10-K

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
þOF THE SECURITIES EXCHANGE ACT OF 1934
For the Fiscal Year Ended: December 31, 2005
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
oOF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from . . . . to . . . .
Commission File Number: 1-7627
FRONTIER OIL CORPORATION
(Exact name of registrant as specified in its charter)
Wyoming	74-1895085
(State or other jurisdiction of	(I.R.S. Employer
incorporation or organization)	Identification No.)
10000 Memorial Drive, Suite 600	77024-3411
Houston, Texas	(Zip Code)
(Address of principal executive offices)
Registrant’s telephone number, including area code: (713) 688-9600
Securities registered pursuant to Section 12(b) of the Act:
	Name of Each Exchange
Title of Each Class	on Which Registered
Common Stock	New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:
None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes þ  No ¨
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨ No þ
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ  No ¨
Indicate by check mark if disclosure of delinquent filers pursuant to rule 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ü
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one)
Large accelerated filer þ  Accelerated filer ¨  Non-accelerated filer ¨
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes ¨  No þ
The aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold as of June 30, 2005 was $1.6 billion.
The number of shares of common stock outstanding as of February 22, 2006 was 56,195,790.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Annual Proxy Statement for the registrant’s 2006 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
Item 1A.	Risk Factors Relating to Our Business
Item 1B.	Unresolved Staff Comments
Item 2.	Properties
Item 3.	Legal Proceedings
Item 4.	Submission of Matters to a Vote of Security Holders
	Available Information
Part II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchasers of Equity Securities
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
Item 9B.	Other Information
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 (“SEC”). Such statements are those concerning contemplated transactions and strategic plans, expectations and objectives for future operations. These include, without limitation:

·   statements, other than statements of historical fact, that address activities, events or developments that we expect, believe or anticipate will or may occur in the future;

·   statements relating to future financial performance, future capital sources and other matters; and

·   any other statements preceded by, followed by or that include the words “anticipates,” “believes,” “expects,” “plans,” “intends,” “estimates,” “projects,” “could,” “should,” “may,” or similar expressions.

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

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

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 162,000 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 52,000 bpd on a twelve-month average. We market its refined products primarily in the eastern slope of the Rocky Mountain region, which encompasses eastern Colorado (including the Denver metropolitan area), eastern Wyoming and western Nebraska (the “Eastern Slope”). The Cheyenne Refinery has a coking unit, which allows the refinery to process extensive amounts of heavy crude oil for use as a feedstock. The ability to process heavy crude oil lowers our raw material costs because heavy crude oil is generally less expensive than lighter types of crude oil. For the year ended December 31, 2005, heavy crude oil constituted approximately 82% of the Cheyenne Refinery’s total crude oil charge. For the year ended December 31, 2005, the Cheyenne Refinery’s product yield included gasoline (43%), diesel fuel (30%) and asphalt and other refined petroleum products (27%).

El Dorado Refinery. The El Dorado Refinery 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, and starting in 2006, to Canada. This access, combined with the El Dorado Refinery’s complexity (including a coking unit), gives it the flexibility to refine a wide variety of crude oils. In connection with our acquisition of the El Dorado Refinery in late 1999, we entered into a 15-year refined product offtake agreement for gasoline and diesel production at this refinery with Shell Oil Products US (“Shell”). Shell will also purchase all jet fuel production until the end of the product offtake agreement. As our deliveries to Shell under the refined product offtake agreement have declined, we have marketed an increasing portion of the El Dorado Refinery’s gasoline and diesel in the same markets where Shell currently sells the El Dorado Refinery’s products, primarily in Denver and throughout the Plains States. For the year ended December 31, 2005, the El Dorado Refinery’s product yield included gasoline (55%), diesel and jet fuel (35%) and chemicals and other refined petroleum products (10%).

Other Assets. We also own 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 and Products. Traditionally, crude oil has been classified within the following types:

·   sweet (low sulfur content),

·   sour (high sulfur content),

·   light (high gravity),

·   heavy (low gravity) and

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

For the most part, heavy crude oil tends to be sour and light crude oil tends to be sweet. When refined, light crude oil produces a higher proportion of high 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 light crude oil is known in the industry as the light/heavy spread or differential. Coking units, such as the ones at our Refineries, can process certain by-products and heavy residual oils to produce additional volumes of gasoline and diesel, thus increasing the aggregate yields of higher margin refined products from the same initial volume of crude oil.

Refineries are frequently classified according to their complexity, which refers to the number, type and capacity of processing units at the refinery. Each of our refineries possesses a coking unit, which provides substantial upgrading capacity. Upgrading capacity refers to the ability of a refinery to produce high yields of high margin refined products such as gasoline and diesel from heavy and intermediate crude oil. In contrast, refiners with low upgrading capacity must process primarily light, sweet crude oil to produce a similar yield of gasoline and diesel. Some low complexity refineries may be capable of processing heavy and intermediate crude oil, but they will produce large volumes of by-products, including heavy residual oils and asphalt. Because gasoline, diesel and jet fuel sales generally achieve higher margins than are available on other refined products, we expect that these products will continue to make up the majority of our production.

Refinery Maintenance. Each of the 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 between our two Refineries. Maintenance turnarounds are implemented using our regular personnel as well as additional contract labor. Once started, turnaround work typically proceeds 24 hours per day to minimize unit downtime. We 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.

During 2005 at the El Dorado Refinery, we had a major turnaround on the fluid catalytic cracking unit (“FCCU”) and installed a new main fractionator for the FCCU. In connection with the FCCU turnaround we also performed a turnaround on the FCCU gas oil hydrotreater. We have no major turnaround work scheduled for the El Dorado Refinery during 2006. However, an existing distillate hydrotreater will be revamped and loaded with new catalyst in preparation for the production of ultra-low sulfur diesel (“ULSD”). Also, construction of a new hydrogen manufacturing plant and a new distillate hydrotreater will be completed during the second quarter of 2006. Those units will be brought on-line and will complete plant modifications necessary to fully comply with the 2006 regulations pertaining to the production of ULSD. During 2005, the only turnaround at the Cheyenne Refinery was on the coker, which had an abbreviated work scope since we are expanding the unit and replacing all three drums in 2007. The major turnaround work to be performed at the Cheyenne Refinery during 2006 is on the alkylation plant. However, the distillate hydroteater unit at the Cheyenne Refinery will also be revamped in preparation for the production of ULSD, including the modification of an existing reactor and addition of a new reactor and furnace. The FCCU turnaround cycle for the Cheyenne Refinery has been deferred from 2006 to 2007 and will be performed concurrent with the crude unit turnaround and the coker expansion.

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, 2005, we sold approximately 86% of the Cheyenne Refinery’s gasoline sales volumes in Colorado and 10% in Wyoming. For the year ended December 31, 2005, we sold approximately 30% of the Cheyenne Refinery’s diesel in Colorado and 62% in Wyoming. Because of the location of the Cheyenne Refinery, we are able to sell a significant portion of its diesel product from the truck rack at the Refinery, thereby eliminating transportation costs. The gasoline and remaining diesel produced by this Refinery are primarily shipped via pipeline to terminals for distribution by truck or rail. Pipeline shipments from the Cheyenne Refinery are handled mainly by the Rocky Mountain pipeline, serving Denver and Colorado Springs, Colorado, and the ConocoPhillips pipeline, serving Sidney, Nebraska.

We sell refined products from our Cheyenne Refinery to a broad base of independent retailers, jobbers and major oil companies. Refined product prices are determined by local market conditions at distribution centers known as “terminal racks.” 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, 2005, approximately 85% 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 Valero pipeline, serving the northern Plains States, the Magellan Pipeline Company, L.P. (“Magellan”) mountain pipeline serving Denver, Colorado, and the Magellan mid-continent pipeline serving the Plains States handle shipments from our El Dorado Refinery.

In connection with our late 1999 acquisition of the El Dorado Refinery, we entered into a 15-year refined product offtake agreement with Shell. For the year ended December 31, 2005, Shell was the El Dorado Refinery’s largest customer, representing 67% of total sales. Under the offtake agreement, Shell purchases gasoline, diesel and jet fuel produced by the El Dorado Refinery at market-based prices. Initially in 1999, Shell purchased all of the El Dorado Refinery’s production of these products. Beginning in 2000, we retained and marketed 5,000 bpd of the Refinery’s gasoline and diesel production. The retained portion is scheduled to increase by 5,000 bpd each year for ten years. In 2005, we retained 30,000 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. As our sales to Shell under this agreement decrease, we intend to sell the gasoline and diesel produced by the El Dorado Refinery in the same general markets 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, three principal refineries serve the Denver market: a 70,000 bpd refinery near Rawlins, Wyoming and a 25,000 bpd refinery in Casper, Wyoming, both owned by Sinclair Oil Company (“Sinclair”); and a 90,000 bpd refinery located in Denver and owned by Suncor Energy (U.S.A.) Inc. (“Suncor”). Five product pipelines also supply Denver, including three from outside the region that enable refined products from other regions to be sold in the Denver market. Refined products shipped from other regions typically bear the burden of higher transportation costs.

The Suncor refinery located in Denver has lower product transportation costs to serve the Denver market than we do. However, the Cheyenne Refinery has lower crude oil transportation costs because of its proximity to the Guernsey, Wyoming hub, the major crude oil pipeline hub in the Rocky Mountain region, and because of our ownership interest in the Centennial pipeline, which runs from Guernsey to the Cheyenne Refinery. Moreover, unlike Sinclair and Suncor, we only sell our products to the wholesale market. We believe that our commitment to the wholesale market gives us a marketing advantage over our principal competitors in the Eastern Slope area, all of which also have retail outlets, because we do not compete directly with independent retailers of gasoline and diesel.

El Dorado Refinery. The El Dorado Refinery faces competition from other Plains States and mid-continent refiners, but the principal competitors for the El Dorado Refinery are Gulf Coast refiners. Although our Gulf Coast competitors typically have lower production costs because of their size (economies of scale) than the El Dorado Refinery, we believe that our competitors’ higher refined product transportation costs allow our El Dorado Refinery to compete effectively in the Plains States and Rocky Mountain region with the Gulf Coast refineries. The Plains States and mid-continent regions are supplied by three product pipelines that originate from the Gulf Coast.

Crude Oil Supply

Cheyenne Refinery. In the year ended December 31, 2005, we obtained approximately 24% of the Cheyenne Refinery’s crude oil charge from Wyoming, 61% from Canada and 15% from Colorado. During the same period, heavy crude oil constituted approximately 82% 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 Poplar and Butte pipelines. The Cheyenne Refinery’s ability to process 82% heavy crude oil in 2005 gave us a distinct advantage over the three other Eastern Slope refineries, none of which has the necessary upgrading capacity to process such 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. This type of crude oil typically sells at a discount to lighter crude oils. Our price for 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 term of the agreement runs through December 31, 2007.

El Dorado Refinery. In the year ended December 31, 2005, we obtained approximately 73% of the El Dorado Refinery’s crude oil charge from Texas, 10% from Kansas, 8% from Louisiana, 7% from the North Sea and the remaining from the Middle East and Russia. 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 90% of our crude oil charge during the year ended December 31, 2005. 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 20,000 bpd of crude oil on the Spearhead Pipeline from Griffith, Indiana to Cushing, Oklahoma once reversal of the pipeline was completed. Enbridge Energy Company completed this reversal of the Spearhead Pipeline and has been accepting line fill volumes since December 2005. Deliveries into Cushing are scheduled to start during March of 2006. This pipeline will enable us to transport heavy 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 (expected to be March 2006). We have the right to extend the Agreement for an additional ten years and increase the volume transported under the preferential tariff to 50,000 bpd.

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, recordkeeping 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’s OSHA recordable incident rate in 2005 of 1.07 continues to be below the industry average of 1.16 as compiled by the National Petrochemical and Refiner’s Association (“NPRA”). For their 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 recordable incidence rate of 1.2 or less,

(2)   the Gold Award for a 25% or greater reduction in the recordable rate as compared to the three-year average,

(3)   the Award for Safety Achievement in Hours for 1.9 million hours worked without a lost time accident, and

(4)   the Award for Safety Achievement in Years for 3.25 years worked 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 contributed to a very positive safety trend at the Cheyenne Refinery. The combination of our behavioral safety program with the management driven safety programs has significantly improved the safety culture for our entire workforce at the Cheyenne Refinery. We are determined not only to sustain our safety record at the Cheyenne Refinery, but to further improve it.

Because our contractor injury rate is higher than our employee injury rate at our Cheyenne Refinery, we increased our efforts on contractor safety in 2005. 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. The growth of the program was successful in our geographic region during 2005. By improving the training of the contractor workforce in general, we expect to improve the safety of the outside labor we hire at our Cheyenne Refinery as well as that of other industrial facilities in our geographic region.

The El Dorado Refinery dramatically improved its safety record last year, from an OSHA recordable incident rate of 1.94 in 2004 to zero for 2005, which is much better than the NPRA industry average of 1.16. For their outstanding improvement in safety, the personnel at El Dorado will be awarded three safety awards by the NPRA, which are:

(1)   an award for Meritorious Safety Performance for achieving the recordable incidence rate of 1.2 or less,

(2)   the Gold Award for a 25% or greater reduction in the recordable rate as compared to the three-year average, and

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

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 drove the excellent results for 2005. Encouraging all employees to contribute toward improving safety performance through personal involvement in safety-related activities is an industry-proven way to reduce injuries.

Achieving a zero OSHA recordable rate during 2005 is a tremendous accomplishment for our El Dorado refinery employees. While we are very proud of the safety performance of our employees during 2005, we also recognize a need to assist our contractors to improve their safety performance. We have implemented two initiatives in 2006 to help our contractors. First, we are working to start a Safety Council for Kansas and Oklahoma as we did in Wyoming and Montana. The Safety Council of Kansas and Oklahoma will provide consistent and high quality safety training for the employees of all contractors in this geographic area. Second, the personnel at the El Dorado Refinery have been very successful with our Brothers Keeper Program, which is a peer safety observation and feedback process. We are transferring this behavioral training approach to our contractors so their employees can use the same peer review process that has produced positive results for us. These and other cooperative programs should increase the active participation of contractor employees and help our contractors to improve their safety performance during 2006.

Government Regulation

Environmental Matters.

See Note 8 in the “Notes to Consolidated Financial Statements”.

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 and holds 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, 2005, we employed approximately 727 full-time employees: 78 in the Houston and Denver offices, 267 at the Cheyenne Refinery, and 382 at the El Dorado Refinery. The Cheyenne Refinery employees include 94 administrative and technical personnel and 173 union members. The El Dorado Refinery employees include 138 administrative and technical personnel and 244 union members. The union members at our El Dorado Refinery are represented by the United Steel, Paper and Forestry, Rubber, Manufacturing, Energy, Allied Industrial and Service Workers International Union (“USW”). The union members at our Cheyenne Refinery are represented by seven bargaining units, the largest being the USW.

In September 2005, the Company, the USW, and its Local 8-0574 (which represents approximately 150 workers at the Cheyenne Refinery) entered into an extension agreement of the previous contract. This extension represents an early settlement of the Cheyenne Refinery contract, which was set to expire in July 2006. The new agreement, which reflects the “national pattern” for the USW, extends the contract until July 2009.

In April 2005, the Company, the USW, and its Local 5-241 (which represents approximately 250 workers at the El Dorado Refinery) entered into an extension agreement of its previous contract. This extension represents an early settlement of the El Dorado Refinery contract, which was set to expire January 31, 2006. The new agreement, which reflects the “national pattern” for the USW, extends the contract until January 31, 2009.

Item 1A.    Risk Factors Relating to Our Business

Crude oil prices and refining margins significantly impact our cash flow and have fluctuated substantially in the past.

Our cash flow from operations is primarily dependent upon producing and selling refined products at margins that are high enough to cover our fixed and variable expenses. In recent years, crude oil costs and crack spreads (the difference between refined product sales prices and crude oil prices) have fluctuated substantially. Factors that may affect crude oil costs and refined product prices include:

·   overall demand for crude oil and refined products;

·   general economic conditions;

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

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

·   the marketing of alternative and competing fuels;

·   the extent of government regulation;

·   global market dynamics;

·   product pipeline capacity;

·   local market conditions; and

·   the level of operations of competing refineries.

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

·   major oil companies;

·   crude oil marketing companies;

·   large independent producers; and

·   smaller local producers.

The price at which we can sell gasoline and other refined products is strongly influenced by the price of crude oil. Generally, an increase or decrease in the price of crude oil results in a corresponding increase or decrease in the price of gasoline and other refined products. However, if crude oil prices increase significantly, our operating margins would fall unless we could pass along these price increases to our customers. From time to time, we purchase forward crude oil supply contracts, enter into forward product agreements to hedge excess inventories and/or 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 affected by crude oil differentials, which increased significantly in 2005 over 2004 levels.

The light/heavy crude oil differential that we report 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 our Cheyenne Refinery. 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. Starting in March 2006, when we anticipate that our El Dorado Refinery will begin receiving heavy Canadian crude oil through the Spearhead Pipeline, its profitability will also benefit from the light/heavy 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 higher refining margin than light or sweet crude oil does. Accordingly, any tightening of these crude oil differentials will reduce our profitability. The light/heavy crude oil differential averaged $15.32 per barrel in the year ended December 31, 2005, compared to $9.90 per barrel in the same period in 2004. The WTI/WTS crude oil differential averaged $4.51 per barrel in the year ended December 31, 2005, compared to $3.74 per barrel in the same period in 2004. Crude oil prices were historically high during 2005, 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 in the future.

External factors beyond our control can cause fluctuations in demand for our products, our prices and margins, which may negatively affect income and cash flow.

External factors can also cause significant fluctuations in the 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 and 2005, 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.

We are dependent on others to supply us with substantial quantities of raw materials.

Our business involves converting crude oil and other refinery charges into liquid fuels. We own no crude oil or natural gas reserves and depend on others to supply these feedstocks to our Refineries. We use large quantities of natural gas and electricity to provide heat and mechanical energy required by our process units. Disruption to our supply of crude oil, natural gas or electricity could have a material adverse effect on our operations.

Our Refineries face operating hazards,and the potential limits on insurance coverage could expose us to significant liability costs.

Our operations could be subject to significant interruption, and our profitability could be impacted if any of our Refineries experienced a major accident or fire, was damaged by severe weather or other natural disaster, or was otherwise forced to curtail its operations or shut down. If a pipeline became 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 many years. One or more of the units may require additional unscheduled down time for unanticipated maintenance or repairs that are more frequent than our scheduled turnaround for such units. Scheduled and unscheduled maintenance could reduce our revenues during the period of time that our units are not operating.

We face substantial competition from other refining and pipeline companies, and an increase in competition in the markets in which we sell refined product could adversely affect our sales and profitability.

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

We are not engaged in the petroleum exploration and production business and therefore do not produce any of our crude oil feedstocks. We do not have a retail business and therefore are dependent upon others for outlets for our refined products. Certain of our competitors, however, obtain a portion of their feedstocks from company-owned production and have retail outlets. Competitors that have their own production or extensive retail outlets, with brand-name recognition, are at times able to offset losses from refining operations with profits from producing or retailing operations, and may be better positioned to withstand periods of depressed refining margins or feedstock shortages. In addition, we compete with other industries that provide alternative means to satisfy the energy and fuel requirements of our industrial, commercial and individual consumers. If we are unable to compete effectively with these competitors, both within and outside of our industry, there could be a material adverse effect on our business, financial condition and results of operations.

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 extensive federal, state and local environmental and health and safety laws and regulations relating to the protection of the environment, including those governing the emission or discharge of pollutants into the air and water, product specifications and the generation, treatment, storage, transportation 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. Any noncompliance with these laws and regulations could subject us to material administrative, civil or criminal penalties or other liabilities.

We are a defendant in a series of lawsuits alleging, among other things, that emissions from an oil field or the production facilities thereon at the campus of the Beverly Hills High School, which were owned and operated by one of our subsidiaries between 1985 and 1995, caused the plaintiffs to develop cancers or various health problems. We could be subject to liability if these lawsuits are resolved adversely to us and the amount of the liability exceeds both the loss mitigation insurance we have purchased and any coverage under insurance policies that were in effect at the time that the alleged incidents occurred. See Note 8 in the “Notes to Consolidated Financial Statements” for more information on these lawsuits.

Our business is inherently subject to accidental spills, discharges or other releases of petroleum or hazardous substances. Past or future spills related to any of our operations, including our Refineries, pipelines or product terminals, could give rise to liability (including potential cleanup responsibility) to governmental entities or private parties under federal, state or local environmental laws, as well as under common law. This could involve contamination associated with facilities that we currently own or operate, facilities that we formerly owned or operated and facilities to which we sent wastes or by-product for treatment or disposal and other contamination. Accidental discharges could occur in the future, future action may be taken in connection with past discharges, governmental agencies may assess penalties against us in connection with past or future contamination and third parties may assert claims against us for damages allegedly arising out of any past or future contamination. The potential penalties and clean-up costs for past or future releases or spills, the failure of 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.

We could incur substantial costs or disruptions in our business if we cannot obtain or maintain necessary permits and authorizations.

Our operations require numerous permits and authorizations under various laws and regulations, including environmental and health and safety laws and regulations. These authorizations and permits are subject to revocation, renewal or modification and can require operational changes, which may involve significant costs, to limit impacts or potential impacts on the environment and/or health and safety. A violation of these authorization or permit conditions or other legal or regulatory requirements could result in substantial fines, criminal sanctions, permit revocations, injunctions and/or refinery shutdowns. In addition, major modifications of our operations could require modifications to our existing permits or expensive upgrades to our existing pollution control equipment, which could have a material adverse effect on our business, financial condition or results of operations.

Hurricanes along the Gulf Coast could disrupt our supply of crude oil and our ability to complete capital improvement projects in a timely manner.

In August and September of 2005, Hurricanes Katrina and Rita and related storm activity, such as windstorms, storm surges, floods and tornadoes, caused extensive and catastrophic physical damage in and to coastal and inland areas located in the Gulf Coast region of the United States (parts of Texas, Louisiana, Mississippi and Alabama) and certain other parts of the southeastern parts of the United States. Some of the materials we use for our capital projects are fabricated at facilities located along the Gulf Coast. Should other storms of this nature occur in the future, it is possible that the storms and their collateral effects could result in delays or cost increases for our planned capital projects.

In addition, supplies of crude oil to our El Dorado Refinery are sometimes shipped from Gulf Coast production or terminaling facilities. This crude oil supply source would be potentially threatened in the event of future catastrophic damage.

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

Approximately 57 percent of our employees were covered by collective bargaining agreements at December 31, 2005. 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 Item 1 “Business-Employees.”

Terrorist attacks and threats or actual war may negatively impact our business.

Terrorist attacks in the United States and the war in Iraq, as well as events occurring in response to or in connection with them, including future terrorist attacks against U.S. targets, rumors or threats of war, actual conflicts involving the United States or its allies, or military or trade disruptions affecting our suppliers or our customers, could adversely impact our operations. In addition, any terrorist attack could have an adverse impact on energy prices, including prices for our crude oil and refined products, and an adverse impact on the margins from our refining and marketing operations. As a result, there could be delays or losses in the delivery of supplies and raw materials to us, decreased sales of our products and extension of time for payment of accounts receivable from our customers.

Item 1B.    Unresolved Staff Comments

None.

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.

Other Properties

We lease approximately 6,500 square feet of office space in Houston, Texas for our corporate headquarters under a lease expiring in October 2009. We also lease approximately 28,000 square feet of office space in Denver, Colorado under a sublease expiring in December 2006 for our refining, marketing and raw material supply operations. We are in the process of renegotiating this lease or securing a lease on similar office space before the end of 2006.

Item 3.    Legal Proceedings

See Note 8 in the “Notes to Consolidated Financial Statements”.

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

None.

Available Information

We file reports with the SEC, including annual reports on Form 10-K, quarterly reports on Form 10-Q and other reports from time to time. The public may read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Room 1580, Washington, DC 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. We are an electronic filer, and the SEC’s Internet site at http://www.sec.gov contains the reports, proxy and information statements, and other information filed electronically.

As required by Section 402 of the Sarbanes-Oxley Act of 2002, we have adopted a code of ethics that applies to our chief executive officer, chief financial officer and principal accounting officer. This code of ethics is posted on our web site. Our web site address is: http://www.frontieroil.com. We make our web site content available for informational purposes only. It should not be relied upon for investment purposes, nor is it incorporated by reference in this Form 10-K. We make available on this web site under “Investor Relations,” free of charge, our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports as soon as reasonably practicable after we electronically file those materials with, or furnish those materials to, the SEC.

We filed our 2005 annual CEO certification with the New York Stock Exchange (“NYSE”) on May 2, 2005. We anticipate filing our 2006 annual CEO certification with the NYSE on or about May 2, 2006. In addition, we filed with the SEC as exhibits to our Form 10-K for the year ended December 31, 2004 the CEO and CFO certifications required under Section 302 of the Sarbanes-Oxley Act of 2002.

PART II

Item 5.    Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Our common stock is listed on the New York Stock Exchange under the symbol FTO. The quarterly high and low sales prices (as adjusted for our June 17, 2005 stock split) as reported on the New York Stock Exchange for 2005 and 2004 are shown in the following table:

2005	High	Low
Fourth quarter Third quarter Second quarter First quarter	$ 45.87    46.18    29.82    18.45	$ 31.54    26.55    18.45    11.95
2004	High	Low
Fourth quarter Third quarter Second quarter First quarter	$ 13.47    11.86    10.60      9.93	$ 11.12      9.12      8.50      8.04

The approximate number of holders of record for our common stock as of February 16, 2006 was 912. Quarterly cash dividends of $0.025 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 $0.03 per share for the quarters ended September 30, 2004 through March 31, 2005. The quarterly cash dividend was $0.04 per share for the quarters ended June 30, 2005 through December 31, 2005. In addition, a special cash dividend of $1.00 per share was declared for the quarter ended December 31, 2005 and paid on January 11, 2006, to shareholders of record on December 15, 2005. The 6.625% Notes may restrict dividend payments based on the covenants related to interest coverage and restricted payments.

The following table sets forth information regarding equity securities that we have repurchased.

Period	Total Number of Shares Purchased	Average Price Paid Per Share	Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs (1)	Maximum Number of Shares that May Yet Be Purchased Under the Plans or Programs (2)
October 1, 2005 to October 31, 2005	-	-	-	7,165,268
November 1, 2005 to November 30, 2005	425,000	$ 32.9141	425,000	6,740,268
December 1, 2005 to December 31, 2005	195,800	38.9405	195,800	6,544,468
Total fourth quarter	620,800	$ 34.8148	620,800	6,544,468

(1)  Shares were purchased under a stock repurchase program initially authorized by our Board of Directors on September 1, 1998, and with several subsequent increases, authorized repurchases up to eight million shares. In August 2005, our Board of Directors confirmed that the number of shares previously authorized under the stock repurchase program had been doubled as a result of our June 2005 stock split to authorize repurchases up to sixteen million shares. The program has no expiration date but may be terminated by the Board of Directors at any time. On November 30, 2005, our Board of Directors confirmed utilizing up to $100 million for share repurchases in the near-term (which we anticipate continuing throughout 2006) under this program, and as of December 31, 2005, $7.6 million (195,800 shares) of the $100 million had been utilized for repurchases. No shares were purchased during the periods shown other than through publicly-announced programs.

(2)  Shares shown in this column reflect authorized shares remaining which may be repurchased under the stock repurchase program referenced in note 1 above (as adjusted for our two-for-one stock split in June 2005).

Item 6.    Selected Financial Data

Five Year Financial Data
	Years Ended December 31,
		2005		2004	2003		2002	2001
	(Dollars in thousands, except per share amounts)
Revenues		$  4,001,162		$  2,861,716	$  2,170,503	$	$  1,813,750	$  1,888,401
Operating income		446,009		143,549	51,864		27,899	164,100
Cumulative effect of accounting change, net of income taxes		(2,503	)	-	-		-	-
Net income		272,532		69,764	3,232		1,028	107,653
Basic earnings per share:
Before cumulative effect of accounting change		4.97		1.31	0.06		0.02	2.06
Cumulative effect of accounting change		(.05	)	-	-		-	-
Net income		4.92		1.31	0.06		0.02	2.06
Diluted earnings per share:
Before cumulative effect of accounting change		4.84		1.27	0.06		0.02	2.00
Cumulative effect of accounting change		(.04	)	-	-		-	-
Net income		4.80		1.27	0.06		0.02	2.00
Working capital		262,264		97,261	38,621		108,253	109,064
Total assets		1,201,509		754,400	642,297		628,877	581,746
Long-term debt		150,000		150,000	168,689		207,966	208,880
Shareholders’ equity		445,059		240,113	169,277		168,258	169,204
Dividends declared per common share		1.15		0.11	0.10		0.10	0.075
Adjusted EBITDA (1)		481,222		180,168	80,696		55,231	189,110

(1) Adjusted EBITDA represents income before cumulative effect of accounting change, interest expense, interest and investment 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 set forth 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 we believe that 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:

	2005			2004			2003			2002			2001
	(in thousands)
Net income	$	272,532		$	69,764		$	3,232		$	1,028		$	107,653
Add cumulative effect of accounting change, net of income taxes		2,503			-			-			-			-
Add provision for income taxes		168,216			42,339			2,956			1,060			28,073
Add interest expense and other financing costs		10,341			37,573			28,746			27,613			31,146
Subtract interest and investment income		(7,583	)		(1,716	)		(1,109	)		(1,802	)		(2,772	)
Add merger financing termination costs, net		-			-			18,039			-			-
Add depreciation and amortization		35,213			32,208			28,832			27,332			25,010
Adjusted EBITDA	$	481,222		$	180,168		$	80,696		$	55,231		$	189,110

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

General

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

Results of Operations

To assist in understanding our operating results, please refer to the operating data at the end of this analysis which provides key operating information for our Refineries. Refinery operating data is also included in our quarterly reports on Form 10-Q and on our web site address: http://www.frontieroil.com.

Overview

Our Refineries have a total annual average permitted crude capacity of 162,000 bpd. The four significant indicators of our profitability, reflected and defined in the operating data at the end of this analysis, are the gasoline crack spread, the diesel crack spread, the light/heavy crude oil differential and the WTI/WTS crude oil differential. Other significant factors that influence our 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 first-in, first-out (“FIFO”) inventory accounting method, crude oil price trends can cause significant fluctuations in the inventory valuation of our crude oil, unfinished products and finished products, thereby resulting in 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 futures trading.

During 2005, the price of crude oil on the New York Mercantile Exchange continued the upward trend, which began during 2004. The crude oil price began the 2005 year at $43.45 per barrel, reached a high of $69.81 per barrel in late August, and ended the year at $61.04 per barrel. The crude oil market fundamentals and geopolitical considerations continued to support prices higher than historic averages. The increase in crude oil prices, along with additional crude oil production being significantly heavy and/or sour crude oil, increased our crude oil differentials during the year ended December 31, 2005, when compared to the same period in 2004. Our 2005 gasoline and diesel crack spreads were the highest in our history. Higher demand for gasoline and diesel along with product supply constraints are reasons for our improved gasoline and diesel crack spreads, especially after the damage to Gulf Coast refineries caused by Hurricanes Katrina and Rita.

As discussed in Note 6 in the “Notes to Consolidated Financial Statements”, we effected a stock split on June 17, 2005. All prior period share related numbers have been revised to reflect the effect of the split.

2005 Compared with 2004

Overview of Results

We had net income for the year ended December 31, 2005, of $272.5 million, or $4.80 per diluted share, compared to net income of $69.8 million, or $1.27 per diluted share, in the same period in 2004. Our operating income of $446.0 million for the year ended December 31, 2005, reflected an increase of $302.5 million from the $143.5 million operating income for the comparable period in 2004. The average diesel crack spread was significantly higher during 2005 ($17.13 per barrel) than in 2004 ($7.35 per barrel). The average gasoline crack spread was also higher during 2005 ($11.67 per barrel) than in 2004 ($8.61 per barrel), and both the light/heavy and WTI/WTS crude oil differentials improved.

Specific Variances

Refined product revenues. Refined product revenues increased $1.1 billion, or 39%, from $2.9 billion to $4.0 billion for the year ended December 31, 2005 compared to the same period in 2004. This increase was primarily due to a significant increase in average product sales prices ($17.05 higher per sales barrel), and higher product sales volumes in 2005 (4,391 more bpd). Sales prices increased primarily as a result of increased crude oil prices and improvements in the gasoline and diesel crack spreads.

Manufactured product yields. Manufactured product yields (“yields”) are the volumes of specific materials that are obtained through the distilling of crude oil and the operations of other refinery process units. Yields increased 1,510 bpd at the El Dorado Refinery and 1,594 bpd at the Cheyenne Refinery for the year ended December 31, 2005 as compared to 2004.

Other revenues. Other revenues increased $11.1 million to a $1.2 million gain for the year ended December 31, 2005, compared to a $9.9 million loss for the same period in 2004, the source of which was $1.0 million in net gains from derivative contracts accounted for using mark-to-market accounting in the year ended December 31, 2005, compared to net derivative losses of $10.3 million for the same period in 2004. See “Price Risk Management Activities” under Item 7A for a discussion of our utilization of commodity derivative contracts.

Raw material, freight and other costs. Raw material, freight and other costs include crude oil and other raw materials used in the refining process, purchased products and blendstocks, freight costs for FOB destination sales, as well as the impact of changes in inventory under the FIFO inventory accounting method. Raw material, freight and other costs increased by $814.9 million during the year ended December 31, 2005, from $2.4 billion in 2004 to $3.3 billion in 2005. The increase in raw material, freight and other costs was due to higher average crude prices and higher crude oil charges, reduced by higher FIFO inventory gains from rising prices in the year ended December 31, 2005 compared to the year ended December 31, 2004. We also benefited from improved crude oil differentials during the year ended December 31, 2005 when compared to the same period in 2004. For the year ended December 31, 2005, we realized a reduction in raw material, freight and other costs as a result of FIFO inventory gains of approximately $29.4 million after tax ($47.6 million pretax, comprised of $39.0 million at the El Dorado Refinery and $8.6 million at the Cheyenne Refinery) due to increasing crude oil and refined product prices. For the year ended December 31, 2004, we realized a reduction in raw material, freight and other costs as a result of FIFO inventory gains of approximately $19.8 million after tax ($32.0 million pretax, comprised of $25.9 million for the El Dorado Refinery and $6.1 million for the Cheyenne Refinery) because of increasing crude oil and refined product prices.

The Cheyenne Refinery raw material, freight and other costs of $48.49 per sales barrel for the year ended December 31, 2005 increased from $38.08 per sales barrel in the same period in 2004 due to higher crude oil prices partially offset by higher FIFO 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 82% in the year ended December 31, 2005 from 85% in 2004 as we increased our charges of lighter crude oil to take advantage of market opportunities. The light/heavy crude oil differential for the Cheyenne Refinery averaged $15.32 per barrel in the year ended December 31, 2005 compared to $9.90 per barrel in the same period in 2004.

The El Dorado Refinery raw material, freight and other costs of $54.01 per sales barrel for the year ended December 31, 2005 increased from $40.98 per sales barrel in the same period in 2004 due to higher average crude oil prices partially offset by higher FIFO inventory gains and an improved WTI/WTS crude oil differential. The WTI/WTS crude oil differential increased from an average of $3.74 per barrel in the year ended December 31, 2004 to $4.51 per barrel in the same period in 2005.

Refinery operating expenses. Refinery operating expenses, excluding depreciation, include both the variable costs (energy and utilities) and the fixed costs (salaries, taxes, maintenance costs and other) of operating the Refineries. Refinery operating expenses, excluding depreciation, were $245.5 million in the year ended December 31, 2005 compared to $219.8 million in the comparable period of 2004.

The Cheyenne Refinery operating expenses, excluding depreciation, were $81.1 million in the year ended December 31, 2005, compared to $72.4 million in the comparable period of 2004. The increased expenses included higher turnaround accruals ($3.2 million), higher electricity costs ($1.2 million), increased environmental expenses ($1.2 million) and higher natural gas costs ($810,000). The higher natural gas costs resulted primarily from an average price increase of $2.72 per MMbtu, materially offset by our using approximately 27% less natural gas during the year ended December 31, 2005 when compared to the same period in 2004.

The El Dorado Refinery operating expenses, excluding depreciation, were $164.4 million in the year ended December 31, 2005, increasing from $147.4 million for the year ended December 31, 2004. The increased expenses included higher salaries and benefits ($4.2 million), natural gas ($3.6 million), electricity ($3.3 million), turnaround costs in excess of accruals ($2.6 million), maintenance ($2.3 million) and additives and chemicals ($2.2 million). The higher natural gas costs resulted primarily from an average price increase of $1.50 per MMbtu, partially offset by our using approximately 12% less natural gas during the year ended December 31, 2005, when compared to the same period in 2004.

Selling and general expenses. Selling and general expenses, excluding depreciation, increased $822,000, or 3%, from $29.9 million for the year ended December 31, 2004 to $30.7 million for the year ended December 31, 2005 due to higher salaries and benefits ($3.1 million, primarily due to bonuses) partly offset by lower costs related to the Beverly Hills litigation during the year ended December 31, 2005, when compared to 2004, as the 2005 litigation costs were reduced by insurance recoveries.

Merger termination and legal costs. Merger termination and legal costs include legal costs associated with the termination of the 2003 Holly merger and the now-concluded lawsuit. These costs were $48,000 for the year ended December 31, 2005, compared to $3.8 million in 2004.

Depreciation and amortization. Depreciation and amortization increased $3.0 million, or 9%, for the year ended December 31, 2005 compared to the same period in 2004 because of increased capital investment in our Refineries, the 2004 El Dorado Refinery contingent earn-out payment and the write-off of undepreciated assets which were retired and replaced during 2005.

Interest expense and other financing costs. Interest expense and other financing costs of $10.3 million for the year ended December 31, 2005 decreased $27.2 million, or 72%, from $37.6 million in the comparable period in 2004. This decrease was primarily due to the refinancing in late 2004 of our 11.75% Senior Notes with $150.0 million of 6.625% Senior Notes. The interest expense and other financing costs for year ended December 31, 2004, also included $14.9 million in redemption-related costs. Average debt outstanding decreased to $161 million during the year ended December 31, 2005 from $209 million for the same period in 2004. Capitalized interest, which reduced interest expense and other financing costs, was $2.6 million for the year ended December 31, 2005, compared to $65,000 in the comparable period of 2004 primarily due to the ultra low sulfur diesel capital projects which commenced in 2005.

Interest and investment income. Interest and investment income increased $5.9 million, or 342%, from $1.7 million in the year ended December 31, 2004 to $7.6 million in the year ended December 31, 2005, due to larger cash balances and higher interest rates on invested cash.

Provision for income taxes. The provision for income taxes for the year ended December 31, 2005 was $168.2 million on pretax income of $443.3 million (or 37.95%). The 2005 provision reflects an estimated benefit from the American Jobs Creation Act of 2004 (“the Act”) production activities deduction for manufacturers ($3.2 million), offset by the impact of permanent book tax differences from our current estimated statutory tax rate of 37.92%. See Note 5 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, 2004 was $42.3 million on pretax income of $112.1 million (or 37.77%) reflecting the net benefit of releasing our deferred tax valuation allowance. Another provision of the Act benefited our current income taxes payable for 2005 by allowing us an accelerated depreciation deduction of 75% of qualified capital costs incurred to achieve low sulfur diesel fuel requirements. The Act also provides for 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 8 in the “Notes to Consolidated Financial Statements”).

2004 Compared with 2003

Overview of Results

We had net income for the year ended December 31, 2004 of $69.8 million, or $1.27 per diluted share, compared to net income of $3.2 million, or $0.06 per diluted share, in the same period in 2003. Our operating income of $143.5 million for the year ended December 31, 2004, represented 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 11.75% Senior Notes. We used available cash and proceeds from a new $150.0 million 6.625% Senior Notes offering to redeem the 11.75% Senior Notes. 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. 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 higher 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 improvements in the gasoline and diesel crack spreads.

Manufactured product yields. Yields for the year ended December 31, 2004 for the El Dorado Refinery increased 224 bpd from the year ended December 31, 2003. Yields for the year ended December 31, 2004 for the Cheyenne Refinery were 2,174 bpd less than in the same period in 2003 because of the Coker furnace fire.

Other revenues. 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.

Raw material, freight and other costs. Raw material, freight and other costs increased by $571.7 million 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 crude prices and more crude oil charges, offset by higher FIFO 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 FIFO inventory gains of approximately $19.8 million after tax ($32.0 million pretax, comprised of $25.9 million at the El Dorado Refinery and $6.1 million at the Cheyenne 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 FIFO 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 FIFO 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 FIFO 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. 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 in the year ended December 31, 2004 compared to $61.4 million 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 utilizing approximately 11% more 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 in the year ended December 31, 2004, increasing from $139.0 million 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 utilizing approximately 2% more natural gas during the year ended December 31, 2004 when compared to the same period in 2003.

Selling and general expenses. 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 were paid from the commutation account (discussed in Note 8 in the “Notes to Consolidated Financial Statements”) 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. Merger termination and legal costs of $3.8 million for the year ended December 31, 2004 included 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. 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. 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 11.75% Senior Notes and subsequent reduced interest expense on our new $150.0 million 6.625% Senior Note debt issuance. 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 9.125% 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 9.125% 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 and investment income. Interest and investment 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.

Gain on involuntary conversion of assets. The gain on involuntary conversion of assets related 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 represented 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.

Merger financing termination costs, net. 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.

Provision for income taxes. 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% 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 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.

Liquidity and Capital Resources

Cash flows from operating activities. Net cash provided by operating activities was $360.3 million for the year ended December 31, 2005, compared to net cash provided by operating activities of $177.9 million during the year ended December 31, 2004. Improved results of operations increased cash flow significantly during 2005, but were partially offset by uses of cash for working capital changes.

Working capital changes provided a total of $9.4 million of cash in the year ended December 31, 2005 while providing $38.6 million of cash in the comparable period in 2004. The uses of cash for working capital during the year ended December 31, 2005, included an increase in inventories of $90.7 million and an increase in trade and other receivables of $43.7 million. The increase in both receivables and inventories was due to the significant increases in crude oil and product prices during 2005. The average per barrel cost of inventories in the year ended December 31, 2005, increased by $14.45 per barrel compared to only a $5.76 per barrel increase in the comparable period in 2004.

The most significant working capital item providing cash during the year ended December 31, 2005 was an increase in trade and crude payables of $117.3 million. This was due to increases in crude payables of $103.5 million which resulted from increased crude oil inventory volumes, higher crude oil prices and increases in trade and other payables of $13.8 million.

We made estimated federal and state income tax payments of $92.5 million and $13.5 million, respectively, during the year ended December 31, 2005, which will be applied to our 2005 income tax liabilities. We also made state income tax payments during the year ended December 31, 2005 of $218,000, which were applied to our 2004 income tax liabilities. We received federal income tax refunds of $3.6 million during 2005, which represented a portion of our overpayment of our 2004 federal income tax liability. We have applied $1.4 million of 2004 state income tax overpayments and $122,000 of 2004 federal income tax overpayments to our estimated 2005 income tax liabilities. As of December 31, 2005, we have accrued estimated federal income taxes payable of $18.5 million and estimated state income taxes payable of $1.9 million.

At December 31, 2005, we had $356.1 million of cash and cash equivalents, working capital of $262.3 million and $155.5 million availability for borrowings under our revolving credit facility. Our operating cash flows are affected by crude oil and refined product prices and other risks as discussed in Item 7A “Quantitative and Qualitative Disclosures About Market Risks.”

Cash flows used in investing activities. Capital expenditures during the year ended December 31, 2005, were $109.7 million and included approximately $89.8 million for the El Dorado Refinery, $19.4 million for the Cheyenne Refinery, and $582,000 for expenditures in our Denver and Houston offices, and our share of crude oil pipeline projects. The $89.8 million of capital expenditures for our El Dorado Refinery included $71.8 million for the ultra low sulfur diesel project (discussed below), as well as operational, payout, safety, administrative, environmental and optimization projects. The $19.4 million of capital expenditures for our Cheyenne Refinery included approximately $5.9 million of capital for the ultra low sulfur diesel project, as well as environmental, operational, safety, administrative and payout projects. We funded our 2005 capital expenditures with cash generated from our operations.

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 its raw material, freight and other costs and refinery operating expenses, excluding depreciation. The total amount of these contingent earn-out payments is capped at $40.0 million, with an annual cap of $7.5 million. A payment of $7.5 million was required based on 2004 results, and was accrued as of December 31, 2004 and paid in January 2005. Such contingent earn-out payments are recorded as additional acquisition costs. Based on the results of operations for the year ended December 31, 2005, a payment of $7.5 million was required, and was accrued as of December 31, 2005, and paid in January 2006. Including the payment we made in early 2006, we have paid a total of $22.5 million for contingent earn-out payments.

During the first quarter of 2005, we received the remaining payments aggregating $2.1 million from our insurance companies related to the 2004 coker fire at our Cheyenne Refinery.

During the year ended December 31, 2005, we received net proceeds of $5.5 million from the sales of assets, including the sale of FGI, LLC, our asphalt terminal and storage facility located in Grand Island, Nebraska, during the fourth quarter of 2005.

Cash flows used in financing activities. During the year ended December 31, 2005, we issued 3,467,650 shares of common stock due to stock option exercises by employees and members of our Board of Directors, for which we received $23.6 million in cash and 190,958 shares ($3.6 million) of our common stock, now held as treasury stock. During the year ended December 31, 2005, we received another 409,156 shares ($11.5 million) of our common stock, now held as treasury stock, from employees and members of our Board of Directors who surrendered stock to pay withholding taxes related to stock option exercises. We also acquired 37,364 shares ($615,000) of our common stock, now held as treasury stock, from employees who surrendered stock to pay withholding taxes on shares of restricted stock that vested during the first quarter of 2005.

We have authorization from our Board of Directors to repurchase up to 16 million shares of our common stock. Through December 2004, we had purchased 8,734,732 shares of common stock under this stock repurchase program. During the year ended December 31, 2005, we purchased an additional 720,800 shares ($24.6 million) in open market transactions under this program, $1.9 million of which did not settle until early 2006 and were accrued as of December 31, 2005. At December 31, 2005, we had authorization remaining under this program to purchase an additional 6,544,468 shares. On November 30, 2005, our Board of Directors confirmed utilizing up to $100 million for share repurchases in the near-term (which we anticipate continuing throughout 2006) under this program, and as of December 31, 2005, $7.6 million (195,800 shares) of the $100 million had been utilized for repurchases. During January and February 2006, we purchased an additional 153,494 shares ($6.4 million) under this program.

As of December 31, 2005, we had $150.0 million of long-term debt and no borrowings under our $225 million revolving credit facility. We had $69.5 million of outstanding letters of credit under our revolving credit facility. We were in compliance with the financial covenants of our revolving credit facility as of December 31, 2005. We had shareholders’ equity of $445.1 million as of December 31, 2005.

Our Board of Directors declared quarterly cash dividends of $0.03 per share of common stock  in December 2004 and March 2005, which were paid in January 2005 and April 2005, respectively. Our Board of Directors declared quarterly cash dividends of $0.04 per share of common stock in June 2005 and September 2005, which were paid in July 2005 and October 2005, respectively. Our Board of Directors declared a quarterly cash dividend of $0.04 per share of common stock and a special cash dividend of $1.00 per share of common stock in December 2005, which was paid in January 2006. The total cash required for the dividend declared in December 2005 was approximately $58.7 million and was accrued as a dividend payable at quarter-end.

Future capital expenditures. Compliance with the upcoming ultra low sulfur diesel requirements affecting our Refineries will require additional capital expenditures through mid-2006. Total capital, including capitalized interest, that we will spend to comply with these regulations is currently estimated to be approximately $106.5 million at the El Dorado Refinery and $16.3 million at the Cheyenne Refinery. Expenditures for the ultra low sulfur diesel projects through December 31, 2005 (including 2004 and 2005 expenditures) were $77.8 million at the El Dorado Refinery and $6.2 million at the Cheyenne Refinery. The remaining costs for the ultra low sulfur diesel projects at both Refineries will be incurred before mid-2006. The American Jobs Creation Act of 2004 allows 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 and will provide income tax credits based on the resulting production of ultra low sulfur diesel for up to 25% of the remaining qualified costs. Production of ultra low sulfur diesel is expected to begin by mid-2006 at our Refineries.

Capital expenditures aggregating approximately $205.7 million are currently planned for 2006, and include $104.0 million at our El Dorado Refinery, $101.0 million at our Cheyenne Refinery, and $658,000 for capital expenditures in our Denver and Houston offices, and for our share of crude oil pipeline projects. The $104.0 million of planned capital expenditures for our El Dorado Refinery includes approximately $28.7 million for the ultra low sulfur diesel project discussed above, $46.5 million on the crude unit and vacuum tower expansion, discussed below, as well as environmental, operational, safety, administrative and payout projects. The $101.0 million of planned capital expenditures for our Cheyenne Refinery includes approximately $10.1 million for the ultra low sulfur diesel project discussed above, $50.8 million on the coker expansion and $5.1 million on the crude fractionation project, both discussed below, as well as environmental, operational, safety, administrative and payout projects. Our 2006 capital expenditures will be funded with cash generated by our operations and the utilization of a portion of our existing cash balance, if necessary.

Our Board of Directors, in November 2005, approved three capital improvement projects which are anticipated to be completed between 2007 and 2008. These projects include a $150 million crude unit and vacuum tower expansion at our El Dorado Refinery, a $78.5 million coker expansion and revamp at our Cheyenne Refinery and an $8.2 million crude fractionation project at our Cheyenne Refinery. The above amounts include estimated capitalized interest. The crude unit and vacuum tower expansion at the El Dorado Refinery will allow for higher crude charge rates (including a much greater percentage of heavy crude oil) and higher gasoline and distillate yields. This project will likely be implemented in the spring of 2008 during the next planned turnaround for the crude/vacuum unit complex. The coker expansion at the Cheyenne Refinery, which is anticipated to be completed in 2007, will significantly decrease the amount of asphalt produced and increase the amount of higher margin light products such as gasoline and diesel. The crude fractionation project at the Cheyenne Refinery will allow us to replace light crude purchases with less expensive heavier crude oil while maintaining gasoline and diesel yields. We expect to fund these projects with existing cash and internally generated cash flow.

The Energy Tax Incentives Act of 2005 (the “Act”) contains provisions that may affect certain of our financial or operational considerations in the coming years. The Act includes a provision that would allow a refiner to expense capital costs associated with expansion of refining capacity, as determined by the manufacture of liquid products other than asphalt and lube oil, in excess of 5% above previously produced volumes. The Act also requires that refiners, importers and blenders ensure that renewable fuel (e.g., ethanol) is blended into the nation’s gasoline pool at escalating, prescribed rates beginning with a 4.0 billion gallon requirement in 2006 and increasing to 7.5 billion gallons in 2012. We are currently evaluating the potential consequence that these and other provisions of the Act may have on our future operations.

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 2006 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. We also 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. 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. The amounts shown in the table on the following page for transportation, terminalling and storage contractual obligations are net of $14.4 million, the approximate cost of the pipeline capacity assigned to other parties for the term of that agreement.

During 2004, we entered into a Transportation Services Agreement (“Agreement”) to transport 20,000 bpd of crude oil on the Spearhead Pipeline from Griffith, Indiana to Cushing, Oklahoma once the reversal of the pipeline was completed. Enbridge Energy Company completed the reversal of the Spearhead Pipeline and has been accepting line fill volumes since December 2005. Deliveries into Cushing are scheduled to start during March 2006. The amounts shown in the table on the following page for transportation, terminalling and storage contractual obligations include our anticipated commitments on the Spearhead Pipeline.

For more information on the agreements discussed above, see “Lease and Other Commitments” in Note 8 in the “Notes to Consolidated Financial Statements.”

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		93,673		13,371		21,990		21,356		36,956
Purchase obligations:
Baytex crude supply (2)		675,741		336,863		338,878		-		-
Other crude supply, feedstocks and natural gas (2)		404,545		404,084		461		-		-
Transportation, terminalling and storage		159,537		22,860		34,206		36,679		65,792
Ultra low sulfur diesel refinery projects (3)		11,636		11,636		-		-		-
Other goods and services		9,869		7,443		1,523		903		-
Total purchase obligations (4)		1,261,328		782,886		375,068		37,582		65,792
Long-term accrued turnaround cost		15,122		-		11,621		3,501		-
Pension funding requirement (5)		1,173		1,173		-		-		-
Other long-term liabilities		8,079		-		2,912		575		4,592
Total contractual cash	$	1,529,375	$	797,430	$	411,591	$	63,014	$	257,340

(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, $422.1 million relate to January and February 2006 feedstock and natural gas requirements of the Refineries.

(3)   The amounts for ultra low sulfur diesel refinery projects reflected here relate to our current commitments as of December 31, 2005, not the total estimated costs of the projects. See Note 8 in the “Notes to Consolidated Financial Statements” for total estimated costs of the projects.

(4)   In the fourth quarter of 2005, we entered into various contracts for future expansion and revamp construction at our Refineries. See “-Future capital expenditures” above for total estimated cost and completion dates for these projects. We signed a contract in December 2005 for $86.8 million of the $150 million total cost of the El Dorado Refinery crude unit and vacuum tower expansion. At December 31, 2005, we had no current obligations associated with this contract. At December 31, 2005, we had accrued approximately $1.5 million for costs incurred for the Cheyenne Refinery coker expansion and revamp project. The agreements are not included in the above table because they were cancellable at December 31, 2005 without penalty, except for the amounts accrued at year end.

(5) Includes the estimated pension funding requirement in 2006 for 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 7 “Employee Benefit Plans” in the “Notes to Consolidated Financial Statements.”

Off-Balance Sheet Arrangements

We have an interest in one unconsolidated entity (See Note 1 “Nature of Operations” in the “Notes to Consolidated Financial Statements”). Other than facility and equipment leasing agreements, we do not participate in any transactions, agreements or other contractual arrangements, which would result in any off-balance sheet liabilities or other arrangements to us.

Environmental

See “Environmental” in Note 8 in the “Notes to Consolidated Financial Statements.”

Application of Critical Accounting Policies

The preparation of financial statements in accordance with United States generally accepted accounting principles requires our management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates. The following summary provides information about our critical accounting policies, including identification of those involving critical accounting estimates, and should be read in conjunction with Note 2 in the “Notes to Consolidated Financial Statements”, which summarizes our significant 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 this policy relies on our 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 our recognizing substantial gains (in periods of rising prices) or losses (in periods of falling prices) from our inventories of crude oil and products. While we believe that this accounting method 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, a comparison of our results to other refineries must take into account the impact of the inventory accounting differences.

Asset Retirement Obligations. We account for asset retirement obligations as required under the Financial Accounting Standards Board (“FASB”) Statement of Financial Accounting Standard (“FAS”) No. 143, “Accounting for Retirement Asset Obligations.” FAS No. 143 requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which 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.

In March 2005, the FASB issued FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations” (“FIN 47”). FIN 47 clarified that the term “conditional asset retirement obligation” as used in FAS No. 143 refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. Since the obligation to perform the asset retirement activity is unconditional, FIN 47 provides that a liability for the fair value of a conditional asset obligation should be recognized if that fair value can be reasonably estimated, even though uncertainty exists about the timing and/or method of settlement. FIN 47 also clarifies when an entity would have sufficient information to reasonably estimate the fair value of a conditional asset retirement obligation under FAS No. 143. We adopted FIN 47 as of December 31, 2005 for which we recorded a net asset retirement obligation of $5.5 million, recognized $4.0 million in 2005 as the pretax cumulative effect of an accounting change ($2.5 million after tax) and recorded a $1.5 million increase in property, plant and equipment.

In order to determine fair value, management must make certain estimates and assumptions, including, among other things, projected cash flows, a credit-adjusted risk-free interest rate, and an assessment of market conditions that could significantly impact the estimated fair value of the asset retirement obligation. These estimates and assumptions are very subjective; however, we believe that we have adequately accrued for our asset retirement obligations at this time and that changes in estimates in future periods would not have a significant effect on our results of operations or financial condition.

Environmental Expenditures. Environmental expenditures are expensed or capitalized based upon their future economic benefit. Costs that improve a property’s pre-existing condition, and costs that prevent future environmental contamination, are capitalized. Remediation costs related to environmental damage resulting from operating activities subsequent to acquisition are expensed. Liabilities for these expenditures are recorded when it is probable that obligations have been incurred and the amounts can be reasonably estimated. Such estimates are subject to change due to many factors, including the identification of new sites requiring remediation, changes in environmental laws and regulations and their interpretation, additional information related to the extent and nature of remediation efforts, and potential improvements in remediation technologies.

Pension and Other Post-retirement Benefit Obligations. We have significant pension and post-retirement benefit liabilities and costs that are developed from actuarial valuations. Inherent in these valuations are key assumptions, including discount rates, expected returns on plan assets and health care cost trend rates. Changes in these assumptions are primarily influenced by factors outside of our control. These assumptions can have a significant effect on the amounts reported in our consolidated financial statements. See Note 7 in the “Notes to Consolidated Financial Statements” for more information on these plans and the current assumptions used.

New Accounting Pronouncements

See “New Accounting Pronouncements” in 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 10 in the “Notes to Consolidated Financial Statements” under “Price Risk Management Activities” for a discussion of our various price risk management activities. When we make the decision to manage our price exposure, our objective is generally to avoid losses from negative price changes, realizing we will not obtain the benefit of positive price changes.

Item 7A.    Quantitative and Qualitative Disclosure About Market Risk

Impact of Changing Prices. Our revenues and cash flows, as well as estimates of future cash flows, are sensitive to changes in energy prices. Major shifts in the cost of crude oil, the prices of refined products and the cost of natural gas can generate large changes in the operating margin from refining operations. These prices also determine the carrying value of our 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 10 in the “Notes to Consolidated Financial Statements.”

Operating Data

The following tables set forth the refining operating statistical information on a consolidated basis and for each Refinery for 2005, 2004 and 2003. The statistical information includes the following terms:

·   Charges - the quantity of crude oil and other feedstock processed through Refinery units on a bpd basis.

·   Manufactured product yields - the volumes of specific materials that are obtained through the distilling of crude oil and the operations of other refinery process units on a bpd basis.

·   Gasoline and diesel crack spreads - The average non-oxygenated gasoline and diesel net sales prices that we receive for each product less the average WTI crude oil price at Cushing, Oklahoma.

·   Light/heavy crude oil differential - the average differential between the benchmark WTI crude oil priced at Cushing, Oklahoma and the heavy crude oil delivered to the Cheyenne Refinery.

·   WTI/WTS crude oil differential - the average differential between benchmark WTI crude oil priced at Cushing, Oklahoma and the West Texas sour crude oil priced at Midland, Texas.

Consolidated:
Years Ended December 31,	2005		2004		2003
Charges (bpd)
Light crude		39,210		37,486		31,314
Heavy and intermediate crude		113,439		110,662		115,907
Other feed and blend stocks		15,955		16,609		18,407
Total		168,604		164,757		165,628
Manufactured product yields (bpd)
Gasoline		83,574		82,944		83,449
Diesel and jet fuel		55,151		53,093		53,156
Asphalt		7,434		7,475		7,530
Chemicals		884		939		842
Other		16,623		16,112		16,536
Total		163,666		160,563		161,513
Total product sales (bpd)
Gasoline		90,372		90,698		89,842
Diesel and jet fuel		54,350		52,818		53,606
Asphalt		7,526		7,427		7,260
Chemicals		864		841		842
Other		17,268		14,205		14,117
Total		170,380		165,989		165,667
Refinery operating margin information (per sales barrel)
Refined products revenue	$	64.32	$	47.27	$	35.88
Raw material, freight and other costs (FIFO inventory accounting)		52.22		40.04		30.77
Refinery operating expenses, excluding depreciation		3.95		3.62		3.31
Depreciation and amortization		0.56		0.53		0.47
Average WTI crude oil price at Cushing, OK (per barrel)	$	55.77	$	41.85	$	31.89
Average gasoline crack spread (per barrel)	$	11.67	$	8.61	$	7.00
Average diesel crack spread (per barrel)		17.13		7.35		5.05
Average sales price (per sales barrel)
Gasoline	$	69.09	$	51.70	$	39.72
Diesel and jet fuel		73.61		49.81		36.91
Asphalt		26.72		24.11		24.68
Chemicals		112.62		115.45		53.90
Other		24.07		17.63		12.24

Cheyenne Refinery:
Years Ended December 31,	2005		2004		2003
Charges (bpd)
Light crude		8,575		6,645		5,405
Heavy crude		38,347		38,408		40,284
Other feed and blend stocks		4,399		4,392		5,966
Total		51,321		49,445		51,655
Manufactured product yields (bpd)
Gasoline		21,035		20,039		20,518
Diesel		14,580		14,387		15,044
Asphalt		7,434		7,475		7,530
Other		6,285		5,839		6,822
Total		49,334		47,740		49,914
Total product sales (bpd)
Gasoline		27,186		26,744		26,836
Diesel		14,428		14,581		15,091
Asphalt		7,526		7,427		7,260
Other		6,124		5,044		4,708
Total		55,264		53,796		53,895
Refinery operating margin information (per sales barrel)
Refined products revenue	$	61.16	$	45.50	$	35.61
Raw material, freight and other costs (FIFO inventory accounting)		48.49		38.08		29.40
Refinery operating expenses, excluding depreciation		4.02		3.68		3.12
Depreciation and amortization		0.90		0.90		0.79
Average light/heavy crude oil differential (per barrel)	$	15.32	$	9.90	$	7.10
Average gasoline crack spread (per barrel)	$	13.17	$	9.33	$	7.32
Average diesel crack spread (per barrel)		19.40		9.34		6.57
Average sales price (per sales barrel)
Gasoline	$	71.14	$	53.28	$	41.42
Diesel		75.57		52.35		39.00
Asphalt		26.72		24.11		24.68
Other		25.29		15.98		8.44

El Dorado Refinery:
Years Ended December 31,	2005		2004		2003
Charges (bpd)
Light crude		30,635		30,841		25,909
Heavy and intermediate crude		75,092		72,254		75,623
Other feed and blend stocks		11,556		12,218		12,440
Total		117,283		115,313		113,972
Manufactured product yields (bpd)
Gasoline		62,539		62,905		63,931
Diesel and jet fuel		40,572		38,706		38,111
Chemicals		884		939		842
Other		10,338		10,273		9,715
Total		114,333		112,823		112,599
Total product sales (bpd)
Gasoline		63,186		63,954		63,006
Diesel and jet fuel		39,922		38,237		38,516
Chemicals		864		841		842
Other		11,145		9,161		9,410
Total		115,117		112,193		111,774
Refinery operating margin information (per sales barrel)
Refined products revenue	$	65.83	$	48.12	$	36.01
Raw material, freight and other costs (FIFO inventory accounting)		54.01		40.98		31.43
Refinery operating expenses, excluding depreciation		3.91		3.59		3.41
Depreciation and amortization		0.40		0.35		0.32
Average WTI/WTS crude oil differential (per barrel)	$	4.51	$	3.74	$	2.68
Average gasoline crack spread (per barrel)	$	11.02	$	8.31	$	6.86
Average diesel crack spread (per barrel)		16.31		6.59		4.45
Average sales price (per sales barrel)
Gasoline	$	68.21	$	51.03	$	38.99
Diesel and jet fuel		72.90		48.84		36.09
Chemicals		112.62		115.45		53.90
Other		23.40		18.53		14.13

Item 8.    Financial Statements and Supplementary Data

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, 2005 and 2004, 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, 2005. 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, 2005 and 2004, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2005, 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.

As discussed in Note 2, the Company adopted the provisions of FASB Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations.

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, 2005, 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, 2006 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, 2006

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, 2005. 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, 2005, 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 27, 2006

James R. Gibbs

Chairman of the Board, President and

Chief Executive Officer

Michael C. Jennings

Executive Vice President - 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, 2005, 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, 2005, 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, 2005, 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, 2005 of the Company and our report dated March 1, 2006 expressed an unqualified opinion on those consolidated financial statements and financial statement schedules and included an emphasis of a matter paragraph regarding the Company’s adoption of the provisions of FASB Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations.

DELOITTE & TOUCHE LLP

Houston, Texas

March 1, 2006

FRONTIER OIL CORPORATION AND SUBSIDIAIRES
Consolidated Statements of Income
	Years Ended December 31,
	2005			2004			2003
	(in thousands, except per share data)
Revenues:
Refined products	$	3,999,935		$	2,871,592		$	2,169,551
Other		1,227			(9,876	)		952
		4,001,162			2,861,716			2,170,503
Costs and expenses:
Raw material, freight and other costs		3,247,372			2,432,461			1,860,795
Refinery operating expenses, excluding depreciation		245,449			219,781			200,383
Selling and general expenses, excluding depreciation		30,715			29,893			19,890
Merger termination and legal costs		48			3,824			8,739
Depreciation and amortization		35,213			32,208			28,832
Gains on sales of assets		(3,644	)		-			-
		3,555,153			2,718,167			2,118,639
Operating income		446,009			143,549			51,864
Interest expense and other financing costs		10,341			37,573			28,746
Interest and investment income		(7,583	)		(1,716	)		(1,109	)
Gain on involuntary conversion of assets		-			(4,411	)		-
Merger financing termination costs, net		-			-			18,039
		2,758			31,446			45,676
Income before income taxes		443,251			112,103			6,188
Provision for income taxes		168,216			42,339			2,956
Income before cumulative effect of accounting change		275,035			69,764			3,232
Cumulative effect of accounting change, net of income taxes of $1,530		(2,503	)		-			-
Net income	$	272,532		$	69,764		$	3,232
Basic earnings per share of common stock:
Before cumulative effect of accounting change	$	4.97		$	1.31		$	0.06
Cumulative effect of accounting change		(.05	)		-			-
Net income	$	4.92		$	1.31		$	0.06
Diluted earnings per share of common stock:
Before cumulative effect of accounting change	$	4.84		$	1.27		$	0.06
Cumulative effect of accounting change		(.04	)		-			-
Net income	$	4.80		$	1.27		$	0.06
The accompanying notes are an integral part of these consolidated financial statements.

FRONTIER OIL CORPORATION AND SUBSIDIAIRES
Consolidated Balance Sheets
	December 31,
	2005			2004
	(in thousands, except share data)
ASSETS
Current assets:
Cash and cash equivalents	$	356,065		$	124,389
Trade receivables, net of allowance of $500 in both years		122,051			78,733
Other receivables		7,584			9,531
Inventory of crude oil, products and other		247,621			156,934
Deferred tax assets		6,819			6,748
Other current assets		7,935			2,344
Total current assets		748,075			378,679
Property, plant and equipment, at cost:
Refineries, terminal equipment and pipelines		657,612			542,356
Furniture, fixtures and other equipment		10,510			8,755
		668,122			551,111
Less - accumulated depreciation and amortization		238,184			204,348
		429,938			346,763
Deferred financing costs, net of amortization
of $945 and $594 in 2005 and 2004, respectively		3,549			4,328
Commutation account		12,606			16,438
Prepaid insurance, net of amortization		3,331			4,542
Other intangible asset, net of amortization
of $158 and $53 in 2005 and 2004, respectively $158 and $53 in 2005 and 2004, respectively		1,422			1,527
Other assets		2,588			2,123
Total assets	$	1,201,509		$	754,400
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	359,577		$	238,991
Accrued dividends		58,726			1,652
Accrued turnaround cost		12,696			15,373
Accrued interest		2,485			2,487
Accrued El Dorado Refinery contingent earn-out payment		7,500			7,500
Accrued liabilities and other		44,827			15,415
Total current liabilities		485,811			281,418
Long-term debt		150,000			150,000
Long-term accrued turnaround cost		15,122			13,153
Post-retirement employee liabilities		24,497			23,139
Other long-term liabilities		8,079			2,511
Deferred compensation liability		2,214			1,516
Deferred income taxes		70,727			42,550
Commitments and contingencies
Shareholders’ equity:
Preferred stock, $100 par value, 500,000 shares authorized,
No shares issued		-			-
Common stock, no par, 90,000,000 shares authorized, 66,814,698 and
63,339,048 shares issued in 2005 and 2004, respectively		57,780			57,607
Paid-in capital		157,910			119,525
Retained earnings		319,150			111,468
Accumulated other comprehensive income (loss)		27			(1,197	)
Treasury stock, at cost, 10,465,414 and 9,276,934
shares at December 31, 2005 and 2004, respectively		(86,870	)		(47,024	)
Deferred employee compensation		(2,938	)		(266	)
Total shareholders’ equity		445,059			240,113
Total liabilities and shareholders’ equity	$	1,201,509		$	754,400
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,
	2005			2004			2003
	(in thousands)
Cash flows from operating activities:
Net income	$	272,532		$	69,764		$	3,232
Adjustments to reconcile net income to net cash from operating activities:
Cumulative effect of accounting change, net of income taxes		2,503			-			-
Depreciation and amortization		35,213			32,208			28,832
Deferred income taxes		28,881			25,005			2,655
Income tax benefits of stock compensation		7,792			5,168			-
Deferred financing cost and bond discount amortization		785			5,484			10,642
Deferred compensation amortization		1,363			1,180			1,386
Gains on sales of assets		(3,644	)		-			-
Gain on involuntary conversion of assets		-			(4,411	)		-
Long-term commutation account and prepaid insurance		3,832			3,712			(26,566	)
Amortization of long-term prepaid insurance		1,211			1,451			423
Decrease in allowance for doubtful receivables		-			-			(186	)
Other		427			(281	)		(501	)
Changes in components of working capital from operations:
Decrease (increase) in derivative assets		354			(354	)		-
Decrease (increase) in trade, note and other receivables		(43,707	)		2,231			(4,577	)
Increase in inventory		(90,687	)		(32,935	)		(18,839	)
(Increase) decrease in other current assets		(5,945	)		(16	)		536
Increase (decrease) in accounts payable		117,275			58,138			(4,282	)
Increase in accrued liabilities and other		32,152			11,555			1,240
Net cash provided by (used in) operating activities		360,337			177,899			(6,005	)
Cash flows from investing activities:
Additions to property, plant and equipment		(109,710	)		(46,502	)		(33,677	)
Net proceeds from insurance - involuntary conversion claim		2,142			3,395			-
Proceeds from sale of assets		5,500			-			304
El Dorado Refinery contingent earn-out payment		(7,500	)		-			-
Other investments		-			-			(927	)
Net cash used in investing activities		(109,568	)		(43,107	)		(34,300	)
Cash flows from financing activities:
Purchase of treasury stock		(34,819	)		(3,029	)		(1,075	)
Proceeds from issuance of common stock		23,616			3,923			1,441
Dividends paid		(7,776	)		(5,664	)		(5,187	)
Debt issue costs and other		(114	)		(3,954	)		(7,136	)
(Repayments) proceeds of revolving credit facility, net		-			(45,750	)		45,750
Proceeds from issuance of 6.625% Senior Notes		-			150,000			-
Repurchases of debt:
11.75% Senior Notes		-			(170,449	)		-
8% Senior Notes		-			-			(220,000	)
9.125% Senior Notes		-			-			(39,475	)
Proceeds from issuance of 8% Senior Notes, net of discount		-			-			218,143
Net cash used in financing activities		(19,093	)		(74,923	)		(7,539	)
Increase (decrease) in cash and cash equivalents		231,676			59,869			(47,844	)
Cash and cash equivalents, beginning of period		124,389			64,520			112,364
Cash and cash equivalents, end of period	$	356,065		$	124,389		$	64,520
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		Comprehensive Income			Retained Earnings			Number of Shares			Amount			Deferred Compensation			Accumulated Other Comprehensive Income (Loss)			Number of Shares			Amount
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
Effect of 6/17/05 stock split on shares		31,669,524		-		-					-			(4,638,467	)		-			-			-			27,031,057			-
Shares issued under:
Stock option plans		3,475,650		173		27,009																				3,475,650			27,182
Restricted stock plan, net of forfeits		-		-		2,360					-			169,798			450			(2,810	)		-			169,798			-
Issue of restricted stock units to directors		-		-		1,224					-			-			-			(1,224	)		-			-			-
Shares received under:
Stock repurchase plan		-		-		-								(720,800	)		(24,596	)		-			-			(720,800	)		(24,596	)
Stock option plans		-		-		-					-			(600,114	)		(15,085	)		-			-			(600,114	)		(15,085	)
Restricted stock plan		-		-		-					-			(37,364	)		(615	)		-			-			(37,364	)		(615	)
Comprehensive income:
Net income		-		-		-	$	272,532			272,532			-			-			-			-			-			272,532
Other comprehensive income:
Minimum pension liability, net of tax of $755								1,224
Other comprehensive income								1,224															1,224			-			1,224
Comprehensive income							$	273,756
Income tax benefits of stock compensation		-		-		7,792					-			-			-			-			-			-			7,792
Deferred compensation:
Amortization/vested shares		-		-		-					-			-			-			1,362			-			-			1,362
Dividends declared		-		-		-					(64,850	)		-			-			-			-			-			(64,850	)
December 31, 2005		66,814,698	$	57,780	$	157,910				$	319,150		$	(10,465,414	)	$	(86,870	)	$	(2,938	)	$	27		$	56,349,284		$	445,059
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, 2005, 2004 and 2003

1.  Nature of Operations

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

The Company operates refineries (“the Refineries”) in Cheyenne, Wyoming and El Dorado, Kansas. The Company also owns 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 $95,000 and $102,000 at December 31, 2005 and 2004, respectively, and is included in “Other assets” on the Consolidated Balance Sheets. The Company also owned, until its sale as of November 30, 2005, FGI, LLC, an asphalt terminal and storage facility in Grand Island, Nebraska. The activities of FGI, LLC have been included in the consolidated financial statements since December 1, 2003, when the Company increased its ownership from 50% to 100%, through November 30, 2005. All of the operations of the Company are in the United States, with its marketing efforts focused in the Rocky Mountain and Plains States regions of the United States. The Rocky Mountain region includes the states of Colorado, Wyoming, Montana and Utah, and the Plains States include the states of Kansas, Oklahoma, Nebraska, Iowa, Missouri, North Dakota and South Dakota. The Company purchases crude oil to be refined and markets the refined petroleum products produced, including various grades of gasoline, diesel fuel, jet fuel, asphalt, chemicals and petroleum coke. The operations of refining and marketing of petroleum products are considered part of one reporting segment.

2.  Significant Accounting Policies

Revenue Recognition

Revenues from sales of refined products are earned and realized upon transfer of title to the customer based on the contractual terms of delivery. Title primarily transfers at the refinery or terminal when the refined product is loaded into the common carrier pipelines, trucks or railcars (free on board origin). In some situations, title transfers at the customer’s destination (free on board destination). Nonmonetary product exchanges and certain buy/sell crude oil transactions which are entered into in the normal course of business are included on a net cost basis in “Raw material, freight and other costs” on the Consolidated Statements of Income.

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

The Company capitalizes interest on the long-term construction of significant assets. Interest capitalized for the years ended December 31, 2005, 2004 and 2003 was $2.6 million, $65,000 and $586,000, 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 4).

Components of Inventory
	December 31,
	2005		2004
	(in thousands)
Crude oil	$	97,766	$	52,643
Unfinished products		53,200		45,957
Finished products		75,790		40,835
Process chemicals		5,441		3,210
Repairs and maintenance supplies and other		15,424		14,289
	$	247,621	$	156,934

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 8) totaling $6.4 million are included in “Prepaid insurance” in the long-term asset portion of the Consolidated Balance Sheets and are reflected net of accumulated amortization as of December 31, 2005 and 2004. 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 is being amortized to expense over the five-year policy term, which began October 1, 2003. Accumulated amortization was $3.1 million and $1.9 million at December 31, 2005 and 2004, 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, 2005, 2004 and 2003. No options were granted during the year ended December 31, 2005. Had compensation costs been determined based on fair value at the grant dates for awards made in 2004, 2003 and prior years for the vested portions of the awards in each of the years 2005, 2004 and 2003, the Company’s net income and EPS would have been the pro forma amounts listed in the following table for the years ended December 31, 2005, 2004 and 2003:

	2005			2004			2003
	(in thousands, except per share amounts)
Net income as reported	$	272,532		$	69,764		$	3,232
Pro forma compensation expense, net of tax		(1,255	)		(2,029	)		(3,070	)
Pro forma net income	$	271,277		$	67,735		$	162
Basic EPS:
As reported	$	4.92		$	1.31		$	0.06
Pro Forma		4.90			1.27			-
Diluted EPS:
As reported	$	4.80		$	1.27		$	0.06
Pro Forma		4.77			1.24			-

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

Compensation costs of $954,000, $1.2 million and $1.4 million related to restricted stock awards were recognized for the years ended December 31, 2005, 2004 and 2003, respectively. Compensation costs of $408,000 related to restricted stock unit awards were recognized for the year ended December 31, 2005. There was no compensation cost related to restricted stock unit awards during the years ended December 31, 2004 and 2003, as none were granted during those years. 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 2006.

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.

In March 2005, the FASB issued FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations” (“FIN 47”). FIN 47 clarified that the term “conditional asset retirement obligation” as used in FAS No. 143 refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. Since the obligation to perform the asset retirement activity is unconditional, FIN 47 provides that a liability for the fair value of a conditional asset obligation should be recognized if that fair value can be reasonably estimated, even though uncertainty exists about the timing and/or method of settlement. FIN 47 also clarifies when an entity would have sufficient information to reasonably estimate the fair value of a conditional asset retirement obligation under FAS No. 143.

The Company adopted FIN 47 as of December 31, 2005 and recognized $4.0 million in 2005 as the pretax cumulative effect of an accounting change ($2.5 million after tax). The Company’s balance sheet as of December 31, 2005, recognizes a net asset retirement obligation of $5.5 million, $325,000 of which is included as a current liability in “Accrued liabilities and other” and $5.2 million of which is included in “Other long-term liabilities,” and a net increase in property plant and equipment of approximately $1.5 million.

The Company has asset retirement obligations related to its Refineries and certain other assets as a result of environmental and other legal requirements. The Company is not required to perform such work in some circumstances until it permanently ceases operations of the long-lived assets. Because the Company considers the useful life of the Refineries and certain other assets indeterminable, an associated asset retirement obligation cannot be calculated at this time. The Company has recorded an asset retirement obligation for the handling and disposal of hazardous substances that the Company is legally obligated to incur in connection with maintaining and improving the Refineries.

Had the Company implemented FIN 47 retroactively to January 1, 2003, the following pro forma information summarizes the impact for the three years in the period ended December 31, 2005.

	2005		2004			2003
	(in thousands, except per share amounts)
Net income as reported	$	272,532	$	69,764		$	3,232
Pro forma asset retirement obligation income (expense), net of tax		2,099		(388	)		(374	)
Pro forma net income	$	274,631	$	69,376		$	2,858
Basic EPS:
As reported	$	4.92	$	1.31		$	0.06
Pro Forma		4.96		1.30			0.06
Diluted EPS:
As reported	$	4.80	$	1.27		$	0.06
Pro Forma		4.83		1.27			0.05
Pro forma asset retirement obligation, December 31,	$	5,469	$	5,106		$	4,767

Principles of Consolidation

The Consolidated Financial Statements include the accounts of FOC and all wholly-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 $345.6 million and $115.3 million at December 31, 2005 and 2004, respectively.

Related Party Transactions

As of December 31, 2005, the Company had an outstanding relocation-related loan to a non-officer employee in the amount of $300,000, which is included in “Other receivables” on the Consolidated Balance Sheets. This loan matures in November 2006.

Supplemental Cash Flow Information

Cash payments for interest, net of capitalized interest, during 2005, 2004 and 2003 were $7.8 million, $20.0 million and $33.5 million, respectively. Cash payments for income taxes during 2005, 2004 and 2003 were $106.0 million, $21.6 million and $626,000, respectively. Cash refunds of income taxes during 2005, 2004 and 2003 were $3.6 million, $3.2 million and none, 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 Accounting Principles Board (“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 at the beginning of their next fiscal year beginning after December 15, 2005. This means that Frontier will be required to implement FAS No. 123(R) for its fiscal year beginning January 1, 2006. Based on the stock options issued through December 31, 2005, the Company will recognize pretax compensation expense in future consolidated statements of income of approximately $290,000 and $4,000 in the years ended December 31, 2006 and 2007, respectively. See “Stock-based Compensation” above for the pro forma impact that the fair value method would have had on the Company’s results of operations for the years ended December 31, 2005, 2004 and 2003.

The Emerging Issues Task Force (“EITF”) reached a consensus on Issue No. 04-13 (“Issue”), “Accounting for Purchases and Sales of Inventory with the Same Counterparty,” and the FASB ratified it on September 28, 2005. This Issue addresses accounting matters 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 consensus in this Issue is to be applied to new arrangements entered into in reporting periods beginning after March 15, 2006. The Company has certain crude oil procurement and product exchange transactions that it accounts for on a net cost basis. The Company does not believe that its revenues or cost of sales will be materially affected by applying the Issue’s consensus.

On September 30, 2005, the FASB issued a revision for an Exposure Draft issued on December 15, 2003, that would amend FAS No. 128, “Earnings per Share”, to clarify guidance for mandatorily convertible instruments, the treasury stock method, contracts that may be settled in cash or shares, and contingently issuable shares. The proposed statement was originally issued in December 2003, but has been reissued due to the significance of changes to the computational guidance applicable to the treasury stock method. The proposed statement would be effective for interim and annual periods ending after June 15, 2006. The Company is currently evaluating the provisions that this proposed statement would have on its earnings per share calculations.

An exposure draft “Accounting for Uncertain Tax Positions - An Interpretation of FAS No. 109, Accounting for Income Taxes”, was issued by the FASB on July 14, 2005. The proposed interpretation is intended to reduce the significant diversity in practice associated with recognition and measurement of income taxes by establishing consistent criteria for evaluating uncertain tax positions in the areas of recognition, measurement, derecognition, financial statement classification and disclosure. This exposure draft was originally to have been effective as of the end of the first fiscal year ending after December 15, 2005; however, the FASB has recently indicated the final interpretation will not be issued until the first quarter of 2006 and thus a revised effective date will likely follow. The Company is in the process of evaluating the provisions of this exposure draft.

3.  Long-term Debt

Schedule of Long-term Debt

	December 31,
	2005		2004
	(in thousands)
6.625% Senior Notes, maturing 2011	$	150,000	$	150,000

On October 1, 2004, the Company issued $150.0 million principal amount of 6.625% Senior Notes. The 6.625% Senior Notes, which mature on October 1, 2011, were issued at par, and the Company received net proceeds (after underwriting fees) of $147.2 million. Interest is paid semi-annually. The 6.625% Senior Notes are redeemable, at the option of the Company, at 103.313% after October 1, 2007, declining to 100% in 2010. Prior to October 1, 2007, the Company may at its option redeem the 6.625% Senior Notes at a defined make-whole amount, plus accrued and unpaid interest. The 6.625% 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. Frontier Holdings Inc. and its subsidiaries are full and unconditional guarantors of the 6.625% Senior Notes (see Note 12 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 11.75% Senior Notes in October 2004 and redeemed on November 15, 2004, the remaining $105.6 million outstanding principal of its 11.75% Senior Notes.

4.  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 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, 2005 or 2004 under the Facility. Standby letters of credit outstanding were $69.5 million and $12.2 million at December 31, 2005 and 2004, respectively. As of December 31, 2005, the Company had borrowing base availability of $155.5 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 oil and product supply. The Facility provides for a quarterly commitment fee of 0.3% per annum. The Company’s current borrowing rates are based, at the Company’s option, on the agent bank’s prime rate plus 0.25%, the prevailing Federal Funds Rate plus 1.25% or LIBOR plus 1.25%. Outstanding standby letters of credit charges are 1.125% per annum, plus standard issuance and renewal fees. The average interest rate on funds borrowed under the Facility during 2005 was 4.355%. 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, 2005.

5.  Income Taxes

The provision for income taxes is comprised of the following:

	Years ended December 31,
	2005		2004		2003
	(in thousands)
Current:
Federal	$	121,455	$	13,959	$	276
State		17,880		3,375		25
Total current provision		139,335		17,334		301
Deferred:
Federal		26,652		23,365		2,244
State		2,229		1,640		411
Total deferred provision		28,881		25,005		2,655
Total provision	$	168,216	$	42,339	$	2,956

The following is a reconciliation of the provision for income taxes computed at the statutory United States income tax rates on pretax income and the provision for income taxes as reported:

	Years ended December 31,
	2005			2004			2003
	(in thousands)
Provision based on statutory rates	$	155,138		$	39,236		$	2,166
Increase (decrease) resulting from:
State and other income taxes		20,109			5,015			436
Federal tax effect of state income taxes		(7,038	)		(1,755	)		(153	)
Benefit of the Section 199 manufacturers production activities deduction		(3,229	)		-			-
Release of valuation allowance		-			(955	)		-
Other, including permanent book-tax differences		3,236			798			507
Provision as reported	$	168,216		$	42,339		$	2,956

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

Components of Deferred Taxes
	December 31, 2005									December 31, 2004
	State			Federal			Total			State			Federal			Total
	(in thousands)
Current deferred tax assets:
Gross current assets:
Turnaround accruals	$	571		$	4,443		$	5,014		$	757		$	5,380		$	6,137
Accrued bonuses		356			2,772			3,128			-			-			-
Pension retirement benefits		53			411			464			58			411			469
Restricted stock amortization		24			183			207			39			279			318
Bad debt reserve		22			175			197			25			175			200
Other liabilities		92			857			949			10			68			78
Unrealized loss on derivative contracts		25			195			220			-			-			-
Capitalized selling and general expenses		20			155			175			19			133			152
Total gross deferred tax assets		1,163			9,191			10,354			908			6,446			7,354
Gross current liabilities:
Prepaid expenses		(342	)		(2,663	)		(3,005	)		-			-			-
State income tax receivable		-			(243	)		(243	)		-			-			-
State deferred taxes		-			(287	)		(287	)		-			(305	)		(305	)
Unrealized gain on derivative contracts		-			-			-			(37	)		(264	)		(301	)
Total current net deferred tax assets	$	821		$	5,998		$	6,819		$	871		$	5,877		$	6,748
Long-term deferred tax liabilities:
Gross long-term assets:
Turnaround accruals	$	680		$	5,293		$	5,973		$	648		$	4,604		$	5,252
Pension retirement benefits		10			77			87			183			1,303			1,486
Other post-retirement benefits		1,080			8,402			9,482			957			6,796			7,753
Environmental liability accrual		67			525			592			74			525			599
Deferred compensation		100			775			875			55			390			445
Asset retirement obligations		231			1,800			2,031			-			-			-
Other		44			345			389			-			-			-
State deferred taxes		-			2,899			2,899			-			2,166			2,166
Federal alternative minimum tax credits		-			-			-			-			6,316			6,316
Total gross long-term assets		2,212			20,116			22,328			1,917			22,100			24,017
Gross long-term liabilities:
Depreciation		(10,495	)		(82,560	)		(93,055	)		(8,106	)		(58,461	)		(66,567	)
Total long-term net deferred tax liabilities	$	(8,283	)	$	(62,444	)	$	(70,727	)	$	(6,189	)	$	(36,361	)	$	(42,550	)

The Company estimates that all remaining alternative minimum tax carryforwards were utilized during 2005. The Company had no federal or state net operating loss carryforwards as of December 31, 2005. The Company recognizes liabilities for potential tax issues based on its estimate of whether, and the extent to which, additional taxes may be due. As of December 31, 2005, amounts reserved for such contingencies were $3.5 million (including interest). The Company is in the process of determining the deductibility for income tax purposes of certain stock compensation for executives. As of December 31, 2005, the Company has accrued $18.1 million in income taxes payable for taxes which may be due should the determination be made that this stock compensation is not deductible. Any income tax benefit allowed for this stock compensation would be recorded as an increase in additional paid in capital. The Company has not identified any other potential income tax contingencies that must be disclosed in accordance with FAS No. 5.

As of December 31, 2005, the Company has accrued federal income taxes payable of $18.5 million and estimated state income taxes payable of $1.9 million, which are included in “Accrued liabilities and other” on the Consolidated Balance Sheet. The American Jobs Creation Act of 2004 created the new Internal Revenue Code section 199 which provides an income tax benefit to domestic manufacturers. The Company recognized an income tax benefit of approximately $3.2 million in 2005 related to the new production activities deduction.

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, 2005.

The Company recognized income tax benefits related to the deductibility of stock compensation in the amounts of $7.8 million, $5.2 million and $1.6 million for the years ended December 31, 2005, 2004 and 2003, 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 an income tax liability (benefit) related to the minimum pension liability reflected in “Accumulated other comprehensive (income) loss” in the amounts of $755,000, ($166,000) and ($201,000) for the years ended December 31, 2005, 2004 and 2003, respectively.

6.  Common Stock

Stock Split

The Company announced on April 15, 2005 that its Board of Directors had approved a 2-for-1 stock split by means of a stock dividend on the Company’s common stock. The stock split was subject to shareholder approval of an amendment to the Company’s articles of incorporation to increase the number of authorized shares from 50 million to 90 million, and the amendment was approved at a special shareholders’ meeting on May 23, 2005. The stock dividend was issued on June 17, 2005 to shareholders of record as of the close of business on May 23, 2005. All prior period share related numbers included in this report have been revised to reflect the effect of the stock split.

Dividends

The Company declared quarterly cash dividends of $0.03 per share of common stock for the quarter ended March 31, 2005. The quarterly cash dividend was $0.04 per share of common stock for the quarters ended June 30, 2005 through December 31, 2005. In addition, a special cash dividend of $1.00 per share of common stock was declared for the quarter ended December 31, 2005. The payment of dividends is prohibited under the Company’s Revolving Credit Facility only if a default has occurred and is continuing or such payment would cause a default. The 6.625% Notes may restrict dividend payments based on covenants related to interest coverage and restricted payments.

Treasury stock

The Company accounts for its treasury stock under the cost method on a FIFO basis. The Company has a Board of Directors’ approved stock repurchase program for up to 16 million shares of the Company’s common stock. On November 30, 2005, the Company’s Board of Directors confirmed utilizing up to $100 million for share repurchases in the near-term (which the Company anticipates continuing throughout 2006) under this program, and as of December 31, 2005, $7.6 million (195,800 shares) of the $100 million had been utilized for repurchases. During January and February 2006, the Company purchased an additional 153,494 shares ($6.4 million) under this program. During the year ended December 31, 2005, the Company purchased 720,800 shares under the stock repurchase program. Through December 31, 2005, 9,455,532 shares of common stock had been purchased under the stock repurchase program. The Company received 190,958 shares ($3.6 million) in 2005, 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 409,156 shares in 2005, 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 37,364 shares in 2005, 48,443 shares in 2004 and 24,825 shares in 2003, of its common stock, now held as treasury stock, from employees to cover withholding taxes on vested restricted stock. As of December 31, 2005, the Company had 10,465,414 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, 2005, 2004 and 2003.

	2005						2004						2003
	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	$	272,532		55,362	$	4.92	$	69,764		53,346	$	1.31	$	3,232		51,878	$	0.06
Dilutive securities:
Stock options and
restricted stock		-		1,456		-		-		1,456		-		-		2,104		-
Diluted EPS:
Net income	$	272,532		56,818	$	4.80	$	69,764		54,802	$	1.27	$	3,232		53,982	$	0.06

        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) was zero for the years ended December 31, 2005 and 2004, and 3,093,400 shares, for the year ended December 31, 2003.

Stock Plan

The Company has a stock plan which authorizes the granting of stock-based awards, including options to purchase shares, to employees and non-employee members of the Company’s Board of Directors. The plan through December 31, 2005, had reserved for issuance a total of 7,200,000 shares of common stock based awards, of which 7,002,500 awards had been granted (738,850 are still outstanding) and 159,900 awards 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.

During the year ended December 31, 2005, no options were granted; however, 56,000 restricted stock units were granted to non-employee members of the Board of Directors. Restricted stock units, when granted, are recorded at the fair market value of the Company’s common stock on the date of issuance as deferred compensation (equity account) and amortized to compensation expense over the respective vesting periods of the restricted stock units. Compensation costs of $408,000 pretax (approximately $253,000 after tax) related to restricted stock unit awards were recognized for the year ended December 31, 2005. No compensation costs were recognized related to restricted stock unit awards for the years ended December 31, 2004 or 2003, as no awards were granted in those years. The restricted stock units generally vest three years after issuance; however, as provided in the stock plan, 8,000 restricted stock units vested during the third quarter of 2005 upon the death of a member of the Company’s Board of Directors. The shares of common stock related to this vesting were issued in October 2005.

Changes during 2005, 2004 and 2003 in outstanding stock-based awards are presented below:

	2005					2004					2003
	Number of Awards			Weighted-Average Exercise Price		Number of Awards			Weighted-Average Exercise Price		Number of Awards			Weighted-Average Exercise Price
Outstanding at beginning of year		4,176,900		$	7.99		6,143,050		$	6.61		5,162,500		$	5.59
Granted		56,000			n/a		90,000			9.33		1,688,000			8.33
Exercised or issued		(3,475,650	)		7.84		(2,051,950	)		3.91		(706,450	)		3.29
Expired		(18,400	)		9.00		(4,200	)		10.93		(1,000	)		4.30
Outstanding at end of year		738,850			8.70		4,176,900			7.99		6,143,050			6.61
Exercisable at end of year		320,350			9.02		2,920,100			7.51		3,891,602			5.44
Available for grant atend of year		159,900					197,500					283,300
Weighted-average fair value of options granted during the year					-					3.84					3.51

The following table summarizes information about stock options and other stock-based awards outstanding at December 31, 2005:

Stock-based Awards Outstanding
Number Outstanding at 12/31/05	Weighted-Average Remaining Contractual Life (Years)		Exercise Price		Exercisable at 12/31/05
11,500		0.16	$	4.30		11,500
528,750		2.14		8.33		195,750
52,500		3.15		9.33		15,000
98,100		1.29		10.93		98,100
48,000		2.10		n/a		n/a

Restricted Stock Plan

On March 13, 2001, the Company established the Frontier Oil Corporation Restricted Stock Plan (the “Plan”) covering 2,000,000 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 award may 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 in the Plan, and any dividends are held by the Company and paid to the employee upon vesting.

The Company made grants of restricted stock during the years ended December 31, 2005, 2002 and 2001. No grants were made in the years ended December 31, 2004 or 2003. All shares from the 2002 and 2001 grants were vested as of December 31, 2005. As of December 31, 2005, there were 159,846 shares of unvested restricted stock outstanding, which represents shares granted in March 2005. These shares will vest 25% in March 2006, 25% in March 2007 and the final 50% in March 2008. Restricted shares, when granted, are recorded at the fair 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, 2005, 2004 and 2003 was $954,000, $1.2 million and $1.4 million, respectively.

7.  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 pension and/or matching contributions on behalf of participating employees. The cost of the defined contribution plans for the years ended December 31, 2005, 2004 and 2003 was $6.1 million, $5.6 million and $5.1 million, respectively.

Deferred Compensation Plan

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

Defined Benefit Plans

The Company established a defined benefit cash balance pension plan, effective January 1, 2000, for eligible El Dorado Refinery employees to supplement retirement benefits that those employees lost upon the sale of the El Dorado Refinery to Frontier. No other current or future employees will be eligible to participate in the plan. This plan has assets of $8.3 million at December 31, 2005, 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 were unfunded as of December 31, 2005 and 2004. The post-retirement health care plan requires retirees to pay between 20% and 40% of total health care costs based on age and length of service. The plan’s prescription drug benefits are at least equivalent to Medicare Part D benefits.

The 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)
	2005			2004			2005			2004
	(in thousands)
Change in benefit obligation:
Benefit obligation at January 1	$	11,810		$	10,695		$	29,039		$	23,250
Service cost		-			-			1,130			863
Interest cost		526			632			2,093			1,460
Plan participant contributions		-			-			25			-
Actuarial (gain)/losses		(2,210	)		485			9,077			3,613
Benefits paid		(184	)		(2	)		(183	)		(147	)
Benefit obligation at December 31	$	9,942		$	11,810		$	41,181		$	29,039
Change in plan assets:
Fair value of plan assets at January 1	$	6,915		$	5,298		$	-		$	-
Actual return on plan assets		374			504			-			-
Employer contribution		1,174			1,115			158			147
Plan participant contributions		-			-			25			-
Benefits paid		(184	)		(2	)		(183	)		(147	)
Fair value of plan assets at December 31	$	8,279		$	6,915		$	-		$	-
Funded status	$	(1,663	)	$	(4,895	)	$	(41,181	)	$	(29,039	)
Unrecognized net actuarial (gain) loss		(43	)		1,936			17,174			9,622
Net amount recognized	$	($,706	)	$	(2,959	)	$	(24,007	)	$	(19,417	)
Amounts recognized in the balance sheets:
Accrued benefit liability (2)	$	(1,663	)	$	(4,895	)	$	(24,007	)	$	(19,417	)
Accumulated other comprehensive (income) loss		(43	)		1,936			-			-
Net amount recognized	$	(1,706	)	$	(2,959	)	$	(24,007	)	$	(19,417	)

	Pension Benefits									Post-retirement Health care and Other Benefits
	2005			2004			2003			2005			2004			2003
	(in thousands)
Components of net periodic benefit cost for the year ended December 31:
Service cost	$	-		$	-		$	-		$	1,130		$	863		$	803
Interest cost		526			632			611			2,093			1,460			1,262
Expected return on plan assets		-606			-479			-373			-			-			-
Amortization of prior service cost		-			-			-			-			-			-
Recognized net actuarial loss		-			22			-			1,525			490			337
Net periodic benefit cost		($80	)	$	175		$	238		$	4,748		$	2,813		$	2,402
Weighted average assumptions:
Benefit obligation discount rate as of December 31		5.50	%		5.50	%		6.00	%		5.50	%		5.50	%		6.00	%
Net periodic benefit cost discount rate for the year ended December 31		5.50	%		6.00	%		6.25	%		5.50	%		6.00	%		6.25	%
Expected return on plan assets (3)		8.00	%		8.00	%		8.00	%		-			-			-

(1) The disclosed post-retirement healthcare obligations and net periodic costs for 2005 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, 2005, by approximately $4.8 million and net periodic cost for the year ended December 31, 2005, by $368,000.

(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, 2005 and 2004, was $1.2 million for both years. 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 have averaged nearly 8% during the two years ended December 31, 2005.

	Post-retirement Healthcare
	and Other Benefits
	2005			2004			2003
	(dollars in thousands)
Healthcare cost-trend rate:	11.00%			13.00%			13.00%
	ratable to			ratable to			ratable to
	5.00%			5.00%			5.00%
	from			from			from
	2008			2008			2007
Sensitivity Analysis:
Effect of 1% (-1%) change in healthcare cost-trend rate:
Year-end benefit obligation	$	8,641		$	6,094		$	5,036
		(6,784	)		(4,767	)		(3,926	)
Total of service and interest cost		720			502			467
		(560	)		(392	)		(363	)

At December 31, 2005, the estimated future benefit payments to be paid over 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
2006	$	119	$	416	$	9
2007		204		650		14
2008		165		923		19
2009		228		1,201		28
2010		361		1,493		38
Next 5 fiscal years thereafter		4,875		12,447		454

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, 2005 and 2004, by asset category are as follows:

	Percentage of Plan Assets at December 31,
	2005	2004
Asset Category:
Cash equivalents	10%	16%
Equity common trust funds	52%	52%
Fixed income common trust funds	26%	26%
Stock fund common trust funds	8%	6%
Common stock	4%	-
Total	100%	100%

The Company does not have a definitive target for the percentage allocation of assets within the plan. Management reviews the earnings on plan assets each year and assesses portfolio asset allocation along with risk and expected returns. After this review, management may direct the trustee to revise the asset allocation. 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 contributed $1.2 million to the Fund during 2005 and expects to contribute approximately $1.2 million to the Fund during the year ending December 31, 2006.

8.  Commitments and Contingencies

Lease and Other Commitments

On November 16, 1999, Frontier acquired the 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 earn-out payments is capped at $40.0 million, with an annual cap of $7.5 million. Any contingent earn-out payment will be recorded when determinable. Such contingent earn-out payments, if any, will be recorded as additional acquisition cost. A contingent earn-out payment of $7.5 million was required based on 2005 results, and was accrued at December 31, 2005 and was paid in January 2006. A contingent earn-out payment of $7.5 million was required based on 2004 results and was paid in January 2005. Including the payment made in early 2006, the Company has paid a total of $22.5 million to date for contingent earn-out payments.

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, although the Company has the option to renew the sublease for an additional eight years. At the end of the renewal period, the Company has the option to purchase the cogeneration facility for the greater of fair value or $22.3 million. The Company also has building, equipment, aircraft and vehicle operating leases that expire from 2005 through 2011. Operating lease rental expense was approximately $13.5 million, $10.4 million and $9.0 million for the years ended December 31, 2005, 2004 and 2003, respectively. The approximate future minimum lease payments for operating leases as of December 31, 2005 are $13.4 million for 2006, $11.3 million for 2007, $10.7 million for 2008, $10.8 million for 2009, $10.5 million for 2010 and $37.0 million thereafter.

In 2002, the Company entered into a five-year crude oil supply agreement with Baytex Marketing Ltd. (“Baytex”), a Canadian crude oil producer. This agreement, which commenced January 1, 2003, provides for the Company to purchase up to 20,000 barrels per day (“bpd”) of a Lloydminster crude oil blend, a heavy Canadian crude. The Company processes this crude oil at the Cheyenne Refinery, which is near Guernsey, Wyoming, the delivery point for 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 agreement expires on December 31, 2007.

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 reduction for the commitments assigned to other parties, is approximately $4.8 million for 2006, $5.1 million for 2007, an average of $12.2 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 term ending December 31, 2007, as provided 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 20,000 bpd of crude oil on the Spearhead Pipeline from Griffith, Indiana to Cushing, Oklahoma once the reversal of the pipeline was completed. Enbridge Energy Company completed the reversal of the Spearhead Pipeline and has been accepting line fill volumes since December 2005. Deliveries into Cushing are scheduled to start during March of 2006. This pipeline will enable the Company to transport Canadian crude oil to the El Dorado Refinery. The initial term of this Agreement is for a period of ten years from the actual commencement date (expected to be March 2006), although the Company has the right to extend the Agreement for an additional ten-year term and increase the volume transported under the preferential tariff to 50,000 bpd. The Company’s estimated Spearhead Pipeline tariff commitments are approximately $4.7 million in 2006, an average of $5.8 million for each of the years 2007 through 2010, an average of $6.4 million for each of the years 2011 through 2015 and $1.1 million in 2016.

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 seven such suits: Moss et al. v. Venoco, Inc. et al., filed in June 2003; Ibraham et al. v. City of Beverly Hills et al., filed in July 2003; Yeshoua et al. v. Venoco, Inc. et al., filed in August 2003; Jacobs v. Wainoco Oil & Gas Company et al., filed in December 2003; Bussel et al. v. Venoco, Inc. et al., filed in January 2004; Steiner et al. v. Venoco, Inc. et al., filed in May 2004; and Kalcic et al. v. Venoco, Inc. et al., filed in April 2005. Of the approximately 1,025 plaintiffs in the seven lawsuits, Wainoco Oil & Gas Company and Frontier are named as defendants by approximately 450 of those plaintiffs. 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 seven pending lawsuits have been consolidated and are pending before 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 is ongoing and a trial date has been set for October 30, 2006.

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 a highly-rated insurance company 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 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 incurred 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, 2005, the commutation account balance was approximately $12.6 million. Frontier has the right to terminate the policy at any time prior to September 30, 2008, and receive a refund of the unearned portion of the premium (approximately $3.0 million as of December 31, 2005, and declining by approximately $270,000 each quarter) 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 also has been 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. The Company has reached a settlement on some of the policies and is continuing to pursue coverage efforts on other policies.

Frontier believes that neither the claims that have been made, the seven 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.

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 believes that any potential liability would not have a material adverse effect on its liquidity, financial position or results of operations.

Holly Lawsuit. On March 31, 2003, the Company announced that it had entered into an agreement (the “Merger Agreement”) with Holly Corporation (“Holly”) pursuant to which the two companies would merge. On August 20, 2003, the Company 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 (the “Court”). 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.

The Court rendered its decision on April 29, 2005, ruling that Frontier had not proved that Holly repudiated the Merger Agreement. Instead, the Court ruled that Frontier had breached the Merger Agreement by declaring that Holly had repudiated the contract and by filing the lawsuit. The Court also ruled, however, that Holly had suffered no damages from Frontier’s breach and thus, Holly was only entitled to an award of nominal damages of $1.00. The opinion also addressed Holly’s position that the potential impact on Frontier of the Beverly Hills litigation would have excused Holly’s performance under the Merger Agreement. The Court ruled that Holly was unable to prove that the Beverly Hills litigation would have, or would reasonably be expected to have, a material adverse effect on Frontier. Neither Frontier nor Holly filed an appeal of the decision, and the appeal period has passed. A final order of judgment was entered May 23, 2005 and a satisfaction of judgment was filed on June 5, 2005.

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 2005, Frontier retained 30,000 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 years ended December 31, 2005 or 2004. During 2003, the Company realized bad debt losses totaling $717,000. The Company made sales to Shell of approximately $1.8 billion, $1.4 billion and $1.1 billion in the years 2005, 2004 and 2003, respectively, which accounted for 46%, 49% and 53%, of consolidated refined products revenues in 2005, 2004 and 2003, respectively.

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. The Company has, in recognition of the EPA’s reinterpretation of certain regulatory requirements associated with the Initiative, determined that Frontier will incur expenditures totaling approximately $9.1 million to further reduce emissions from the Refineries’ flare systems. At the Cheyenne Refinery, the Company estimates spending $4.6 million on the flare system, of which $223,000 was spent in 2004, $4.1 million in 2005 and the remaining $270,000 is expected to be incurred in the first quarter of 2006. At the El Dorado Refinery, the Company spent $1.2 million in prior years, and it estimates incurring $3.3 million during 2006, on the flare system. In addition to Frontier’s expenditures, Shell is expected to contribute $5.0 million for modification of the El Dorado Refinery flare system in accordance with certain provisions of the 1999 asset purchase and sale agreement for the El Dorado Refinery entered into between Frontier and Shell.

Although the Company has not received any formal notice of any violation of any of the following regulatory requirements, EPA Headquarters has recently stated their expectation that all domestic refineries, including both of the Company’s Refineries, enter into Consent Decrees to address all four of the EPA’s “marquee” regulatory programs. These programs are:

·     New Source Review (“NSR”) - a program requiring permitting of certain facility modifications,

·     New Source Performance Standards - a program establishing emission standards for new emission sources as defined in the regulations,

·     Benzene Waste National Elimination System for Hazardous Air Pollutants (“NESHAPS”) - a program limiting the amount of benzene allowable in industrial wastewaters, and

·     Leak Detection and Repair (“LDAR”) - a program designed to control hydrocarbon emissions from refinery pipes, pumps and valves.

Settlement negotiations with the EPA and state regulatory agencies regarding these items are underway. The Company now estimates that capital expenditures totaling approximately $30 million at each of its Refineries, in addition to the flare gas recovery projects discussed above, will be required prior to 2013 to satisfy these issues. Notwithstanding these anticipated legal settlements, many of these same expenditures would be required for the Company to implement its planned facility expansions. Previous settlements between the EPA and other refiners have required monetary penalties in addition to capital expenditures. While the EPA has not yet proposed monetary penalties for Frontier, it is possible that such penalties may be imposed; however, the amount of any potential penalties is not currently estimatable.

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 meet the interim gasoline sulfur standard, which was required by January 1, 2004. An additional $7.0 million in estimated costs to meet the final standard, and an additional $6.0 million for facilities to handle intermediate inventories, for the Cheyenne Refinery are expected to be incurred between 2008 and 2010. The total capital expenditures estimated as of December 31, 2005, for the El Dorado Refinery to achieve the final gasoline sulfur standard are approximately $21.0 million, and are expected to be incurred between 2007 and 2009.

The EPA has promulgated regulations that will limit the sulfur content of highway diesel fuel beginning in mid-2006. As indicated above, Frontier has elected to comply with the highway diesel sulfur standard by June 2006. As of December 31, 2005, capital costs, including capitalized interest, for diesel desulfurization are expected to be approximately $106.5 million for the El Dorado Refinery and approximately $16.3 million for the Cheyenne Refinery. The expenditures for the ultra low sulfur diesel projects through December 31, 2005 (including 2004 and 2005 expenditures) were $77.8 million at the El Dorado Refinery and $6.2 million at the Cheyenne Refinery. The remaining costs for the ultra low sulfur diesel projects at both Refineries will be incurred before mid-2006. Certain provisions of the American Jobs Creation Act of 2004 will provide federal income tax benefits to 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 income tax credit on compliant diesel fuel up to an amount equal to the remaining 25% of these qualified capital costs.

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 uses. 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 either to 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.

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

Cheyenne Refinery. The Company is party to an agreement with the State of Wyoming requiring investigation and interim remediation actions at the Cheyenne Refinery’s property that may have been impacted by past operational activities. As a result of past and ongoing investigative efforts, capital expenditures and remediation of conditions found to exist have already taken place, including the completion of surface impoundment closures, waste stabilization activities and other site remediation projects 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, 2005, 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%). Based upon the results of the ongoing investigation, additional remedial action could be required by a subsequent administrative order or permit.

The Company is negotiating the settlement of a Notice of Violation from the Wyoming Department of Environmental Quality alleging non-compliance with certain refinery waste management requirements. The Company has estimated that the capital cost of necessary corrective measures will be approximately $1.5 million, with an additional $1.2 million of expense work which has been accrued as of December 31, 2005. Penalty amounts are still in negotiation; however, an estimated penalty amount of $250,000 was accrued as of December 31, 2005.

The Company has agreed to contribute $750,000, all of which was accrued as of December 31, 2005, toward a City of Cheyenne project to relocate a city storm water conveyance pipe now located on Refinery property and therefore potentially subject to contaminants from Refinery operations.

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

Collective Bargaining Agreements

The union members at our Cheyenne Refinery are represented by seven bargaining units, the largest being the United Steel, Paper and Forestry, Rubber, Manufacturing, Energy, Allied Industrial and Service Workers International Union (“USW”) and the others being affiliated with the AFL-CIO. In September 2005, the Company, the USW and its Local 8-0574 (which represents approximately 150 workers at the Cheyenne Refinery) entered into an extension agreement of its previous contract. This extension represents an early settlement of the Cheyenne Refinery contract, which was set to expire in July 2006. The new agreement, which reflects the “national pattern” for the USW, extends the contract until July 2009.

In April 2005, the Company, the USW, and its Local 5-241 (which represents approximately 250 workers at the El Dorado Refinery) entered into an extension agreement of its previous contract. This extension represents an early settlement of the El Dorado Refinery contract, which was set to expire January 31, 2006. The new agreement, which reflects the “national pattern” for the USW, extends the contract until January 31, 2009.

9.  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 both December 31, 2005 and 2004, the carrying amounts of long-term debt instruments were $150.0 million, and the estimated fair values were $153.8 million and $151.5 million, respectively. For cash and cash equivalents, trade receivables, inventory and accounts payable, the carrying amount is a reasonable estimate of fair value.

10.  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. The value of open derivative contracts is included on the Consolidated Balance Sheets in “Accrued liabilities and other” when the unrealized value is a loss ($854,000 at December 31, 2005) or in “Other current assets” when the unrealized value is a gain ($354,000 at December 31, 2004).

Trading Activities

During 2005, 2004 and 2003, the Company had the following derivative activities which, while economic hedges, were not accounted for as hedges and whose gains or losses are reflected in “Other revenues” on the Consolidated Statements of Income:

·     Crude Purchases. As of December 31, 2005, the Company had open derivative contracts on 372,000 barrels of crude oil to hedge in-transit Canadian crude oil costs for the El Dorado Refinery. At December 31, 2005, these positions had a $661,000 unrealized loss. During the year ended December 31, 2005, the Company recorded $200,000 in realized gains on positions to hedge in-transit Canadian crude oil for the El Dorado Refinery.

·     Derivative contracts on barrels of crude oil to hedge excess intermediate, finished product and crude oil inventory for both the Cheyenne and El Dorado Refineries.As of December 31, 2005, the Company had no open derivative contracts to hedge intermediate or finished product inventory. During the year ended December 31, 2005, the Company recorded $1.4 million in gains on these types of positions. During the years ended December 31, 2004 and 2003, the Company recorded $8.1 million and $130,000, respectively, in realized losses on these types of 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, 2005, the Company did not purchase any derivative contracts for this purpose. 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.

Hedging Activities

During the year ended December 31, 2005, the Company had the following derivatives which were appropriately designated and accounted for as hedges.

·     Crude Purchases. As of December 31, 2005, the Company had open derivative contracts on 186,000 barrels of crude oil to hedge in-transit Canadian crude oil costs for the Cheyenne Refinery, which are being accounted for as a fair value hedge. At December 31, 2005, these positions had a $193,000 unrealized loss, of which $296,000 increased the related crude oil in-transit inventory to fair market value, and $103,000 increased income, which was reflected in “Other revenues” in the Consolidated Statements of Income for the ineffective portion of this hedge.

During the year ended December 31, 2004, the Company had no derivative contracts which were accounted for as hedges.

During 2003, 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.

·     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.

11.  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.

12.  Consolidating Financial Statements

Frontier Holdings Inc. and its subsidiaries (“FHI”) are full and unconditional guarantors of the Company’s 6.625% 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 consoli-dated 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 Income
For the Year Ended December 31, 2005
(in thousands)
	FOC (Parent)			FHI (Guarantor Subsidiaries)			Other Non-Guarantor Subsidiaries		Eliminations			Consolidated
Revenues:
Refined products	$	-		$	3,999,935		$	-	$	-		$	3,999,935
Other		(6	)		1,143			90		-			1,227
		(6	)		4,001,078			90		-			4,001,162
Costs and expenses:
Raw material, freight and other costs		-			3,247,372			-		-			3,247,372
Refinery operating expenses, excluding depreciation		-			245,449			-		-			245,449
Selling and general expenses, excluding depreciation		14,681			16,034			-		-			30,715
Merger termination and legal costs		48			-			-		-			48
Depreciation and amortization		69			35,700			-		(556	)		35,213
Gains on sales of assets		(3	)		(3,641	)		-		-			(3,644	)
		14,795			3,540,914			-		(556	)		3,555,153
Operating income		(14,801	)		460,164			90		556			446,009
Interest expense and other financing costs		10,593			2,009			-		(2,261	)		10,341
Interest and investment income		(5,905	)		(1,678	)		-		-			(7,583	)
Equity in earnings of subsidiaries		(458,023	)		-			-		458,023			-
		(453,335	)		331			-		455,762			2,758
Income before income taxes		438,534			459,833			90		(455,206	)		443,251
Provision for income taxes		167,532			170,543			-		(169,859	)		168,216
Income before cumulative effect of accounting change		271,002			289,290			90		(285,347	)		275,035
Cumulative effect of accounting change, net of income taxes		1,530			(2,503	)		-		(1,530	)		(2,503	)
Net income	$	272,532		$	286,787		$	90	$	(286,877	)	$	272,532

FRONTIER OIL CORPORATION
Condensed Consolidating Statement of Income
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 and investment 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 Income
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 and investment 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 Balance Sheet
As of December 31, 2005
(in thousands)
	FOC (Parent)		FHI (Guarantor Subsidiaries)		Other Non-Guarantor Subsidiaries			Eliminations			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	244,357	$	111,708	$	-		$	-		$	356,065
Trade and other receivables		6,381		123,254		-			-			129,635
Receivable from affiliated companies		-		4,556		189			(4,745	)		-
Inventory		-		247,621		-			-			247,621
Deferred tax assets		6,819		7,514		-			(7,514	)		6,819
Other current assets		499		7,436		-			-			7,935
Total current assets		258,056		502,089		189			(12,259	)		748,075
Property, plant and equipment, at cost:		1,235		675,639		-			(8,752	)		668,122
Less - accumulated depreciation and amortization		988		245,157		-			(7,961	)		238,184
		247		430,482		-			(791	)		429,938
Deferred financing costs, net		2,775		774		-			-			3,549
Commutation account		12,606		-		-			-			12,606
Prepaid insurance, net		3,331		-		-			-			3,331
Other intangible assets, net		-		1,422		-			-			1,422
Other assets		2,508		80		-			-			2,588
Investment in subsidiaries		483,766		-		-			(483,766	)		-
Total assets	$	763,289	$	934,847	$	189		$	(496,816	)	$	1,201,509
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities:
Accounts payable	$	2,480	$	357,097	$	-		$	-		$	359,577
Accrued dividends		58,726		-		-			-			58,726
Accrued turnaround cost		-		12,696		-			-			12,696
Accrued interest		2,485		-		-			-			2,485
Accrued liabilities and other		26,853		25,205		269			-			52,327
Total current liabilities		90,544		394,998		269			-			485,811
Long-term debt		150,000		-		-			-			150,000
Long-term accrued and other liabilities		-		47,698		-			-			47,698
Deferred compensation liability and other		2,214		-		-			-			2,214
Deferred income taxes		70,727		71,563		-			(71,563	)		70,727
Payable to affiliated companies		4,745		7,026		-			(11,771	)		-
Shareholders’ equity		445,059		413,562		(80	)		(413,482	)		445,059
Total liabilities and shareholders’ equity	$	763,289	$	934,847	$	189		$	(496,816	)	$	1,201,509

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 Statement of Cash Flows
For the Year Ended December 31, 2005
(in thousands)
	FOC (Parent)			FHI (Guarantor Subsidiaries)			Other Non-Guarantor Subsidiaries			Eliminations			Consolidated
Cash flows from operating activities:
Net income	$	272,532		$	286,787		$	90		$	(286,877	)	$	272,532
Adjustments to reconcile net income to net cash from operating activities:
Equity in earnings of subsidiaries		(458,023	)		-			-			458,023			-
Cumulative effect of accounting change, net of income taxes		(1,530	)		2,503			-			1,530			2,503
Depreciation and amortization		69			35,700			-			(556	)		35,213
Deferred income taxes		28,881			-			-			-			28,881
Income tax benefits of stock compensation		7,792			-			-			-			7,792
Income taxes eliminated in consolidation		-			169,859			-			(169,859	)		-
Deferred finance cost amortization		483			302			-			-			785
Deferred compensation amortization		1,363			-			-			-			1,363
Gains on sales of assets		(3	)		(3,641	)		-			-			(3,644	)
Long-term commutation account and prepaid insurance		3,832			-			-			-			3,832
Amortization of long-term prepaid insurance		1,211			-			-			-			1,211
Other		492			(65	)		-			-			427
Changes in components of working capital		24,853			(15,411	)		-			-			9,442
Net cash provided by (used in) operating activities		(118,048	)		476,034			90			2,261			360,337
Cash flows from investing activities:
Additions to property, plant and equipment		(143	)		(107,306	)		-			(2,261	)		(109,710	)
El Dorado contingent earn-out payment		-			(7,500	)		-			-			(7,500	)
Proceeds from sale of assets		3			5,497			-			-			5,500
Net proceeds from insurance - involuntary conversion claim		-			2,142			-			-			2,142
Net cash used in investing activities		(140	)		(107,167	)		-			(2,261	)		(109,568	)
Cash flows from financing activities:
Proceeds from issuance of common stock		23,616			-			-			-			23,616
Purchase of treasury stock		(34,819	)		-			-			-			(34,819	)
Dividends paid		(7,776	)		-			-			-			(7,776	)
Debt issue costs and other		(100	)		(14	)		-			-			(114	)
Intercompany transactions		276,215			(276,125	)		(90	)		-			-
Net cash provided by (used in) financing activities		257,136			(276,139	)		(90	)		-			(19,093	)
Increase in cash and cash equivalents		138,948			92,728			-			-			231,676
Cash and cash equivalents, beginning of period		105,409			18,980			-			-			124,389
Cash and cash equivalents, end of period	$	244,357		$	111,708		$	-		$	-		$	356,065

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
Adjustments to reconcile net income to net cash from operating activities:
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 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  6.625% Senior Notes		150,000			-			-			-			150,000
Repurchase of 11.75% 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
Adjustments to reconcile net income to net cash from operating activities:
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 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 9.125% 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	)
Decrease 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

SELECTED QUARTERLY FINANCIAL AND OPERATING DATA
(Dollars in thousands, except per share and per bbl)
	2005									2004
Unaudited	Fourth			Third		Second		First		Fourth		Third		Second		First
Revenues	$	1,150,315		$	1,185,927	$	972,280	$	692,640	$	803,404	$	785,076	$	735,904	$	537,332
Operating income		103,408			177,250		107,688		57,663		15,881		42,557		85,433		(322	)
Cumulative effect of accounting change, net of income taxes		(2,503	)		-		-		-		-		-		-		-
Net income (loss)		62,950			109,185		65,961		34,436		239		23,792		49,469		(3,736	)
Basic earnings (loss) per share:
Before cumulative effect of accounting change		1.16			1.95		1.20		0.64		0.00		0.44		0.93		(0.07	)
Cumulative effect of accounting change		(.04	)		-		-		-		-		-		-		-
Net income (loss)		1.12			1.95		1.20		0.64		0.00		0.44		0.93		(0.07	)
Diluted earnings (loss) per share:
Before cumulative effect of accounting change		1.14			1.91		1.16		0.62		0.00		0.43		0.91		(0.07	)
Cumulative effect of accounting change		(.04	)		-				-		-		-		-		-
Net income (loss)		1.10			1.91		1.16		0.62		0.00		0.43		0.91		(0.07	)
Adjusted EBITDA (1)		111,960			187,046		116,293		65,923		27,978		50,723		93,970		7,497
Refining operations:
Total charges (bpd) (2)		175,589			176,566		171,316		150,580		164,581		169,436		172,951		152,015
Gasoline yields (bpd) (3)		92,850			85,827		88,306		67,006		85,997		84,477		86,782		74,468
Diesel and jet fuel yields (bpd) (3)		57,926			55,409		58,060		49,111		54,898		55,057		54,917		47,459
Total product sales (bpd)		181,436			177,196		176,514		145,911		169,518		174,204		171,460		148,642
Average gasoline crack spread (per bbl)	$	8.59		$	18.11	$	12.50	$	7.28	$	3.71	$	8.88	$	14.23	$	7.49
Average diesel crack spread (per bbl)		24.69			18.38		15.51		9.92		9.84		8.10		7.39		4.07
Average light/heavy crude oil differential (per bbl)		18.11			14.93		14.15		14.10		13.34		9.28		8.81		8.17
Average WTI/WTS crude oildifferential (per bbl)		5.56			3.13		4.67		4.68		5.82		2.95		3.29		2.88

(1)   Adjusted EBITDA represents income before cumulative effect of accounting change, interest expense, interest and investment 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):

	2005												2004
	Fourth			Third			Second			First			Fourth			Third			Second			First
Net income (loss)	$	62,950		$	109,185		$	65,961		$	34,436		$	239		$	23,792		$	49,469		$	(3,736	)
Add cumulative effect of accounting change, net of income taxes		2,503			-			-			-			-			-			-			-
Add provision (benefit) for income taxes		39,668			67,843			39,778			20,927			330			13,437			30,813			(2,241	)
Add interest expense and other financing costs		2,006			2,359			2,939			3,037			19,955			5,813			5,949			5,856
Subtract interest and investment income		(3,719	)		(2,137	)		(990	)		(737	)		(826	)		(485	)		(204	)		(201	)
Add depreciation and amortization		8,552			9,796			8,605			8,260			8,280			8,166			7,943			7,819
Adjusted EBITDA	$	111,960		$	187,046		$	116,293		$	65,923		$	27,978		$	50,723		$	93,970		$	7,497

(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 and 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 and 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.

Item 9B.    Other Information

None.

PART III

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

PART IV

Item 15.    Exhibits and Financial Statement Schedules

(a)1.Financial Statements and Supplemental Data

(a)2.Financial Statements Schedules

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

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

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

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

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

* 3.5 Articles of Amendment to the Restated Articles of Incorporation of Frontier Oil Corporation dated May 23, 2005 (Exhibit 3.1 to Form 8-K ,File Number 1-07627, filed May 24, 2005).

* 3.6 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 October 1, 2004, among the Company, as issuer, the guarantors party thereto and Wells Fargo Bank, N.A., as trustee relating to the Company’s 6.625% Senior Notes due 2011 (Exhibit 4.1 to Form 8-K, File Number1-07627, filed October 4, 2004).

* 4.2 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).

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

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

*² 10.3 Executive Change in Control Severance Agreement effective December 30, 2005, between the Company and James R. Gibbs (Exhibit 10.1 to Form 8-K, File Number 1-07627, filed February 2, 2006).

*² 10.4 Executive Change in Control Severance Agreement effective December 30, 2005, between the Company and W. Reed Williams (Exhibit 10.2 to Form 8-K, File Number 1-07627, filed February 2, 2006).

*² 10.5 Executive Change in Control Severance Agreement effective December 30, 2005, between the Company and Michael C. Jennings (Exhibit 10.3 to Form 8-K, File Number 1-07627, filed February 2, 2006).

*² 10.6 Executive Change in Control Severance Agreement effective December 30, 2005, between the Company and Doug S. Aron (Exhibit 10.4 to Form 8-K, File Number 1-07627, filed February 2, 2006).

*² 10.7 Executive Change in Control Severance Agreement effective December 30, 2005, between the Company and J. Currie Bechtol (Exhibit 10.5 to Form 8-K, File Number 1-07627, filed February 2, 2006).

*² 10.8 Executive Change in Control Severance Agreement effective December 30, 2005, between the Company and Gerald B. Faudel (Exhibit 10.6 to Form 8-K, File Number 1-07627, filed February 2, 2006).

*² 10.9 Executive Change in Control Severance Agreement effective December 30, 2005, between the Company and Jon D. Galvin (Exhibit 10.7 to Form 8-K, File Number 1-07627, filed February 2, 2006).

*² 10.10 Executive Change in Control Severance Agreement effective December 30, 2005, between the Company and Nancy J. Zupan (Exhibit 10.8 to Form 8-K, File Number 1-07627, filed February 2, 2006).

*² 10.11 Executive Change in Control Severance Agreement effective December 30, 2005, between the Company and Penny S. Newmark (Exhibit 10.9 to Form 8-K, File Number 1-07627, filed February 2, 2006).

*² 10.12 Executive Change in Control Severance Agreement effective December 30, 2005, between the Company and Lloyd J. Nordhausen (Exhibit 10.10 to Form 8-K, File Number 1-07627, filed February 2, 2006).

*² 10.13 Executive Change in Control Severance Agreement effective December 30, 2005, between the Company and Kent A. Olsen (Exhibit 10.11 to Form 8-K, File Number 1-07627, filed February 2, 2006).

*² 10.14 Executive Change in Control Severance Agreement effective December 30, 2005, between the Company and Joel W. Purdy (Exhibit 10.12 to Form 8-K, File Number 1-07627, filed February 2, 2006).

*² 10.15 Executive Change in Control Severance Agreement effective December 30, 2005, between the Company and Billy N. Rigby (Exhibit 10.13 to Form 8-K, File Number 1-07627, filed February 2, 2006).

*² 10.16 Executive Change in Control Severance Agreement effective December 30, 2005, between the Company and James M. Stump (Exhibit 10.14 to Form 8-K, File Number 1-07627, filed February 2, 2006).

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

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

* 10.19 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.

* 10.20 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).

*² 10.21 Directors’ Compensation Summary Sheet (Exhibit 10.1 to Form 8-K, File Number 1-07627, filed April 20, 2005).

*² 10.22 Form of Non-Employee Director Restricted Stock Unit Grant Agreement (Exhibit 10.1 to Form 8-K, File Number 1-07627, filed May 2, 2005).

*² 10.23 Form of Restricted Stock Agreement (Exhibit 10.1 to Form 8-K, File Number 1-07627, filed May 6, 2005).

*² 10.24 Summary of Management Incentive Compensation Plan (Exhibit 10.2 to Form 8-K, File Number 1-07627, filed May 6, 2005).

*² 10.25 Summary of Long-Term Incentive Compensation Plan for 2005 (Exhibit 10.3 to Form 8-K, File Number 1-07627, filed May 6, 2005).

*² 10.26 Letter Agreement dated May 20, 2005, between the Company and Ms. Julie H. Edwards (Exhibit 10.1 to Form 8-K, File Number 1-07627, filed May 24, 2005).

21 Subsidiaries of the Registrant.

23 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.

²Diamond indicates management contract or compensatory plan or arrangement.

(b) Exhibits

The Company’s 2005 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
			Schedule I
	December 31,
	2005			2004
ASSETS	(in thousands)
Current assets:
Cash and cash equivalents	$	244,357		$	105,409
Trade and other receivables		6,381			7,013
Deferred tax assets		6,819			6,748
Other current assets		499			105
Total current assets		258,056			119,275
Property, plant and equipment, at cost:
Furniture, fixtures and other		1,235			1,114
Less - accumulated depreciation		988			941
		247			173
Deferred financing costs, net		2,775			3,252
Commutation account		12,606			16,438
Prepaid insurance, net		3,331			4,542
Other assets		2,508			2,108
Investment in subsidiaries		483,766			295,764
Total assets	$	763,289		$	441,552
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	2,480		$	853
Accrued interest		2,485			2,485
Accrued dividends		58,726			1,652
Accrued liabilities and other		26,853			1,853
Total current liabilities		90,544			6,843
Long-term debt		150,000			150,000
Deferred compensation liability		2,214			1,516
Deferred income taxes		70,727			42,550
Payable to affiliated companies		4,745			530
Shareholders’ equity		445,059			240,113
Total liabilities and shareholders’ equity	$	763,289		$	441,552

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
							Schedule I
	Years Ended December 31,
	2005			2004			2003
	(in thousands)
Revenues		($6	)		($6	)		($17	)
		(6	)		(6	)		(17	)
Costs and expenses:
Selling and general expenses, excluding depreciation		14,681			15,590			7,936
Merger termination and legal costs		48			3,824			8,739
Depreciation		69			75			113
Gain on sale of assets		(3	)		-			-
		14,795			19,489			16,788
Operating income		(14,801	)		(19,495	)		(16,805	)
Interest expense and other financing costs		10,593			35,004			26,981
Interest and investment income		(5,905	)		(1,545	)		(1,004	)
Equity in earnings of subsidiaries		(458,023	)		(165,038	)		(48,949	)
		(453,335	)		(131,579	)		(22,972	)
Income before income taxes		438,534			112,084			6,167
Provision for income taxes		167,532			42,320			2,935
Income before cumulative effect of accounting change		271,002			69,764			3,232
Income tax benefit for cumulative effect of accounting change		1,530			-			-
Net income	$	272,532		$	69,764		$	3,232

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 Cash Flows
							Schedule I
	Years Ended December 31,
	2005			2004			2003
	(in thousands)
Operating Activities
Net income	$	272,532		$	69,764		$	3,232
Equity in earnings of subsidiaries		(458,023	)		(165,038	)		(48,949	)
Cumulative effect of accounting change,		(1,530	)		-			-
net of income taxes
Depreciation		69			75			113
Deferred income taxes		28,881			25,005			2,655
Income tax benefits of stock compensation		7,792			5,168			-
Deferred finance cost and bond discount amortization		483			5,180			2,206
Deferred employee compensation amortization		1,363			1,180			1,386
Long-term commutation account and prepaid insurance		3,832			3,712			(26,566	)
Amortization of long-term prepaid insurance		1,211			1,451			423
Other		489			582			(264	)
Changes in components of working capital		24,853			(5,664	)		49
Net cash used by operating activities		(118,048	)		(58,585	)		(65,715	)
Investing Activities
Additions to property, plant and equipment		(143	)		(3	)		(47	)
Proceeds from sale of asset		3			-			240
Other investments		-			-			(32	)
Investment in subsidiaries		-			-			(18,039	)
Net cash used by investing activities		(140	)		(3	)		(17,878	)
Financing Activities
Proceeds from issuance of 6.625% Senior Notes		-			150,000			-
Repurchases of debt:
11.75% Senior Notes		-			(170,449	)		-
9.125% Senior Notes		-			-			(39,475	)
Proceeds from issuance of common stock		23,616			3,923			1,441
Purchase of treasury stock		(34,819	)		(3,029	)		(1,075	)
Intercompany transactions, net		4,215			(202	)		117
Dividends paid to shareholders		(7,776	)		(5,664	)		(5,187	)
Dividends received from subsidiaries		272,000			132,851			81,500
Debt issue costs		(100	)		(3,279	)		-
Net cash provided by financing activities		257,136			104,151			37,321
Increase (decrease) in cash and cash equivalents		138,948			45,563			(46,272	)
Cash and cash equivalents, beginning of period		105,409			59,846			106,118
Cash and cash equivalents, end of period	$	244,357		$	105,409		$	59,846

 

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
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)
2005
Allowance for doubtful accounts	$	500	$	-	$	-	$	500
Turnaround accruals (1)		28,526		15,443		16,151		27,818
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		-		1555		-
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

(1) The turnaround accrual deductions are actual costs incurred.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized on the date indicated.

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

Date: March 1, 2006

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of Frontier Oil Corporation and in the capacities and on the date indicated.

/s/ James R. Gibbs	/s/ T. Michael Dossey
James R. Gibbs	T. Michael Dossey
Chairman of the Board, President and	Director
Chief Executive Officer and Director
(chief executive officer)
/s/ Michael C. Jennings	/s/ James H. Lee
Michael C. Jennings	James H. Lee
Executive Vice President	Director
Chief Financial Officer
(principal financial officer)
/s/ Nancy J. Zupan	/s/ Paul B. Loyd, Jr.
Nancy J. Zupan	Paul B. Loyd, Jr.
Vice President - Controller	Director
(principal accounting officer)
/s/ Douglas Y. Bech	/s/ Michael E. Rose
Douglas Y. Bech	Michael E. Rose
Director	Director
/s/ G. Clyde Buck
G. Clyde Buck
Director

Date: March 1, 2006

EX-21

EXHIBIT 21 - LIST OF SUBSIDIARIES

Wainoco Resources Inc. (incorporated in Delaware),

a subsidiary of Frontier Oil Corporation

Wainoco Oil & Gas Company (incorporated in Delaware),

a subsidiary of Wainoco Resources Inc.

Frontier Holdings Inc. (incorporated in Delaware),

a subsidiary of Frontier Oil Corporation

Frontier Refining & Marketing Inc. (incorporated in Delaware),

a subsidiary of Frontier Holdings Inc.

Frontier Refining Inc. (incorporated in Delaware),

a subsidiary of Frontier Refining & Marketing Inc.

Frontier Oil and Refining Company (incorporated in Delaware),

a subsidiary of Frontier Refining & Marketing Inc.

Frontier Pipeline Inc. (incorporated in Delaware),

a subsidiary of Frontier Refining & Marketing Inc.

Frontier El Dorado Refining Company (incorporated in Delaware),

a subsidiary of Frontier Refining & Marketing Inc.

EX-23

EXHIBIT 23 - CONSENT OF DELOITTE & TOUCHE LLP

Consent of Independent Registered Public Accounting Firm

We consent to the incorporation by reference in Registration Statement No. 333-130292 on Form S-3ASR, Registration Statement No. 333-120643 on Form S-4, and Registration Statement Nos. 333-36204, 333-56946, 333-59290, 333-83971, and 333-89876 on Form S-8 of our reports dated March 1, 2006, relating to the financial statements and financial statement schedules of Frontier Oil Corporation (which included an emphasis of a matter paragraph regarding the Company’s adoption of the provisions of FASB Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations) and management’s report of the effectiveness of internal control over financial reporting, appearing in this Annual Report on Form 10-K of Frontier Oil Corporation for the year ended December 31, 2005.

DELOITTE & TOUCHE LLP

Houston, Texas

March 1, 2006

EX-31.1

EXHIBIT 31.1

Certification By Chief Executive Officer

Pursuant To Rule 13a-14(a) and 15d-14(a) Under The Exchange Act

I, James R. Gibbs, certify that:

1.   I have reviewed this annual report on Form 10-K of Frontier Oil Corporation;

2.   Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.   Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.   The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.   The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

March 1, 2006

/s/ James R. Gibbs

James R. Gibbs

Chairman of the Board, President

and Chief Executive Officer

EX-31.2

EXHIBIT 31.2

Certification By Chief Financial Officer

Pursuant To Rule 13a-14(a) and 15d-14(a) Under The Exchange Act

I, Michael C. Jennings, certify that:

1.   I have reviewed this annual report on Form 10-K of Frontier Oil Corporation;

2.   Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.   Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.   The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and the internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.   The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

March 1, 2006

/s/ Michael C. Jennings

Michael C. Jennings

Executive Vice President -

Chief Financial Officer

EX-32.1

EXHIBIT 32.1

Certification By Chief Executive Officer Pursuant To

18 U.S.C. Section 1350,

As Adopted Pursuant To

Section 906 Of The Sarbanes-Oxley Act Of 2002

In connection with the Annual Report of Frontier Oil Corporation (the “Company”) on Form 10-K for the period ending December 31, 2005 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, James R. Gibbs, Chairman of the Board, President and Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, to my knowledge, that:

(1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the Company.

/s/ James R. Gibbs

James R. Gibbs

Chairman of the Board, President and

Chief Executive Officer

March 1, 2006

EX-32.2

EXHIBIT 32.2

Certification Of Chief Financial Officer Pursuant To

18 U.S.C. Section 1350,

As Adopted Pursuant To

Section 906 Of The Sarbanes-Oxley Act Of 2002

In connection with the Annual Report of Frontier Oil Corporation (the “Company”) on Form 10-K for the period ending December 31, 2005 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Michael C. Jennings, Executive Vice President - Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, to my knowledge, that:

(1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the Company.

/s/ Michael C. Jennings

Michael C. Jennings

Executive Vice President -

Chief Financial Officer

March 1, 2006