is a member of the Board of Directors of Carrizo Oil & Gas, Inc., a member of the Board of Directors of Enterprise Oil, Plc., a member of the Board of Directors of Transocean Sedco Forex and serves on the Board of Trustees of Southern Methodist University and the Executive Board of the Cox School of Business. He was appointed a director of the Company in 1994.
Mr. Carl W. Schafer (67) has been the President of the Atlantic Foundation, a charitable foundation, since 1990. From 1987 until 1990, Mr. Schafer was a principal of the investment management firm of Rockefeller & Co., Inc. Mr. Schafer presently serves on the Board of Directors of Roadway Corporation, a transportation company; the UBS PaineWebber, Guardian, Harding Loevner, and European Investors Groups of Mutual Funds, registered investment companies; and Labor Ready, Inc., a temporary labor company. Mr. Schafer was elected a director of the Company in 1984.
Executive and Other Officers
Set forth below are the executive officers of the Company as of year end 2002 along with their ages as of March 3, 2003 and the office held by each officer.
Mr. James R. Gibbs (58) is Chairman of the Board, President and Chief Executive Officer. Information about Mr. Gibbs is included above under “Directors”.
Ms. Julie H. Edwards (44) is Executive Vice President-Finance & Administration. She joined the Company in March 1991 as Vice President-Secretary & Treasurer, was Senior Vice President-Finance & Chief Financial Officer from August 1994 until April 2000, when she was promoted to her current position. From 1985 to February 1991, she was employed by Smith Barney, Harris Upham & Co. Inc. in the Corporate Finance Department. Prior to 1985, she was employed by Amerada Hess Corporation and American Ultramar, Ltd., which were oil companies, as a geologist. Ms. Edwards recently became a member of the board of directors of EOTT Energy LLC, a crude oil pipeline company, the new entity that emerged from the bankruptcy of EOTT Energy Partners, L.P.
Mr. W. Reed Williams (55) has been Executive Vice President-Refining & Marketing since joining the Company in July 2000. He has over 29 years of experience in refining and marketing. Prior to joining the Company, Mr. Williams was employed by Ultramar Diamond Shamrock beginning in 1993, where his responsibilities included corporate development, operations planning, pipeline operations and product supply and distribution. His final position at Ultramar Diamond Shamrock was Vice President of Logistics Development. Prior to 1993, Mr. Williams was employed by Tesoro Petroleum Corporation for nineteen years (1973 until 1992) where he held numerous positions, including Group Vice President of Refining, Marketing and Supply from 1990 to 1992. During 1992, he was President of Remote Operating Systems, Inc. before joining Ultramar Diamond Shamrock.
Mr. J. Currie Bechtol (61) has been Vice President-General Counsel of the Company since January 1998 and became Secretary of the Company in August 2000. Prior to joining the Company, Mr. Bechtol was in private legal practice for 28 years, most recently with Hutcheson & Grundy L.L.P. from 1984 until joining the Company.
Mr. Jon D. Galvin (49) is Vice President of the Company. He was appointed to this position in July 2000 and served as Vice President-Controller of the Company from September 1997 until July 2000. Mr. Galvin was the Chief Financial Officer of the Company's Frontier refining subsidiaries from February 1992 until July 2000, when he was promoted to Vice President-Crude Oil Supply of certain of the Company’s refining subsidiaries. Previously, he had spent 15 years with Arthur Andersen, ultimately as Audit Principal.
Mr. Gerald B. Faudel (53) has been Vice President-Corporate Relations and Environmental Affairs of the Company since February 2000. Mr. Faudel had previously been Vice President-Safety and Environmental Affairs and had served in similar capacities since November 1993. From October 1991 through November 1993, Mr. Faudel was Director of Safety, Environmental and External Affairs of the refining subsidiaries of the Company. Mr. Faudel was employed by Frontier Oil Corporation from October 1989 through October 1991 as Director of Safety, Environmental and External Affairs. Prior to October 1989, Mr. Faudel was employed with Tosco Corporation's Avon Refinery as Manager of Hazardous Waste and Wastewater Program.
Ms. Nancy J. Zupan (48) is Vice President-Controller of the Company. Prior to her appointment to this position in February 2001, Ms. Zupan was Controller for the Company's subsidiaries from 1991, when Frontier acquired the Cheyenne Refinery. She held the same position for the prior owners of the Cheyenne Refinery from 1987 until the acquisition. Prior to 1986, Ms. Zupan was employed by Husky Oil Company, the predecessor owner of the Cheyenne Refinery.
Section 16 Filings Disclosure
Section 16(a) of the 1934 Act requires the Company’s directors and executive officers, and persons who own more than ten percent of a registered class of the Company's equity securities, to file with the Commission and the New York Stock Exchange initial reports of ownership and reports of changes in ownership of Common Stock of the Company. Officers, directors and greater than ten-percent shareholders are required by Commission regulations to furnish the Company with copies of all Section 16(a) forms they file.
To the Company’s knowledge, based solely on review of the Company's copies of such reports furnished to the Company and written representations that no other reports were required, during the fiscal year ended December 31, 2002, all Section 16(a) filing requirements applicable to its officers, directors and greater than ten-percent beneficial owners were complied with.
ITEM 11. EXECUTIVE COMPENSATION
Information appearing under the caption “Executive Compensation and Other Information” in the 2003 Proxy Statement is hereby incorporated by reference except for the information under the caption “– Stock Options” which is set forth below.
Stock Options
The Company currently maintains three stock option plans pursuant to which options to purchase shares of Common Stock are outstanding. One plan currently has shares of Common Stock available for future grants to eligible employees, the Frontier Oil Corporation 1999 Stock Plan, in which directors and other non-employee agents of the Company are eligible to participate. The purpose of the stock option plans is to advance the best interest of the Company by providing those persons who have substantial responsibility for the management and growth of the Company with additional incentive by increasing their proprietary interest in the success of the Company. As of March 3, 2003, there were 141,650 of shares of Common Stock available for grant under the Company’s existing stock option plans.
OPTION GRANTS IN 2002
Individual Grants
---------------------------------------------------------
Number of Percent of Potential Realizable
Securities Total Value at Assumed
Underlying Options Annual Rates of Stock
Options Granted to Exercise Price Appreciation for
Granted Employees Price Expiration Option Term (1)
Name (#) in 2002 ($/sh) Date 5% 10%
------------- --------------- ------------- ------------- ---------------- --------------
James R. Gibbs 270,000 38.4 21.85 4/16/07 1,629,923 3,601,704
Julie H. Edwards 95,000 13.5 21.85 4/16/07 573,491 1,267,266
W. Reed Williams 95,000 13.5 21.85 4/16/07 573,491 1,267,266
J. Currie Bechtol 10,400 1.5 21.85 4/16/07 62,782 138,732
Jon D. Galvin 19,000 2.7 21.85 4/16/07 114,698 253,453
| (1) | The Commission requires disclosure of the potential realized value or present value of each grant. The disclosure assumes the options will be held for the full term of the option prior to exercise. Such options may be exercised prior to the end of such term. The actual value, if any, an executive officer may realize will depend on the excess of the stock price over the exercise price or the date the option is exercised. There can be no assurance that the stock price will appreciate at the rates shown in the table. |
AGGREGATE OPTION EXERCISES IN 2002
AND OPTION VALUES AT DECEMBER 31, 2002
Number of Securities Value of Unexercised
Shares Underlying Unexercised In-the-Money Options at
Acquired on Value Options at Dec. 31, 2002 Dec. 31, 2002
Name Exercise (#) Realized ($) Exercisable/Unexercisable Exercisable/Unexercisable (1)
--------------- -------------- ----------------------------- --------------------------------
James R. Gibbs 0 0 647,500/352,500 $6,163,850/$1,453,000
Julie H. Edwards 0 0 220,500/122,500 2,131,785/523,775
W. Reed Williams 0 0 132,500/122,500 946,050/444,650
J. Currie Bechtol 12,000 169,260 78,600/29,800 801,970/208,840
Jon D. Galvin 25,200 408,400 97,750/37,250 994,960/219,060
| (1) | Computed based on the difference between aggregate fair market value and aggregate exercise price. The fair market value of the Company’s Common Stock on December 31, 2002 was $17.22 based on the closing sale price on December 31, 2002. |
Information setting forth the security ownership of certain beneficial owners and management appearing under the captions “Principal Shareholders” and “Common Stock Owned by Directors and Executive Officers” in the 2003 Proxy Statement is hereby incorporated by reference. Information regarding the Company's securities authorized for issuance under equity compensation plans is included in Part II, Item 5.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Burnet, Duckworth & Palmer, a law firm of which Mr. Palmer, a director emeritus of the Company, is a partner, is retained by the Company as its counsel for certain Canadian legal matters. The Company has paid Mr. Palmer’s law firm $47,751 since January 2001 through May 31, 2003, substantially all of which has been paid in 2003.
In 2002, Mr. Dossey consulted on behalf of the Adizes Institute LLC, a management consulting organization. In July 2001, the Company entered into an agreement for a one year corporate membership with the Adizes Institute for a fee of $150,000 plus certain expenses. In 2001, the Company paid $87,900 to the Adizes Institute for 50% of the annual fee and reimbursement of the expenses related to their services. Their services were completed in 2002 and the company paid $75,580 for the remainder of the membership fee and reimbursement of expenses.
ITEM 14. CONTROLS AND PROCEDURES
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. Within the 90 days prior to the date of this report, we carried out an evaluation, under the supervision and with the participation of our management, including our Chairman of the Board, President and Chief Executive Officer and Executive Vice President - Finance & Administration, Chief Financial Officer, of the effectiveness of our disclosure controls and procedures pursuant to Rule 13a-14 of the Exchange Act. Based on that evaluation, our Chairman of the Board, President and Chief Executive Officer and Executive Vice President - Finance & Administration, Chief Financial Officer, concluded that our disclosure controls and procedures are effective.
There have been no significant changes in our internal controls or other factors that could significantly affect those controls subsequent to the date of their evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
| (a)2. | Financial Statements Schedules |
| Report of Independent Public Accountants | |
| Schedule I - Condensed Financial Information of Registrant | |
| Schedule II - Valuation and Qualifying Accounts | |
| 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. |
| (a)3. | List of Exhibits | ||
| * | 3.1 - | Articles of Amendment to the Restated Articles of Incorporation of the Company (Exhibit 3.2 to Registration Statement No. 333-47745, filed May 4, 1998). | |
| * | 3.2 - | Fourth Restated By-Laws of the Company as amended through February 20, 1992 (Exhibit 3.2 to Form 10-K dated December 31, 1992, file no. 1-07627,filed March 10, 1993). | |
| * | 4.1 - | Indenture dated as of February 9, 1998 between the Company and Chase Bank of Texas, National Association, as Trustee relating to the Company’s 9-1/8% Senior Notes due 2006 (filed as Exhibit 4.8 to Registration Statement No. 333-47745, filed March 11, 1998). | |
| * | 4.2 - | Indenture dated as of November 12, 1999, among the Company and Chase Bank of Texas, National Association, as Trustee relating to the Company’s 11¾% Senior Notes due 2009 (Exhibit 4.1 to Form 8-K, file no. 1-07627, filed December 1, 1999). | |
| * | 10.1 - | Asset Purchase and Sale Agreement among Frontier El Dorado Refining Company, as buyer, Frontier Oil Corporation, as Guarantor and Equilon Enterprises LLC, as seller, dated as of October 19, 1999 (Exhibit 10.1 to Form 8-K, file no. 1-07627,filed dated December 1, 1999). | |
| * | 10.2 - | Revolving Credit Agreement dated as of November 16, 1999 among Frontier Oil and Refining Company, as borrower, the lenders named therein, Union Bank of California, N.A., as administrative agent, documentation agent and lead arranger, and Paribas, as syndication agent and lead arranger (Exhibit 10.2 to Form 8-K, file no. 1-07627, filed December 1, 1999). | |
| * | 10.3 - | Purchase and Sale Agreement, dated May 5, 1997, for the sale of Canadian oil and gas properties (Exhibit to From 8-K ,file no. 1-07627,filed June 30, 1997). | |
| *+ | 10.5 - | The 1968 Incentive Stock Option Plan as amended and restated (Exhibit 10.1 to Form 10-K dated December 31, 1987, file no. 1-07627, filed March 3, 1998). | |
| *+ | 10.6 - | 1995 Stock Grant Plan for Non-employee Directors (Exhibit 10.14 to Form 10-Q dated June 30, 1995, file no. 1-07627,filed August 3, 1995). | |
| *+ | 10.7 - | Frontier Deferred Compensation Plan (previously named Wainoco Deferred Compensation Plan dated October 29, 1993 and filed as Exhibit 10.19 to Form 10-K dated December 31, 1994, file no. 1-07627, filed March 17, 1995). | |
| *+ | 10.8 - | 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 dated December 31, 1994, file no. 1-07627, filed March 17, 1995). | |
| *+ | 10.9 - | Executive Employment Agreement dated December 18, 2000 between the Company and W. Reed Williams (Exhibit 10.10 to Form 10-K dated December 31,2001, file no. 1-07627, filed March 1, 2002). | |
| *+ | 10.10 - | Executive Employment Agreement dated December 18, 2000 between the Company and James R. Gibbs (Exhibit 10.11 to Form 10-K dated December 31,2001, file no. 1-07627, filed March 1, 2002). | |
| *+ | 10.11 - | Executive Employment Agreement dated December 18, 2000 between the Company and Julie H. Edwards (Exhibit 10.12 to Form 10-K dated December 31,2001, file no. 1-07627, filed March 1, 2002). | |
| *+ | 10.12 - | Executive Employment Agreement dated December 18, 2000 between the Company and J. Currie Bechtol (Exhibit 10.13 to Form 10-K dated December 31,2001, file no. 1-07627, filed March 1, 2002). | |
| *+ | 10.13 - | Executive Employment Agreement dated December 18, 2000 between the Company and Jon D. Galvin (Exhibit 10.14 to Form 10-K dated December 31,2001, file no. 1-07627, filed March 1, 2002). | |
| *+ | 10.14 - | Executive Employment Agreement dated December 18, 2000 between the Company and Gerald B. Faudel (Exhibit 10.15 to Form 10-K dated December 31,2001, file no. 1-07627, filed March 1, 2002). | |
| *+ | 10.15 - | Executive Employment Agreement dated February 28, 2001 between the Company and Nancy J. Zupan (Exhibit 10.16 to Form 10-K dated December 31,2001, file no. 1-07627, filed March 1, 2002). | |
| * | 10.16 - | First Amendment to Revolving Credit Agreement and Guaranty dated September 20, 2000 among Frontier Oil and Refining Company, the lenders named therein, Union Bank of California, N.A., as administrative agent, documentation agent and lead arranger, and BNP Paribas, as syndication agent and lead arranger. (filed as Exhibit 10.02 to Form 10-Q dated September 30, 2000, file no. 1-07627, filed November 1, 2000). | |
| *+ | 10.17 - | Frontier Oil Corporation Restricted Stock Plan (Exhibit 99.1 to Registration Statement No 333-56946, filed March 13, 2001). | |
| * | 10.18 - | Second amendment to Revolving Credit Agreement and Guaranty and First Amendment to Clawback Agreement dated June 20, 2001 among Frontier Oil and Refining Company, as borrower, each of Frontier Holdings Inc., Frontier Refining & Marketing Inc., Frontier Refining Inc., Frontier El Dorado Refining Company and Frontier Pipeline Inc., as guarantors, the lenders named therein and Union Bank of California, N.A., as administrative agent for the lenders (Exhibit 10 to Form 10-Q dated June 30, 2001, file no. 1-07627, filed August 7, 2001). | |
| *+ | 10.19 - | Amended and Restated Frontier Oil Corporation 1999 Stock Plan (Exhibit 99.1 to Registration Statement No 333-89876 filedJune 6, 2002). | |
| * | 10.20 - | Sixth Amendment to the Guaranty of the Revolving Credit Agreement dated September 23, 2002 among Frontier Oil and Refining Company, the lenders named therein, Union Bank of California, N.A., as administrative agent and lead arranger, and BNP Paribas, as syndication agent and lead arranger. (Exhibit 10.1 to Form 10-Q dated September 30, 2002,file no. 1-07627, filed October 30, 2002). | |
| * | 10.21 - | Crude Oil Supply Agreement dated October 15, 2002 between Baytex Energy Ltd, and Frontier Oil and Refining Company. On November 28, 2002 this agreement was assigned by Baytex Energy Ltd. to its wholly-owned subsidiary, Baytex Marketing Ltd. (Exhibit 10.2 to Form 10-Q dated September 30, 2002, file no. 1-07627, filed October 30, 2002). | |
| 21.1 - | Subsidiaries of the Registrant. | ||
| 23 - | Consent of Deloitte & Touche LLP. | ||
| 31.1 - | Certification by Chief Executive Officer pursuant Rule 13a-14(a) and 15d-14(a) under the Exchange Act. | ||
| 31.2 - | Certification by Chief Financial Officer pursuant to Rule 13a-14(a) and 15d-14(a) under the Exchange Act. | ||
| 32.1 - | Certification by Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. | ||
| 32.2 - | Certification by Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. | ||
* Asterisk indicates exhibits incorporated by reference as shown.
+ Plus indicates management contract or compensatory plan or arrangement.
| (b) | Reports on Form 8-K None. |
| (c) | Exhibits The Company’s 2002 Annual Report is available upon request. Shareholders of the Company may obtain a copy of any other exhibits to this Form 10-K at a charge of $.05 per page. Requests should be directed to: Investor Relations Frontier Oil Corporation 10000 Memorial Drive, Suite 600 Houston, Texas 77024-3411 |
| (d) | Schedules Report of Independent Public Accountants on Financial Statement Schedules: |
To the Board of Directors and Shareholders of
Frontier Oil Corporation
Houston, Texas
We have audited the consolidated financial statements of Frontier Oil Corporation as of December 31, 2002 and for the year then ended, and have issued our report thereon dated February 7, 2003; such consolidated financial statements and report are included in your 2002 Annual Report to Shareholders and are incorporated herein by reference. Our audits also included the financial statement schedules of Frontier Oil Corporation for the year ended December 31, 2002, listed in Item 15. These financial statement schedules are the responsibility of the Corporation’s management. Our responsibility is to express an opinion based on our audits. The consolidated financial statements and financial statement schedules of Frontier Oil Corporation as of December 31, 2001 and for the years ended December 31, 2001 and 2000 were audited by other auditors who have ceased operations. Those auditors expressed an unqualified opinion on those consolidated financial statements and financial statement schedules in their report dated February 8, 2002. In our opinion, the 2002 financial statement schedules, when considered in relation to the basic 2002 consolidated financial statements taken as a whole, present fairly in all material respects the information set forth therein.
DELOITTE & TOUCHE LLP
Houston, Texas
February 7, 2003
Frontier Oil Corporation dismissed Arthur Andersen LLP on March 28, 2002 and subsequently engaged Deloitte & Touche LLP as its independent auditors. The predecessor auditors’ report appearing below is a copy of Arthur Andersen LLP’s previously issued opinion dated February 8, 2002. Since Frontier Oil Corporation is unable to obtain a manually signed audit report, a copy of Arthur Andersen LLP’s most recent signed and dated report has been included to satisfy filing requirements, as permitted under Rule 2-02(e) of Regulation S-X.
To Frontier Oil Corporation:
We have audited in accordance with auditing standards generally accepted in the United States, the financial statements included in Frontier Oil Corporation’s annual report to shareholders incorporated by reference in this Form 10-K, and have issued our report thereon dated February 8, 2002. Our audits were made for the purpose of forming an opinion on those statements taken as a whole. The schedules listed in the index above are the responsibility of the Company’s management and are presented for purposes of complying with the Securities and Exchange Commission’s rules and are not part of the basic financial statements. These schedules have been subjected to the auditing procedures applied in the audit of the basic financial statements and, in our opinion, fairly states in all material respects the financial data required to be set forth therein in relation to the basic financial statements taken as a whole.
ARTHUR ANDERSEN LLP
Houston, Texas
February 8, 2002
Frontier Oil Corporation
Condensed Financial Information of Registrant
Balance Sheets
As of December 31, Schedule I
- ------------------------------------------------------------------------------------------------------
(in thousands)
2002 2001
----------- ----------
ASSETS
Current Assets:
Cash and cash equivalents $ 106,118 $ 103,460
Receivables 86 4,714
Deferred tax current asset 5,346 4,845
Other current assets 231 197
----------- ----------
Total current assets 111,781 113,216
----------- ----------
Property, Plant and Equipment, at cost -
Furniture, fixtures and other 1,064 1,990
Less - Accumulated depreciation (753) (847)
------------ ----------
311 1,143
Assets Held for Sale 472 -
Investment in Subsidiaries 279,055 310,555
Other Assets 8,972 9,556
----------- ----------
$ 400,591 $ 434,470
=========== ==========
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities:
Accounts payable $ 41 $ 504
Other accrued liabilities 5,503 6,954
----------- ----------
Total current liabilities 5,544 7,458
----------- ----------
Deferred Income Taxes 15,176 15,080
Deferred Revenues and Other 3,032 2,780
Payable to Affiliated Companies 615 31,068
Long-Term Debt 207,966 208,880
Shareholders' Equity 168,258 169,204
----------- ----------
$ 400,591 $ 434,470
=========== ==========
The “Notes to Condensed Financial Information of Registrant” and the “Notes to Financial Statements of Frontier Oil Corporation and Subsidiaries” are an integral part of these financial statements.
Frontier Oil Corporation
Condensed Financial Information of Registrant
Statements of Operations
For the three years ended December 31, Schedule I
- ------------------------------------------------------------------------------------------------------
(in thousands)
2002 2001 2000
---------- ---------- -----------
Revenues:
Equity in earnings of subsidiaries $ 31,704 $ 166,828 $ 70,627
Other income (1) 24 (9)
----------- ---------- ----------
31,703 166,852 70,618
----------- ---------- ----------
Costs and Expenses:
Selling and general expenses 5,845 5,900 4,140
Impairment loss on asset held for sale 363 - -
Depreciation 247 227 212
---------- ---------- ----------
6,455 6,127 4,352
----------- ---------- ----------
Operating Income 25,248 160,725 66,266
Interest Expense and Other Financing Costs 24,858 27,543 29,318
Interest Income (1,698) (2,517) (3,030)
---------- ---------- ----------
Income before Income Taxes 2,088 135,699 39,978
Provision for Income Taxes 1,060 28,046 2,772
---------- ---------- ----------
Net Income $ 1,028 $ 107,653 $ 37,206
========== ========== ==========
The “Notes to Condensed Financial Information of Registrant” and the “Notes to Financial Statements of Frontier Oil Corporation and Subsidiaries” are an integral part of these financial statements.
Frontier Oil Corporation
Condensed Financial Information of Registrant
Statements of Cash Flows
For the three years ended December 31, Schedule I
- ---------------------------------------------------------------------------------------------------------
(in thousands)
2002 2001 2000
----------- ----------- ----------
Operating Activities
Net income $ 1,028 $ 107,653 $ 37,206
Equity in earnings of subsidiaries (31,704) (166,828) (70,627)
Depreciation 247 227 212
Deferred income taxes 1,149 9,463 830
Other 5,430 (1,598) 750
----------- ----------- ----------
Net cash used by operating activities (23,850) (51,083) (31,629)
----------- ----------- ----------
Investing Activities
Additions to property, plant and equipment and other (350) (46) (208)
Investment in subsidiaries (181,867) (12,000) (309)
----------- ----------- ----------
Net cash used by investing activities (182,217) (12,046) (517)
----------- ----------- ----------
Financing Activities
Repurchases of debt:
9-1/8% Senior Notes (1,090) (24,410) (5,025)
11-3/4% Senior Notes - (6,541) (13,010)
Proceeds from issuance of common stock 1,702 3,271 2,743
Purchase of treasury stock (787) (22,600) (9,215)
Change in intercompany balances, net (30,453) 953 (5,407)
Dividends paid to shareholders (5,161) (2,629) -
Dividends received from subsidiaries 244,514 174,800 68,048
Other - 13 11
----------- ----------- ----------
Net cash provided by financing activities 208,725 122,857 38,145
----------- ----------- ----------
Increase in cash and cash equivalents 2,658 59,728 5,999
Cash and cash equivalents, beginning of period 103,460 43,732 37,733
----------- ----------- ----------
Cash and cash equivalents, end of period $ 106,118 $ 103,460 $ 43,732
=========== =========== ==========
The “Notes to Condensed Financial Information of Registrant” and the “Notes to Financial Statements of Frontier Oil Corporation and Subsidiaries” are an integral part of these financial statements.
Schedule I
(1) General
The accompanying condensed financial statements of Frontier Oil Corporation (Registrant) should be read in conjunction with the consolidated financial statements of the Registrant and its subsidiaries included in the Registrant’s 2002 Annual Report to Shareholders.
(2) Long-term debt
The components (in thousands) of long-term debt are as follows:
2002 2001
----------- ----------
11-3/4% Senior Notes, net of unamortized discount $ 168,491 $ 168,315
9-1/8% Senior Notes 39,475 40,565
----------- ----------
$ 207,966 $ 208,880
=========== ==========
(3) Five-year maturities of long-term debt
The 9-1/8% Senior Notes are due 2006 and the 11-3/4% Senior Notes are due 2009; until then there are no maturities of long-term debt.
Frontier Oil Corporation and Subsidiaries
Valuation and Qualifying Accounts
For the three years ended December 31, Schedule II
- ----------------------------------------------------------------------------------------------------------
(in thousands)
Balance at
beginning of Balance at end
Description period Additions Deductions of period
- ----------------------------------------------------------------------------------------------------------
2002
Allowance for doubtful accounts $ 500 $ 800 $ - $ 1,300
Turnaround accruals (1) 25,837 10,969 9,944 26,862
Valuation allowance on deferred tax assets - - - -
2001
Allowance for doubtful accounts 500 - - 500
Turnaround accruals (1) 31,056 10,637 15,856 25,837
Valuation allowance on deferred tax assets 24,603 - 24,603 -
2000
Allowance for doubtful accounts (2) 500 533 533 500
Turnaround accruals (1) 29,448 13,944 12,336 31,056
Valuation allowance on deferred tax assets 38,748 - 14,145 24,603
(1) The turnaround accrual deductions are actual costs incurred.
(2) The deductions in the 2000 allowance for doubtful accounts were uncollectible trade receivables written off against the allowance.
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/ James R. Gibbs —————————————————— James R. Gibbs Chairman of the Board, President and Chief Executive Officer (chief executive officer) |
Date: October 31, 2003
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 —————————————————— James R. Gibbs Chairman of the Board, President and Chief Executive Officer and Director (chief executive officer) | /s/ T. Michael Dossey —————————————————— T. Michael Dossey Director |
/s/ Julie H. Edwards —————————————————— Julie H. Edwards Executive Vice President - Finance and Administration Chief Financial Officer (principal financial officer) | /s/ James H. Lee —————————————————— James H. Lee Director |
/s/ Nancy J. Zupan —————————————————— Nancy J. Zupan Vice President - Controller (principal accounting officer) | /s/ Paul B. Loyd, Jr. —————————————————— Paul B. Loyd, Jr. Director |
/s/ Douglas Y. Bech —————————————————— Douglas Y. Bech Director | /s/ Carl W. Schafer —————————————————— Carl W. Schafer Director |
/s/ G. Clyde Buck —————————————————— G. Clyde Buck Director |
Date: October 31, 2003