FRONTIER OIL CORP /NEW/ - 10-K Annual Report

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-K

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
þ	OF THE SECURITIES EXCHANGE ACT OF 1934
For the Fiscal Year Ended: December 31, 2004
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
o	OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from . . . . to . . . .

Commission File Number: 1-7627

FRONTIER OIL CORPORATION
(Exact name of registrant as specified in its charter)

Wyoming		74-1895085
(State or other jurisdiction of		(I.R.S. Employer
incorporation or organization)		Identification No.)

10000 Memorial Drive, Suite 600		77024-3411
Houston, Texas		(Zip Code)
(Address of principal executive offices)

Registrant’s telephone number, including area code: (713) 688-9600

Securities registered pursuant to Section 12(b) of the Act:

		Name of Each Exchange
Title of Each Class		on Which Registered

Common Stock		New York Stock Exchange
6⅝% Senior Notes due 2011

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 ü No . . .

Indicate by check mark if disclosure of delinquent filers pursuant to rule 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ü

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act).
Yes ü 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 as of June 30, 2004 was $556.0 million.

The number of shares of common stock outstanding as of February 18, 2005 was 27,150,710.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Annual Proxy Statement for the registrant’s 2005 annual meeting of shareholders are incorporated by reference into Items 10 through 14 of Part III.

TABLE OF CONTENTS

Part I
	Item 1.	Business
		Summary and Overview
		Refining Operations
		Marketing and Distribution
		Competition
		Crude Oil Supply
		Safety
		Government Regulation
		Employees
		Risk Factors Relating to Our Business
		Available Information
	Item 2.	Properties
	Item 3.	Legal Proceedings
	Item 4.	Submission of Matters to a Vote of Security Holders

Part II
	Item 5.	Market for Registrant’s Common Equity and Related Stockholder Matters
	Item 6.	Selected Financial Data
	Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations
	Item 7A.	Quantitative and Qualitative Disclosures About Market Risk
	Item 8.	Financial Statements and Supplementary Data
	Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
	Item 9A.	Controls and Procedures

Part III

Part IV
	Item 15.	Exhibits and Financial Statement Schedules

Forward-Looking Statements

This Form 10-K contains “forward-looking statements” as defined by the Securities and Exchange Commission. Such statements are those concerning contemplated transactions and strategic plans, expectations and objectives for future operations. These include, without limitation:

·	statements, other than statements of historical facts, that address activities, events or developments that we expect, believe or anticipate will or may occur in the future;
·	statements relating to future financial performance, future capital sources and other matters; and
·	any other statements preceded by, followed by or that include the words “anticipates,” “believes,” “expects,” “plans,” “intends,” “estimates,” “projects,” “could,” “should,” “may,” or similar expressions.

Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this Form 10-K are reasonable, we can give no assurance that such plans, intentions or expectations will be achieved. These statements are based on assumptions made by us based on our experience and perception of historical trends, current conditions, expected future developments and other factors that we believe are appropriate in the circumstances. Such statements are subject to a number of risks and uncertainties, many of which are beyond our control. You are cautioned that any such statements are not guarantees of future performance and that actual results or developments may differ materially from those projected in the forward-looking statements.

We undertake no obligation to update or revise publicly any revisions to any such forward-looking statements that may be made to reflect events or circumstances after the date of this Form 10-K, or to reflect the occurrence of unanticipated events.

PART I

Item 1. Business

Summary

The terms “Frontier,” “we,” “us” and “our” as used in this Form 10-K refer to Frontier Oil Corporation and its subsidiaries, except where it is clear that those terms mean only the parent company. When we use the term “Rocky Mountain region,” we refer to the states of Colorado, Wyoming, Montana and Utah, and when we use the term “Plains States,” we refer to the states of Kansas, Oklahoma, Nebraska, Iowa, Missouri, North Dakota and South Dakota.

Overview

We are an independent energy company engaged in crude oil refining and the wholesale marketing of refined petroleum products. We operate refineries (the “Refineries”) in Cheyenne, Wyoming and El Dorado, Kansas with a total annual average crude oil capacity of 156,000 barrels per day (“bpd”). Both of our Refineries are complex refineries, which means that they can process heavier, less expensive types of crude oil and still produce a high percentage of gasoline, diesel fuel and other high 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 bpd on a twelve-month average. We market its refined products primarily in the eastern slope of the Rocky Mountain region, which encompasses eastern Colorado (including the Denver metropolitan area), eastern Wyoming and western Nebraska (the “Eastern Slope”). The Cheyenne Refinery has a coking unit, which allows the refinery to process up to 100% heavy crude oil for use as a feedstock. The 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, 2004, heavy crude oil constituted approximately 85% of the Cheyenne Refinery’s total crude oil charge. For the year ended December 31, 2004, the Cheyenne Refinery’s yielded product mix included gasoline (42%), diesel fuel (30%) and asphalt and other refined petroleum products (28%).

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 bpd. The El Dorado Refinery can select from many different types of crude oil because of its direct access to Cushing, Oklahoma, which is connected by pipeline to the Gulf Coast. This access, combined with the El Dorado Refinery’s complexity (including a coking unit), gives it the flexibility to refine a wide variety of crude oils. In connection with our acquisition of the El Dorado Refinery in 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. Shell will also continue to purchase all jet fuel production until the end of the product offtake agreement. The offtake agreement allowed us to maximize the operating efficiency of the El Dorado Refinery during the initial years. 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 in Denver and throughout the Plains States. For the year ended December 31, 2004, the El Dorado Refinery’s yielded product mix included gasoline (56%), diesel and jet fuel (34%) and chemicals and other refined petroleum products (10%).

Other Assets. We also own FGI, LLC, a 120,000 barrel asphalt terminal and storage facility in Grand Island Nebraska, a 34.72% interest in a crude oil pipeline in Wyoming and a 50% interest in two crude oil tanks in Guernsey, Wyoming.

Refining Operations

Varieties of Crude Oil. Traditionally, crude oil has been classified within the following types:

·	sweet (low sulfur content),

·	sour (high sulfur content),

·	light (high gravity),

·	heavy (low gravity) and

·	intermediate (if gravity or sulfur content is in between).

For the most part, heavy crude oil tends to be sour and light crude oil tends to be sweet. When refined, light crude oil produces a higher 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 or differential. 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 yields 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.

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 coordinate operations by staggering turnarounds at the two refineries. Maintenance turnarounds are implemented using our regular personnel as well as additional contract labor. Turnaround work typically proceeds on a continuous 24-hour basis to minimize unit downtime. We accrue for our turnaround costs over the period from the prior turnaround to the next scheduled turnaround. We normally schedule our maintenance turnaround work during the spring or fall of each year. When we perform a turnaround we may increase product inventories prior to the turnaround to minimize the impact of the turnaround on our sales of refined products. We have major turnaround work scheduled on the fluid catalytic cracking unit (“FCCU”) and related units at our El Dorado Refinery during March 2005. Major turnaround work was performed on our alkylation unit at our El Dorado Refinery in March 2004. Turnaround work was performed on our sulfur and hydrotreating units at our Cheyenne Refinery in February 2004.

Marketing And Distribution

Cheyenne Refinery. The primary market for the Cheyenne Refinery’s refined products is the Eastern Slope. For the year ended December 31, 2004, we sold approximately 87% of the Cheyenne Refinery’s gasoline sales volumes in Colorado and 8% in Wyoming. For the year ended December 31, 2004, we sold approximately 33% of the Cheyenne Refinery’s diesel sales volumes in Colorado and 56% 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 ConocoPhillips pipeline, serving Sidney, Nebraska.

We sell refined products from our Cheyenne Refinery to a broad base of independent retailers, jobbers and major oil companies. Refined product prices are determined by local market conditions at distribution centers known as “terminal racks.” The customer at a terminal rack typically supplies its own truck transportation. Prices at the terminal rack are posted daily by sellers. In the year ended December 31, 2004, approximately 81% of the Cheyenne Refinery’s sales were made to its 25 largest customers. Occasionally, marketing volumes exceed the Refinery’s production, in which case we purchase product in the spot market as needed.

El Dorado Refinery. The primary markets for the El Dorado Refinery’s refined products are Colorado and the Plains States, which include the Kansas City metropolitan area. The gasoline, diesel and jet fuel produced by the El Dorado Refinery are primarily shipped via pipeline to terminals for distribution by truck or rail. The Kaneb pipeline, serving the northern Plains States, the Magellan pipeline serving Denver, Colorado, the Magellan pipeline serving Kansas City and Carthage, Missouri and Des Moines, Iowa, and until December 2004 the KCPL pipeline, serving Kansas City, handle pipeline shipments from our El Dorado Refinery.

In connection with our late 1999 acquisition of this Refinery we entered into a 15-year refined product offtake agreement with Shell. For the year ended December 31, 2004, Shell was the El Dorado Refinery’s largest customer, representing 71% of total sales. Under the agreement, Shell purchases gasoline, diesel and jet fuel produced by the El Dorado Refinery at market-based prices. Initially in 1999, Shell purchased all of the El Dorado Refinery’s production of these products. Beginning in 2000, we retained and marketed 5,000 bpd of the Refinery’s gasoline and diesel production. The retained portion is scheduled to increase by 5,000 bpd each year for ten years. In 2004, we retained 25,000 bpd of the Refinery’s gasoline and diesel production. Shell will continue to purchase all jet fuel production for the remainder of the original 15-year product offtake agreement term. The agreement allows us to focus on maximizing the operating efficiency of our El Dorado Refinery during these years. 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 bpd refinery near Rawlins, Wyoming and a 22,000 bpd refinery in Casper, Wyoming, both owned by Sinclair Oil Company (“Sinclair”); a 28,000 bpd refinery in Denver owned by Valero Energy Corporation (“Valero”); and a 58,000 bpd refinery in Denver owned by Suncor Energy (U.S.A.) (“Suncor”). Five product pipelines also supply Denver, including three from outside the region that enable refined products from other regions to be sold in the Denver market. Refined products shipped from other regions bear the burden of higher transportation costs.

The Valero and Suncor refineries located in Denver have lower product transportation costs in serving 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 Suncor, we only sell our products to the wholesale market. We believe that our commitment to the wholesale market gives us a customer relation’s 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 because of their size (economies of scale) than the El Dorado Refinery, we believe that our competitors’ 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 regions are also supplied by three product pipelines that originate from the Gulf Coast.

Crude Oil Supply

Cheyenne Refinery. In the year ended December 31, 2004, we obtained approximately 32% of the Cheyenne Refinery’s crude oil charge from Wyoming, 57% from Canada and 11% from Colorado. During the same period, heavy crude oil constituted approximately 85% of the Cheyenne Refinery’s total crude oil charge. Cheyenne is 88 miles south of Guernsey, Wyoming, the main hub and crude oil trading center for the Rocky Mountain region. We transport up to 25,000 bpd 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 pipeline system 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.

We purchase crude oil for the Cheyenne Refinery from several 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 bpd of a Lloydminster crude oil blend, a heavy Canadian crude. Initially, we received 9,000 bpd, which increased to 20,000 bpd by October 2003. This type of crude oil typically sells at a discount to lighter crude oils. Our price for 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 Express 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 a portion of our dedicated capacity through the Express pipeline.

El Dorado Refinery. In the year ended December 31, 2004, we obtained approximately 57% of the El Dorado Refinery’s crude oil charge from Texas, 17% from the Middle East, 15% from Kansas, 10% from Louisiana, and the remaining from the North Sea. El Dorado is 125 miles north of Cushing, Oklahoma, a major crude oil hub. The Cushing hub is supplied by the Seaway pipeline, which runs from the Gulf Coast; the Basin pipeline, which runs through Wichita Falls 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 85% of our crude oil charge during the year ended December 31, 2004. The remainder of our crude oil charge was transported to the El Dorado Refinery through Kansas gathering system pipelines. During 2004, we entered into a Transportation Services Agreement (“Agreement”) to transport crude oil on the Spearhead Pipeline from Griffith, Indiana to Cushing, Oklahoma. The owner of the Spearhead Pipeline intends to alter an existing pipeline, including reversing the flow, with an anticipated date to be able to commence crude oil shipments on or around January 1, 2006. This pipeline will enable us to transport Canadian crude oil to our El Dorado Refinery. The initial term of this Agreement is for a period of ten years from the actual commencement date, although we have the right to extend the Agreement for an additional ten-year term.

Safety

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, as well as fines and penalties.

The Cheyenne Refinery reduced its OSHA recordable incident rate from 1.38 in 2003 to 1.03 for 2004. For comparison, the National Petrochemical and Refiner’s Association (“NPRA”) industry average is 1.46. For the continued improvement in safety, the personnel at Cheyenne will be awarded four safety awards by the NPRA, which are:

(1)	an award for Meritorious Safety Performance for achieving a total recordable incidence rate of 1.2 or lower,

(2)	the Gold Award for a reduction in recordable accidents and no workplace injury,

(3)	the Award for Safety Achievement in Hours for one million or more hours worked without a lost time accident, and

(4)	the Award for Safety Achievement in Years for one or more years worked without a lost time accident.

By the end of 2004, the Cheyenne employees had worked 825 days without a lost time accident. Our behavioral safety program initiated in 2000, our Safety Training Observation Program started in 2002, and our supervisor’s safety training program added in 2003 have maintained a very positive safety trend at the Cheyenne Refinery. The combination of our behavioral safety program with the management driven safety programs has made very positive changes in the safety culture of the entire workforce at the Cheyenne Refinery. We are determined not only to sustain our safety record, but also to further improve our safety record at the Cheyenne Refinery.

Because our contractor injury rate is higher than our employee injury rate at our Cheyenne Refinery, we increased our efforts on contractor safety in 2004. In addition to the local safety training provided to contractors, personnel at the Cheyenne Refinery assisted the Wyoming-Montana Safety Council in obtaining accreditation by the Association to Reciprocal Safety Councils that allows them to provide contractor safety training with nation-wide reciprocity. This has been a very successful program in the Gulf Coast region, and we have high expectations in our geographic region. By improving the training of the contractor workforce in general, we also improve the safety of the outside labor that we hire at our Cheyenne Refinery as well as other industrial facilities in our geographic region.

The El Dorado Refinery also improved its safety record last year from an OSHA recordable incident rate of 2.14 in 2003 to 1.94 for 2004, which is slightly above the NPRA industry average. Our employees and management continue to dedicate their efforts to a balanced safety program that combines individual behavioral elements in a safety-coaching environment with very structured management driven programs to improve the safety of the facility and operating procedures. Our objective is a safe working environment for employees who know how to work safely. Management believes that our implementation of the Active Safety Participation program introduced in 2004 will drive much improved performance in 2005. Encouraging all employees to contribute toward improving safety performance through their personal involvement in safety-related activities is an industry-proven way to reduce injuries. The El Dorado Refinery’s performance bonus program will be linked to the overall level of participation in the safety process and injury prevention. The El Dorado Refinery is also transitioning from a management driven to an employee driven behavioral based safety program that we anticipate will also reduce the number of injuries. To further emphasize the importance of safety in the overall success of the El Dorado Refinery in 2005, and to ensure all our employees have personal accountability in this endeavor, the individual portion of the El Dorado Refinery’s bonus program will be based upon each individual’s commitment to safety.

Government Regulation

Environmental Matters. Our operations and many of our manufactured products are specifically subject to certain requirements of the Clean Air Act (“CAA”) and related state and local regulations. The 1990 amendments to the CAA contain provisions that will require capital expenditures for the installation of certain air pollution control devices at the Refineries during the next several years. The Environmental Protection Agency (“EPA”) has embarked on a Petroleum Refining Initiative (“Initiative”) alleging industry-wide noncompliance with certain longstanding 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 the Initiative may affect us. We have, however, in recognition of the EPA’s reinterpretation of certain regulatory requirements associated with the Initiative, determined that we will incur expenditures totaling approximately $8.0 million to further reduce emissions from our Refineries’ flare systems. At our Cheyenne Refinery, we spent $223,000 in 2004, and estimate spending an additional $4.0 million, primarily in 2005, on the flare system. At our El Dorado Refinery, we spent $423,000 in 2004, and we estimate incurring a total additional $3.3 million during 2005 and 2006, on the flare system. Both the Kansas Department of Health and Environment (“KDHE”) and the Wyoming Department of Environmental Quality (“WDEQ”) have expressed their preference to enter into consent decrees with Frontier to settle these and certain other compliance matters. The provisions of a KDHE order have not yet been proposed; however, Region VII of the EPA has informed the State of Kansas and Frontier that requirements for reductions in emissions from the El Dorado Refinery’s FCCU must also be included in any settlement with the State of Kansas if we want protection from a subsequent EPA enforcement action under the Initiative. We are currently evaluating interim and final FCCU emission control options.

In a settlement entered on February 22, 2005, the WDEQ accepted a penalty payment in the amount of $120,000 in addition to our commitment to complete the aforementioned flare system controls and an agreed upon Capital Supplemental Environmental Project estimated to cost $535,000 to resolve one of the Initiative’s four concerns and other violations. The settlement addresses:

·	the reduction of flare system emissions,

·	an earlier notice of violation regarding excess emissions from our Cheyenne Refinery’s crude unit heaters,

·	resolution of a 1992 Odor Consent Decree, and

·	two recent odor violations associated with the startup of our Cheyenne Refinery’s new gasoline desulfurization equipment.

During the first quarter of 2004, we decreased the previously estimated penalty accrual of $317,000 recorded as of December 31, 2003 to $120,000. This $197,000 reduction is reflected as a reduction of “Refinery operating expenses, excluding depreciation” on the Consolidated Statement of Income for the year ended December 31, 2004.

The EPA has promulgated regulations requiring the phase-in of gasoline sulfur standards, which began January 1, 2004 and continues through 2008, with special provisions for small business refiners. Because we qualify as a small business refiner, we have elected to extend our small refinery interim gasoline sulfur standard at each of our Refineries until 2011 and to comply with the highway diesel sulfur standard by June 2006, as discussed below. Our Cheyenne Refinery has spent approximately $28.9 million (including capitalized interest) to complete the project to meet the interim gasoline sulfur standard, which was required by January 1, 2004. The remaining $7.0 million estimated cost to meet the additional standard for the Cheyenne Refinery is expected to be incurred in 2009 and 2010. The total capital expenditures estimated as of December 31, 2004 for the El Dorado Refinery to achieve the final gasoline sulfur standard are approximately $15 million, which are expected to be incurred between 2006 and 2009. Our approach to achieve the gasoline sulfur standard at the El Dorado Refinery has been revised from building a new unit to the modification of existing equipment, thus reducing the cost from the original estimate of $44.0 million.

The EPA has promulgated regulations that will limit the sulfur content of highway diesel fuel beginning in 2006. As indicated above, we have elected to comply with the highway diesel sulfur standard by June 2006. As of December 31, 2004, capital costs, including capitalized interest, for diesel desulfurization are estimated to be approximately $14.0 million for the Cheyenne Refinery and approximately $106.5 million for the El Dorado Refinery. Approximately $250,000 of the Cheyenne Refinery expenditures were incurred in 2004, $9.0 million is estimated to be incurred in 2005, with the remaining $4.7 million estimated to be incurred in the first half of 2006. Approximately $6.0 million of the El Dorado Refinery expenditures were incurred in 2004, with $90.5 estimated to be incurred in 2005, and the remaining $10.0 million estimated to be incurred in the first half of 2006. Certain provisions of The American Jobs Creation Act of 2004 should benefit us by allowing an accelerated depreciation deduction of 75% of these qualified capital costs in the years incurred and by providing a $0.05 per gallon credit on compliant diesel fuel up to an amount equal to the remaining 25% of these qualified capital costs for federal income tax purposes.

On June 29, 2004, the EPA promulgated regulations designed to reduce emissions from the combustion of diesel fuel in non-road applications such as mining, agriculture, locomotives and marine vessels. We currently participate in this market through the manufacture and sale of approximately 6,000 bpd of non-road diesel fuel from our El Dorado Refinery. The new regulations will, in part, require refiners to reduce the sulfur content of non-road diesel fuel from 5,000 parts per million (“ppm”) to 500 ppm in 2007 and further to 15 ppm in 2010 for all uses but locomotive and marine. Diesel fuel used in locomotives and marine operations will be required to meet the 15 ppm sulfur standard in 2012. Small refiners, such as Frontier, will be allowed to either postpone the new sulfur limits or, if the small refiner chooses to meet the new limit on the national schedule, to increase their gasoline sulfur limits by 20%. We intend to desulfurize all of our diesel fuel, including non-road, to the 15 ppm sulfur standard by 2006. The new regulation also clarifies that EPA-approved small business refiners will be allowed to exceed both the small refiner maximum capacity and/or employee criteria through merger with or acquisition of another approved small business refiner without loss of small refiner regulatory status.

The front range of Colorado (including the Denver metropolitan area) is a major market for the products manufactured by our Refineries. During 2004, the State of Colorado undertook an effort to develop and implement controls necessary to ensure that the area will regain compliance with the EPA’s National Ambient Air Quality Standards for ozone during the three-year averaging period of 2005 through 2007. On March 25, 2004, the EPA advised the refiners supplying the Denver region that their request for continuance of the long-standing Reid Vapor Pressure (“RVP”) waiver would not be granted for the 2004 ozone control period and that gasoline marketed in the area could not exceed the regulatory standard of 7.8 pounds RVP beginning May 1, 2004 at the marketing distribution terminals and June 1, 2004 at customer retail locations. During 2004, we incurred $2.0 million in capital costs at our Cheyenne Refinery to comply with this standard.

As is the case with all companies engaged in similar industries, we face potential exposure from future claims and lawsuits involving environmental matters including soil and water contamination, air pollution, personal injury and property damage allegedly caused by substances that we may have manufactured, handled, used, released or disposed.

Cheyenne Refinery. We are party to an agreement with the State of Wyoming requiring the investigation and possible eventual remediation of certain areas of our Cheyenne Refinery’s property that may have been impacted by past operational activities. Prior to this agreement, we addressed tasks required under a consent decree approved by the Wyoming State District Court on November 28, 1984 and involving the State of Wyoming, the 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, capital expenditures and remediation of conditions found to exist have already taken place, including the completion of surface impoundment closures, waste stabilization activities and other site remediation projects totaling approximately $4.0 million. In addition, we estimate that an ongoing groundwater remediation program averaging approximately $200,000 in annual operating and maintenance costs will be required for approximately ten more years. As of December 31, 2004, we have a reserve of $1.5 million in environmental liabilities reflecting the estimated present value of these expenditures ($2.0 million, discounted at a rate of 5.0%). The EPA also issued an administrative consent order with respect to our Cheyenne Refinery on September 24, 1990 pursuant to the Resource Conservation and Recovery Act. Among other things, this order required a technical investigation of the Cheyenne Refinery to determine if certain areas had been adversely impacted by past operational activities. Based upon the results of the ongoing investigation, additional remedial action could be required by a subsequent administrative order or permit.

In accordance with permits issued by the State of Wyoming under the federal National Pollutant Discharge Elimination System (“NPDES”), our Cheyenne Refinery is permitted to discharge its treated wastewater to either of two receiving waterways: a creek adjacent to the Cheyenne Refinery or a normally dry ravine called “Porter Draw.” Certain landowners downstream of the Cheyenne Refinery’s permitted discharge to Porter Draw expressed their unwillingness to continue to accommodate this wastewater flow by appealing our discharge permit and by giving notice of possible legal action. In response, as an alternative to continuing to discharge into the ravine, we arranged to deliver our treated wastewater beginning in July 2004 to the City of Cheyenne (“Cheyenne”) municipal treatment plant for additional treatment and release, and we have entered into settlements with the landowners. To initiate this wastewater treatment service, we have agreed to pay Cheyenne a $1.6 million development fee (reflected in “Other intangible asset” on our Consolidated Balance Sheet as of December 31, 2004). The $1.6 million fee will be paid in equal installments over five years, with the first payment having been made in July 2004. In addition, we pay Cheyenne $2.00 per 1,000 gallons of wastewater treated, which is included as “Refinery operating expenses, excluding depreciation” in our Consolidated Statements of Income.

El Dorado Refinery. Our El Dorado Refinery is subject to a 1988 consent order with the KDHE. This order, including various subsequent modifications, requires the El Dorado Refinery to continue the implementation of a groundwater management program with oversight provided by the KDHE Bureau of Environmental Remediation. More specifically, the El Dorado Refinery must continue to operate the hydrocarbon recovery well systems and containment barriers at the site and conduct sampling from monitoring wells and surface water stations. Quarterly and annual reports must also be submitted to the KDHE. The order requires that remediation activities continue until KDHE-established groundwater criteria or other criteria agreed to by the KDHE and the El Dorado Refinery are met. Subject to the terms of the purchase and sale agreement for the El Dorado Refinery entered into between Frontier and Shell, Shell is responsible for the costs of continued compliance with this order.

Centennial Pipeline Regulation. We have a 34.72% undivided ownership interest in the Centennial pipeline, which runs approximately 88 miles from Guernsey to Cheyenne, Wyoming. Suncor Pipe Line Company is the sole operator of the Centennial pipeline as well as the holder of the remaining ownership interest. The Cheyenne Refinery receives up to 25,000 bpd 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 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.

Employees

At December 31, 2004, we employed approximately 731 full-time employees in the refining operations, 74 of whom were in the Houston and Denver offices, 261 at the Cheyenne Refinery, 390 at the El Dorado Refinery and 6 at our asphalt terminal in Grand Island, Nebraska. The Cheyenne Refinery employees include 91 administrative and technical personnel and 170 union members. The El Dorado Refinery employees include 134 administrative and technical personnel and 256 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.

Risk Factors Relating to Our Business

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 (the difference between crude oil prices and refined product sales prices) have fluctuated substantially. Factors that may affect crude oil costs and refined product prices include:

·	overall demand for crude oil and refined products;

·	general economic conditions;

·	the level of foreign and domestic production of crude oil and refined products;

·	the availability of imports of crude oil and refined products;

·	the marketing of alternative and competing fuels;

·	the extent of government regulation;

·	global market dynamics;

·	product pipeline capacity;

·	local market conditions; and

·	the level of operations of other refineries in the Plains States and Rocky Mountain region.

Crude oil supply contracts are generally short-term contracts with price terms that change as market prices change. Our crude oil requirements are supplied from sources that include:

·	major oil companies;

·	crude oil marketing companies;

·	large independent producers; and

·	smaller local producers.

The price at which we can sell gasoline and other refined products is strongly influenced by the 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, enter into forward product agreements to hedge excess inventories and hedge 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 fluctuations in market prices. Our inventories of crude oil, unfinished products and finished products are recorded at the lower of cost on a first-in, first-out (“FIFO”) basis or market prices. As a result, a rapid and significant increase or decrease in the market prices for crude oil or refined products could have a significant short-term impact on our earnings and cash flow.

Our profitability is linked to crude oil differentials, which increased significantly in 2004 over 2003 levels.

The light/heavy crude oil differential is the average differential between the benchmark West Texas Intermediate (“WTI”) crude oil priced at Cushing, Oklahoma and the heavy crude oil priced delivered to the Cheyenne Refinery, and the WTI/WTS (sweet/sour) crude oil differential is the average differential between benchmark WTI crude oil priced at Cushing, Oklahoma and West Texas sour crude oil priced at Midland, Texas. Our profitability at our Cheyenne Refinery is linked to the light/heavy crude oil differential and our profitability at our El Dorado Refinery is linked to the WTI/WTS crude oil differential. We prefer to refine heavy crude oil at the Cheyenne Refinery and sour crude oil at the El Dorado Refinery because they provide a wider refining margin than light or sweet crude does. Accordingly, any tightening of these crude oil differentials will reduce our profitability. The light/heavy crude oil differential averaged $9.90 per barrel in the year ended December 31, 2004, compared to $7.10 per barrel in the same period in 2003. The WTI/WTS crude oil differential averaged $3.74 per barrel in the year ended December 31, 2004, compared to $2.68 per barrel in the same period in 2003. Crude prices were high during 2004, which resulted in both attractive light/heavy crude oil differentials and WTI/WTS crude oil differentials. However, crude oil prices may not remain at current levels and the crude oil differentials 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 (“OPEC”).

Demand for our products is influenced by general economic conditions. For example, near record level refined product margins and crude oil differentials in 2001 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. In 2003, refined product margins and crude oil differentials returned closer to historical average levels. In 2004, crude oil differentials reached record levels, and refined product margins exceeded historical average levels. However, the recurrence of weaker economic and market conditions in the future may have a negative impact on our business and financial results.

Our Refineries face operating hazards, and 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 our Refineries through an alternative pipeline or from additional tank trucks to the Refineries, 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 either of our Refineries experiences a major accident or fire or other event or an interruption in supply or operations, our business could be materially adversely affected if the damage or liability exceeds the amounts of business interruption, property, terrorism and other insurance that we maintain against these risks.

Our Refineries consist of many processing units, a number of which have been in operation for a long time. One or more of the units may require additional unscheduled down time for unanticipated maintenance or repairs that are more frequent than our scheduled turnaround for each unit every one to five years. Scheduled and unscheduled maintenance could reduce our revenues during the period of time that our units are not operating.

We face substantial competition from other refining and pipeline companies.

The refining industry is highly competitive. Many of our competitors are large, integrated, major or independent oil companies that, because of their more diverse operations, larger refineries and stronger capitalization, may be better positioned than we are to withstand volatile industry conditions, including shortages or excesses of crude oil or refined products or intense price competition at the wholesale level. Many of these competitors have financial and other resources substantially greater than ours.

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 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 for our Cheyenne Refinery. However, reduced road construction and agricultural work during the winter months somewhat depresses 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. 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 that we currently own or operate, facilities that we formerly owned or operated and facilities to which we sent wastes or by-product for treatment or disposal and other contamination. Accidental discharges could occur in the future, future action may be taken in connection with past discharges, governmental agencies may assess penalties against us in connection with past or future contamination and third parties may assert claims against us for damages allegedly arising out of any past or future contamination. The potential penalties and clean-up costs for past or future releases or spills, the failure of 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.

An adverse decision in a lawsuit pending between Holly Corporation and Frontier could have a material adverse effect on our financial condition and therefore, on our results of operations.

On August 20, 2003, we filed a lawsuit in the Delaware Court of Chancery seeking declaratory relief and unspecified damages based on allegations that Holly Corporation (“Holly”) repudiated its obligations and breached an implied covenant of good faith and fair dealing under a merger agreement announced in late March 2003 under which Frontier and Holly were to be combined. On September 2, 2003, Holly filed its answer and counterclaims seeking declaratory judgments that Holly had not repudiated the merger agreement, that we had repudiated the merger agreement, that we had breached certain representations made by us in the merger agreement, that Holly’s obligations under the merger agreement were and are excused and that Holly may terminate the merger agreement without liability, and seeking unspecified damages as well as costs and attorneys’ fees. The trial with respect to our complaint and the Holly answer and counterclaims began in the Delaware Court of Chancery on February 23, 2004 and was completed on March 5, 2004. In this litigation, the maximum amount of damages currently asserted by us against Holly is approximately $161 million plus interest, attorneys’ fees and costs, and the maximum amount of damages currently asserted by Holly against us is approximately $148 million plus interest, attorneys’ fees and costs. Post-trial briefing was completed in late April 2004, and on May 4, 2004 the court heard oral arguments. We are awaiting a decision to be announced by the court. While we cannot predict the outcome of this litigation, an adverse decision to us could have a material adverse effect on our business, financial condition, liquidity, competitive position or prospects.

We may have labor relations difficulties with some of our employees represented by unions.

Approximately 58 percent of our employees were covered by collective bargaining agreements at December 31, 2004. 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 of time for payment of accounts receivable from our customers.

Available Information

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 that 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’s Internet site at http://www.sec.gov contains the reports, proxy and information statements, and other information filed electronically.

Our web site address is: http://www.frontieroil.com. We make our web site content available for informational purposes only. It should not be relied upon for investment purposes, nor is it incorporated by reference in this Form 10-K. We make available on this web site under “Investor Relations,” free of charge, our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports as soon as reasonably practicable after we electronically file those materials with, or furnish those materials to, the SEC.

We filed our 2004 annual CEO certification with the New York Stock Exchange (“NYSE”) on April 15, 2004. We anticipate filing our 2005 annual CEO certification with the NYSE on or about April 20, 2005. Additionally, we filed with the SEC as exhibits to our Form 10-K for the year ended December 31, 2003 the CEO and CFO certifications required under Section 302 of the Sarbanes-Oxley Act of 2002.

Item 2. Properties

Refining Operations

We own the 125 acre site of the Cheyenne Refinery in Cheyenne, Wyoming and the approximately 1,000 acre site of the El Dorado Refinery in El Dorado, Kansas. The following tables set forth the refining operating statistical information on a consolidated basis and for each Refinery for 2004, 2003 and 2002. The statistical information includes the following terms not previously defined:

·	Charges - the quantity of crude oil and other feedstock processed through refinery units on bpd basis.
·	Manufactured product yields - the volumes of specific materials that are obtained through the distilling of crude oil and the operations of other refinery process units on a bpd basis.
·	Gasoline and diesel crack spreads - The average non-oxygenated gasoline and diesel net sales prices that we receive for each product less the average WTI crude oil price at Cushing, Oklahoma.

Consolidated:

Year Ended December 31,	2004		2003		2002
Charges (bpd)
Light crude		37,486		31,314		35,684
Heavy and intermediate crude		110,662		115,907		110,372
Other feed and blend stocks		16,609		18,407		17,760
Total		164,757		165,628		163,816

Manufactured product yields (bpd)
Gasoline		82,944		83,449		84,645
Diesel and jet fuel		53,093		53,156		53,436
Asphalt		7,475		7,530		7,437
Chemicals		939		842		369
Other		16,112		16,536		14,915
Total		160,563		161,513		160,802

Total product sales (bpd)
Gasoline		90,698		89,842		91,989
Diesel and jet fuel		52,818		53,606		53,378
Asphalt		7,427		7,260		7,490
Chemicals		841		842		439
Other		14,205		14,117		13,236
Total		165,989		165,667		166,532

Refinery operating margin information (per sales barrel)
Refined products revenue	$	47.27	$	35.88	$	29.82
Raw material, freight and other costs (FIFO inventory accounting)		40.04		30.77		25.71
Refinery operating expenses, excluding depreciation		3.62		3.31		2.93
Depreciation and amortization		0.53		0.47		0.44

Average WTI crude oil price at Cushing, OK (per barrel)	$	41.85	$	31.89	$	26.17

Average gasoline crack spread (per barrel)	$	8.61	$	7.00	$	5.88
Average diesel crack spread (per barrel)		7.35		5.05		3.97

Average sales price (per sales barrel)
Gasoline	$	51.70	$	39.72	$	33.08
Diesel and jet fuel		49.81		36.91		30.35
Asphalt		24.11		24.68		21.64
Chemicals		115.45		53.90		41.68
Other		17.63		12.24		9.24

Cheyenne Refinery:

Year Ended December 31,	2004		2003		2002
Charges (bpd)
Light crude		6,645		5,405		4,070
Heavy crude		38,408		40,284		37,231
Other feed and blend stocks		4,392		5,966		4,882
Total		49,445		51,655		46,183

Manufactured product yields (bpd)
Gasoline		20,039		20,518		18,196
Diesel and jet fuel		14,387		15,044		13,434
Asphalt		7,475		7,530		7,437
Other		5,839		6,822		5,855
Total		47,740		49,914		44,922

Total product sales (bpd)
Gasoline		26,744		26,836		24,559
Diesel and jet fuel		14,581		15,091		13,361
Asphalt		7,427		7,260		7,490
Other		5,044		4,708		4,243
Total		53,796		53,895		49,653

Refinery operating margin information (per sales barrel)
Refined products revenue	$	45.50	$	35.61	$	29.91
Raw material, freight and other costs (FIFO inventory accounting)		38.08		29.40		25.18
Refinery operating expenses, excluding depreciation		3.68		3.12		3.02
Depreciation and amortization		0.90		0.79		0.83

Average light/heavy crude oil differential (per barrel)	$	9.90	$	7.10	$	4.77

Average gasoline crack spread (per barrel)	$	9.33	$	7.32	$	6.44
Average diesel crack spread (per barrel)		9.34		6.57		4.99

Average sales price (per sales barrel)
Gasoline	$	53.28	$	41.42	$	35.22
Diesel and jet fuel		52.35		39.00		32.16
Asphalt		24.11		24.68		21.64
Other		15.98		8.44		6.68

El Dorado Refinery:

Year Ended December 31,	2004		2003		2002
Charges (bpd)
Light crude		30,841		25,909		31,614
Heavy and intermediate crude		72,254		75,623		73,141
Other feed and blend stocks		12,218		12,440		12,878
Total		115,313		113,972		117,633

Manufactured product yields (bpd)
Gasoline		62,905		63,931		66,449
Diesel and jet fuel		38,706		38,111		40,002
Chemicals		939		842		369
Other		10,273		9,715		9,061
Total		112,823		112,599		115,881

Total product sales (bpd)
Gasoline		63,954		63,006		67,430
Diesel and jet fuel		38,237		38,516		40,017
Chemicals		841		842		439
Other		9,161		9,410		8,993
Total		112,193		111,774		116,879

Refinery operating margin information (per sales barrel)
Refined products revenue	$	48.12	$	36.01	$	29.78
Raw material, freight and other costs (FIFO inventory accounting)		40.98		31.43		25.93
Refinery operating expenses, excluding depreciation		3.59		3.41		2.90
Refinery depreciation		0.35		0.32		0.28

WTI/WTS crude oil differential (per barrel)	$	3.74	$	2.68	$	1.36

Average gasoline crack spread (per barrel)	$	8.31	$	6.86	$	5.68
Average diesel crack spread (per barrel)		6.59		4.45		3.63

Average sales price (per sales barrel)
Gasoline	$	51.03	$	38.99	$	32.30
Diesel and jet fuel		48.84		36.09		29.75
Chemicals		115.45		53.90		41.68
Other		18.53		14.13		10.45

Other Properties

We lease approximately 6,500 square feet of office space in Houston for our corporate headquarters under a lease expiring in October 2009. For our refining operations headquarters, we lease approximately 28,000 square feet in Denver, Colorado under a four and a half year sublease expiring in December 2006. We lease approximately ten acres of land, including a building and railroad spur in Grand Island, Nebraska, under a ten-year lease expiring January 31, 2009, on which our asphalt and terminal storage facility are located.

Item 3. Legal Proceedings

Beverly Hills Lawsuits. Our subsidiary, Wainoco Oil & Gas Company, owned and operated an interest in an oil field in the Los Angeles, California metropolitan area from 1985 to 1995. The production facilities for that interest in the oil field are located at the campus of the Beverly Hills High School. In April 2003, a law firm began filing claims with the Beverly Hills Unified School District and the City of Beverly Hills on behalf of former students, school employees, area residents and others alleging that emissions from the oil field or the production facilities caused cancers or various other health problems in those individuals. Wainoco Oil & Gas Company and Frontier have been named in six such suits: Moss et al. v. Veneco, Inc. et al., filed in June 2003; Ibraham et al. v. City of Beverly Hills et al., filed in July 2003; Yeshoua et al. v. Veneco, Inc. et al., filed in August 2003; Jacobs v. Wainoco Oil & Gas Company et al., filed in December 2003; Bussel et al. v. Veneco, Inc. et al., filed in January 2004; and Steiner et al. v. Venoco Inc. et al., filed in May 2004. Other defendants in these lawsuits include the Beverly Hills Unified School District, the City of Beverly Hills, ten other oil and gas companies, two additional companies involved in owning or operating a power plant adjacent to the Beverly Hills High School and three of their related parent companies. The lawsuits include claims for personal injury, wrongful death, loss of consortium and/or fear of contracting diseases, and also ask for punitive damages. No dollar amounts of damages have been specified in any of the lawsuits. The six pending lawsuits have been related to one another and have been transferred to a judge on the complex civil litigation panel in the Superior Court of the State of California for the County of Los Angeles. A case management order has been entered in the case pursuant to which 12 plaintiffs have been selected as the initial group of plaintiffs to go to trial, discovery has commenced and a preliminary trial date has been set for July 25, 2005.

The oil production site operated by our subsidiary was a modern facility and was operated with a high level of safety and responsibility. We believe that our subsidiary’s activities did not cause any health problems for anyone, including former Beverly Hills high school students, school employees or area residents. Nevertheless, as a matter of prudent risk management, we purchased insurance in 2003 from an insurance company with an A.M. Best rating of A++ (Superior) covering the existing claims described above and any similar claims for bodily injury or property damage asserted during the five-year period following the policy’s September 30, 2003 commencement date. The claims are covered, whether asserted directly against the insured parties or as a result of contractual indemnity. In October 2003, we paid $6.25 million to the insurance company (which included an indemnity premium of $5.75 million and a $500,000 administration fee) and also funded with the insurance company a commutation account of approximately $19.5 million, from which the insurance company is funding the first costs under the policy including, but not limited to, the costs of defense of the claims. The policy covers defense costs and any payments made to claimants, up to an aggregate limit of $120 million, including coinsurance by us of up to $3.9 million of the coverage between $40 million and $120 million. As of December 31, 2004, the commutation account balance was approximately $16.4 million. We also paid $772,500 to the State of California for insurance tax on the premium in 2003, of which $600,000 was refunded in 2004. We have the right to terminate the policy at any time after September 30, 2004 and prior to September 30, 2008, and receive a refund of the unearned portion of the premium (approximately $4.0 million as of December 31, 2004, and declining by approximately $1.1 million each year) plus any unspent balance in the commutation account plus accumulated interest. While the policy is in effect, the insurance company will manage the defense of the claims. We are also seeking coverage with respect to the Beverly Hills, California claims from the insurance companies that provided policies to us during the 1985 to 1995 period.

We believe that neither the claims that have been made, the six pending lawsuits, nor other potential future litigation, by which similar or related claims may be asserted against us or our subsidiary, will result in any material liability or have any material adverse effect upon our financial position or results of operations.

Holly Lawsuit. On August 20, 2003, we announced that Holly had advised us that it was not willing to proceed with the merger agreement previously announced on March 31, 2003 on the agreed terms. As a result, we filed suit for damages in the Delaware Court of Chancery. On September 2, 2003, Holly filed an answer and counterclaims, denying our claims, asserting that we repudiated the merger agreement by filing the Delaware lawsuit, and claiming among other things that the Beverly Hills, California litigation caused us to be in breach of our representations and warranties in the merger agreement. We have denied all of Holly’s counterclaims. Trial on the suit and Holly’s counterclaims concluded on March 5, 2004. Oral arguments were held on May 4, 2004, and we are awaiting a decision. We believe that the counterclaims filed against us by Holly will not result in any material liability or have any material adverse effect upon our financial position or results of operations.

MTBE Concentration Lawsuits. In November 2003, our El Dorado Refinery (owned by our subsidiary, Frontier El Dorado Refining Company (“FEDRC”)) was included as one of 52 defendants in four lawsuits brought on behalf of the City of Dodge City, Kansas, the Chisholm Creek Utility Authority, the City of Bel Aire, Kansas, the County of Sedgwick Water Authority and the City of Park City, Kansas (the “Kansas Plaintiffs”) alleging unspecified damages for contamination of groundwater/public water wells by methyl tertiary butyl ether (“MTBE”) and tertiary butyl alcohol, a degradation product of MTBE. These four cases were removed to federal court and were then transferred with other similar cases to a federal district court in New York to be presided over by one federal court judge. In November 2004, our Cheyenne Refinery (owned by our subsidiary, Frontier Refining Inc (“FRI”)) was notified that it had been added as a defendant to these same four cases involving Kansas Plaintiffs. Because neither FEDRC nor FRI had either manufactured MTBE or provided MTBE blended gasoline in the Kansas marketplace, the Kansas Plaintiffs voluntarily dismissed both FEDRC and FRI in January 2005. These voluntary dismissals are without prejudice. Accordingly, the Kansas Plaintiffs are able, if they have the required evidentiary support, to add either FEDRC or FRI back into the litigation. However, given the basis for the dismissals, we continue to believe that any potential liability would not have a material adverse effect on our liquidity, financial position or results of operations.

Other. We are also involved in various other lawsuits which are incidental to our business. In management’s opinion, the adverse determination of such lawsuits would not have a material adverse effect on our liquidity, financial position or results of operations.

Item 4. Submission of Matters to a Vote of Security Holders

None.

PART II

Item 5. Market for Registrant’s Common Equity and Related Stockholder Matters

Our 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 2004 and 2003 are shown in the following table:

2004	High	Low
Fourth quarter Third quarter Second quarter First quarter	$ 26.93 23.70 21.19 19.85	$ 22.24 18.23 17.00 16.07
2003	High	Low
Fourth quarter Third quarter Second quarter First quarter	$ 17.81 16.14 18.16 18.25	$ 14.70 13.91 15.08 14.01

The approximate number of holders of record for our common stock as of February 18, 2005 was 1,046. Quarterly cash dividends of $.05 per share have been declared on our common stock for each quarter beginning with the quarter ended June 2001 and through the quarter ended June 30, 2004. The quarterly cash dividend was increased to $.06 per share for the quarters ended September 30, 2004 and December 31, 2004.

Item 6. Selected Financial Data

Five Year Financial Data

	2004			2003			2002			2001			2000
	(Dollars in thousands except per share amounts)
Revenues	$	2,861,716		$	2,170,503		$	1,813,750		$	1,888,401		$	2,045,157
Operating income		143,549			51,864			27,899			164,100			70,655
Net income		69,764			3,232			1,028			107,653			37,206
Basic earnings per share		2.62			0.12			0.04			4.12			1.36
Diluted earnings per share		2.55			0.12			0.04			4.00			1.34
Net cash provided by (used by) operating activities		177,899			(6,005	)		50,822			138,575			66,346
Net cash used in investing activities		(43,107	)		(34,300	)		(37,117	)		(22,824	)		(12,688	)
Net cash used in financing activities		(74,923	)		(7,539	)		(5,336	)		(76,202	)		(27,557	)
Working capital		97,261			38,621			108,253			109,064			43,610
Total assets		754,400			642,297			628,877			581,746			588,213
Long-term debt		150,000			168,689			207,966			208,880			239,583
Shareholders’ equity		240,113			169,277			168,258			169,204			81,424
Dividends declared per common share		0.22			0.20			0.20			0.15			-
Adjusted EBITDA (1)		180,168			80,696			55,231			189,110			93,662

(1)

Adjusted EBITDA represents income before interest expense, interest income, merger financing termination costs (includes both interest expense and income), income tax, and depreciation and amortization. Adjusted EBITDA is not a calculation based upon generally accepted accounting principles; however, the amounts included in the adjusted EBITDA calculation are derived from amounts included in our consolidated financial statements included in Item 8 of this Form 10-K. Adjusted EBITDA should not be considered as an alternative to net income or operating income, as an indication of our operating performance, or as an alternative to operating cash flow as a measure of liquidity. Adjusted EBITDA is not necessarily comparable to similarly titled measures of other companies. Adjusted EBITDA is presented here because it enhances an investor’s understanding of our ability to satisfy principal and interest obligations with respect to our indebtedness and to use cash for other purposes, including capital expenditures. Adjusted EBITDA is also used for internal analysis and as a basis for financial covenants. Our adjusted EBITDA is reconciled to net income as follows:

	2004			2003			2002			2001			2000
	(in thousands)
Net income	$	69,764		$	3,232		$	1,028		$	107,653		$	37,206
Add provision for income taxes		42,339			2,956			1,060			28,073			2,075
Add interest expense and other financing costs		37,573			28,746			27,613			31,146			34,738
Subtract interest income		(1,716	)		(1,109	)		(1,802	)		(2,772	)		(3,364	)
Add merger financing termination costs, net		-			18,039			-			-			-
Add depreciation and amortization		32,208			28,832			27,332			25,010			23,007
Adjusted EBITDA	$	180,168		$	80,696		$	55,231		$	189,110		$	93,662

Five Year Operating Data

	2004		2003		2002		2001		2000
Charges (bpd)
Light crude		37,486		31,314		35,684		31,456		35,605
Heavy crude (1)		110,662		115,907		110,372		111,061		105,529
Other feed and blend stocks		16,609		18,407		17,760		15,538		14,884
Total charges		164,757		165,628		163,816		158,055		156,018

Manufactured product yields (bpd)
Gasoline		82,944		83,449		84,645		78,126		76,795
Diesel and jet fuel		53,093		53,156		53,436		51,210		50,924
Chemicals (2)		939		842		369		1,370		1,804
Asphalt and other		23,587		24,066		22,352		24,483		23,363
Total manufactured product yields		160,563		161,513		160,802		155,189		152,886

Product sales (bpd)
Gasoline		90,698		89,842		91,989		83,737		83,070
Diesel and jet fuel		52,818		53,606		53,378		51,539		51,568
Chemicals (2)		841		842		439		1,413		1,964
Asphalt and other		21,632		21,377		20,726		22,411		21,556
Total product sales		165,989		165,667		166,532		159,100		158,158

Average sales price (per barrel)
Gasoline	$	51.70	$	39.72	$	33.08	$	35.85	$	38.09
Diesel and jet fuel		49.81		36.91		30.35		34.12		37.19
Chemicals (2)		115.45		53.90		41.68		70.81		70.52
Asphalt and other		19.85		16.46		13.72		14.07		16.14

Refinery operating margin information (per sales barrel)
Refined products revenue	$	47.27	$	35.88	$	29.82	$	32.53	$	35.20
Raw material, freight and other costs		40.04		30.77		25.71		25.69		30.41
Refinery operating expenses, excluding depreciation		3.62		3.31		2.93		3.27		3.07
Depreciation and amortization		0.53		0.47		0.44		0.42		0.39

Average gasoline crack spread (per barrel)	$	8.61	$	7.00	$	5.88	$	8.91	$	5.76
Average diesel crack spread (per barrel)		7.35		5.05		3.97		7.91		5.64

Average WTI crude oil price at Cushing, OK (per barrel)	$	41.85	$	31.89	$	26.17	$	26.09	$	31.25

Average light/heavy crude oil differential (per barrel)	$	9.90	$	7.10	$	4.77	$	7.62	$	5.88
Average WTI/WTS crude oil differential (per barrel)		3.74		2.68		1.36		3.10		2.06

(1)	Includes intermediate varieties of crude oil used by the El Dorado Refinery.

(2)	During 2002, the process of shutting down the phenol and cumene units at the El Dorado Refinery began and by year-end, we had discontinued the production of phenol and acetone and began producing and selling benzene.

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

General

Frontier operates the Refineries in Cheyenne, Wyoming and El Dorado, Kansas as previously discussed in Part I, Item 1 of this Form 10-K. We focus our marketing efforts in the Rocky Mountain and Plains States regions of the United States. We purchase the crude oil to be refined and market the refined petroleum products produced, including various grades of gasoline, diesel fuel, jet fuel, asphalt and other by-products.

Results of Operations

To assist in understanding our operating results, please refer to the operating data in Part I, Item 6 of this Form 10-K, which provides key operating information for our combined Refineries. Data for each Refinery is included in Part I, Item 2 of this Form 10-K, our quarterly reports on Form 10-Q and on our web site address: http://www.frontieroil.com.

The three significant indicators of our profitability reflected in the operating data of the analysis referred to above are the gasoline and diesel crack spreads, the light/heavy crude oil differential and the WTI/WTS crude oil differential. Other significant factors that influence our results are Refinery utilization, crude oil price trends, asphalt and by-product margins and refinery operating expenses (including natural gas prices and turnaround, or planned maintenance activity). We typically do not use derivative instruments to offset price risk on our base level of operating inventories. Under our FIFO inventory accounting method, crude oil price trends can cause significant fluctuation in the inventory valuation of our crude oil, unfinished products and finished products resulting in FIFO inventory gains when crude oil prices increase and FIFO inventory losses when crude oil prices decrease during the reporting period. See “Price Risk Management Activities” under Item 7A for a discussion of our utilization of derivative contracts.

The price of crude oil on the New York Mercantile Exchange was very volatile during 2004. The price began the year at $32.52 per barrel, reached a yearly high of $55.17 per barrel in October, and then declined to $43.45 per barrel by December 31, 2004. The price of crude oil increased during 2004 as the oil market supply/demand fundamentals continued to support higher prices. Demand for crude oil continued to increase throughout the world in 2004, especially in China, because of improved economic growth. Excess supply capability within both OPEC and non-OPEC countries has declined significantly in recent years. Industry experts estimate that excess supply capacity for OPEC is currently less than 2 million bpd compared to estimated world oil demand of nearly 83 million bpd in 2004. These factors, along with others such as geopolitical risk, have resulted in higher oil prices and OPEC’s increased ability to manage prices. The increase in crude oil prices, along with additional crude oil production in 2004 being primarily heavy and/or sour crude oil, increased our crude oil differentials during 2004.

In the U.S., gasoline demand increased approximately 140,000 bpd, or 2.2%, in 2004. Production of gasoline in the U.S. and imports of gasoline into the U.S. were required to comply with the new low sulfur gasoline requirements, and production was reduced by the elimination of MTBE blending in major markets. At times during 2004, production was unable to meet supply, thereby resulting in low levels of gasoline inventories during the 2004 driving season. These factors led to higher spring and summer gasoline crack spreads than we had received in prior years. Diesel crack spreads improved later in the year, as diesel inventories were below five-year averages entering the heating oil season.

We believe that many of the market fundamentals that caused higher crude oil prices and wider crude oil differentials in 2004 will continue into 2005. Although we believe that gasoline and diesel crack spreads will remain attractive because of increasing demand, they may not meet or exceed 2004 gasoline and diesel crack spreads due to higher inventories of gasoline entering the spring and summer driving seasons of 2005 and less planned turnaround activity in the industry in early 2005 compared to the same period in 2004.

2004 Compared with 2003

Overview of Results: We had net income for the year ended December 31, 2004 of $69.8 million, or $2.55 per diluted share, compared to net income of $3.2 million, or $0.12 per diluted share, in the same period in 2003. Our operating income of $143.5 million for the year ended December 31, 2004 was an increase of $91.7 million from the $51.9 million operating income for the comparable period in 2003. The average diesel crack spread was significantly higher during 2004 ($7.35 per barrel) than in 2003 ($5.05 per barrel). The average gasoline crack spread was also higher during 2004 ($8.61 per barrel) than in 2003 ($7.00 per barrel), and both the light/heavy and WTI/WTS crude oil differentials improved.

Our net income for the year ended December 31, 2004 was reduced by $14.9 million pretax ($9.2 million after tax) in additional costs associated with the redemption of our 11¾% Senior Notes. We used available cash and proceeds from a new $150.0 million 6⅝% Senior Notes offering to redeem the 11¾% Senior Notes. This refinancing will reduce interest expense in future years by $10.1 million per year. Our net income for the year ended December 31, 2004 was also reduced by the legal costs associated with the termination of the Holly merger and the Beverly Hills litigation. On March 31, 2003, we announced that we had entered into an agreement with Holly pursuant to which the two companies would merge. On August 20, 2003, we announced that Holly had advised us that it was not willing to proceed with our merger agreement on the agreed terms. As a result, we filed suit against Holly for damages in Delaware. Merger termination and legal costs reduced earnings in the year ended December 31, 2004 by $3.8 million pretax ($2.4 million after tax), and costs related to the Beverly Hills litigation reduced earnings in the year ended December 31, 2004 by an additional $5.6 million pretax ($3.4 million after tax). Our net income for the year ended December 31, 2004 was increased by $4.4 million pretax ($2.7 million after tax) from the gain on involuntary conversion of assets related to the fire that occurred on January 19, 2004 in the furnaces of the Cheyenne Refinery coker.

Specific Variances: Refined product revenues increased $702.0 million, or 32%, from $2.2 billion to $2.9 billion for the year ended December 31, 2004 compared to the same period in 2003. This increase was due to increased sales prices ($11.39 higher average per sales barrel), and slightly higher sales volumes in 2004 (322 more bpd). Sales prices increased primarily as a result of increased crude oil prices and net improvements in the gasoline and diesel crack spreads. Average gasoline prices increased from $39.72 per sales barrel in 2003 to $51.70 per sales barrel in 2004. Sales volumes of gasoline increased from 89,842 bpd in 2003 to 90,698 bpd in 2004. Average diesel and jet fuel prices increased from $36.91 per sales barrel in 2003 to $49.81 per sales barrel during 2004. However, sales volumes of diesel and jet fuel decreased 788 bpd from 53,606 bpd during the year ended December 31, 2003 to 52,818 bpd during the same period in 2004. Total product sales volumes overall increased only slightly from 165,667 bpd in the year ended December 31, 2003 to 165,989 bpd in the same period in 2004.

Yields of gasoline decreased 505 bpd, or less than 1%, from 83,449 bpd in the year ended December 31, 2003 to 82,944 bpd in the same period in 2004. Yields of diesel and jet fuel remained fairly flat year to year, decreasing only 63 bpd, from 53,156 bpd in the year ended December 31, 2003 to 53,093 bpd in the same period in 2004. Yields for the year ended December 31, 2004 for the El Dorado Refinery were nearly flat, increasing just 224 bpd from the year ended December 31, 2003. Yields for the year ended December 31, 2004 for the Cheyenne Refinery were lower than in the same period in 2003 primarily because of the coker furnace fire (see Note 3 in the “Notes to Consolidated Financial Statements”). The Cheyenne Refinery coking unit was out of service for one month in the first quarter of 2004.

Other revenues decreased $10.8 million to a $9.9 million loss for the year ended December 31, 2004 compared to income of nearly $1.0 million for the same period in 2003 due to $10.3 million in net losses from derivative contracts accounted for using mark-to-market accounting in the year ended December 31, 2004, compared to net losses of $268,000 for the same period in 2003. See “Price Risk Management Activities” under Item 7A for a discussion of our utilization of commodity derivative contracts. Processing income from our Cheyenne Refinery coker was $834,000 less during the year ended December 31, 2004, compared to the same period in 2003 due to the July 2004 conclusion of the long-term resid processing agreement with Suncor Energy (USA) Inc. (“Suncor”), and the coker being out of service for a portion of 2004 from the previously mentioned fire. The processing agreement entitled Suncor to process in the Cheyenne Refinery coker up to 3,300 bpd of resid, a heavy end by-product of the refining process.

Raw material, freight and other costs include crude oil and other raw materials used in the refining process, purchased products and blendstocks, freight costs for FOB destination sales, as well as the impact of changes in inventory under the FIFO inventory accounting method. The average price of crude oil was higher in the year ended December 31, 2004 than in the same period in 2003. The average price of WTI crude oil priced at Cushing, Oklahoma was $41.85 per barrel in the year ended December 31, 2004 compared to $31.89 per barrel in the same period in 2003. Raw material, freight and other costs increased by $571.7 million, or $9.27 per sales barrel, during the year ended December 31, 2004 when compared to the same period in 2003. The increase in raw material, freight and other costs was due to higher average crude prices and more crude oil charges, offset by higher inventory gains from rising prices in the year ended December 31, 2004 compared to the year ended December 31, 2003. We also benefited from improved crude oil differentials during the year ended December 31, 2004 when compared to the same period in 2003. For the year ended December 31, 2004, we realized a reduction in raw material, freight and other costs as a result of inventory gains of approximately $19.8 million after tax ($32.0 million pretax, comprised of $6.1 million at the Cheyenne Refinery and $25.9 million at the El Dorado Refinery) because of increasing crude oil and refined product prices. For the year ended December 31, 2003, we realized a reduction in raw material, freight and other costs as a result of inventory gains of approximately $4.4 million after tax ($7.2 million pretax, comprised of a $4.2 million gain for the El Dorado Refinery and a $3.0 million gain for the Cheyenne Refinery).

The Cheyenne Refinery raw material, freight and other costs of $38.08 per sales barrel for the year ended December 31, 2004 increased from $29.40 per sales barrel in the same period in 2003 due to higher crude oil prices offset by higher inventory gains and an improved light/heavy crude oil differential. The heavy crude oil utilization rate at the Cheyenne Refinery expressed as a percentage of the total crude oil charge decreased to 85% in the year ended December 31, 2004 from 88% in 2003, as we processed more light crude oil due to the coker being out of service for approximately one month. The light/heavy crude oil differential for the Cheyenne Refinery averaged $9.90 per barrel in the year ended December 31, 2004 compared to $7.10 per barrel in the same period in 2003.

The El Dorado Refinery raw material, freight and other costs of $40.98 per sales barrel for the year ended December 31, 2004 increased from $31.43 per sales barrel in the same period in 2003 due to higher average crude oil prices offset by higher inventory gains and an improved WTI/WTS crude oil differential. The WTI/WTS crude oil differential increased from an average of $2.68 per barrel in the year ended December 31, 2003 to $3.74 per barrel in the same period in 2004.

Refinery operating expenses, excluding depreciation, include both the variable costs (energy and utilities) and the fixed costs (salaries, taxes, maintenance costs and other) of operating the Refineries. Refinery operating expenses, excluding depreciation, were $219.8 million, or $3.62 per sales barrel, in the year ended December 31, 2004 compared to $200.4 million, or $3.31 per sales barrel, in the comparable period of 2003.

The Cheyenne Refinery operating expenses, excluding depreciation, were $72.4 million, or $3.68 per sales barrel, in the year ended December 31, 2004 compared to $61.4 million, or $3.12 per sales barrel, in the comparable period of 2003. The increased expenses included higher costs in natural gas ($3.1 million), maintenance ($3.2 million), salaries ($1.5 million), a 2004 bonus accrual ($1.3 million) and increased environmental expenses ($2.0 million). The higher natural gas costs resulted primarily from an average increase in price of $1.21 per mmbtu, along with also utilizing approximately 11% more volumes of natural gas during the year ended December 31, 2004 when compared to the same period in 2003.

The El Dorado Refinery operating expenses, excluding depreciation, were $147.4 million, or $3.59 per sales barrel, in the year ended December 31, 2004, increasing from $139.0 million, or $3.41 per sales barrel, for the year ended December 31, 2003 primarily due to higher costs in natural gas ($6.3 million), a 2004 bonus accrual ($1.9 million) and higher salaries and benefits ($1.0 million), offset by reduced costs in consulting and legal ($1.0 million). The higher natural gas costs resulted primarily from an average increase in price of $0.87 per mmbtu, along with also utilizing approximately 2% more volumes of natural gas during the year ended December 31, 2004 when compared to the same period in 2003.

Selling and general expenses, excluding depreciation, increased $10.0 million, or 50%, from $19.9 million for the year ended December 31, 2003 to $29.9 million for the year ended December 31, 2004 due to increased costs related to the Beverly Hills litigation and increases in salaries. Costs related to the Beverly Hills litigation during the year ended December 31, 2004 were $5.6 million ($4.1 million in legal costs, substantially all of which have been paid or will be paid from the Commutation Account, and $1.5 million amortization of the previously purchased loss mitigation insurance premium), as opposed to $1.8 million in the same period in 2003. Salaries increased by $5.5 million for the year ended December 31, 2004 compared to the same period in 2003, primarily due to $3.8 million in bonuses being accrued in 2004, while none were accrued in 2003.

Merger termination and legal costs of $3.8 million for the year ended December 31, 2004 include legal costs associated with the termination of the anticipated 2003 Holly merger and resulting lawsuit, compared to $8.7 million in merger termination and legal costs for the comparable period in 2003.

Depreciation and amortization increased $3.4 million, or 12%, for the year ended December 31, 2004 compared to the same period in 2003 because of increased capital investment in our Refineries.

Interest expense and other financing costs of $37.6 million for the year ended December 31, 2004 increased $8.8 million, or 31%, from $28.7 million in the comparable period in 2003. Interest expense and other financing costs for the year ended December 31, 2004 included $14.9 million in costs related to the redemption of our 11¾% Senior Notes and subsequent reduced interest expense on our new $150.0 million 6⅝% Senior Note debt issuance. This refinancing will reduce interest expense in future years by $10.1 million per year. The $14.9 million in redemption-related costs includes $10.4 million of premium, the write-off at redemption of the remaining unamortized $1.5 million of issue discount, $2.7 million for the write-off at redemption of the remaining unamortized debt issue costs, and $0.3 million of legal and administrative costs to facilitate the tender offer and redemption. We also had no interest on the 9⅛% Senior Notes during the year ended December 31, 2004, as they were redeemed in December 2003 ($3.5 million in interest expense for the year ended December 31, 2003). Interest expense and other financing costs for the year ended December 31, 2003 also included $1.2 million of premium paid upon redemption of our 9⅛% Senior Notes in December 2003. Average debt outstanding decreased to $209 million during the year ended December 31, 2004 from $236 million (excluding merger debt) for the same period in 2003. Capitalized interest, which reduced interest expense and other financing costs, was $65,000 during the year ended December 31, 2004 compared to $586,000 in the comparable period of 2003.

Interest income increased $607,000, or 55%, from $1.1 million in the year ended December 31, 2003 to $1.7 million in the year ended December 31, 2004, as we had more cash available to invest.

The gain on involuntary conversion of assets relates to the fire that occurred on January 19, 2004 in the furnaces of the coking unit at the Cheyenne Refinery. For the year ended December 31, 2004, the gain represents the settlement proceeds of $7.1 million from our insurers less $1.6 million of expenses related to clean-up costs and $1.1 million of net property, plant and equipment written-off due to the fire.

The merger financing termination costs, net, during the year ended December 31, 2003 were $18.0 million, which related to the 8% Senior Notes issued to finance the contemplated Holly merger and included interest expense, issue discount, financing issue costs and redemption premium, net of $752,000 interest income earned on the escrow account.

The provision for income taxes for the year ended December 31, 2004 was $42.3 million on pretax income of $112.1 million (or 37.8%) reflecting the net benefit of releasing our deferred tax valuation allowance offset by the effect of the permanent book versus tax differences and prior year adjustments from our current estimated effective tax rate of 38.2%. As of December 31, 2004, we have no valuation allowance against our deferred tax assets. See Note 7 in the “Notes to Consolidated Financial Statements” for detailed information on our deferred tax assets. The income tax provision for the year ended December 31, 2003 was $3.0 million on pretax income of $6.2 million (or 47.8%) due to one-time adjustments for permanent book versus tax differences related to 2002 and 2003 expenses and an increase of $280,000 in the income tax provision for the year ended December 31, 2003 resulting from an adjustment to the 2002 tax provision. The new “American Jobs Creation Act of 2004” (“the Act”) provision providing tax relief for manufacturers should result in reduced effective federal income tax rates beginning in 2005. In December 2004, the Financial Accounting Standards Board (“FASB”) staff issued FASB Staff Position (“FSP”) No. FAS 109-1 to provide guidance on the application of FAS 109 to the provision within the Act that provides tax relief to U.S. domestic manufacturers. The FSP states that the manufacturers’ deduction set forth in the Act should be accounted for as a special deduction in accordance with FAS 109 and not as a tax rate reduction. A special deduction is accounted for by recording the benefit of the deduction in the year in which it can be taken in our tax return, and not by adjusting deferred tax assets and liabilities in the period of the Act’s enactment. The FSP was effective upon issuance, and we have properly accounted for our deferred taxes at December 31, 2004 in accordance with the FSP. Other certain provisions of the Act should benefit Frontier by allowing us an accelerated depreciation deduction of 75% of qualified capital costs incurred to achieve low sulfur diesel fuel requirements and by providing a $0.05 per gallon credit on compliant diesel fuel up to an amount equal to the remaining 25% of these qualified capital costs for federal income tax purposes. (See “Environmental” under Note 10 in the “Notes to Consolidated Financial Statements.”)

2003 Compared with 2002

Overview of Results: We had net income for the year ended December 31, 2003 of $3.2 million, or $0.12 per diluted share, compared to net income of $1.0 million, or $0.04 per diluted share, for 2002. Our 2003 net income was negatively impacted by the termination of the Holly merger. Merger termination and legal costs and merger termination financing costs, net of interest income, reduced 2003 earnings by $26.8 million pretax ($16.5 million after tax). The merger-related costs were on an accrual basis and did not include bank facility charges related to the merger.

Despite the negative impact of the terminated Holly merger, our operating income of $51.9 million for 2003 increased $24.0 million from $27.9 million for 2002. The major factors improving operating income were improved gasoline and diesel crack spreads, increases in the light/heavy crude oil differential and WTI/WTS crude oil differential and improved yields and sales from our Cheyenne Refinery. Yields and sales were down in 2003 at our El Dorado Refinery due to a major crude unit turnaround, or planned maintenance, in the spring of 2003. Results were also negatively impacted by higher refinery operating expenses at both Refineries, primarily due to higher natural gas costs.

Specific Variances: Refined product revenues increased $356.9 million, or 20%, from $1.8 billion to $2.2 billion for the year ended December 31, 2003 compared to 2002 due to increased sales prices resulting from higher crude oil prices and higher gasoline and diesel crack spreads on nearly flat sales volumes. Our gasoline and diesel crack spreads averaged $7.00 per barrel and $5.05 per barrel, respectively, in 2003, compared to $5.88 per barrel and $3.97 per barrel, respectively, in 2002. Average gasoline prices increased from $33.08 per sales barrel in 2002 to $39.72 per sales barrel in 2003. Sales volumes of gasoline decreased 2,147 bpd from 91,989 bpd during 2002 to 89,842 bpd in 2003. Average diesel and jet fuel prices increased from $30.35 per sales barrel in 2002 to $36.91 per sales barrel during 2003. Sales volumes of diesel and jet fuel increased 228 bpd from 53,378 bpd during 2002 to 53,606 bpd in 2003. Total product sales volumes overall decreased less than 1% from 166,532 bpd in 2002 to 165,667 bpd in 2003.

Yields of gasoline decreased 1,196 bpd, or 1%, from 84,645 bpd in 2002 to 83,449 bpd in 2003, and yields of diesel and jet fuel decreased 280 bpd, or less than 1%, from 53,436 bpd in 2002 compared to 53,156 bpd in 2003. Sales and yield volumes for 2003 for the El Dorado Refinery were lower than during 2002 primarily because of the crude unit turnaround at the El Dorado Refinery, which commenced on March 18, 2003 and was completed on March 30, 2003. During the first quarter of 2003, the El Dorado Refinery’s charge and yield volumes were 20,682 bpd and 21,161 bpd less respectively, than the first quarter of 2002; however upon completion of the turnaround, the El Dorado Refinery operations were very strong during the remainder of 2003, ending the year at only 3,661 fewer bpd of charges and 3,282 fewer bpd of yields than 2002. The Cheyenne Refinery operations were very strong all year resulting in both increased charge and yield volumes sufficient to offset the reduced charges and yields at the El Dorado Refinery resulting in aggregate small increases in charge volumes of 1,812 bpd and yield volumes of 711 bpd.

Other revenues decreased $185,000 to $952,000 for the year ended December 31, 2003 compared to revenues of $1.1 million for the same period in 2002 due to $268,000 in net losses from derivative contracts accounted for using mark-to-market accounting in the year ended December 31, 2003, compared to net income of $108,000 for the same period in 2002 (see “Price Risk Management Activities” in Item 7A), offset by increased processing income from our Cheyenne Refinery coker.

The average price of crude oil was substantially higher in 2003 than in 2002. The average price of WTI crude oil priced at Cushing, Oklahoma was $31.89 per barrel in 2003 compared to $26.17 per barrel in 2002. Raw material, freight and other costs increased $298.2 million, or $5.06 per sales barrel, from 2002 due to higher average crude oil prices and a smaller amount of inventory gains from rising prices during 2003 than during 2002, offset by improved crude oil spreads. For the year ended December 31, 2003, we realized a decrease in raw material, freight and other costs as a result of inventory gains of approximately $4.4 million after tax ($7.2 million pretax, comprised of $3.0 million at the Cheyenne Refinery and $4.2 million at the El Dorado Refinery) because of the increasing crude oil prices. The price of crude oil on the New York Mercantile Exchange was very volatile in 2003. The crude price began the year at $31.20 per barrel, reached a high of $37.83 per barrel in March, dropped to a low of $25.24 per barrel in April and closed the year at $32.52 per barrel. 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 increasing crude oil prices. The price of crude oil on the New York Mercantile Exchange increased during 2002 from $19.84 per barrel to $31.20 per barrel by year-end.

The Cheyenne Refinery raw material, freight and other costs of $29.40 per sales barrel in 2003 increased from $25.18 per sales barrel in 2002 due to higher crude oil prices and less inventory gains, offset by an improved light/heavy crude oil differential. The heavy crude oil utilization rate at the Cheyenne Refinery expressed as a percentage of the total crude oil charge decreased to 88% in 2003 from 90% in 2002, as we utilized slightly more light crude oil. The light/heavy crude oil differential for the Cheyenne Refinery averaged $7.10 per barrel in 2003 compared to $4.77 per barrel in 2002.

The El Dorado Refinery raw material, freight and other costs of $31.43 per sales barrel in 2003 increased from $25.93 per sales barrel in 2002 due to higher average crude oil prices and less inventory gains, offset by an improved WTI/WTS crude oil differential. The WTI/WTS crude oil differential increased from an average of $1.36 per barrel in 2002 to $2.68 per barrel in 2003.

Refinery operating expenses, excluding depreciation, were $200.4 million, or $3.31 per sales barrel, in 2003 compared to $178.3 million, or $2.93 per sales barrel, in 2002.

The Cheyenne Refinery operating expense, excluding depreciation, was $61.4 million, or $3.12 per sales barrel, in 2003 compared to $54.7 million, or $3.02 per sales barrel, in 2002 primarily due to higher natural gas and other utility costs ($2.6 million), salaries ($2.5 million), consulting and legal ($800,000) and additives and chemicals ($700,000).

The El Dorado Refinery operating expense, excluding depreciation, was $139.0 million, or $3.41 per sales barrel, in 2003, increasing from $123.6 million, or $2.90 per sales barrel, in 2002 primarily due to higher natural gas costs ($8.2 million), salaries ($3.8 million), chemicals ($1.2 million) and excess turnaround costs ($2.3 million). The per barrel refinery operating expense variance was exacerbated by lower sales volumes in 2003 than in 2002.

Selling and general expenses, excluding depreciation, increased $2.3 million, or 13%, for the year ended December 31, 2003 because of $1.8 million in legal costs related to the Beverly Hills lawsuits, increases in other legal costs and salaries, and travel, engineering and other consulting services related to evaluating potential acquisitions and possible refinery improvements.

Merger termination and legal costs of $8.7 million for the year ended December 31, 2003 included transaction and ongoing legal costs (on an accrual basis) associated with the termination of the anticipated merger and resulting lawsuit with Holly.

Depreciation and amortization increased $1.5 million, or 5%, for the year ended December 31, 2003 as compared to 2002 because of increases in capital investment at our Refineries.

The interest expense and other financing costs (excluding costs relating to the 8% Senior Notes issued and redeemed in connection with the terminated Holly merger) of $28.7 million for 2003 increased $1.1 million from $27.6 million in 2002 primarily due to the premium of $1.2 million paid upon redemption of our 9⅛% Senior Notes in December 2003. Average debt outstanding (excluding the 8% Senior Notes) decreased to $236 million for the year ended December 31, 2003 from $246 million for the year ended December 31, 2002.

Interest income (excluding interest income earned on the 8% Senior Notes escrow account) decreased $693,000 from $1.8 million in 2002 to $1.1 million in 2003 due to less cash available to invest and lower interest rates.

The 2003 merger financing termination costs, net were $18.0 million and included interest expense, issue discount, financing issue costs and a 1% redemption premium, net of $752,000 interest income earned on the escrow account, related to the $220.0 million principal 8% Senior Notes. These costs did not include bank facility charges related to the merger.

The provision for income taxes for the year ended December 31, 2003 was $3.0 million on pretax income of $6.2 million (or 47.8%) due to one-time adjustments for permanent book versus tax differences related to 2003 and 2002 expenses and an increase of $280,000 in the income tax provision for 2003 resulting from a true-up of the 2002 tax provision. Our current estimated effective tax rate was 38.26%. Our effective income tax rate for the book provision of income taxes for the year ended December 31, 2002 of 50.8% was also greater than our estimated statutory rate 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.

Liquidity and Capital Resources

Net cash provided by operating activities was $177.9 million during the year ended December 31, 2004 compared to net cash used by operating activities of $6.0 million during the year ended December 31, 2003. Our improved result of operations was the largest contributor to improved cash flow, along with working capital changes.

Working capital changes provided a total of $38.6 million of cash flows in the year ended December 31, 2004 while using $25.9 million of cash flows in the comparable period in 2003. The most significant provider of cash for working capital changes during the year ended December 31, 2004 was the increase in accounts payable of $58.1 million and the increase in accrued liabilities and other of $11.6 million compared to a decrease in accounts payable of $4.3 million and an increase in accrued liabilities and other of only $1.2 million in the 2003 comparable period. The increase in accounts payable was due to the significant increase in crude oil prices during 2004. The increase in accrued liabilities and other was primarily due to $7.0 million for bonuses accrued as of December 31, 2004, which were based on 2004 operating results and will be paid during the first quarter of 2005, compared to no accrued bonuses as of December 31, 2003. The most significant working capital item offsetting the positive cash flow impacts during the year ended December 31, 2004 was an increase in inventories, which utilized cash of $32.9 million in the 2004 period. This was due to higher crude oil prices and resulting higher product prices.

During the year ended December 31, 2004, we made net estimated federal and state income tax payments of approximately $18.4 million ($21.6 million payments, net of a federal tax refund received of $3.2 million).

At December 31, 2004, we had $124.4 million of cash and cash equivalents, working capital of $97.3 million and $182.0 million of borrowing base availability for additional borrowings under our revolving credit facility.

We have a Board of Director approved stock repurchase program to repurchase up to eight million shares of our common stock. Through December 31, 2004, 4,367,366 shares of common stock had been purchased under the stock repurchase program. We did not initiate any additional purchases of common stock under the stock repurchase program in 2004, 2003 nor in 2002. We received 215,599 shares in 2004 and 51,082 shares in 2003 of our common stock, now held as treasury stock, from employees in cashless stock option exercises. We received 112,752 shares in 2004 and 37,556 shares in 2003 of our common stock, now held as treasury stock, from employees to cover withholding taxes on stock option exercises. We also received 48,443 shares in 2004, 24,825 shares in 2003, and 19,041 shares in 2002 of our common stock, now held as treasury stock, from employees to cover withholding taxes on vested restricted stock.

Capital expenditures during the year ended December 31, 2004 were $46.5 million. These 2004 capital expenditures included approximately $19.3 million for the El Dorado Refinery, $26.8 million for the Cheyenne Refinery, and $364,000 of capital for expenditures in our Denver and Houston offices, our asphalt terminal in Nebraska and for our share of crude pipeline projects. The approximately $19.3 million of capital expenditures for our El Dorado Refinery included approximately $6.0 million to begin the ultra low sulfur diesel compliance project, as well as operational, payout, safety, administrative, environmental and optimization projects. The approximately $26.8 million of capital expenditures for our Cheyenne Refinery included $7.8 million of capital incurred due to the Cheyenne Refinery coker fire, $6.1 million incurred on the low sulfur gasoline project, $250,000 to begin the ultra low sulfur diesel compliance project, as well as environmental, operational, safety, administrative and payout projects.

Compliance with the upcoming ultra low sulfur diesel requirements at our Refineries will require additional capital expenditures through mid-2006. The total capital, including capitalized interest that we will utilize to comply with the regulations is estimated to be approximately $14.0 million at the Cheyenne Refinery and approximately $106.5 million at the El Dorado Refinery. The expenditures for the ultra low sulfur diesel projects for 2004 were $250,000 at the Cheyenne Refinery and $6.0 million at the El Dorado Refinery. The remaining costs for the ultra low sulfur diesel projects at both Refineries are expected to be spent in 2005 and 2006. The recently enacted “American Jobs Creation Act of 2004” will allow us, as a small business refiner, to deduct for federal income tax purposes 75% of the qualified costs related to these low sulfur diesel expenditures in the years incurred as well as provide tax credits based on the resulting production of ultra low sulfur diesel up to 25% of the remaining qualified costs.

Capital expenditures aggregating approximately $146.8 million are currently planned for 2005, and include $118.1 million at our El Dorado Refinery, $28.2 million at our Cheyenne Refinery, and $500,000 for capital expenditures in our Denver and Houston offices, our asphalt terminal in Nebraska and for our share of crude pipeline projects. The $118.1 million of planned capital expenditures for our El Dorado Refinery includes approximately $90.5 million for the ultra low sulfur diesel project discussed above, nearly $3.0 million of capital on the FCCU, to be done in conjunction with the turnaround, as well as environmental, operational, safety, administrative and payout projects. The $28.2 million of planned capital expenditures for our Cheyenne Refinery includes approximately $9.0 million for the ultra low sulfur diesel project discussed above, as well as environmental, operational, safety, administrative and payout projects. Our 2005 capital expenditures will be funded with cash generated by our operations and the utilization of a portion of our existing cash balance.

As of December 31, 2004, we had received payments of $5.0 million from our insurers for reimbursement of costs related to the coker fire at the Cheyenne Refinery. Additional proceeds of $2.1 million were received in early 2005 and were accrued as of December 31, 2004.

As of December 31, 2004, we had $150.0 million principal of total consolidated debt, of which all was long-term debt, as we had no borrowings under our revolving credit facility. We also had $12.2 million outstanding letters of credit under our revolving credit facility. We were in compliance with the financial covenants of our revolving credit facility as of December 31, 2004. We had shareholders’ equity of $240.1 million as of December 31, 2004. Operating cash flows are affected by crude oil and refined product prices and other risks as discussed in “Item 7A. Quantitative and Qualitative Disclosures About Market Risks.”

Under the provisions of the purchase agreement with Shell 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 $60.0 million per year of the El Dorado Refinery’s annual revenues less material costs and operating costs, other than depreciation. The total amount of these contingent payments is capped at $40.0 million, with an annual cap of $7.5 million. Based on 2003 results, no payment was necessary in 2004. A payment of $7.5 million was paid in early 2005, based on 2004 results, and was accrued as of December 31, 2004. Such contingency payments are recorded as additional acquisition costs. Including the payment we made in early 2005, we have paid a total of $15.0 million to date for contingent earn-out payments.

Our Board of Directors declared quarterly cash dividends of $.05 per share in December 2003, March 2004, and June 2004 , which were paid in January 2004, April 2004, and July 2004, respectively. Our Board of Directors declared quarterly cash dividends of $.06 per share in September 2004 and December 2004, which was paid in October 2004 and January 2005, respectively. The total cash required for the dividend declared in December 2004 was approximately $1.6 million and was accrued at year-end.

On October 1, 2004, we issued $150 million principal amount of 6⅝% Senior Notes due 2011. The 6⅝% Notes, which mature on October 1, 2011, were issued at par, and we received net proceeds (after underwriting fees) of $147.2 million. Interest is paid semi-annually. The 6⅝% Notes are redeemable, at our option, at 103.313% after October 1, 2007, declining to 100% in 2010. Prior to October 1, 2007, we may at our option redeem the 6⅝% Notes at a defined make-whole amount, plus accrued and unpaid interest. We used a portion of the net proceeds from this offering to fund a tender offer and consent solicitation for $64.9 million principal of our 11¾% Senior Notes in October 2004 and redeemed on November 15, 2004, the remaining $105.6 million outstanding principal of our 11¾% Senior Notes. Other cash expenditures related to the redemption included $10.4 million of premium and $9.1 million of accrued interest payments made at the time of consummation of the tender offer and redemption. These actions will reduce our interest expense in future years by $10.1 million per year.

Contractual Cash Obligations

The table on the following page lists the contractual cash obligations we have by period. These items include our long-term debt based on their maturity dates, our operating lease commitments, purchase obligations and other long-term liabilities.

Our operating leases include building, equipment, aircraft and vehicle leases, which expire from 2005 through 2011, as well as an operating sublease for the use of the cogeneration facility at our El Dorado Refinery. The non-cancelable sublease, entered into in connection with the acquisition of our El Dorado Refinery in 1999, expires in 2016 with an option that allows us to renew the sublease for an additional eight years.

Purchase obligations include agreements to purchase goods or services that are enforceable and legally binding and that specify terms, including fixed or minimum quantities to be purchased, fixed, minimum or variable price provisions, and the approximate timing of the transaction. Purchase obligations exclude agreements that are cancelable without penalty. We have a five-year crude oil supply agreement, which began in 2003, with Baytex Marketing Ltd. (“Baytex”), a Canadian crude oil producer. This agreement provides for us to purchase 20,000 bpd of a Lloydminster crude oil blend, a heavy Canadian crude, at a price 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 Express Pipeline tariff, less $0.25 per barrel. We have two contracts that obligate us for crude oil pipeline capacity into 2015 on the Express Pipeline from Hardisty, Alberta to Guernsey, Wyoming from which we then have pipeline access to take the crude oil to our Cheyenne Refinery. The first contract, which began in 1997, is for 15 years and for an average of 13,800 bpd over that 15-year period. We were allowed to assign a portion of our capacity in earlier years for additional capacity in later years with this first contract. Our crude oil supply agreement with Baytex includes an assignment of a portion of our pipeline capacity obligation to it. In December 2003, we entered into an expansion capacity agreement on the Express Pipeline for an additional 10,000 bpd of crude oil starting in April 2005 through 2015. Of the additional 10,000 bpd, we assigned 4,000 bpd to another party starting in April 2005 through March 2006. Our remaining Express Pipeline commitments range from a high of 32,600 bpd in 2005, then reducing to 23,800 bpd in 2006 through early 2012, and then reducing to 10,000 bpd through 2015. The amounts shown below for transportation, terminalling and storage contractual obligations are net of $25.0 million, the approximate cost of the pipeline capacity assigned to other parties for the initial term of that agreement. The amounts shown below for transportation, terminalling and storage contractual obligations also include our anticipated commitments on the Spearhead pipeline. See Note 10 in the “Notes to Consolidated Financial Statements” for more information on these commitments.

Contractual Cash Obligations	Payments Due by Period
	Total		Within 1 Year		Within 2-3 years		Within 4-5 years		After 5 years
	(in thousands)
Long-term debt (1)	$	150,000	$	-	$	-	$	-	$	150,000
Operating leases		96,924		12,679		21,923		19,394		42,928
Purchase obligations:
Baytex crude supply (2)		741,511		246,856		494,655		-		-
Other crude supply, feedstocks and natural gas (2)		276,074		275,074		828		172		-
Transportation, terminalling and storage		161,686		16,073		30,703		37,006		77,904
Ultra low sulfur diesel refinery projects (3)		69,765		63,395		6,370		-		-
Other goods and services		6,088		6,008		80		-		-
Total purchase obligations		1,255,124		607,406		532,636		37,178		77,904
Long-term accrued turnaround cost		13,153		-		7,659		5,350		144
Pension funding requirement (4)		1,173		1,173		-		-		-
Other long-term liabilities		2,511		-		660		351		1,500
Total contractual cash	$	1,518,885	$	621,258	$	562,878	$	62,273	$	272,476

(1)	Cash requirements for interest on the long-term debt are approximately $9.9 million per year.

(2)

Baytex crude supply and other crude supply, feedstocks and natural gas future obligations were calculated using current market prices and/or prices established in applicable contracts. Of these obligations, $227.7 million relate to January and February 2005 feedstock and natural gas requirements of the Refineries.

(3)	The amounts for ultra low sulfur diesel refinery projects reflected here relate to our commitments as of December 31, 2004, not the total estimated costs of the projects. See “Environmental” under “Government Regulation” in Part I, Item I of this Form 10-K for total estimated costs of the projects.

(4)

Includes our estimated pension funding requirement in 2005 to our cash balance pension plan. Funding requirements for remaining years will be based on actuarial estimates and actual experience. Our retiree health care plan is unfunded. Future payments for retiree health care benefits are estimated for the next ten years in Note 9 “Employee Benefit Plans” in the “Notes to Consolidated Financial Statements.”

Off-Balance Sheet Arrangements

We only have one interest in an unconsolidated entity (See Note 1 “Nature of Operations” in the “Notes to Consolidated Financial Statements”). Neither Frontier nor this entity participates in any transactions, agreements or other contractual arrangements, which would result in any off-balance sheet liabilities, or other arrangements to us.

Environmental

See “Environmental” in Note 10 in the “Notes to Consolidated Financial Statements.”

Critical Accounting Policies

Turnarounds. The costs for turnarounds (scheduled and required shutdowns of refinery operating units for significant overhaul and refurbishment) are ratably accrued over the period from the prior turnaround to the next scheduled turnaround. Since utilizing this policy relies on estimated costs for the next turnaround, adjustments occur as the estimate changes or even when the turnaround is in progress should more or less extensive work be necessary than was anticipated. These accruals are included in our Consolidated Balance Sheets in the accrued turnaround cost and long-term accrued turnaround cost. The turnaround accrual, any turnaround costs in excess of accrual incurred at the time of turnaround, or reductions of expenses when the actual costs are less than the estimate are included in Refinery operating expenses, excluding depreciation in our Consolidated Statements of Income. Turnaround costs include contract services, materials and rental equipment.

Inventories. Inventories of crude oil, unfinished products and all finished products are recorded at the lower of cost on a FIFO basis or market. Crude oil includes both domestic and foreign crude oil volumes at its cost and associated freight and other cost. Unfinished products (work in process) include any crude oil that has entered into the refining process, and other feedstocks that are not finished as far as refining operations are concerned. These include unfinished gasoline and diesel, blendstocks and other feedstocks. Finished product inventory includes saleable gasoline, diesel, jet fuel, chemicals, asphalt and other finished products. Unfinished and finished products inventory values have components of raw material, the associated raw material freight and other costs, and direct refinery operating expense allocated when refining begins relative to their proportionate market values. The FIFO method of accounting for inventories sometimes results in Frontier recognizing substantial gains (in periods of rising prices) or losses (in periods of falling prices) from our inventories of crude oil and products. While we believe that this accounting method more accurately reflects the results of our operations, since many other refining companies instead utilize the last-in, first-out (“LIFO”) method of accounting for inventories, comparison of our results to other refineries must take into account the impact of the inventory accounting differences.

Stock-based Compensation. 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 Frontier’s common stock at the grant date over the amount the employee must pay to acquire the stock. We have a stock option plan which authorizes the granting of options to employees to purchase shares. 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. No compensation expense is recorded. See “New Accounting Pronouncements,” under Note 2 in the “Notes to Consolidated Financial Statements” for a discussion of FAS No. 123(R) which will require a change in our method of accounting for stock based compensation in 2005. This will require us to record compensation expense based on the fair value of the awards at the grant date and will result in increased expenses; however, it is not expected to have a material effect on our financial statements.

New Accounting Pronouncements

See “New Accounting Pronouncements” under Note 2 in the “Notes to Consolidated Financial Statements.” No new pronouncements are expected to have a material impact on our financial statements.

Market Risks

See the Item 7A “Quantitative and Qualitative Disclosure about Market Risk” and Notes 2 and 12 in the “Notes to Consolidated Financial Statements” under “Price Risk Management Activities” for a discussion of our various price risk management activities. When we make the decision to manage our price exposure, we neither incur losses from negative price changes nor do we obtain the benefit of positive price changes.

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, purchases of foreign crude oil and consumption of natural gas in the refining process or to fix margins on certain future production. Gains or losses on commodity derivative contracts accounted for as hedges are recognized in the Consolidated Statements of Income as “Raw material, freight and other costs” or “Refinery operating expenses, excluding depreciation” when the associated transactions are consummated, while gains and losses on transactions accounted for using mark-to-market accounting are reflected in “Other revenues” in the Consolidated Statements of Income at each period end. See “Price Risk Management Activities” under Notes 2 and 12 in the “Notes to Consolidated Financial Statements.”

Item 8. Financial Statements and Supplementary Data

FRONTIER OIL CORPORATION AND SUBSIDIAIRES
CONSOLIDATED STATEMENTS OF INCOME

	Years Ended December 31,
	2004			2003			2002
	(in thousands except per share data)
Revenues:
Refined products	$	2,871,592		$	2,169,551		$	1,812,613
Other		(9,876	)		952			1,137
		2,861,716			2,170,503			1,813,750

Costs and Expenses:
Raw material, freight and other costs		2,432,461			1,860,795			1,562,613
Refinery operating expenses, excluding depreciation		219,781			200,383			178,295
Selling and general expenses, excluding depreciation		29,893			19,890			17,611
Merger termination and legal costs		3,824			8,739			-
Depreciation and amortization		32,208			28,832			27,332
		2,718,167			2,118,639			1,785,851

Operating income		143,549			51,864			27,899

Interest expense and other financing costs		37,573			28,746			27,613
Interest income		(1,716	)		(1,109	)		(1,802	)
Gain on involuntary conversion of assets		(4,411	)		-			-
Merger financing termination costs, net		-			18,039			-
		31,446			45,676			25,811

Income before income taxes		112,103			6,188			2,088
Provision for income taxes		42,339			2,956			1,060
Net income	$	69,764		$	3,232		$	1,028


Basic earnings per share of common stock	$	2.62		$	0.12		$	0.04

Diluted earnings per share of common stock	$	2.55		$	0.12		$	0.04


The accompanying notes are an integral part of these consolidated financial statements.

FRONTIER OIL CORPORATION AND SUBSIDIAIRES
CONSOLIDATED BALANCE SHEETS
	December 31,
	2004			2003
	(in thousands except share data)
ASSETS
Current assets:
Cash and cash equivalents	$	124,389		$	64,520
Trade receivables, net of allowance of $500 in both years		78,733			86,519
Other receivables		9,531			1,834
Inventory of crude oil, products and other		156,934			123,999
Deferred tax assets		6,748			5,967
Other current assets		2,344			1,974
Total current assets		378,679			284,813
Property, plant and equipment, at cost:
Refineries, terminal equipment and pipelines		542,356			489,502
Furniture, fixtures and other equipment		8,755			6,142
		551,111			495,644
Less – accumulated depreciation and amortization		204,348			173,196
		346,763			322,448
Deferred financing costs, net of amortization
of $594 and $2,484 in 2004 and 2003, respectively		4,328			4,009
Commutation account		16,438			19,550
Prepaid insurance, net of amortization		4,542			6,593
Other intangible asset, net of amortization of $53 in 2004		1,527			-
Other assets		2,123			4,884
Total assets	$	754,400		$	642,297

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	238,991		$	177,235
Revolving credit facility		-			45,750
Accrued turnaround cost		15,373			10,412
Accrued interest		2,487			2,513
Accrued El Dorado Refinery contingent earn-out payment		7,500			-
Accrued liabilities and other		17,067			10,282
Total current liabilities		281,418			246,192

Long-term debt		150,000			168,689
Long-term accrued turnaround cost		13,153			16,229
Post-retirement employee liabilities		23,139			20,725
Other long-term liabilities		2,511			-
Deferred compensation liability and other		1,516			4,255
Deferred income taxes		42,550			16,930

Commitments and contingencies

Shareholders’ equity:
Preferred stock, $100 par value, 500,000 shares authorized,
no shares issued		-			-
Common stock, no par, 50,000,000 shares authorized, 31,669,524 and
30,643,549 shares issued in 2004 and 2003, respectively		57,607			57,504
Paid-in capital		119,525			106,443
Retained earnings		111,468			47,614
Accumulated other comprehensive loss, net of income taxes
of $739 and $573, in 2004 and 2003, respectively		(1,197	)		(924	)
Treasury stock, at cost, 4,638,467 and 4,264,673
shares at December 31, 2004 and 2003, respectively		(47,024	)		(39,914	)
Deferred employee compensation		(266	)		(1,446	)
Total shareholders’ equity		240,113			169,277
Total liabilities and shareholders’ equity	$	754,400		$	642,297


The accompanying notes are an integral part of these consolidated financial statements.

FRONTIER OIL CORPORATION AND SUBSIDIAIRES
CONSOLIDATED STATEMENTS OF CASH FLOWS

	Years Ended December 31,
	2004			2003			2002
	(in thousands)
Cash flows from operating activities:
Net income	$	69,764		$	3,232		$	1,028
Depreciation and amortization		32,208			28,832			27,332
Deferred income taxes		25,005			2,655			1,149
Income tax benefits of stock compensation		5,168			-			-
Deferred finance cost and bond discount amortization		5,484			10,642			2,033
Deferred employee compensation amortization		1,180			1,386			907
Gain on involuntary conversion of assets		(4,411	)		-			-
Long-term commutation account and prepaid insurance		3,712			(26,566	)		-
Amortization of long-term prepaid insurance		1,451			423			-
(Decrease) increase allowance for doubtful trade and note receivables		-			(186	)		800
Other		(281	)		(501	)		(199	)
Changes in components of working capital from operations:
Increase in derivative assets		(354	)		-			-
Decrease (increase) in trade, note and other receivables		2,231			(4,577	)		(22,178	)
Increase in inventory		(32,935	)		(18,839	)		(17,190	)
(Increase) decrease in other current assets		(16	)		536			(267	)
Increase (decrease) in accounts payable		58,138			(4,282	)		64,004
Increase (decrease) in accrued liabilities and other		11,555			1,240			(6,597	)
Net cash provided by (used in) operating activities		177,899			(6,005	)		50,822

Cash flows from investing activities:
Additions to property, plant and equipment		(46,502	)		(33,677	)		(29,517	)
Net proceeds from insurance - involuntary conversion claim		3,395			-			-
Proceeds from sale of assets		-			304			-
Other investments		-			(927	)		(100	)
El Dorado Refinery contingent earn-out payment		-			-			(7,500	)
Net cash used in investing activities		(43,107	)		(34,300	)		(37,117	)

Cash flows from financing activities:
Proceeds from issuance of 6⅝% Senior Notes		150,000			-			-
Proceeds from issuance of 8% Senior Notes, net of discount		-			218,143			-
Repurchases of debt:
11¾% Senior Notes		(170,449	)		-			-
8% Senior Notes		-			(220,000	)		-
9⅛% Senior Notes		-			(39,475	)		(1,090	)
(Repayments) proceeds of revolving credit facility, net		(45,750	)		45,750			-
Debt issue costs and other		(3,954	)		(7,136	)		-
Proceeds from issuance of common stock		3,923			1,441			1,702
Purchase of treasury stock		(3,029	)		(1,075	)		(787	)
Dividends paid		(5,664	)		(5,187	)		(5,161	)
Net cash used in financing activities		(74,923	)		(7,539	)		(5,336	)
Increase (decrease) in cash and cash equivalents		59,869			(47,844	)		8,369
Cash and cash equivalents, beginning of period		64,520			112,364			103,995
Cash and cash equivalents, end of period	$	124,389		$	64,520		$	112,364


The accompanying notes are an integral part of these consolidated financial statements.

FRONTIER OIL CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY AND STATEMENTS OF COMPREHENSIVE INCOME
(in thousands except share data)
	Common Stock												Treasury Stock												Total
	Number of Shares issued		Amount		Paid-in Capital		Compre-hensive Income			Retained Earnings			Number of Shares			Amount			Deferred Employee Compensation			Accumulated Other Comprehensive Income (Loss)			Number of Shares			Amount
December 31, 2001		30,059,574	$	57,446	$	98,046				$	53,764			(4,240,937	)	$	(38,163	)	$	(1,634	)	$	(255	)		25,818,637		$	169,204
Shares issued under:
Stock option plans		230,750		23		1,543					-			-			-			-			-			230,750			1,566
Directors stock plan		-		-		-					-			3,000			13			-			-			3,000			13
Resricted stock issuances, net		-		-		1,544					-			105,768			561			(2,105	)		-			105,768			-
Shares received 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
Shares issued under:
Stock option plans		353,225		35		2,286					-			-			-			-			-			353,225			2,321
Shares received under:
Stock option plans		-		-		-					-			(88,638	)		(1,527	)		-			-			(88,638	)		(1,527	)
Restricted stock plan		-		-		-					-			(24,825	)		(428	)		-			-			(24,825	)		(428	)
Comprehensive income:
Net income		-		-		-	$	3,232			3,232			-			-			-			-			-			3,232
Other comprehensive income:
Minimum pension liability, net of tax of $201								(326	)
Other comprehensive income								(326	)														(326	)		-			(326	)
Comprehensive income							$	2,906
Income tax benefits of stock compensation		-		-		1,600					-			-			-			-			-			-			1,600
Deferred employee compensation:
Amortization/vested shares		-		-		-					-			-			-			1,386			-			-			1,386
Dividends declared		-		-		-					(5,239	)		-			-			-			-			-			(5,239	)
December 31, 2003		30,643,549	$	57,504	$	106,443				$	47,614			(4,264,673	)	$	(39,914	)	$	(1,446	)	$	(924	)		26,378,876		$	169,277
Shares issued under:
Stock option plans		1,025,975		103		7,914					-			-			-			-			-			1,025,975			8,017
Directors stock plan		-		-		-					-			3,000			13			-			-			3,000			13
Shares received under:
Stock option plans		-		-		-					-			(328,351	)		(6,222	)		-			-			(328,351	)		(6,222	)
Restricted stock plan		-		-		-					-			(48,443	)		(901	)		-			-			(48,443	)		(901	)
Comprehensive income:
Net income		-		-		-	$	69,764			69,764			-			-			-			-			-			69,764
Other comprehensive income:
Minimum pension liability, net of tax of $166								(273	)
Other comprehensive income								(273	)														(273	)		-			(273	)
Comprehensive income							$	69,491
Income tax benefits of stock compensation		-		-		5,168					-			-			-			-			-			-			5,168
Deferred employee compensation:
Amortization/vested shares		-		-		-					-			-			-			1,180			-			-			1,180
Dividends declared		-		-		-					(5,910	)		-			-			-			-			-			(5,910	)
December 31, 2004		31,669,524	$	57,607	$	119,525				$	111,468			(4,638,467	)	$	(47,024	)	$	(266	)	$	(1,197	)		27,031,057		$	240,113


The accompanying notes are an integral part of these consolidated financial statements

FRONTIER OIL CORPORATION AND SUBSIDIARIES

Notes To Consolidated Financial Statements

For The Years Ended December 31, 2004, 2003 and 2002

1.	Nature of Operations

The financial statements include the accounts of Frontier Oil Corporation, a Wyoming corporation, and its wholly-owned subsidiaries, collectively referred to as Frontier or the Company. The Company is an energy company engaged in crude oil refining and wholesale marketing of refined petroleum products (the “refining operations”).

The Company operates refineries (“the Refineries”) in Cheyenne, Wyoming and El Dorado, Kansas. The Company also owns FGI, LLC, an asphalt terminal and storage facility in Grand Island, Nebraska, whose activities have been included in the consolidated financial statements since December 1, 2003 when the Company increased its ownership from 50% to 100%. This additional investment is reflected on the 2003 Consolidated Statements of Cash Flows under “Other investments” in the cash flows from investing activities section. Previously, the Company’s 50% interest in FGI, LLC was accounted for using the equity method of accounting. The Company also owns a 34.72% interest in a crude oil pipeline in Wyoming and a 50% interest in two crude oil tanks in Guernsey, Wyoming, both of which are accounted for as undivided interests. Each asset, liability, revenue and expense is reported on a proportionate gross basis. In addition, the equity method of accounting is utilized for the Company’s 25% interest in 8901 Hangar, Inc., a company which leases and operates a private airplane hangar. The Company’s investment in 8901 Hangar, Inc. was $102,000 and $108,000 at December 31, 2004 and 2003, respectively, and is included in “Other assets” on the Consolidated Balance Sheets. All of the operations of the Company are in the United States, with its marketing efforts focused in the Rocky Mountain and Plains States regions of the United States. The Company purchases crude oil to be refined and markets the refined petroleum products produced, including various grades of gasoline, diesel fuel, jet fuel, asphalt, chemicals and petroleum coke. The operations of refining and marketing of petroleum products are considered part of one reporting segment.

2.	Significant Accounting Policies

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

Property, plant and equipment additions are recorded at cost and depreciated using the straight-line method over the estimated useful lives, which range as follows:

Refinery buildings and equipment	5 to 50 years
Pipelines and pipeline improvements	5 to 20 years
Furniture, fixtures and other	3 to 10 years

The Company reviews long-lived assets for impairments under the Financial Accounting Standards Board (“FASB”) Statement of Financial Accounting Standard (“FAS”) No. 144, “Accounting for the Impairment or Disposal of Long-lived Assets” whenever events or changes in circumstances indicate that the carrying value of an asset may not be recoverable. If the undiscounted future cash flow of an asset to be held and used in operations is less than the carrying value, the Company would recognize a loss for the difference between the carrying value and fair value. When fair values are not available, the Company estimates fair value based on a discounted cash flow analysis.

The Company capitalizes interest on the long-term construction of significant assets. Interest capitalized for the years ended December 31, 2004, 2003 and 2002 was $65,000, $586,000 and $342,000, respectively.

Turnarounds

Normal maintenance and repairs are expensed as incurred. The costs for turnarounds (scheduled and required shutdowns 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 Sheets in “Accrued turnaround cost” and “Long-term accrued turnaround cost.” The turnaround accrual expenses are included in “Refinery operating expenses, excluding depreciation” in the Company’s Consolidated Statements of Income. Turnaround costs include contract services, materials and rental equipment. Major improvements are capitalized, and the material 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 that has entered into the refining process, and other feedstocks that are not finished as far as refining operations are concerned. These include unfinished gasoline and diesel, blendstocks and other feedstocks. Finished product inventory includes saleable gasoline, diesel, jet fuel, chemicals, asphalt and other finished products. Unfinished and finished products inventory values have components of raw material, the associated raw material freight and other costs, and direct refinery operating expense allocated when refining begins relative to their proportionate market values. Refined product exchange transactions are considered asset exchanges with deliveries offset against receipts (See “New Accounting Pronouncements” below for a discussion of Emerging Issues Task Force (“EITF”) Issue No. 04-13). The net exchange balance is included in inventory. Inventories of materials and supplies and process chemicals are recorded at the lower of average cost or market. Crude oil inventories, unfinished product inventories and finished product inventories are used to secure financing for operations under the Company’s revolving credit facility (See Note 6).

Components of Inventory

	December 31,
	2004		2003
	(in thousands)
Crude oil	$	52,643	$	39,374
Unfinished products		45,957		31,240
Finished products		40,835		34,712
Process chemicals		3,210		5,175
Repairs and maintenance supplies and other		14,289		13,498
	$	156,934	$	123,999

Prepaid Insurance

The Company expenses the amounts paid for insurance policies over the term of the policy. Prepaid insurance related to policies with terms in the range of one year are included in “Other current assets” on the Consolidated Balance Sheets. The loss mitigation insurance premium and related expenses (see “Litigation - Beverly Hills Lawsuits” under Note 10) totaling $6.4 million and $7.0 million at December 31, 2004 and 2003, respectively, are in “Prepaid insurance” in the long-term asset portion of the Consolidated Balance Sheets and are reflected net of accumulated amortization as of each balance sheet date. Of the total indemnity premium, $1.4 million related to year one of the policy, and was amortized to expense over the one-year period which began October 1, 2003. The remaining $4.3 million of the indemnity premium is being amortized over four years beginning October 1, 2004. The administrative fee and California insurance tax totaling $673,000 ($1.3 million at December 31, 2003 less $600,000 of insurance tax refunded in 2004) is being amortized to expense over the five-year policy term, which began October 1, 2003. Accumulated amortization was $1.9 million and $423,000 at December 31, 2004 and 2003, respectively.

Income Taxes

The Company accounts for income taxes under the provisions of FAS No. 109, “Accounting for Income Taxes.” FAS No. 109 requires the asset and liability approach for accounting for income taxes. Under this approach, deferred tax assets and liabilities are recognized based on anticipated future tax consequences attributable to differences between 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 that improve a property’s pre-existing condition, and costs that prevent future environmental contamination are capitalized. Remediation costs related to environmental damage resulting from operating activities subsequent to acquisition are expensed. Liabilities for these expenditures are recorded when it is probable that obligations have been incurred and the amounts can be reasonably estimated.

Price Risk Management Activities

The Company, at times, enters into commodity derivative contracts to manage its price exposure to its inventory positions, 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 that 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 under FAS No. 133, “Accounting for Derivative Instruments and Hedging Activities.” As such, gains or losses on commodity derivative contracts accounted for as hedges are recognized in “Raw material, freight and other costs” or “Refinery operating expenses, excluding depreciation” 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

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. No compensation cost for stock options was recognized in the Consolidated Statements of Income for the years ended December 31, 2004, 2003 and 2002. Had compensation costs been determined based on fair value at the grant dates for awards made in 2004, 2003, 2002 and prior years for the vested portions of the awards in each of the years 2004, 2003 and 2002, the Company’s net income (loss) and EPS would have been the pro forma amounts listed in the following table for the years ended December 31, 2004, 2003 and 2002:

	2004			2003			2002
	(in thousands, except per share amounts)
Net income as reported	$	69,764		$	3,232		$	1,028
Pro forma compensation expense, net of tax		(2,029	)		(3,070	)		(2,540	)
Pro forma net income (loss)	$	67,735		$	162		$	(1,512	)
Basic EPS:
As reported	$	2.62		$	0.12		$	0.04
Pro Forma		2.54			0.01			(0.06	)
Diluted EPS:
As reported	$	2.55		$	0.12		$	0.04
Pro Forma		2.47			0.01			(0.06	)

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 2004, 2003 and 2002, respectively: risk-free interest rates of 2.97%, 2.75% and 2.76%; expected volatilities of 47.80%, 50.50% and 51.40%; expected lives of 5.0 years, 5.0 years and 5.0 years; and dividend yields of 1.10%, 1.27% and 1.27%.

Compensation costs of $1.2 million, $1.4 million and $907,000 related to restricted stock awards was recognized for the years ended December 31, 2004, 2003 and 2002, respectively. See “New Accounting Pronouncements” below for a discussion of FAS No. 123(R), which will require a change in the Company’s method of accounting for stock-based compensation in 2005.

Asset Retirement Obligations

The Company accounts for asset retirement obligations as required under FAS No. 143, “Accounting for Retirement Asset Obligations.” FAS No. 143 requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred, with the associated asset retirement costs being capitalized as a part of the carrying amount of the long-lived asset. FAS No. 143 also includes disclosure requirements that provide a description of asset retirement obligations and reconciliation of changes in the components of those obligations. The Company has asset retirement obligations related to its Refineries and certain other assets as a result of environmental and other legal requirements. The Company is not required to perform the obligations in some circumstances until it permanently ceases operations of the long-lived assets and therefore, considers the useful life of the Refineries and certain other assets indeterminable. Accordingly, the Company cannot calculate an associated asset retirement obligation at this time. The Company will measure and recognize the fair value of its asset retirement obligations at such time as the useful life is determinable, or in the event that the Company decides to cease the use of a particular refinery, an asset retirement obligation liability would be recorded at that time.

Principles of Consolidation

The Consolidated Financial Statements include the accounts of Frontier Oil Corporation and all majority-owned subsidiaries, as well as the Company’s undivided interests in a crude oil pipeline and crude oil tanks. All intercompany transactions and balances are eliminated in consolidation.

Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Cash Equivalents

Highly liquid investments with maturity, when purchased, of three months or less are considered to be cash equivalents. Cash equivalents were $115.3 million and $56.8 million at December 31, 2004 and 2003, respectively.

Supplemental Cash Flow Information

Cash payments for interest, excluding capitalized interest, during 2004, 2003 and 2002 were $20.0 million, $33.5 million and $24.5 million, respectively. Cash payments for income taxes during 2004, 2003 and 2002 were $21.6 million, $626,000 and $83,000, respectively.

New Accounting Pronouncements

In December 2004, the FASB issued FAS No. 123(R), “Share-Based Payment,” an amendment of FASB Statements No. 123 and 95. FAS No. 123(R) replaces FAS No. 123, “Accounting for Stock-Based Compensation,” and supersedes APB Opinion No. 25, “Accounting for Stock Issued to Employees.” This statement requires companies to recognize the fair value of stock options and other stock-based compensation to employees prospectively beginning with fiscal periods beginning after June 15, 2005. This means that Frontier will be required to implement FAS No. 123(R) no later than the quarter beginning July 1, 2005. The Company currently measures stock-based compensation in accordance with APB Opinion No. 25 as discussed above. The Company anticipates adopting the modified prospective method of FAS No. 123(R) on July 1, 2005. Based on the stock options outstanding as of December 31, 2004, the Company will recognize compensation expense in future Consolidated Statements of Income of approximately $800,000, $350,000, and $20,000 in the years ended December 31, 2005, 2006 and 2007, respectively. The impact on the Company’s financial condition or results of operations will depend on the number and terms of stock options outstanding on the date of change, as well as future options that may be granted. See “Stock-based Compensation” earlier in this Note for the pro forma impact that the fair value method would have had on the Company’s net income for each of the years ended December 31, 2004, 2003 and 2002.

In December 2004, the FASB issued FAS No. 153, “Exchanges of Nonmonetary Assets,” an amendment of APB Opinion No. 29. This statement was the result of a joint effort by the FASB and the International Accounting Standards Board (“IASB”) to improve financial reporting by eliminating certain narrow differences between their existing standards. One such difference was the exception from fair value measurement in APB Opinion No. 29, “Accounting for Nonmonetary Transactions,” for nonmonetary exchanges of similar productive assets. FAS No. 153 replaces this exception with a general exception from fair value measurement for exchanges of nonmonetary assets that do not have commercial substance. A nonmonetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. This statement shall be applied prospectively and is effective for nonmonetary asset exchanges occurring in fiscal periods beginning after June 15, 2005. The Company does not believe that the adoption of FAS No. 153 will have a material effect on its financial statements.

In November 2004, the FASB issued FAS No. 151, “Inventory Costs, an amendment of Accounting Research Bulletin (“ARB”) No. 43, Chapter 4.” The FASB issued FAS No. 151 to clarify the accounting for abnormal amounts of idle facility expense, freight, handling costs and wasted material (spoilage). This statement was a result of joint effort by the FASB and IASB to improve financial reporting by eliminating certain narrow differences between their existing standards. One such difference was the accounting for abnormal inventory costs. Both the FASB and IASB agree that abnormal expenses should be recognized in the period in which they are incurred; however wording in ARB No. 43, Chapter 4, “Inventory Pricing,” led to inconsistent application of that principle. As such, this statement requires that these items be recognized as current period charges regardless of whether they meet the “so abnormal” criterion outlined in ARB No. 43. FAS No. 151 also introduces the concept of “normal capacity” and requires the allocation of fixed production overheads to inventory based on the normal capacity of the production facilities. Unallocated overheads must be recognized as an expense in the period in which they are incurred. This statement is effective for inventory costs incurred during fiscal years beginning after June 15, 2005. The Company does not believe that the adoption of FAS No. 153 will have a material effect on its financial statements.

In January 2003, the FASB issued FASB Interpretation No. 46, “Consolidation of Variable Interest Entities” (FIN 46). FIN 46 clarifies the application of Accounting Research Bulletin No. 51, “Consolidated Financial Statements” to certain entities in which equity investors do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated support from other parties. FIN 46 requires existing unconsolidated variable interest entities to be consolidated by their primary beneficiaries if the entities do not effectively disperse risks among parties involved. All companies with interests in variable interest entities created after January 31, 2003 are required to apply the provisions of FIN 46 to those entities immediately. FIN 46 was effective for the first fiscal year or interim period beginning after December 15, 2003, for variable interest entities created before February 1, 2003. The Company adopted FIN 46 on January 1, 2004, and the adoption had no effect on its financial statements.

In December 2004, the FASB staff issued FASB Staff Position (“FSP”) No. FAS 109-1, “Application of FASB Statement No. 109, Accounting for Income Taxes, to the Tax Deduction on Qualified Production Activities Provided by the American Jobs Creation Act of 2004” to provide guidance on the application of FAS No. 109 to the provision within the “American Jobs Creation Act of 2004” that provides tax relief to U.S. domestic manufacturers. See Note 7 for additional information and discussion of this FSP.

The EITF of the FASB is currently considering Issue No. 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty.” This Issue addresses accounting issues that arise when one company both sells inventory to and buys inventory from another company in the same line of business, specifically, when it is appropriate to measure purchases and sales of inventory at fair value and record them in cost of sales and revenues and when they should be recorded as an exchange measured at the book value of the item sold. The Company has certain crude oil procurement and product exchange transactions which it accounts for on a net cost basis. Should the EITF reach a consensus on this Issue, the Company does not believe that it will have any impact on its revenues or cost of sales.

3.	Cheyenne Refinery Fire

On January 19, 2004, a fire occurred in the furnaces of the coking unit at the Cheyenne Refinery. The coker was out of service for approximately one month. The “Gain on involuntary conversion of assets” in the Consolidated Statement of Income for the year ended December 31, 2004 represents the settlement proceeds of $7.1 million from the Company’s insurers, less $1.6 million of expenses related to clean-up costs and $1.1 million of property, plant and equipment written off due to the fire. Insurance proceeds of $5.0 million (of the total $7.1 million), had been received as of December 31, 2004, and the remaining $2.1 million was accrued as a receivable as of December 31, 2004, and was received in early 2005.

4.	Holly Merger Agreement and Litigation

On March 31, 2003, the Company announced that it had entered into an agreement with Holly Corporation (“Holly”) pursuant to which the two companies would merge. On August 20, 2003, Frontier announced that Holly had advised the Company that it was not willing to proceed with the merger agreement on the agreed terms. As a result, the Company filed suit for damages in the Delaware Court of Chancery. On September 2, 2003, Holly filed an answer and counterclaims, denying the Company’s claims, asserting that Frontier repudiated the merger agreement by filing the Delaware lawsuit, and claiming among other things that the Beverly Hills, California litigation caused the Company to be in breach of its representations and warranties in the merger agreement. Frontier has denied all of Holly’s counterclaims. Trial on the suit and Holly’s counterclaims concluded on March 5, 2004. Oral arguments were held on May 4, 2004, and the Company is awaiting a decision. Frontier believes that the counterclaims filed against it by Holly will not result in any material liability or have any material adverse effect upon Frontier.

The operating results for the year ended December 31, 2004 were negatively impacted by legal costs related to the termination of the Holly merger aggregating $3.8 million pretax ($2.4 million after tax), which are reflected in the Consolidated Statements of Income as “Merger termination and legal costs.” The operating results for the year ended December 31, 2003 were negatively impacted by costs related to the Holly merger transaction aggregating $26.8 million pretax ($16.5 million after tax), which were reflected in the Consolidated Statements of Income as “Merger termination and legal costs” ($8.7 million) and “Merger financing termination costs, net” ($18.0 million). The $8.7 million of “Merger termination and legal costs” for the year ended December 31, 2003 included $3.0 million in transaction related costs and $5.7 million in legal expenses relating to the Holly lawsuit. The $18.0 million of “Merger financing termination costs, net” for the year ended December 31, 2003, included interest expense, issue discount, debt issue costs and redemption premium on the 8% Senior Notes, net of $752,000 interest income earned on the senior notes escrow account (see Note 5).

5.	Long-term Debt

Schedule of Long-term Debt

	December 31,
	2004		2003
	(in thousands)
6⅝% Senior Notes, maturing 2011	$	150,000	$	-
11¾% Senior Notes, net of unamortized discount		-		168,689
	$	150,000	$	168,689

6⅝% Senior Notes. On October 1, 2004, the Company issued $150.0 million principal amount of 6⅝% Senior Notes. The 6⅝% Senior Notes, which mature on October 1, 2011, were issued at par, and the Company received net proceeds (after underwriting fees) of $147.2 million. Interest is paid semi-annually. The 6⅝% Senior Notes are redeemable, at the option of the Company, at 103.313% after October 1, 2007, declining to 100% in 2010. Prior to October 1, 2007, the Company may at its option redeem the 6⅝% Senior Notes at a defined make-whole amount, plus accrued and unpaid interest. The 6⅝% Senior Notes may restrict payments, including dividends, and limit the incurrence of additional indebtedness based on covenants related to interest coverage ratio and restricted payments tests. Frontier Holdings Inc. and its subsidiaries are full and unconditional guarantors of the 6⅝% Senior Notes (see Note 13 for consolidating financial statements). The Company used a portion of the net proceeds from this offering, together with other available funds, to fund a tender offer and consent solicitation for $64.9 million principal of its 11¾% Senior Notes in October 2004 and redeemed on November 15, 2004, the remaining $105.6 million outstanding principal of its 11¾% Senior Notes.

11¾% Senior Notes. On November 5, 1999, the Company issued $190.0 million principal amount of 11¾% Senior Notes due 2009. The 11¾% Senior Notes were issued at a price of 98.562% and interest was paid semi-annually. The net proceeds were utilized to acquire the El Dorado Refinery. During 2001 and 2000, the Company purchased and held 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. As discussed above, the Company redeemed all of the remaining 11¾% Senior Notes during the fourth quarter of 2004 via the tender offer and redemption. Interest expense and other financing costs for the year ended December 31, 2004, included $14.9 million in costs related to the redemption of the 11¾% Senior Notes. The $14.9 million in redemption-related costs included $10.4 million of premium, the write-off at redemption of the remaining unamortized $1.5 million of issue discount, $2.7 million for the write-off at redemption of the remaining unamortized debt issue costs, and $0.3 million of legal and administrative costs to facilitate the tender offer and redemption. In addition, $9.1 million of accrued interest payments were made at the time of consummation of the tender offer and redemption.

9⅛% Senior Notes. On December 22, 2003, the Company called and redeemed, at the premium of 3.042%, or $1.2 million, provided for in the indenture, the remaining outstanding $39.5 million of the 9⅛% Senior Notes. The original $70.0 million of 9⅛% Senior Notes had semi-annual interest payments, were issued on February 9, 1998, and were due 2006. During 2002, 2001 and 2000, the Company purchased and held as treasury notes $1.1 million, $24.4 million and $5.0 million, respectively, principal amount of the 9⅛% Senior Notes, the accounting for which was a reduction of debt.

8% Senior Notes. On April 17, 2003, the Company received $218.1 million (net of issue discount and underwriting fees) from a private placement of $220.0 million of 8% Senior Notes due April 2013. The net proceeds of the 8% Senior Notes were to be used, together with other available funds, to finance the cash portion of the merger with Holly, to pay related fees and expenses and to refinance or pay off existing Holly indebtedness. Pending consummation of the merger with Holly, the net proceeds of the 8% Senior Notes offering, along with other amounts contributed by the Company, were placed in an escrow account. As provided for in the escrow agreement, because the merger with Holly did not occur, on October 10, 2003, Frontier closed the escrow account and redeemed the 8% Senior Notes at a price equal to 101% of the aggregate principal amount of the notes plus accrued interest. The redemption premium, financing costs and issue discount of the 8% Senior Notes were all reflected as expenses as of December 31, 2003 and included under the heading “Merger financing termination costs, net” on the Consolidated Statements of Income.

6.	Revolving Credit Facility

The refining operations have a working capital credit facility with a group of banks led by Union Bank of California and BNP Paribas (“Facility”). The Facility was amended and restated in November 2004 to increase the available commitment and to extend the current expiration date. The facility has a current expiration date of June 16, 2008. The Facility is a collateral-based facility with total borrowing capacity, subject to borrowing base amounts, of up to $225 million, which capacity may be increased up to $250 million at the Company’s request. Any unutilized capacity after cash borrowings is available for letters of credit. No borrowings were outstanding at December 31, 2004 under the Facility. Debt outstanding under the Facility was $45.8 million at December 31, 2003. Standby letters of credit outstanding were $12.2 million and $26.2 million at December 31, 2004 and 2003, respectively. As of December 31, 2004, the Company had borrowing base availability of $182.0 million under the Facility.

The Facility, secured by inventory, accounts receivable and related contracts and intangibles, and certain deposit accounts, provides working capital financing for operations, generally the financing of crude and product supply. The Facility provides for a quarterly commitment fee of 0.3% to 0.375% per annum. Borrowing rates are based, at the Company’s option, on the agent bank’s prime rate plus 0.25% to 1%, prevailing Federal Funds Rate plus 1.25% to 2% or LIBOR plus 1.25% to 2.0%. Outstanding standby letters of credit charges are 1.125% to 1.75% per annum, plus standard issuance and renewal fees. The rates/fees discussed above increase from the lower to higher levels based on the ratio of funded debt to earnings, as defined in the Facility agreement. The average interest rate on funds borrowed under the Facility during 2004 was 2.95%. The Facility is subject to compliance with financial covenants relating to working capital, tangible net worth, fixed charges and cash coverage, and debt leverage ratios. The Company was in compliance with these covenants at December 31, 2004.

7.	Income Taxes

The following is the provision for income taxes for the three years ended December 31, 2004, 2003 and 2002.

Provision for Income Taxes
	2004		2003		2002
	(in thousands)
Current:
State	$	3,375	$	25	$	32
Federal		13,959		276		(204	)
Canadian		-		-		83
Total current provision (benefit)		17,334		301		(89	)
Deferred:
State		1,640		411		303
Federal		23,365		2,244		846
Total deferred provision		25,005		2,655		1,149
Total provision	$	42,339	$	2,956	$	1,060

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, 2004, 2003 and 2002

Reconciliation of Tax Provision
	2004			2003			2002
	(in thousands)
Provision based on statutory rates	$	39,236		$	2,166		$	731
Increase (decrease) resulting from:
State and other income taxes		5,015			436			418
Federal tax effect of state income taxes		(1,755	)		(153	)		(146	)
Release of valuation allowance		(955	)		-			-
Other		798			507			57
Provision as reported	$	42,339		$	2,956		$	1,060

Significant components of deferred tax assets and liabilities are shown below:

Components of Deferred Taxes
	December 31, 2004									December 31, 2003
	State			Federal			Total			State			Federal			Total
	(in thousands)
Current deferred tax assets:
Gross current assets:
Turnaround accruals	$	757		$	5,380		$	6,137		$	522		$	3,644		$	4,166
Pension retirement benefits		58			411			469			71			498			569
Restricted stock amortization		39			279			318			57			396			453
Bad debt reserve		25			175			200			25			175			200
Other liabilities		10			68			78			-			-			-
Unrealized loss on derivative contracts		-			-			-			20			140			160
Charitable contributions carryforward		-			-			-			12			82			94
Capitalized selling and general expenses		19			133			152			-			-			-
State net operating losses		-			-			-			880			-			880
Total gross deferred tax assets		908			6,446			7,354			1,587			4,935			6,522
Gross current liabilities:
Unrealized gain on derivative contracts		(37	)		(264	)		(301	)		-			-			-
State deferred taxes		-			(305	)		(305	)		-			(555	)		(555	)
Total current net deferred tax assets	$	871		$	5,877		$	6,748		$	1,587		$	4,380		$	5,967

Long-term deferred tax liabilities:
Gross long-term assets:
Turnaround accruals	$	648		$	4,604		$	5,252		$	813		$	5,679		$	6,492
Pension retirement benefits		183			1,303			1,486			199			1,391			1,590
Other post-retirement benefits		957			6,796			7,753			840			5,862			6,702
Environmental liability accrual		74			525			599			-			-			-
Deferred compensation		55			390			445			99			692			791
State deferred taxes		-			2,166			2,166			-			1,850			1,850
Federal net operating loss		-			-			-			-			6,757			6,757
Federal alternative minimum tax credits		-			6,316			6,316			-			13,434			13,434
Gross long-term assets		1,917			22,100			24,017			1,951			35,665			37,616
Less valuation allowance		-			-			-			(600	)		(955	)		(1,555	)
Total long-term net deferred tax assets		1,917			22,100			24,017			1,351			34,710			36,061
Gross long-term liabilities:
Depreciation		(8,106	)		(58,461	)		(66,567	)		(6,636	)		(46,355	)		(52,991	)
Total long-term net deferred tax liabilities	$	(6,189	)	$	(36,361	)	$	(42,550	)	$	(5,285	)	$	(11,645	)	$	(16,930	)

At December 31, 2004, the Company had alternative minimum tax carryforwards of approximately $6.3 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 Refinery operations prior to its 1991 acquisition by the Company, which may be subject to certain limitations. The Company had no federal or state net operating loss carryforwards as of December 31, 2004. The Company has no income tax contingencies recorded and has not identified any potential gain or loss income tax contingencies that must be disclosed in accordance with FAS No. 5.

The Company recognizes the amount of taxes payable or refundable for the current year and recognizes deferred tax liabilities and assets for the expected future tax consequences of events and transactions that have been recognized in the Company’s financial statements or tax returns. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some or all of its deferred tax assets will not be realized. Realization of the deferred income tax assets is dependent on generating sufficient taxable income in future years. Although realization is not assured, management believes that it is more likely than not that all of the deferred income tax assets will be realized and thus, no valuation allowance was provided for as of December 31, 2004. Since the Company utilized all remaining federal and state net operating losses and also utilized a significant portion of its alternative minimum tax credits in 2004, valuation allowances provided in prior years have also been eliminated in 2004.

The Company recognized income tax benefits related to the deductibility of stock options and restricted stock in the amounts of $5.2 million, $1.6 million and $1.4 million for the years ended December 31, 2004, 2003 and 2002, respectively. Such benefits were recorded as an increase in additional paid in capital and a reduction of either income taxes payable (when the Company had taxable income) or a reduction in net deferred income tax liabilities (when the Company had tax net operating losses). The Company also recognized income tax benefits related to the minimum pension liability reflected in “Accumulated other comprehensive loss” in the amounts of $166,000, $201,000 and $214,000 for the years ended December 31, 2004, 2003 and 2002, respectively.

The new “American Jobs Creation Act of 2004” (the “Act”) provision providing tax relief for manufacturers should result in reduced effective federal income tax rates beginning in 2005. In December 2004, the FASB staff issued FSP No. FAS 109-1 to provide guidance on the application of FAS No. 109 to the provision within the Act that provides tax relief to U.S. domestic manufacturers. The FSP states that the manufacturers’ deduction provided for in the Act should be accounted for as a special deduction in accordance with FAS 109 and not as a tax rate reduction. A special deduction is accounted for by recording the benefit of the deduction in the year in which it can be taken in our tax return, and not by adjusting deferred tax assets and liabilities in the period of the Act’s enactment. The FSP was effective upon issuance, and the Company has properly accounted for its deferred taxes at December 31, 2004 in accordance with the FSP. Other certain provisions of the Act will benefit Frontier by allowing the Company an accelerated depreciation deduction of 75% of qualified capital costs incurred to achieve low sulfur diesel fuel requirements and by providing a $0.05 per gallon credit on compliant diesel fuel up to an amount equal to the remaining 25% of these qualified capital costs for federal income tax purposes (See Note 10).

8.	Common Stock

Dividends

The Company declared quarterly dividends of $.06 per share of common stock for the quarters ended September 30, 2004 and December 31, 2004 and $.05 per share for the quarters ended March 31, 2004 and June 30, 2004. The payment of dividends is prohibited under the Company’s Revolving Credit Facility only if a default has occurred and is continuing or such payment would cause a default. The 6⅝% Notes may restrict dividend payments based on covenants related to interest coverage ratio and restricted payments tests.

Treasury stock

The Company accounts for its treasury stock under the cost method on a FIFO basis. The Company has a Board of Director approved stock repurchase program for up to eight million shares of the Company’s common stock. Through December 2004, 4,367,366 shares of common stock had been purchased under the stock repurchase program. The Company did not initiate any additional purchases of common stock under the stock repurchase program in 2004, 2003 or 2002. The Company received 215,599 shares ($4.1 million) in 2004 and 51,082 shares ($880,000) in 2003 of its common stock, now held as treasury stock, from employees in cashless stock option exercises. The Company received 112,752 shares in 2004 and 37,556 shares in 2003 of its common stock, now held as treasury stock, from employees to cover withholding taxes on stock option exercises. The Company received 48,443 shares in 2004, 24,825 shares in 2003, and 19,041 shares in 2002 of its common stock, now held as treasury stock, from employees to cover withholding taxes on vested restricted stock. The Company issued treasury stock to non-employee directors under the “Non-employee Directors Stock Grant Plan,” discussed below, of 3,000 shares during each of the years ending December 31, 2004 and 2002. As of December 31, 2004, the Company had 4,638,467 shares of treasury stock.

Earnings per Share

The following sets forth the computation of diluted earnings per share (“EPS”) for the years ended December 31, 2004, 2003 and 2002.

	2004						2003						2002
	Income (Num-erator)		Shares (Denomi-nator)		Per Share Amount		Income (Num-erator)		Shares (Denomi-nator)		Per Share Amount		Income (Num-erator)		Shares (Denomi-nator)		Per Share Amount
	(in thousands except per share amounts)
Basic EPS:
Net income	$	69,764		26,673	$	2.62	$	3,232		25,939	$	0.12	$	1,028		25,780	$	0.04
Dilutive securities:
Stock options and
restricted stock		-		728		-		-		1,052		-		-		1,154		-
Diluted EPS:
Net income	$	69,764		27,401	$	2.55	$	3,232		26,991	$	0.12	$	1,028		26,934	$	0.04

The number of outstanding stock options that could potentially dilute EPS in future years but were not included in the computation of diluted EPS (because the exercise prices exceeded the average market prices for the periods) were none for the year ended December 31, 2004, and 1,546,700 and 702,700 shares, for the years ended December 31, 2003 and 2002, respectively.

Non-employee Directors Stock Grant Plan

During 1995, the Company established a stock grant plan for non-employee directors. The purpose of the plan was to provide a part of non-employee directors’ compensation in Company stock. The plan was 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. Under the plan, the Company could have granted an aggregate of 60,000 shares of the Company’s common stock held in treasury. The Company made aggregate grants to non-employee directors under this plan of 3,000 shares during each of the years ending December 31, 2004 and 2002, and expensed compensation in the amount of $13,500 in each of those years. No grants were made under this plan during the year ended December 31, 2003. Through December 31, 2004, a total of 21,000 shares had been granted under this plan. No further grants will be made under this plan as it expired on December 31, 2004.

Stock Option Plan

The Company has a stock option plan which authorizes the granting of options to employees to purchase shares. The plan through December 31, 2004 has reserved for issuance a total of 3,600,000 shares of common stock, of which 3,501,250 shares have been granted (1,930,850 are still outstanding) and 98,750 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. The Company received 215,599 shares ($4.1 million) in 2004 and 51,082 shares ($880,000) in 2003 of its common stock, now held as treasury stock, from employees in cashless stock option exercises.

Prior Stock Option Plans

There are options granted and outstanding to purchase a total of 157,600 shares of common stock under two prior stock option plans of the Company. No additional options are available for grant under these plans.

Changes during 2004, 2003 and 2002 in outstanding options are presented below:

	2004					2003					2002
	Number of Options			Weighted-Average Exercise Price		Number of Options			Weighted-Average Exercise Price		Number of Options			Weighted-Average Exercise Price
Outstanding at beginning of year		3,071,525		$	13.21		2,581,250		$	11.18		2,159,700		$	7.22
Granted		45,000			18.65		844,000			16.65		702,400			21.85
Exercised		(1,025,975	)		7.82		(353,225	)		6.57		(230,750	)		6.79
Expired		(2,100	)		21.85		(500	)		8.60		(50,100	)		10.21
Outstanding at end of year		2,088,450			15.97		3,071,525			13.21		2,581,250			11.18
Exercisable at end of year		1,460,050			15.02		1,945,801			10.88		1,512,325			8.63
Available for grant at end of year		98,750					141,650					985,650
Weighted-average fair value of options granted during the year					7.67					7.01					9.34

The following table summarizes information about stock options outstanding at December 31, 2004:

	Options Outstanding						Options Exercisable
Range of Exercise Prices	Number Outstanding at 12/31/04		Weighted-Average Remaining Contractual Life (Years)		Weighted-Average Exercise Price		Exercisable at 12/31/04		Weighted-Average Exercise Price
$6.44 to $7.00		227,500		0.17	$	6.98		227,500	$	6.98
$8.60 to $8.75		330,250		1.16		8.60		330,250		8.60
$12.10 to $16.65		822,500		3.10		16.54		400,500		16.42
$18.65 to $21.85		708,200		2.41		21.65		501,800		21.78

Restricted Stock Plan

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.

The Company made grants of restricted stock during the years ended December 31, 2002 and 2001. As of December 31, 2004, there were 54,698 shares of unvested restricted stock outstanding, which represents the remaining shares from the 2002 grants, which will vest in March 2005. No grants were made in the years ended December 31, 2004 or 2003. Restricted shares, when granted, are recorded at the market value on the date of issuance as deferred employee compensation (equity account) and amortized to compensation expense over the respective vesting periods of the stock. Compensation expense under the Plan for the years ended December 31, 2004, 2003 and 2002 was $1.2 million, $1.4 million and $907,000, respectively. The Company received 48,443 shares in 2004, 24,825 shares in 2003 and 19,041 shares in 2002 of its common stock, now held as treasury stock, from employees to cover withholding taxes on vested restricted stock.

9.	Employee Benefit Plans

Contribution Plans

The Company sponsors defined contribution plans for its employees. All employees may participate by contributing a portion of their annual earnings to the plans. The Company makes basic and/or matching contributions on behalf of participating employees. The cost of the plans for the years ended December 31, 2004, 2003 and 2002 was $5.6 million, $5.1 million and $5.1 million, respectively.

Deferred Compensation Plan

The Company sponsors a deferred compensation plan for certain employees or directors whose eligibility to participate in the plan is determined by the Company’s compensation committee. Participants may contribute a portion of their earnings to the plan, and the Company makes basis and/or matching contributions on behalf of eligible employees. The contributions and any earnings are held in an irrevocable trust known as a “rabbi trust” by an independent trustee. The trust account balance and related liability are reflected in “Other assets” and “Deferred compensation liability and other,” respectively, in the Consolidated Balance Sheets.

Defined Benefit Plans

The Company established a defined cash balance pension plan, effective January 1, 2000, for eligible El Dorado Refinery employees to supplement retirement benefits that those employees lost upon the sale of the El Dorado Refinery to Frontier. No other current or future employees will be eligible to participate in the plan. This plan has assets of $6.9 million at December 31, 2004, and its funding status is in compliance with ERISA.

The Company provides post-retirement healthcare and other benefits to certain employees of the El Dorado Refinery. Eligible employees are employees hired by the Refinery before certain defined dates and who satisfy certain age and service requirements. Employees hired on or before November 16, 1999 qualify for retirement healthcare insurance until eligible for Medicare. Employees hired on or before January 1, 1995 are also eligible for Medicare supplemental insurance. These plans have no assets as of December 31, 2004 and 2003. The post-retirement health care plan requires retirees to pay between 20% and 40% of total health care costs based on age and length of service. The plan’s prescription drug benefits are at least equivalent to the new Medicare Part D benefits.

The Company uses a December 31st measurement date for its plans. The following tables set forth the change in benefit obligation, the change in plan assets, the funded status of the pension plan and post-retirement healthcare and other benefit plans, amounts recognized in the Company’s financial statements, and the principal weighted-average assumptions used:

	Pension Benefits						Post-retirement Healthcare and Other Benefits (1)
	2004			2003			2004			2003
	(in thousands)
Change in benefit obligation:
Benefit obligation at January 1	$	10,695		$	9,794		$	23,250		$	19,380
Service cost		-			-			862			803
Interest cost		632			611			1,460			1,262
Plan participant contributions		-			-			-			-
Actuarial losses		485			355			3,614			1,894
Benefits paid		(2	)		(65	)		(147	)		(89	)
Benefit obligation at December 31	$	11,810		$	10,695		$	29,039		$	23,250

Change in plan assets:
Fair value of plan assets at January 1	$	5,298		$	3,777		$	-		$	-
Actual return on plan assets		504			200			-			-
Employer contribution		1,115			1,386			147			89
Plan participant contributions		-			-			-			-
Benefits paid		(2	)		(65	)		(147	)		(89	)
Fair value of plan assets at December 31	$	6,915		$	5,298		$	-		$	-

Funded status	$	(4,895	)	$	(5,397	)	$	(29,039	)	$	(23,250	)
Unrecognized net actuarial loss		1,936			1,498			9,622			6,498
Net amount recognized	$	(2,959	)	$	(3,899	)	$	(19,417	)	$	(16,752	)

Amounts recognized in the balance sheets:
Accrued benefit liability (2)	$	(4,895	)	$	(5,397	)	$	(19,417	)	$	(16,752	)
Accumulated other comprehensive loss		1,936			1,498			-			-
Net amount recognized	$	(2,959	)	$	(3,899	)	$	(19,417	)	$	(16,752	)

	Pension Benefits									Post-retirement Healthcare and Other Benefits
	2004			2003			2002			2004		2003		2002
	(in thousands)
Components of net periodic benefit cost for the year ended December 31:
Service cost	$	-		$	-		$	-		$	863	$	803	$	691
Interest cost		632			611			582			1,460		1,262		1,071
Expected return on plan assets		(479	)		(373	)		(162	)		-		-		-
Amortization of prior service cost		-			-			-			-		-		-
Recognized net actuarial loss		22			-			-			490		337		136
Net periodic benefit cost	$	175		$	238		$	420		$	2,813	$	2,402	$	1,898

Weighted average assumptions:
Benefit obligation discount rate as of December 31	5.50	%	6.00	%	-		5.50	%	6.00	%	-
Net periodic benefit cost discount rate for the year ended December 31	6.00	%	6.25	%	6.82	%	6.00	%	6.25	%	6.82	%
Expected return on plan assets (3)	8.00	%	8.00	%	8.00	%	-		-		-

(1)

The disclosed post-retirement healthcare obligations and net periodic costs for 2004 reflect government subsidies for prescription drugs as allowed under the Medicare Prescription Drug, Improvement and Modernization Act. The subsidy reduced the benefit obligation at December 31, 2004, by approximately $3.0 million and net periodic cost for the year ended December 31, 2004, by $0.1 million.

(2)

The portion of the liability of the pension benefit plan which is expected to be funded during the next year is included in “Accrued liabilities and other” in the current liability section on the Consolidated Balance Sheets. The current portion as of December 31, 2004 and 2003 was $1.2 million and $1.4 million, respectively. The remainder of the liabilities are reflected in “Post-retirement employee liabilities” in the long-term liability section of the Consolidated Balance Sheets.

(3)	The cash balance pension plan assumes an 8% expected long-term rate of return on assets based on a blend of historic returns of equity and debt securities. Actual returns on the Company’s plan assets exceeded 8% during 2004.

	Post-retirement Healthcare
	and Other Benefits
	2004			2003			2002
	(dollars in thousands)
Healthcare cost-trend rate:
		13.00	%		13.00	%		15.00	%
		ratable to			ratable to			ratable to
		5.00	%		5.00	%		5.00	%
		from 2008			from 2007			from 2007
Sensitivity Analysis:
Effect of 1% (-1%) change in healthcare cost-trend rate:
Year-end benefit obligation	$	6,094		$	5,036		$	4,258
		(4,767	)		(3,926	)		(3,313	)
Total of service and interest cost		502			467			394
		(392	)		(363	)		(307	)

At December 31, 2004, the estimated future benefit payments to be paid out in the next ten years are as follows:

Estimated future benefit payments For year ending December 31, *(in thousands)*	Pension Benefits		Post-retirement Healthcare and Other Benefits
	Payment		Payment		Subsidy Receipts
2005	$	133	$	255	$	-
2006		214		394		7
2007		305		546		11
2008		303		730		14
2009		436		907		21
Next 5 fiscal years thereafter		5,433		7,705		258

Plan Assets

The pension plan assets are held in a Trust Fund (the “Fund”) whose trustee is Frost National Bank (“trustee”). Frontier’s pension plan weighted-average asset allocations in the Fund at December 31, 2004 and 2003, by asset category are as follows:

	Percentage of Plan Assets at December 31,
	2004			2003
Asset Category:
Cash equivalents		16	%		47	%
Equity common trust funds		52	%		16	%
Fixed income common trust funds		26	%		37	%
Stock fund common trust funds		6	%		-	%
Total		100	%		100	%

The Company does not have a definitive target for the percentage allocation of assets in the plan. Management reviews the earnings on plan assets each year and compares them to the expected return utilized by the actuary in the prior year. If the actual returns vary dramatically from the expected returns, management may direct the trustee to make changes in the allocation of types of investments. The trustee has the following investment powers:

except for limitations on investing Fund assets in Company securities or real property, the trustee may invest and reinvest in any property, real, personal or mixed, wherever situated, including without limitation, common and preferred stocks, bonds, notes, debentures, mutual funds, leaseholds, mortgages, certificates of deposit, and oil, mineral or gas properties, royalties, interests or rights;

·	to make commingled, collective or common investments and to invest or reinvest all or any portion of the pension plan assets with funds of other pension and profit sharing trusts exempt from tax under section 501(a) of the Internal Revenue Code; and

·	to deposit or invest all or a part of the Fund in savings accounts, certificates of deposit or other deposits which bear a reasonable rate of interest in a bank or similar financial institution, including the commercial department of the trustee.

The Company expects to make contributions into the Fund during the year ending December 31, 2005, of approximately $1.2 million.

10.

Commitments and Contingencies

Lease and Other Commitments

On November 16, 1999, Frontier acquired the 110,000 barrels per day (“bpd”) 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 $60.0 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 $40.0 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. A contingent earn-out payment of $7.5 million was required based on 2004 results; this amount was accrued at December 31, 2004 and was paid in January 2005. No contingent earn-out payment was required based on 2003, 2002 or 2000 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.

In connection with the acquisition of the El Dorado Refinery, the Company entered into an operating sublease agreement with Shell for the use of the cogeneration facility at the El Dorado Refinery. The non-cancelable operating sublease 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 2005 through 2011. Operating lease rental expense was approximately $10.4 million, $9.0 million and $11.3 million for the years ended December 31, 2004, 2003 and 2002, respectively. The approximate future minimum lease payments for operating leases as of December 31, 2004 are $12.7 million for 2005, $12.0 million for 2006, $10.0 million for 2007, $9.4 million for 2008, $9.9 million for 2009 and $42.9 million thereafter.

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 commenced January 1, 2003, provides for the Company to purchase up to 20,000 bpd of a Lloydminster crude oil blend, a heavy Canadian crude. Initially, the Company received 9,000 bpd, which increased to 20,000 bpd by October 2003. The Company processes 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 is 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 Express 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 some of the Company’s dedicated capacity through the Express Pipeline.

The Company has two contracts for crude oil pipeline capacity into 2015 on the Express Pipeline. The first contract, which began in 1997, is for 15 years and for an average of 13,800 bpd over that 15-year period. The agreement has allowed the Company to assign a portion of its capacity in early years for additional capacity in later years. The Company has assigned a portion of its contracted pipeline capacity to Baytex in connection with the crude supply agreement discussed above. In December 2003, the Company entered into an expansion capacity agreement on the Express Pipeline for an additional 10,000 bpd starting in April 2005 through 2015. Of the additional 10,000 bpd, the Company assigned 4,000 bpd to another party starting in April 2005 through March 2006. The Company’s remaining commitment for pipeline capacity, based on the current tariff, and after reducing for the commitments assigned to other parties, is approximately $3.2 million for 2005, $4.8 million for 2006, $5.1 million for 2007, an average of $12.0 million for each of the years 2008 through 2011, $7.4 million for 2012, approximately $5.8 million for each of the years 2013 and 2014 and $1.5 million for 2015. Should the Baytex agreement be extended beyond the initial term ending December 31, 2007, as provided for in the agreement, a portion of the Company’s commitment for pipeline capacity will continue to be assigned to Baytex in the years 2008 through 2012.

During 2004, the Company entered into a Transportation Services Agreement (“Agreement”) to transport crude oil on the Spearhead Pipeline from Griffith, Indiana to Cushing, Oklahoma. The owner of the Spearhead Pipeline intends to alter an existing pipeline, including reversing the flow, with an anticipated date to be able to commence crude oil shipments on or around January 1, 2006. This pipeline will enable Frontier to transport Canadian crude oil to its El Dorado Refinery. The initial term of this Agreement is for a period of ten years from the actual commencement date, with the Company having the right to extend the Agreement for an additional ten-year term. The Company has committed to transport a minimum volume of 20,000 bpd of crude oil, with the right to increase that commitment. Under this Agreement, the Company has an annual commitment of $5.5 million in crude oil pipeline tariffs for each of the ten years in the term of the Agreement.

The Company had a Resid Processing Agreement, as amended, with ConocoPhillips, which was to expire after the earlier of a certain number of barrels processed, but no later than December 2006. During 2003, this agreement was assigned from ConocoPhillips to Suncor Energy (U.S.A.) (“Suncor”), when Suncor purchased the refinery in Denver from ConocoPhillips. Suncor was entitled to process in the Cheyenne Refinery coker up to 3,300 bpd of resid, a heavy end by-product of the refining process. The Company earned a processing fee ranging from $0.80 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. This agreement expired in July 2004 due to the required number of barrels being reached.

The Company owns a 34.72% interest in a crude oil pipeline from Guernsey, Wyoming to the Cheyenne Refinery and a 50% interest in two crude oil tanks in Guernsey. The Company’s share of operating costs for the crude oil pipeline and the tanks are recorded as “Raw material, freight and other costs.”

Litigation

Beverly Hills Lawsuits. A Frontier subsidiary, Wainoco Oil & Gas Company, owned and operated an interest in an oil field in the Los Angeles, California metropolitan area from 1985 to 1995. The production facilities for that interest in the oil field are located at the campus of the Beverly Hills High School. In April 2003, a law firm began filing claims with the Beverly Hills Unified School District and the City of Beverly Hills on behalf of former students, school employees, area residents and others alleging that emissions from the oil field or the production facilities caused cancers or various other health problems in those individuals. Wainoco Oil & Gas Company and Frontier have been named in six such suits: Moss et al. v. Veneco, Inc. et al., filed in June 2003; Ibraham et al. v. City of Beverly Hills et al., filed in July 2003; Yeshoua et al. v. Veneco, Inc. et al., filed in August 2003; Jacobs v. Wainoco Oil & Gas Company et al., filed in December 2003; Bussel et al. v. Veneco, Inc. et al., filed in January 2004; and Steiner et al. v. Venoco Inc. et al., filed in May 2004. Other defendants in these lawsuits include the Beverly Hills Unified School District, the City of Beverly Hills, ten other oil and gas companies, two additional companies involved in owning or operating a power plant adjacent to the Beverly Hills High School and three of their related parent companies. The lawsuits include claims for personal injury, wrongful death, loss of consortium and/or fear of contracting diseases, and also ask for punitive damages. No dollar amounts of damages have been specified in any of the lawsuits. The six pending lawsuits have been related to one another and have been transferred to a judge on the complex civil litigation panel in the Superior Court of the State of California for the County of Los Angeles. A case management order has been entered in the case pursuant to which 12 plaintiffs have been selected as the initial group of plaintiffs to go to trial, discovery has commenced and a preliminary trial date has been set for July 25, 2005.

The oil production site operated by Frontier’s subsidiary was a modern facility and was operated with a high level of safety and responsibility. Frontier believes that its subsidiary’s activities did not cause any health problems for anyone, including former Beverly Hills high school students, school employees or area residents. Nevertheless, as a matter of prudent risk management, Frontier purchased insurance in 2003 from an insurance company with an A.M. Best rating of A++ (Superior) covering the existing claims described above and any similar claims for bodily injury or property damage asserted during the five-year period following the policy’s September 30, 2003 commencement date. The claims are covered, whether asserted directly against the insured parties or as a result of contractual indemnity. In October 2003, the Company paid $6.25 million to the insurance company for loss mitigation insurance (which included an indemnity premium of $5.75 million and a $500,000 administration fee) and also funded with the insurance company a commutation account of approximately $19.5 million, from which the insurance company is funding the first costs under the policy including, but not limited to, the costs of defense of the claims. The policy covers defense costs and any payments made to claimants, up to an aggregate limit of $120 million, including coinsurance by Frontier of up to $3.9 million of the coverage between $40 million and $120 million. As of December 31, 2004, the commutation account balance was approximately $16.4 million. The Company also paid $772,500 to the State of California for insurance tax on the premium in 2003, of which $600,000 was refunded in 2004. Frontier has the right to terminate the policy at any time after September 30, 2004 and prior to September 30, 2008, and receive a refund of the unearned portion of the premium (approximately $4.0 million as of December 31, 2004, and declining by approximately $1.1 million each year) plus any unspent balance in the commutation account plus accumulated interest. While the policy is in effect, the insurance company will manage the defense of the claims. The Company is also seeking coverage with respect to the Beverly Hills, California claims from the insurance companies that provided policies to Frontier during the 1985 to 1995 period.

Frontier believes that neither the claims that have been made, the six pending lawsuits, nor other potential future litigation, by which similar or related claims may be asserted against Frontier or its subsidiary, will result in any material liability or have any material adverse effect upon Frontier.

Holly Lawsuit. See Note 4 “Holly Merger Agreement and Litigation.”

MTBE Concentration Lawsuits. In November 2003, the El Dorado Refinery (owned by the Company’s subsidiary, Frontier El Dorado Refining Company (“FEDRC”)) was included as one of 52 defendants in four lawsuits brought on behalf of the City of Dodge City, Kansas, the Chisholm Creek Utility Authority, the City of Bel Aire, Kansas, the County of Sedgwick Water Authority and the City of Park City, Kansas (the “Kansas Plaintiffs”) alleging unspecified damages for contamination of groundwater/public water wells by methyl tertiary butyl ether (“MTBE”) and tertiary butyl alcohol, a degradation product of MTBE. These four cases were removed to federal court and were then transferred with other similar cases to a federal district court in New York to be presided over by one federal court judge. In November 2004, the Cheyenne Refinery (owned by the Company’s subsidiary, Frontier Refining Inc (“FRI”)) was notified that it had been added as a defendant to these same four cases involving Kansas Plaintiffs. Because neither FEDRC nor FRI had either manufactured MTBE or provided MTBE blended gasoline in the Kansas marketplace, the Kansas Plaintiffs voluntarily dismissed both FEDRC and FRI in January 2005. These voluntary dismissals are without prejudice. Accordingly, the Kansas Plaintiffs are able, if they have the required evidentiary support, to add either FEDRC or FRI back into the litigation. However, given the basis for the dismissals, the Company continues to believe that any potential liability would not have a material adverse effect on its liquidity, financial position or results of operations.

Other. The Company is also involved in various other 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.

Concentration of Credit Risk

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, Colorado, 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 in 1999. Beginning in 2000, the Company retained and marketed 5,000 bpd of the El Dorado Refinery’s gasoline and diesel production. The retained portion is scheduled to increase by 5,000 bpd each year for ten years. In 2004, Frontier retained 25,000 bpd of the Refinery’s gasoline and diesel production. Shell will also purchase all jet fuel production from the El Dorado Refinery through the offtake agreement term. The Company retains and markets all by-products produced from the El Dorado Refinery.

The Company 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. No bad debt losses were recorded during the year ended December 31, 2004. During 2002, the Company provided an allowance of $800,000 against a $2.2 million note receivable from a customer, which represented the estimated unsecured portion of the note. During 2003, the Company foreclosed on the collateral of the note, realized a $614,000 bad debt loss and reversed $186,000 of the previously provided allowance related to the note. During 2003, the Company also wrote off a doubtful account for one customer totaling $103,000. The Company made sales to Shell of approximately $1.4 billion, $1.1 billion and $1.1 billion in the years 2004, 2003 and 2002, respectively, which accounted for 49% of consolidated refined products revenues in 2004, 53% of consolidated refined products revenues in 2003 and 58% of consolidated refined products revenues in 2002.

Environmental

The Company accounts for environmental costs as indicated in Note 2. The Company’s operations and many of its manufactured products are specifically subject to certain requirements of the Clean Air Act (“CAA”) and related state and local regulations. The 1990 amendments to the CAA contain provisions that will require capital expenditures for the installation of certain air pollution control devices at the Refineries during the next several years. The Environmental Protection Agency (“EPA”) has embarked on a Petroleum Refining Initiative (“Initiative”) alleging industry-wide noncompliance with certain longstanding 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, Frontier does not know how the Initiative may affect the Company. The Company has, however, in recognition of the EPA’s reinterpretation of certain regulatory requirements associated with the Initiative, determined that Frontier will incur expenditures totaling approximately $8.0 million to further reduce emissions from the Refineries’ flare systems. At the Cheyenne Refinery, the Company spent $223,000 in 2004, and estimates spending an additional $4.0 million, primarily in 2005, on the flare system. At the El Dorado Refinery, the Company spent $423,000 in 2004, and it estimates incurring a total additional $3.3 million during 2005 and 2006, on the flare system. Both the Kansas Department of Health and Environment (“KDHE”) and the Wyoming Department of Environmental Quality (“WDEQ”) have expressed their preference to enter into consent decrees with the Company to settle these and certain other compliance matters. The provisions of a KDHE order have not yet been proposed; however, Region VII of the EPA has informed the State of Kansas and the Company that requirements for reductions in emissions from the El Dorado Refinery’s Fluid Catalytic Cracking Unit (“FCCU”) must also be included in any settlement with the State of Kansas if the Company wants protection from a subsequent EPA enforcement action under the Initiative. The Company is currently evaluating interim and final FCCU emission control options.

In a settlement entered on February 22, 2005, the WDEQ has accepted a penalty in the amount of $120,000 in addition to the Company’s commitment to complete the aforementioned flare system controls and an agreed upon Capital Supplemental Environmental Project estimated to cost $535,000 to resolve one of the Iniative’s four concerns and other prior violations. The settlement addresses:

·	the reduction of flare system emissions,
·	an earlier notice of violation regarding excess emissions from the Cheyenne Refinery’scrude unit heaters,
·	resolution of a 1992 Odor Consent Decree, and
·	two recent odor violations associated with the startup of the Cheyenne Refinery’s new gasoline desulfurization equipment.

During the first quarter of 2004, the Company decreased the previously estimated penalty accrual of $317,000 recorded as of December 31, 2003 to $120,000. This $197,000 reduction is reflected as a reduction of “Refinery operating expenses, excluding depreciation” on the Consolidated Statement of Income for the year ended December 31, 2004.

The EPA has promulgated regulations requiring the phase-in of gasoline sulfur standards, which began January 1, 2004 and continues through 2008, with special provisions for small business refiners. Because the Company qualifies as a small business refiner, Frontier has elected to extend its small refinery interim gasoline sulfur standard at each of the Refineries until 2011 and to comply with the highway diesel sulfur standard by June 2006 as discussed below. The Cheyenne Refinery has spent approximately $28.9 million (including capitalized interest) to complete the project to meet the interim gasoline sulfur standard, which was required by January 1, 2004. The remaining $7.0 million estimated cost to meet the additional standard for the Cheyenne Refinery is expected to be incurred in 2009 and 2010. The total capital expenditures estimated as of December 31, 2004, for the El Dorado Refinery to achieve the final gasoline sulfur standard are approximately $15 million, which are expected to be incurred between 2006 and 2009. The Company’s approach to achieve the gasoline sulfur standard at the El Dorado Refinery has been revised from building a new unit to the modification of existing equipment, thus reducing the cost from the original estimate of $44.0 million.

The EPA has promulgated regulations that will limit the sulfur content of highway diesel fuel beginning in 2006. As indicated above, Frontier has elected to comply with the highway diesel sulfur standard by June 2006. As of December 31, 2004, capital costs, including capitalized interest, for diesel desulfurization are estimated to be approximately $14.0 million for the Cheyenne Refinery and approximately $106.5 million for the El Dorado Refinery. Approximately $250,000 of the Cheyenne Refinery expenditures were incurred in 2004, $9.0 million is estimated to be incurred in 2005, and the remaining $4.7 million is estimated to be incurred in the first half of 2006. Approximately $6.0 million of the El Dorado Refinery expenditures were incurred in 2004, $90.5 is estimated to be incurred in 2005, and the remaining $10.0 million is estimated to be incurred in the first half of 2006. Certain provisions of The American Jobs Creation Act of 2004 should benefit Frontier by allowing the Company an accelerated depreciation deduction of 75% of these qualified capital costs in the years incurred and by providing a $0.05 per gallon credit on compliant diesel fuel up to an amount equal to the remaining 25% of these qualified capital costs for federal income tax purposes.

On June 29, 2004, the EPA promulgated regulations designed to reduce emissions from the combustion of diesel fuel in non-road applications such as mining, agriculture, locomotives and marine vessels. The Company currently participates in this market through the manufacture and sale of approximately 6,000 bpd of non-road diesel fuel from the El Dorado Refinery. The new regulations will, in part, require refiners to reduce the sulfur content of non-road diesel fuel from 5,000 parts per million (“ppm”) to 500 ppm in 2007 and further to 15 ppm in 2010 for all uses but locomotive and marine. Diesel fuel used in locomotives and marine operations will be required to meet the 15 ppm sulfur standard in 2012. Small refiners, such as Frontier, will be allowed to either postpone the new sulfur limits or, if the small refiner chooses to meet the new limit on the national schedule, to increase their gasoline sulfur limits by 20%. Frontier intends to desulfurize all of its diesel fuel, including non-road, to the 15 ppm sulfur standard by 2006. The new regulation also clarifies that EPA-approved small business refiners will be allowed to exceed both the small refiner maximum capacity and/or employee criteria through merger with or acquisition of another approved small business refiner without loss of small refiner regulatory status.

The front range of Colorado (including the Denver metropolitan area) is a major market for the products manufactured by the Company’s Refineries. During 2004, the State of Colorado undertook an effort to develop and implement controls necessary to ensure that the area will regain compliance with the EPA’s National Ambient Air Quality Standards for ozone during the three-year averaging period of 2005 through 2007. On March 25, 2004, the EPA advised the refiners supplying the Denver region that their request for continuance of the long-standing Reid Vapor Pressure (“RVP”) waiver would not be granted for the 2004 ozone control period and that gasoline marketed in the area could not exceed the regulatory standard of 7.8 pounds RVP beginning May 1, 2004 at the marketing distribution terminals and June 1, 2004 at customer retail locations. During 2004, the Company incurred $2.0 million in capital costs at our Cheyenne Refinery to comply with this standard.

As is the case with all companies engaged in similar industries, the Company faces potential exposure from future claims and lawsuits involving environmental matters, including soil and water contamination, air pollution, personal injury and property damage allegedly caused by substances that the Company may have manufactured, handled, used, released or disposed.

Cheyenne Refinery. The Company is party to an agreement with the State of Wyoming requiring the investigation and possible eventual remediation of certain areas of the Cheyenne Refinery’s property that may have been impacted by past operational activities. Prior to this agreement, the Company addressed tasks required under a consent decree approved by the Wyoming State District Court on November 28, 1984 and involving the State of Wyoming, the 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, capital expenditures and remediation of conditions found to exist have already taken place, including the completion of surface impoundment closures, waste stabilization activities and other site remediation projects totaling approximately $4.0 million. In addition, the Company estimates that an ongoing groundwater remediation program averaging approximately $200,000 in annual operating and maintenance costs will be required for approximately ten more years. As of December 31, 2004, the Company has a reserve included in “Other long-term liabilities” of $1.5 million in environmental liabilities reflecting the estimated present value of these expenditures ($2.0 million, discounted at a rate of 5.0%). The EPA also issued an administrative consent order with respect to the Cheyenne Refinery on September 24, 1990 pursuant to the Resource Conservation and Recovery Act. Among other things, this order required a technical investigation of the Cheyenne Refinery to determine if certain areas had been adversely impacted by past operational activities. Based upon the results of the ongoing investigation, additional remedial action could be required by a subsequent administrative order or permit.

In accordance with permits issued by the State of Wyoming under the federal National Pollutant Discharge Elimination System (“NPDES”), the Cheyenne Refinery is permitted to discharge its treated wastewater to either of two receiving waterways: a creek adjacent to the Cheyenne Refinery or a normally dry ravine called “Porter Draw.” Certain landowners downstream of the Cheyenne Refinery’s permitted discharge to Porter Draw expressed their unwillingness to continue to accommodate this wastewater flow by appealing the Company’s discharge permit and by giving notice of possible legal action. In response, as an alternative to continuing to discharge into the ravine, the Company arranged to deliver its treated wastewater beginning in July 2004 to the City of Cheyenne (“Cheyenne”) municipal treatment plant for additional treatment and release, and it has entered into settlements with the landowners. To initiate this wastewater treatment service, Frontier has agreed to pay Cheyenne a $1.6 million development fee (reflected in “Other intangible asset, net of accumulated amortization” on the Consolidated Balance Sheet as of December 31, 2004). This fee will be amortized over 15 years with the amortization expense included in “Depreciation and amortization” in the Consolidated Statements of Income. The $1.6 million fee will be paid in equal installments over five years, with the first payment having been made in July 2004. In addition, beginning in July 2004, the Cheyenne Refinery pays Cheyenne $2.00 per 1,000 gallons of wastewater treated, which is included as “Refinery operating expenses, excluding depreciation” in the Consolidated Statement of Income.

El Dorado Refinery. The El Dorado Refinery is subject to a 1988 consent order with the 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 for the El Dorado Refinery entered into between the Company and Shell, Shell is responsible for the costs of continued compliance with this order.

Collective Bargaining Agreement Expiration

The Company’s refining 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 58% of the Company’s work force at December 31, 2004.

11.

Fair Value of Financial Instruments

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, 2004 and 2003, the carrying amounts of long-term debt instruments were $150.0 million and $168.7 million, respectively, and the estimated fair values were $151.5 million and $185.8 million, respectively. For cash and cash equivalents, trade receivables, inventory and accounts payable, the carrying amount is a reasonable estimate of fair value.

12.

Price Risk Management Activities

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.

Trading Activities

During 2004, 2003 and 2002, the Company had the following derivative activities which, while economic hedges, were not accounted for as hedges and whose gains or losses are reflected in “Other revenues” on the Consolidated Statements of Income:

Derivative contracts on barrels of crude oil to hedge excess crude oil, intermediate and finished product inventory for both the Cheyenne and El Dorado Refineries. As of December 31, 2004, the Company had reported $354,000 in unrealized gains on open derivative contracts. During the year ended December 31, 2004, the Company recorded $8.1 million in realized losses on these types of positions. During the year ended December 31, 2003, the Company recorded $130,000 in realized gains on these types of positions. During the year ended December 31, 2002, the Company recorded $740,000 in net realized losses on these positions.

·	Derivative contracts to fix the heavy crude differential to the New York Mercantile Exchange light crude oil contract price for a portion of the committed purchases under the Company’s crude oil supply agreement with Baytex.

During the year ended December 31, 2004, the Company recorded losses of approximately $2.5 million on contracts purchased for this purpose. During the year ended December 31, 2003, the Company recorded realized and unrealized losses totaling $417,000 on contracts for this purpose. No derivative contracts were utilized for this purpose in 2002.

Hedging Activities

During the year ended December 31, 2004, the Company had no derivative contracts which were accounted for as hedges. During 2003 and 2002, the Company had the following derivatives which were appropriately designated and accounted for as hedges:

Crude Purchases. During the year ended December 31, 2003, the Company had derivative contracts on barrels of crude oil to hedge Canadian crude costs for the Cheyenne Refinery which were accounted as fair value hedges. A $13,000 loss was realized on these positions, of which $31,000 increased crude costs and $18,000 increased income, which was reflected in “Other revenues” in the Consolidated Statements of Income for the ineffective portion of this hedge. The Company also utilized derivative contracts on barrels of crude oil to hedge two foreign crude cargos purchased for the El Dorado Refinery during the year ended December 31, 2003. A $13,000 gain was realized on these positions, of which $11,000 reduced crude costs and $2,000 was reflected in “Other revenues” for the ineffective portion of these hedges. During the year ended December 31, 2002, the Company utilized derivative contracts on barrels of crude oil to hedge foreign crude purchases for the El Dorado Refinery and recorded net losses of $9.8 million, of which $10.7 million increased crude costs and $848,000 income was reflected in “Other revenues” for the ineffective portion of those hedges. These contracts were accounted for as fair value hedges.

Natural Gas Collars. The Company entered into price swaps on natural gas for the purpose of hedging against natural gas price increases for the El Dorado Refinery in 2003, which resulted in a realized $1.7 million gain and which reduced “Refinery operating expenses, excluding depreciation” for the year ended December 31, 2003. 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, which resulted in $434,000 net realized gains and reduced “Refinery operating expenses, excluding depreciation” for the year ended December 31, 2002. These contracts were accounted for as cash flow hedges.

13.

Consolidating Financial Statements

Frontier Holdings Inc. and its subsidiaries (“FHI”) are full and unconditional guarantors of the Company’s 6⅝% Senior Notes. Presented on the following pages are the Company’s consolidating balance sheets, statements of operations, and cash flows as required by Rule 3-10 of Regulation S-X of the Securities Exchange Act of 1934, as amended. As specified in Rule 3-10, the condensed consolidating balance sheets, statement of operations, and cash flows presented below meet the requirements for financial statements of the issuer and each guarantor of the notes because guarantors are all direct or indirect wholly-owned subsidiaries of Frontier, and all of the guarantees are full and unconditional on a joint and several basis. The Company files a consolidated U.S. federal income tax return and consolidated state income tax returns in the majority of states in which it does business. Each subsidiary calculates its income tax provisions on a separate company basis, which are eliminated in the consolidation process.

CONSOLIDATING FINANCIAL STATEMENTS

FRONTIER OIL CORPORATION
Condensed Consolidating Statement of Operations
For the Year Ended December 31, 2004
(in thousands)
	FOC (Parent)			FHI (Guarantor Subsidiaries)			Other Non-Guarantor Subsidiaries		Eliminations			Consolidated
Revenues:
Refined products	$	-		$	2,871,592		$	-	$	-		$	2,871,592
Other		(6	)		(9,932	)		62		-			(9,876	)
		(6	)		2,861,660			62		-			2,861,716

Costs and expenses:
Raw material, freight and other costs		-			2,432,461			-		-			2,432,461
Refinery operating expenses, excluding depreciation		-			219,781			-		-			219,781
Selling and general expenses, excluding depreciation		15,590			14,303			-		-			29,893
Merger termination and legal costs		3,824			-			-		-			3,824
Depreciation and amortization		75			32,688			-		(555	)		32,208
		19,489			2,699,233			-		(555	)		2,718,167

Operating income		(19,495	)		162,427			62		555			143,549

Interest expense and other financing costs		35,004			2,609			-		(40	)		37,573
Interest income		(1,545	)		(171	)		-		-			(1,716	)
Equity in earnings of subsidiaries		(165,038	)		-			-		165,038			-
Gain on involuntary conversion of assets		-			(4,411	)		-		-			(4,411	)
		(131,579	)		(1,973	)		-		164,998			31,446

Income before income taxes		112,084			164,400			62		(164,443	)		112,103
Provision for income taxes		42,320			62,429			-		(62,410	)		42,339
Net income	$	69,764		$	101,971		$	62	$	(102,033	)	$	69,764

FRONTIER OIL CORPORATION
Condensed Consolidating Statement of Operations
For the Year Ended December 31, 2003
(in thousands)
	FOC (Parent)			FHI (Guarantor Subsidiaries)			Other Non-Guarantor Subsidiaries			Eliminations			Consolidated
Revenues:
Refined products	$	-		$	2,169,551		$	-		$	-		$	2,169,551
Other		(17	)		922			47			-			952
		(17	)		2,170,473			47			-			2,170,503

Costs and expenses:
Raw material, freight and other costs		-			1,860,795			-			-			1,860,795
Refinery operating expenses, excluding depreciation		-			200,383			-			-			200,383
Selling and general expenses, excluding depreciation		7,936			11,954			-			-			19,890
Merger termination and legal costs		8,739			-			-			-			8,739
Depreciation and amortization		113			29,275			-			(556	)		28,832
		16,788			2,102,407			-			(556	)		2,118,639

Operating income		(16,805	)		68,066			47			556			51,864

Interest expense and other financing costs		26,981			1,765			-			-			28,746
Interest income		(1,004	)		(105	)		-			-			(1,109	)
Equity in earnings of subsidiaries		(48,949	)		-			-			48,949			-
Merger financing termination costs, net		-			-			18,039			-			18,039
		(22,972	)		1,660			18,039			48,949			45,676

Income (loss) before income taxes		6,167			66,406			(17,992	)		(48,393	)		6,188
Provision for income taxes		2,935			25,506			-			(25,485	)		2,956
Net income (loss)	$	3,232		$	40,900		$	(17,992	)	$	(22,908	)	$	3,232

FRONTIER OIL CORPORATION
Condensed Consolidating Statement of Operations
For the Year Ended December 31, 2002
(in thousands)

	FOC (Parent)			FHI (Guarantor Subsidiaries)			Other Non-Guarantor Subsidiaries		Eliminations			Consolidated
Revenues:
Refined products	$	-		$	1,812,613		$	-	$	-		$	1,812,613
Other		(1	)		1,113			25		-			1,137
		(1	)		1,813,726			25		-			1,813,750

Costs and expenses:
Raw material, freight and other costs		-			1,562,613			-		-			1,562,613
Refinery operating expenses, excluding depreciation		-			178,295			-		-			178,295
Selling and general expenses, excluding depreciation		6,208			11,403			-		-			17,611
Depreciation and amortization		247			27,640			-		(555	)		27,332
		6,455			1,779,951			-		(555	)		1,785,851

Operating income		(6,456	)		33,775			25		555			27,899

Interest expense and other financing costs		24,858			2,755			-		-			27,613
Interest income		(1,698	)		(104	)		-		-			(1,802	)
Equity in earnings of subsidiaries		(31,704	)		-			-		31,704			-
		(8,544	)		2,651			-		31,704			25,811

Income before income taxes		2,088			31,124			25		(31,149	)		2,088
Provision for income taxes		1,060			12,364			-		(12,364	)		1,060
Net income	$	1,028		$	18,760		$	25	$	(18,785	)	$	1,028

FRONTIER OIL CORPORATION
Condensed Consolidating Balance Sheet
As of December 31, 2004
(in thousands)
	FOC (Parent)		FHI (Guarantor Subsidiaries)		Other Non-Guarantor Subsidiaries			Eliminations			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	105,409	$	18,980	$	-		$	-		$	124,389
Trade and other receivables		7,013		81,251		-			-			88,264
Receivable from affiliated companies		-		431		99			(530	)		-
Inventory		-		156,934		-			-			156,934
Deferred tax assets		6,748		6,626		-			(6,626	)		6,748
Other current assets		105		2,239		-			-			2,344
Total current assets		119,275		266,461		99			(7,156	)		378,679
Property, plant and equipment, at cost:		1,114		561,010		-			(11,013	)		551,111
Less - accumulated depreciation and amortization		941		210,812		-			(7,405	)		204,348
		173		350,198		-			(3,608	)		346,763
Deferred financing costs, net		3,252		1,076		-			-			4,328
Commutation account		16,438		-		-			-			16,438
Prepaid insurance, net		4,542		-		-			-			4,542
Other intangible assets, net		-		1,527		-			-			1,527
Other assets		2,108		15		-			-			2,123
Investment in subsidiaries		295,764		-		-			(295,764	)		-
Total assets	$	441,552	$	619,277	$	99		$	(306,528	)	$	754,400

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities:
Accounts payable	$	853	$	238,138	$	-		$	-		$	238,991
Accrued turnaround cost		-		15,373		-			-			15,373
Accrued interest		2,485		2		-			-			2,487
Accrued liabilities and other		3,505		20,793		269			-			24,567
Total current liabilities		6,843		274,306		269			-			281,418

Long-term debt		150,000		-		-			-			150,000
Long-term accrued and other liabilities		-		38,803		-			-			38,803
Deferred compensation liability and other		1,516		-		-			-			1,516
Deferred income taxes		42,550		50,462		-			(50,462	)		42,550
Payable to affiliated companies		530		7,353		-			(7,883	)		-

Shareholders’ equity		240,113		248,353		(170	)		(248,183	)		240,113
Total liabilities and shareholders’ equity	$	441,552	$	619,277	$	99		$	(306,528	)	$	754,400

FRONTIER OIL CORPORATION
Condensed Consolidating Balance Sheet
As of December 31, 2003
(in thousands)
	FOC (Parent)		FHI (Guarantor Subsidiaries)		Other Non-Guarantor Subsidiaries			Eliminations			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	59,846	$	4,674	$	-		$	-		$	64,520
Trade and other receivables		710		87,643		-			-			88,353
Receivable from affiliated companies		-		692		40			(732	)		-
Inventory		-		123,999		-			-			123,999
Deferred tax assets		5,967		5,201		-			(5,201	)		5,967
Other current assets		68		1,906		-			-			1,974
Total current assets		66,591		224,115		40			(5,933	)		284,813
Property, plant and equipment, at cost:		1,111		505,586		-			(11,053	)		495,644
Less - accumulated depreciation		866		179,180		-			(6,850	)		173,196
		245		326,406		-			(4,203	)		322,448
Deferred financing costs, net		3,299		710		-			-			4,009
Commutation account		19,550		-		-			-			19,550
Prepaid insurance, net		6,593		-		-			-			6,593
Other assets		4,884		-		-			-			4,884
Investment in subsidiaries		264,016		-		-			(264,016	)		-
Total assets	$	365,178	$	551,231	$	40		$	(274,152	)	$	642,297

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	1,736	$	175,496	$	3		$	-		$	177,235
Revolving credit facility		-		45,750		-			-			45,750
Accrued turnaround cost		-		10,412		-			-			10,412
Accrued interest		2,504		9		-			-			2,513
Accrued liabilities and other		1,587		8,426		269			-			10,282
Total current liabilities		5,827		240,093		272			-			246,192

Long-term debt		168,689		-		-			-			168,689
Long-term accrued and other liabilities		-		36,954		-			-			36,954
Deferred compensation liability and other		3,723		532		-			-			4,255
Deferred income taxes		16,930		38,183		-			(38,183	)		16,930
Payable to affiliated companies		732		3,271		-			(4,003	)		-

Shareholders’ equity		169,277		232,198		(232	)		(231,966	)		169,277
Total liabilities and shareholders’ equity	$	365,178	$	551,231	$	40		$	(274,152	)	$	642,297

FRONTIER OIL CORPORATION
Condensed Consolidating Statement of Cash Flows
For the Year Ended December 31, 2004
(in thousands)
	FOC (Parent)			FHI (Guarantor Subsidiaries)			Other Non-Guarantor Subsidiaries			Eliminations			Consolidated

Cash flows from operating activities:
Net income	$	69,764		$	101,971		$	62		$	(102,033	)	$	69,764
Equity in earnings of subsidiaries		(165,038	)		-			-			165,038			-
Depreciation and amortization		75			32,688			-			(555	)		32,208
Deferred income taxes		25,005			-			-			-			25,005
Income tax benefits of stock compensation		5,168			-			-			-			5,168
Income taxes eliminated in consolidation		-			62,410			-			(62,410	)		-
Deferred finance cost and bond discount amortization		5,180			304			-			-			5,484
Deferred employee compensation amortization		1,180			-			-			-			1,180
Gain on involuntary conversion of assets		-			(4,411	)		-			-			(4,411	)
Long-term commutation account and prepaid insurance		3,712			-			-			-			3,712
Amortization of long-term prepaid insurance		1,451			-			-			-			1,451
Other		582			(863	)		-			-			(281	)
Changes in components of working capital		(5,664	)		44,286			(3	)		-			38,619
Net cash provided by (used in) operating activities		(58,585	)		236,385			59			40			177,899

Cash flows from investing activities:
Additions to property, plant and equipment		(3	)		(46,459	)		-			(40	)		(46,502	)
Net proceeds from insurance - involuntary conversion claim		-			3,395			-			-			3,395
Net cash used in investing activities		(3	)		(43,064	)		-			(40	)		(43,107	)

Cash flows from financing activities:
Proceeds from issuance of 6⅝% Senior Notes		150,000			-			-			-			150,000
Repurchase of 11¾% Senior Notes		(170,449	)		-			-			-			(170,449	)
Repayments of revolving credit facility, net		-			(45,750	)		-			-			(45,750	)
Proceeds from issuance of common stock		3,923			-			-			-			3,923
Purchase of treasury stock		(3,029	)		-			-			-			(3,029	)
Dividends paid		(5,664	)		-			-			-			(5,664	)
Debt issue costs and other		(3,279	)		(675	)		-			-			(3,954	)
Intercompany transactions		132,649			(132,590	)		(59	)		-			-
Net cash provided by (used in) financing activities		104,151			(179,015	)		(59	)		-			(74,923	)
Increase in cash and cash equivalents		45,563			14,306			-			-			59,869
Cash and cash equivalents, beginning of period		59,846			4,674			-			-			64,520
Cash and cash equivalents, end of period	$	105,409		$	18,980		$	-		$	-		$	124,389

FRONTIER OIL CORPORATION
Condensed Consolidating Statement of Cash Flows
For the Year Ended December 31, 2003
(in thousands)

	FOC (Parent)			FHI (Guarantor Subsidiaries)			Other Non-Guarantor Subsidiaries			Eliminations			Consolidated

Cash flows from operating activities:
Net income	$	3,232		$	40,900		$	(17,992	)	$	(22,908	)	$	3,232
Equity in earnings of subsidiaries		(48,949	)		-			-			48,949			-
Depreciation and amortization		113			29,275			-			(556	)		28,832
Deferred income taxes		2,655			-			-			-			2,655
Income taxes eliminated in consolidation		-			25,485			-			(25,485	)		-
Deferred finance cost and bond discount amortization		2,206			322			8,114			-			10,642
Deferred employee compensation amortization		1,386			-			-			-			1,386
Long-term commutation account and prepaid insurance		(26,566	)		-			-			-			(26,566	)
Amortization of long-term prepaid insurance		423			-			-			-			423
Other		(264	)		(423	)		-			-			(687	)
Changes in components of working capital		49			(25,946	)		(25	)		-			(25,922	)
Net cash provided by (used in) operating activities		(65,715	)		69,613			(9,903	)		-			(6,005	)

Cash flows from investing activities:
Additions to property, plant and equipment		(47	)		(33,630	)		-			-			(33,677	)
Proceeds from sale of assets		240			64			-			-			304
Other investments		(32	)		(895	)		-			-			(927	)
Investment in subsidiaries		(18,039	)		-			18,039			-			-
Net cash (used in) provided by investing activities		(17,878	)		(34,461	)		18,039			-			(34,300	)

Cash flows from financing activities:
Proceeds from issuance of 8% Senior Notes, net of discount		-			-			218,143			-			218,143
Repurchase of 9⅛% Senior Notes		(39,475	)		-			-			-			(39,475	)
Repurchase of 8% Senior Notes		-			-			(220,000	)		-			(220,000	)
Proceeds of revolving credit facility borrowings, net		-			45,750			-			-			45,750
Proceeds from issuance of common stock		1,441			-			-			-			1,441
Purchase of treasury stock		(1,075	)		-			-			-			(1,075	)
Dividends paid		(5,187	)		-			-			-			(5,187	)
Debt issue costs and other		-			(879	)		(6,257	)		-			(7,136	)
Intercompany transactions		81,617			(81,595	)		(22	)		-			-
Net cash provided by (used in) financing activities		37,321			(36,724	)		(8,136	)		-			(7,539	)
Increase in cash and cash equivalents		(46,272	)		(1,572	)		-			-			(47,844	)
Cash and cash equivalents, beginning of period		106,118			6,246			-			-			112,364
Cash and cash equivalents, end of period	$	59,846		$	4,674		$	-		$	-		$	64,520

FRONTIER OIL CORPORATION
Condensed Consolidating Statement of Cash Flows
For the Year Ended December 31, 2002
(in thousands)

	FOC (Parent)			FHI (Guarantor Subsidiaries)			Other Non-Guarantor Subsidiaries			Eliminations			Consolidated

Cash flows from operating activities:
Net income	$	1,028		$	18,760		$	25		$	(18,785	)	$	1,028
Equity in earnings of subsidiaries		(31,704	)		-			-			31,704			-
Depreciation and amortization		247			27,640			-			(555	)		27,332
Deferred income taxes		1,149			-			-			-			1,149
Income taxes eliminated in consolidation		-			12,364			-			(12,364	)		-
Deferred finance cost and bond discount amortization		1,123			910			-			-			2,033
Deferred employee compensation amortization		907			-			-			-			907
Other		365			236			-			-			601
Changes in components of working capital		3,035			14,721			16			-			17,772
Net cash provided by (used in) operating activities		(23,850	)		74,631			41			-			50,822

Cash flows from investing activities:
Additions to property, plant and equipment		(250	)		(29,267	)		-			-			(29,517	)
Other investments		(100	)		-			-			-			(100	)
El Dorado Refinery - contingent earn-out payment		-			(7,500	)		-			-			(7,500	)
Investment in subsidiaries		(181,867	)		-			181,867			-			-
Net cash (used in) provided by investing activities		(182,217	)		(36,767	)		181,867			-			(37,117	)

Cash flows from financing activities:
Repurchase of 9⅛% Senior Notes		(1,090	)		-			-			-			(1,090	)
Proceeds from issuance of common stock		1,702			-			-			-			1,702
Purchase of treasury stock		(787	)		-			-			-			(787	)
Dividends paid		(5,161	)		-			-			-			(5,161	)
Intercompany transactions		214,061			(32,153	)		(181,908	)		-			-
Net cash provided by (used in) financing activities		208,725			(32,153	)		(181,908	)		-			(5,336	)

Increase in cash and cash equivalents		2,658			5,711			-			-			8,369
Cash and cash equivalents, beginning of period		103,460			535			-			-			103,995
Cash and cash equivalents, end of period	$	106,118		$	6,246		$	-		$	-		$	112,364

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of Frontier Oil Corporation:

We have audited the accompanying consolidated balance sheets of Frontier Oil Corporation and subsidiaries (the “Company”) as of December 31, 2004 and 2003, and the related consolidated statements of income, changes in shareholders’ equity and comprehensive income, and cash flows for each of the three years in the period ended December 31, 2004. Our audits also included the financial statement schedules listed in the Index at Item 15. These financial statements and financial statement schedules are the responsibility of the Company’s management. Our responsibility is to express an opinion on the financial statements and financial statement schedules based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Frontier Oil Corporation and subsidiaries as of December 31, 2004 and 2003, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2004, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth therein.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 1, 2005 expressed an unqualified opinion on management’s assessment of the effectiveness of the Company’s internal control over financial reporting and an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

DELOITTE & TOUCHE LLP

Houston, Texas

March 1, 2005

SELECTED QUARTERLY FINANCIAL AND OPERATING DATA
(Dollars in thousands, except per share)
	2004												2003
Unaudited	Fourth			Third			Second			First			Fourth			Third			Second			First
Revenues	$	803,404		$	785,076		$	735,904		$	537,332		$	542,943		$	594,763		$	533,413		$	499,384
Operating income		15,881			42,557			85,433			(322	)		14,830			27,304			8,599			1,131
Net income (loss)		239			23,792			49,469			(3,736	)		4,102			3,822			(992	)		(3,700	)
Basic earnings (loss) per share		0.01			0.89			1.86			(0.14	)		0.16			0.15			(0.04	)		(0.14	)
Diluted earnings (loss) per share		0.01			0.87			1.81			(0.14	)		0.15			0.14			(0.04	)		(0.14	)
Net cash provided by (used in) operating activities		72,443			42,058			79,248			(15,850	)		(35,322	)		29,341			19,315			(19,339	)
Net cash used in investing activities		(10,057	)		(2,950	)		(12,111	)		(17,989	)		(7,544	)		(7,193	)		(12,956	)		(6,607	)
Net cash provided by (used in) financing activities		(60,738	)		(4,453	)		(41,685	)		31,953			770			6,646			(42,468	)		27,513
Adjusted EBITDA (1)		27,978			50,723			93,970			7,497			22,475			34,460			15,670			8,091
Refining operations:
Total charges (bpd) (2)		164,581			169,436			172,951			152,015			166,347			177,364			173,610			144,824
Gasoline yields (bpd) (3)		85,997			84,477			86,782			74,468			87,937			86,014			85,056			74,614
Diesel and jet fuel yields (bpd) (3)		54,898			55,057			54,917			47,459			53,059			57,321			59,324			42,760
Total product sales (bpd)		169,518			174,204			171,460			148,642			169,233			176,914			171,215			144,921
Average gasoline crack spread (per bbl)	$	3.71		$	8.88		$	14.23		$	7.49		$	5.22		$	9.70		$	7.24		$	5.85
Average diesel crack spread (per bbl)		9.84			8.10			7.39			4.07			5.57			4.75			3.91			5.95
Average light/heavy crude oil differential (per bbl)		13.34			9.28			8.81			8.17			7.66			6.81			6.56			7.37
Average WTI/WTS crude oil differential (per bbl)		5.82			2.95			3.29			2.88			2.71			2.44			3.19			2.38

(1)

Adjusted EBITDA represents income before interest expense, interest income, merger financing termination costs (includes both interest expense and income), income tax, and depreciation and amortization. Adjusted EBITDA is not a calculation based upon generally accepted accounting principles; however, the amounts included in the adjusted EBITDA calculation are derived from amounts included in the consolidated financial statements of the Company. Adjusted 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. Adjusted EBITDA is not necessarily comparable to similarly titled measures of other companies. Adjusted 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. Adjusted EBITDA is also used for internal analysis and as a basis for financial covenants. Frontier’s adjusted EBITDA is reconciled to net income as follows (in thousands):

	2004												2003
	Fourth			Third			Second			First			Fourth			Third			Second			First
Net income (loss)	$	239		$	23,792		$	49,469		$	(3,736	)	$	4,102		$	3,822		$	(992	)	$	(3,700	)
Add provision (benefit) for income taxes		330			13,437			30,813			(2,241	)		2,526			2,940			(288	)		(2,222	)
Add interest expense and other financing costs		19,955			5,813			5,949			5,856			7,997			6,590			6,733			7,426
Subtract interest income		(826	)		(485	)		(204	)		(201	)		(202	)		(260	)		(274	)		(373	)
Add merger financing termination costs, net		-			-			-			-			407			14,212			3,420			-
Add depreciation and amortization		8,280			8,166			7,943			7,819			7,645			7,156			7,071			6,960
Adjusted EBITDA	$	27,978		$	50,723		$	93,970		$	7,497		$	22,475		$	34,460		$	15,670		$	8,091

(2)	Charges are the quantity of crude oil and other feedstock processed through refinery units.

(3)	Manufactured product yields are the volumes of specific materials that are obtained through the distilling of crude oil and the operations of other refinery process units.

Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

None.

Item 9A. Controls And Procedures

The information contained in this Form 10-K, as well as the financial and operational data we present concerning the Company, is prepared by management. Our financial statements are fairly presented in all material respects in conformity with generally accepted accounting principles. It has always been our intent to apply proper and prudent accounting guidelines in the presentation of our financial statements, and we are committed to full and accurate representation of our condition through complete and clear disclosures.

We maintain a set of disclosure controls and procedures that are designed to ensure that information required to be disclosed by us in the reports filed by us under the Securities Exchange Act of 1934, as amended (“Exchange Act”) is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. As of the end of the period covered by this report, we evaluated, under the supervision and with the participation of our management, including our Chairman of the Board, President and Chief Executive Officer and our Executive Vice President - Finance & Administration, Chief Financial Officer, the effectiveness of our disclosure controls and procedures pursuant to Rule 13a-15 of the Exchange Act. Based on that evaluation, our Chairman of the Board, President and Chief Executive Officer and our Executive Vice President - Finance & Administration, Chief Financial Officer concluded that our disclosure controls and procedures are effective.

During the most recent fiscal quarter, there have been no changes in our internal control over financial reporting that have materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

MANAGEMENT’S REPORT ON INTERNAL

CONTROL OVER FINANCIAL REPORTING

The management of Frontier Oil Corporation is responsible for establishing and maintaining adequate internal control over financial reporting. Our internal control system was designed to provide reasonable assurance to the Company’s management and board of directors regarding the preparation and fair presentation of published financial statements. All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.

Frontier Oil Corporation’s management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004. In making this assessment, it used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control-Integrated Framework. Based on our assessment, we believe that, as of December 31, 2004, the Company’s internal control over financial reporting is effective based on those criteria.

Frontier Oil Corporation’s independent auditors have issued an audit report on our assessment of the Company’s internal control over financial reporting. This report appears on the following page.

February 22, 2005

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

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of Frontier Oil Corporation:

We have audited management’s assessment, included in the accompanying Management’s Report on Internal Control Over Financial Reporting, that Frontier Oil Corporation (the “Company”) maintained effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, management’s assessment that the Company maintained effective internal control over financial reporting as of December 31, 2004, is fairly stated, in all material respects, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2004, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements and financial statement schedules as of and for the year ended December 31, 2004 of the Company and our report dated March 1, 2005 expressed an unqualified opinion on those consolidated financial statements and financial statement schedules.

DELOITTE & TOUCHE LLP

Houston, Texas

March 1, 2005

PART III

The information called for by Part III of this Form is incorporated by reference from the Company’s definitive proxy statement to be filed with the SEC pursuant to Regulation 14A within 120 days after the close of its last fiscal year.

PART IV

Item 15. Exhibits and Financial Statement Schedules

(a)1. Financial Statements and Supplemental Data

Consolidated Statements of Income

Consolidated Balance Sheets

Consolidated Statements of Cash Flows

Consolidated Statements of Changes in Shareholders’ Equity and Statements of Comprehensive Income

Notes to Consolidated Financial Statements

Reports of Independent Registered Public Accounting Firm

Selected Quarterly Financial Data

(a)2. Financial Statements Schedules

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

2.1

Agreement and Plan of Merger, dated March 30, 2003, by and among Frontier Oil Corporation (the “Company”), Front Range Himalaya Corporation, Front Range Merger Corporation, Himalaya Merger Corporation and Holly Corporation (incorporated by reference and filed as Exhibit 99.2 to Form 8-K dated March 30, 2003, filed April 2, 2002, File Number 1-07627).

3.1

Restated Articles of Incorporation of Wainoco Oil Corporation (now Frontier Oil Corporation) dated August 5, 1987 (Exhibit 3.1.1 to Registration Statement No. 333-120643, filed November 19, 2004).

3.2

Articles of Amendment to the Restated Articles of Incorporation of Wainoco Oil Corporation (now Frontier Oil Corporation) dated June 14, 1988 (Exhibit 3.1.2 to Registration Statement Number 333-120643, filed November 19, 2004).

3.3

Articles of Amendment to the Restated Articles of Incorporation of Wainoco Oil Corporation (now Frontier Oil Corporation) dated April 24, 1992 (Exhibit 3.1.3 to Registration Statement Number 333-120643, filed November 19, 2004).

3.4

Articles of Amendment to the Restated Articles of Incorporation of Wainoco Oil Corporation (now Frontier Oil Corporation) dated April 27, 1998 (Exhibit 3.1.4 to Registration Statement Number 333-120643, filed November 19, 2004).

3.5

Fourth Restated Bylaws of Wainoco Oil Corporation (now Frontier Oil Corporation), as amended through February 20, 2002 (Exhibit 3.2 to Wainoco Oil Corporation’s Annual Report on Form 10-K, File Number 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 9⅛% Senior Notes due 2006 (filed as Exhibit 4.8 to Registration Statement Number 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 Number 1-07627, filed November 19, 1999).

4.3

Indenture, dated as of October 1, 2004, among the Company, as issuer, the guarantors party thereto and Wells Fargo Bank, N.A., as trustee relating to the Company’s 6⅝% Senior Notes due 2011 (Exhibit 4.1 to Form 8-K, File Number1-07627, filed October 4, 2004).

4.4

Registration Rights Agreement, dated as of October 1, 2004, among the Company, each of the guarantors party thereto and Bear, Stearns & Co. Inc., BNP Paribas Securities Corp. and TD Securities (USA) Inc. (Exhibit 4.2 to Form 8-K, File Number1-07627, filed October 4, 2004).

10.1

Asset Purchase and Sale Agreement, dated as of October 19, 1999, among Frontier El Dorado Refining Company, as buyer, the Company, as Guarantor, and Equilon Enterprises LLC, as seller (Exhibit 10.1 to Form 8-K, File Number 1-07627, filed December 1, 1999).

10.2

Purchase and Sale Agreement dated May 5, 1997, for the sale of Canadian oil and gas properties (Exhibit to Form 8-K, File Number 1-07627, filed June 30, 1997).

*²

10.3

1968 Incentive Stock Option Plan as amended and restated (Exhibit 10.1 to Form 10-K dated December 31, 1987, File Number 1-07627, filed March 3, 1998).

*²

10.4

1995 Stock Grant Plan for Non-employee Directors (Exhibit 10.14 to Form 10-Q, File Number 1-07627, filed August 3, 1995).

*²

10.5

Frontier Deferred Compensation Plan (previously named Wainoco Deferred Compensation Plan dated October 29, 1993 and filed as Exhibit 10.19 to Form 10-K, File Number 1-07627, filed March 17, 1995).

*²

10.6

Frontier Deferred Compensation Plan for Directors (previously named Wainoco Deferred Compensation Plan for Directors dated May 1, 1994 and filed as Exhibit 10.20 to Form 10-K, File Number 1-07627, filed March 17, 1995).

*²

10.7

Executive Employment Agreement dated December 18, 2000, between the Company and W. Reed Williams (Exhibit 10.10 to Form 10-K, File Number 1-07627, filed March 1, 2002).

*²

10.8

Executive Employment Agreement dated December 18, 2000, between the Company and James R. Gibbs (Exhibit 10.11 to Form 10-K, File Number 1-07627, filed March 1, 2002).

*²

10.9

Executive Employment Agreement dated December 18, 2000, between the Company and Julie H. Edwards (Exhibit 10.12 to Form 10-K, File Number 1-07627, filed March 1, 2002).

*²

10.10

Executive Employment Agreement dated December 18, 2000, between the Company and J. Currie Bechtol (Exhibit 10.13 to Form 10-K, File Number 1-07627, filed March 1, 2002).

*²

10.11

Executive Employment Agreement dated December 18, 2000, between the Company and Jon D. Galvin (Exhibit 10.14 to Form 10-K, File Number 1-07627, filed March 1, 2002).

*²

10.12

Executive Employment Agreement dated December 18, 2000, between the Company and Gerald B. Faudel (Exhibit 10.15 to Form 10-K, File Number 1-07627, filed March 1, 2002).

*²

10.13

Executive Employment Agreement dated February 28, 2001, between the Company and Nancy J. Zupan (Exhibit 10.16 to Form 10-K, File Number 1-07627, filed March 1, 2002).

*²

10.14

Frontier Oil Corporation Restricted Stock Plan (Exhibit 99.1 to Registration Statement Number 333-56946, filed March 13, 2001).

*²

10.15

Amended and Restated Frontier Oil Corporation 1999 Stock Plan (Exhibit 99.1 to Registration Statement Number 333-89876, filed June 6, 2002).

10.16

Crude Oil Supply Agreement dated October 15, 2002, between Baytex Energy Ltd. and Frontier Oil and Refining Company (Exhibit 10.2 to Form 10-Q, File Number 1-07627, filed October 30, 2002). On November 28, 2002, this agreement was assigned by Baytex Energy Ltd. to its wholly-owned subsidiary, Baytex Marketing Ltd.

10.17

Amended and Restated Revolving Credit Agreement, dated May 27, 2003, among the Company, 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 PNB Paribas, as syndication agent (Exhibit 99.2 to Form 8-K, File Number 1-07627, filed May 29, 2003).

10.18

Second Amended and Restated Revolving Credit Agreement dated November 22, 2004, among the Company, Frontier Oil and Refining Company, as borrower, the lenders named therein, Union Bank of California, N.A., as administrative agent, and PNB Paribas, as syndication agent (Exhibit 10.1 to Form 8-K, File Number 1-07627, filed November 24, 2004).

Subsidiaries of the Registrant.

Consent of Deloitte & Touche LLP.

31.1

Certification by Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2

Certification by Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1

Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2

Certification 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.

² Diamond indicates management contract or compensatory plan or arrangement.

(b)

Exhibits

The Company’s 2004 Annual Report is available upon request. Shareholders of the Company may obtain a copy of any exhibits to this Form 10-K at a charge of $0.05 per page. Requests should be directed to:

Investor Relations

Frontier Oil Corporation

10000 Memorial Drive, Suite 600

Houston, Texas 77024-3411

Frontier Oil Corporation
Condensed Financial Information of Registrant
Balance Sheet
As of December 31,			Schedule I


	2004			2003
ASSETS	(in thousands)
Current Assets:
Cash and cash equivalents	$	105,409		$	59,846
Trade and other receivables		7,013			710
Deferred tax assets		6,748			5,967
Other current assets		105			68
Total current assets		119,275			66,591
Property, plant and equipment, at cost -
Furniture, fixtures and other		1,114			1,111
Less - accumulated depreciation		941			866
		173			245
Deferred financing costs, net		3,252			3,299
Commutation account		16,438			19,550
Prepaid insurance, net		4,542			6,593
Other assets		2,108			4,884
Investment in subsidiaries		295,764			264,016

Total assets	$	441,552		$	365,178

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities:
Accounts payable	$	853		$	1,736
Accrued interest		2,485			2,504
Accrued liabilities and other		3,505			1,587
Total current liabilities		6,843			5,827

Long-term debt		150,000			168,689
Deferred compensation liability		1,516			3,723
Deferred income taxes		42,550			16,930
Payable to affiliated companies		530			732

Shareholders’ equity		240,113			169,277

Total liabilities and shareholders’ equity	$	441,552		$	365,178

The “Notes to Condensed Financial Information of Registrant” and the “Notes to Consolidated Financial Statements” in Item 8 of this Form 10-K are an integral part of these financial statements.

Frontier Oil Corporation
Condensed Financial Information of Registrant
Statements of Income
For the three years ended December 31,				Schedule I


	2004			2003			2002
	(in thousands)

Revenues	$	(6	)	$	(17	)	$	(1	)
		(6	)		(17	)		(1	)
Costs and expenses:
Selling and general expenses, excluding depreciation		15,590			7,936			6,208
Merger termination and legal costs		3,824			8,739			-
Depreciation		75			113			247
		19,489			16,788			6,455

Operating income		(19,495	)		(16,805	)		(6,456	)

Interest expense and other financing costs		35,004			26,981			24,858
Interest income		(1,545	)		(1,004	)		(1,698	)
Equity in earnings of subsidiaries		(165,038	)		(48,949	)		(31,704	)
		(131,579	)		(22,972	)		(8,544	)

Income before income taxes		112,084			6,167			2,088
Provision for income taxes		42,320			2,935			1,060

Net income	$	69,764		$	3,232		$	1,028

Frontier Oil Corporation
Condensed Financial Information of Registrant
Statements of Cash Flows
For the three years ended December 31,				Schedule I

	2004			2003			2002
	(in thousands)
Operating Activities
Net income	$	69,764		$	3,232		$	1,028
Equity in earnings of subsidiaries		(165,038	)		(48,949	)		(31,704	)
Depreciation		75			113			247
Deferred income taxes		25,005			2,655			1,149
Income tax benefits of stock compensation		5,168			-			-
Deferred finance cost and bond discount amortization		5,180			2,206			1,123
Deferred employee compensation amortization		1,180			1,386			907
Long-term commutation account and prepaid insurance		3,712			(26,566	)		-
Amortization of long-term prepaid insurance		1,451			423			-
Other		582			(264	)		365
Changes in components of working capital		(5,664	)		49			3,035
Net cash used by operating activities		(58,585	)		(65,715	)		(23,850	)

Investing Activities
Additions to property, plant and equipment		(3	)		(47	)		(250	)
Proceeds from sale of asset		-			240			-
Other investments		-			(32	)		(100	)
Investment in subsidiaries		-			(18,039	)		(181,867	)
Net cash used by investing activities		(3	)		(17,878	)		(182,217	)

Financing Activities
Proceeds from issuance of 6⅝% Senior Notes		150,000			-			-
Repurchases of debt:
11¾% Senior Notes		(170,449	)		-			-
9⅛% Senior Notes		-			(39,475	)		(1,090	)
Proceeds from issuance of common stock		3,923			1,441			1,702
Purchase of treasury stock		(3,029	)		(1,075	)		(787	)
Intercompany transactions, net		(202	)		117			(30,453	)
Dividends paid to shareholders		(5,664	)		(5,187	)		(5,161	)
Dividends received from subsidiaries		132,851			81,500			244,514
Debt issue costs		(3,279	)		-			-
Net cash provided by financing activities		104,151			37,321			208,725

Increase (decrease) in cash and cash equivalents		45,563			(46,272	)		2,658
Cash and cash equivalents, beginning of period		59,846			106,118			103,460

Cash and cash equivalents, end of period	$	105,409		$	59,846		$	106,118

Frontier Oil Corporation
Valuation and Qualifying Accounts
For the three years ended December 31,					Schedule II


Description	Balance at beginning of period		Additions		Deductions		Balance at end of period
	(in thousands)
2004
Allowance for doubtful accounts	$	500	$	-	$	-	$	500
Turnaround accruals (1)		26,641		13,531		11,646		28,526
Valuation allowance on deferred tax assets		1,555		-		1,555		-

2003
Allowance for doubtful accounts		1,300		103		903		500
Turnaround accruals (1)		26,862		12,163		12,384		26,641
Valuation allowance on deferred tax assets		1,555		-		-		1,555

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		-		1,555		-		1,555


	FRONTIER OIL CORPORATION

	By:	/s/ James R. Gibbs
		James R. Gibbs Chairman of the Board, President and Chief Executive Officer (chief executive officer)


/s/ James R. Gibbs			/s/ T. Michael Dossey
James R. Gibbs Chairman of the Board, President and Chief Executive Officer and Director (chief executive officer)			T. Michael Dossey Director


/s/ Julie H. Edwards			/s/ James H. Lee
Julie H. Edwards Executive Vice President - Finance and Administration, Chief Financial Officer (principal financial officer)			James H. Lee Director


/s/ Nancy J. Zupan			/s/ Paul B. Loyd, Jr.
Nancy J. Zupan Vice President - Controller (principal accounting officer)			Paul B. Loyd, Jr. Director


/s/ Douglas Y. Bech			/s/ Carl W. Schafer
Douglas Y. Bech Director			Carl W. Schafer Director