FRONTIER OIL CORP /NEW/ (Form: 10-K, Received: 02/28/2007 16:21:27)

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

FORM 10-K

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
þ	OF THE SECURITIES EXCHANGE ACT OF 1934
For the Fiscal Year Ended: December 31, 2006
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
o	OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from . . . . to . . . .

Commission File Number: 1-7627

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

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

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

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

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

		Name of Each Exchange
Title of Each Class		on Which Registered

Common Stock		New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act:
None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
Yes þ No ¨
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
Yes ¨ No þ
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No ¨

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, 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, 2006 was $3.1 billion.

The number of shares of common stock outstanding as of February 22, 2007 was 109,223,306.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Annual Proxy Statement for the registrant’s 2007 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, eastern 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 approximately 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 oil capacity of 52,000 bpd on a twelve-month average. We market its refined products primarily in the eastern slope of the Rocky Mountain region, which encompasses eastern Colorado (including the Denver metropolitan area), eastern Wyoming and western Nebraska (the “Eastern Slope”). The Cheyenne Refinery has a coking unit, which allows the refinery to process extensive amounts of heavy crude oil for use as a feedstock. The ability to process heavy crude oil lowers our raw material costs because heavy crude oil is generally less expensive than lighter types of crude oil. For the year ended December 31, 2006, heavy crude oil constituted approximately 73% of the Cheyenne Refinery’s total crude oil charge. For the year ended December 31, 2006, the Cheyenne Refinery’s product yield included gasoline (42%), diesel fuel (31%) 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 an average crude oil 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, beginning in early 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 1999, we entered into a 15-year refined product offtake agreement for gasoline and diesel production at this refinery with Shell Oil Products US (“Shell”). Shell has also agreed to purchase all jet fuel production until the end of the product offtake agreement. As our deliveries to Shell 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, 2006, the El Dorado Refinery’s product yield included gasoline (52%), diesel and jet fuel (36%) and chemicals and other refined petroleum products (12%).

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, while the discount at which sour crude oil sells compared to light crude oil is known as the sweet/sour, or WTI/WTS, spread or differential. Coking units, such as the ones at our Refineries, can process certain by-products and heavy residual oils to produce additional volumes of gasoline and diesel, thus increasing the aggregate yields of higher 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 and generally increases a refinery’s complexity rating. 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 processing 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. Turnarounds are implemented using our regular personnel as well as additional contract labor. Once started, turnaround work typically proceeds 24 hours per day to minimize unit downtime. We defer the costs of turnarounds when incurred and amortize them on a straight-line basis over the period of time estimated to lapse until the next turnaround occurs. We normally schedule our turnaround work during the spring or fall of each year. When we perform a turnaround, we may increase product inventories prior to the turnaround to minimize the impact of the turnaround on our sales of refined products.

During 2006, we had no major turnaround work at the El Dorado Refinery. However, an existing distillate hydrotreater was revamped and loaded with new catalyst in preparation for the production of ultra-low sulfur diesel (“ULSD”). Construction of a new hydrogen manufacturing plant and a new distillate hydrotreater was also completed during the second quarter of 2006. Those units were brought on-line, and we completed plant modifications necessary to fully comply with the 2006 regulations pertaining to the production of ULSD. At the El Dorado Refinery, the only 2007 major turnaround work is expected to be on the alkylation unit.

The major turnaround work performed at the Cheyenne Refinery during 2006 was on the alkylation plant. However, the distillate hydrotreater unit at the Cheyenne Refinery was also revamped in 2006 in preparation for the production of ULSD, including the modification of an existing reactor and addition of a new reactor and furnace. For 2007, the major turnaround work planned at the Cheyenne Refinery is on the fluid catalytic cracking unit (“FCCU”), the crude unit and the coker. Timing of these turnarounds is expected to coincide with our shutdown of the delayed coking unit to implement the planned coker unit 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, 2006, we sold approximately 85% of the Cheyenne Refinery’s gasoline sales volumes in Colorado and 12% in Wyoming. For the year ended December 31, 2006, we sold approximately 69% of the Cheyenne Refinery’s diesel in Wyoming and 25% in Colorado. Because of the location of the Cheyenne Refinery, we are able to sell a significant portion of its diesel product from the truck rack at the Refinery, thereby eliminating transportation costs. The gasoline and remaining diesel produced by this Refinery are primarily shipped via pipeline to terminals for distribution by truck or rail. Pipeline shipments from the Cheyenne Refinery are handled mainly by the Plains All American Pipeline (formerly Rocky Mountain Pipeline), serving Denver and Colorado Springs, Colorado, and the ConocoPhillips pipeline, serving Sidney, Nebraska.

We sell refined products from our Cheyenne Refinery to a broad base of independent retailers, jobbers and major oil companies. Refined product prices are determined by local market conditions at distribution centers known as “terminal racks,” and prices at the terminal racks are posted daily by sellers. The customer at a terminal rack typically supplies its own truck transportation. In the year ended December 31, 2006, approximately 88% of the Cheyenne Refinery’s sales were made to its 25 largest customers compared to the year ended December 31, 2005, when 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.

For the year ended December 31, 2006, Shell was the El Dorado Refinery’s largest customer, representing approximately 64% of the El Dorado Refinery’s total sales and 44% of our 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 increases by 5,000 bpd each year through 2009. In 2006, we retained 35,000 bpd of the Refinery’s gasoline and diesel production. As our sales to Shell under this agreement decrease, we intend to sell the gasoline and diesel produced by the El Dorado Refinery in the same general markets as Shell currently does, as described above.

Competition

Cheyenne Refinery. The most competitive market for the Cheyenne Refinery’s products is the Denver metropolitan area. Other than the Cheyenne Refinery, three principal refineries serve the Denver market: 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 certain marketing advantages over our principal competitors in the Eastern Slope area, all of which also have retail outlets, because we do not compete directly with independent retailers of gasoline and diesel.

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

Crude Oil Supply

Cheyenne Refinery. In the year ended December 31, 2006, we obtained approximately 58% of the Cheyenne Refinery’s crude oil charge from Canada, 22% from Wyoming, 17% from Colorado and 3% from other domestic sources. During the same period, heavy crude oil constituted approximately 73% of the Cheyenne Refinery’s total crude oil charge, compared to 82% in 2005 as we increased our charges of lighter crude oil in 2006 to take advantage of market opportunities. 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. We anticipate that by mid-2007 Plains All American Pipeline will have completed construction of a new pipeline from Guernsey to Cheyenne, Wyoming. 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 processing of 73% heavy crude oil in 2006, and our ability to process a higher percentage of heavy crude oil, gives 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. We have a five-year crude oil supply agreement with Baytex Marketing Ltd., which commenced January 1, 2003, and expires December 31, 2007. This agreement provides for the purchase of up to 20,000 bpd of a Lloydminster crude oil blend, a heavy Canadian crude oil. This type of crude oil typically sells at a discount from lighter crude oil prices. 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.

El Dorado Refinery. In the year ended December 31, 2006, we obtained approximately 67% of the El Dorado Refinery’s crude oil charge from Texas, 15% from Canada, 8% from Kansas, 6% from Louisiana, and the remaining 4% from other foreign and domestic locations. El Dorado is 125 miles north of Cushing, Oklahoma, a major crude oil hub. The Cushing hub is supplied by the Seaway pipeline, which runs from the Gulf Coast; the Basin pipeline, which runs through Wichita Falls, Texas from West Texas; the Sun pipeline, which originates at the Gulf Coast and connects to the Basin pipeline at Wichita Falls and the Spearhead Pipeline which connects at Griffith, Indiana with the Enbridge Pipeline to bring crude from Canada. The Osage pipeline runs from Cushing to El Dorado and transported approximately 92% of our crude oil charge during the year ended December 31, 2006. The remainder of our crude oil charge was transported to the El Dorado Refinery through Kansas gathering system pipelines. We have a Transportation Services Agreement to transport 38,000 bpd of crude oil on the Spearhead Pipeline from Griffith, Indiana to Cushing, Oklahoma, which enables 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 of March 2006. We have the right to extend the agreement for an additional ten years and increase the volume transported under a preferential tariff to 50,000 bpd.

Saf e ty

We are subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) and comparable state occupational safety statutes.

The Cheyenne Refinery’s OSHA recordable incident rate in 2006 of 1.67 is higher than the latest reported industry average of 1.05 in 2005 as compiled by the National Petrochemical and Refiner’s Association (“NPRA”). While the frequency of injuries at the Cheyenne Refinery has risen above the NPRA average and our 2005 OSHA recordable incident rate of 1.07, we continue to emphasize safety and the various programs in place that support maintenance of a strong safety culture. This emphasis was evidenced by our 2006 achivement of completing more than four years without a lost-time accident. These efforts are supported by both management and our union employees. We are working to strengthen our behavioral-based safety observation programs as well as our process safety management programs. Because our contractor injury rate is higher than our employee injury rate at our Cheyenne Refinery, we increased our efforts in the area of contractor safety in 2006. By improving the training of the contractor workforce in general, we believe that we can 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’s OSHA recordable incident rate of 1.47 in 2006 compares to a rate of zero for 2005. The industry standard incident rate is 1.05 as last reported by NPRA for 2005. After completing 16 months in March 2006 without a recordable injury, El Dorado experienced a recordable event in April and four other OSHA recordable events for the rest of 2006. Management and employees at the El Dorado Refinery remain committed to those programs, processes and behaviors that had helped achieve a run of almost a year-and-a-half without a single OSHA recordable event. Improvement in contractor safety was a key initiative for the El Dorado refinery during 2006. Behavior-based safety programs were introduced in 2004 for our own employees. During 2006, we included the majority of our contractor base in these programs as well. These efforts resulted in a significant increase in contractor safety awareness and much improved contractor safety results.

Our employees and management continue to dedicate their efforts to a balanced safety program that combines individual behavioral elements in a safety-coaching environment with structured management-driven programs to improve the safety of the facility and operating procedures. Our objective is a safe working environment for employees who know how to work safely. Encouraging all employees to contribute toward improving safety performance through personal involvement in safety-related activities is an industry-proven way to reduce injuries.

Government Regulation

Environmental Matters.

See “Environmental” in Note 9 in the “Notes to Consolidated Financial Statements.”

Centennial Pipeline Regulation. We own a 34.72% undivided 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, 2006, we employed approximately 747 full-time employees: 82 in the Houston and Denver offices, 285 at the Cheyenne Refinery, and 380 at the El Dorado Refinery. The Cheyenne Refinery employees include 99 administrative and technical personnel and 186 union members. The El Dorado Refinery employees include 138 administrative and technical personnel and 242 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.

For our Cheyenne Refinery, the current contract between the Company, the USW, and its Local 8-0574 (which represents approximately 150 workers) expires in July 2009.

At our El Dorado Refinery, the current contract between the Company, the USW, and its Local 5-241 (which represents approximately 250 workers) expires in January 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.

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 slightly in 2006 over 2005 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 (ConocoPhillips WTI crude oil posting plus) 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 affected by the light/heavy crude oil differential, and our profitability at our El Dorado Refinery is affected by the WTI/WTS crude oil differential. Starting in March 2006, when our El Dorado Refinery began receiving heavy Canadian crude oil through the Spearhead Pipeline, its profitability also began benefiting from the light/heavy crude oil differential. We typically prefer to refine heavy sour crude oil at the Cheyenne Refinery and intermediate sour crude oil at the El Dorado Refinery because 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 Cheyenne Refinery light/heavy crude oil differential averaged $16.21 per barrel in the year ended December 31, 2006, compared to $15.32 per barrel in the same period in 2005. The El Dorado Refinery light/heavy crude oil differential averaged $18.13 per barrel in the ten months ended December 31, 2006. The WTI/WTS crude oil differential averaged $5.22 per barrel in the year ended December 31, 2006, compared to $4.51 per barrel in the same period in 2005. Crude oil prices were historically high during 2006, contributing to attractive light/heavy crude oil differentials and WTI/WTS crude oil differentials. However, at the end of 2006, crude oil prices had declined from the highest 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. In 2004, 2005 and 2006, 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 negatively impact 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 our Refineries or the environment or cause personal injuries. If either of our Refineries experiences a major accident or fire or other event or an interruption in supply or operations, our business could be materially adversely affected if the damage or liability exceeds the amounts of business interruption, property, terrorism and other insurance that we maintain against these risks.

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

We face substantial competition from other refining and pipeline companies, and greater competition in the markets where we sell refined products could adversely affect our sales and profitability.

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

We are not engaged in the petroleum exploration and production business and therefore do not produce any of our crude oil feedstocks. We do not have a retail business and therefore are dependent upon others for outlets for our refined products. Certain of our competitors, however, obtain a portion of their feedstocks from company-owned production and have retail outlets. Competitors that have their own 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 operations involve environmental risks that may require us to make substantial capital expenditures to remain in compliance or that could give rise to material liabilities.

Our results of operations may be affected by increased costs of complying with the extensive environmental laws to which our business is subject and from any possible contamination of our facilities as a result of accidental spills, discharges or other releases of petroleum or hazardous substances.

Our operations are subject to extensive federal, state and local environmental and health and safety laws and regulations relating to the protection of the environment, including those governing the emission or discharge of pollutants into the air and water, product specifications and the generation, treatment, storage, transportation 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 “Litigation - Beverly Hills Lawsuits” in Note 9 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 prior owners of our facilities to complete their clean-up obligations, the liability to third parties for damage to their property, or the need to address newly-discovered information or conditions that may require a response could be significant, and the payment of these amounts could have a material adverse effect on our business, financial condition and results of operations.

Our operations are subject to various laws and regulations relating to occupational health and safety, which could give rise to increased costs and material liabilities.

The nature of our business may result from time to time in industrial accidents. Our operations are subject to various laws and regulations relating to occupational health and safety. Continued efforts to comply with applicable health and safety laws and regulations, or a finding of non-compliance with current regulations, could result in additional capital expenditures or operating expenses, as well as fines and penalties.

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

Our operations require numerous permits and authorizations under various laws and regulations, including environmental and health and safety laws and regulations. These authorizations and permits are subject to revocation, renewal or modification and can require operational changes, which may involve significant costs, to limit impacts or potential impacts on the environment and/or health and safety. A violation of these authorization or permit conditions or other legal or regulatory requirements could result in substantial fines, criminal sanctions, permit revocations, injunctions and/or refinery shutdowns. In addition, major modifications of our operations could require 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 could 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, 2006. 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 approximately 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 lease expiring in April 2012 for our refining, marketing and raw material supply operations.

Item 3. Legal Proceedings

See “Litigation” in Note 9 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 2006 annual CEO certification with the New York Stock Exchange (“NYSE”) on April 28, 2006. We anticipate filing our 2007 annual CEO certification with the NYSE on or about April 27, 2007. In addition, we filed with the SEC as exhibits to our Form 10-K for the year ended December 31, 2005 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 and June 26, 2006 stock splits) as reported on the New York Stock Exchange for 2006 and 2005 are shown in the following table:

2006	High	Low
Fourth quarter Third quarter Second quarter First quarter	$ 33.00 37.80 33.10 30.98	$ 24.00 24.33 23.75 18.99
2005	High	Low
Fourth quarter Third quarter Second quarter First quarter	$ 22.94 23.09 14.91 9.23	$ 15.77 13.28 9.23 5.98

The approximate number of holders of record for our common stock as of February 16, 2007 was 888. Quarterly cash dividends of $0.0125 per share have been declared on our common stock for each quarter beginning with the quarter ended June 2001 through the quarter ended June 30, 2004. The quarterly cash dividend was $0.015 per share for the quarters ended September 30, 2004 through March 31, 2005. The quarterly cash dividend was $0.02 per share for the quarters ended June 30, 2005 through March 31, 2006. In addition, a special cash dividend of $0.50 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 quarterly cash dividend was $0.03 per share for the quarters ended June 30, 2006 through December 31, 2006. Our 6.625% Notes and our Revolving Credit Facility may restrict dividend payments based on the covenants related to interest coverage and restricted payments. See Notes 4 and 5 in the “Notes to Consolidated Financial Statements.”

The following graph indicates the performance of our common stock against the S&P 500 Index and against a refining peer group which is comprised of Sunoco Inc., Holly Corporation, Giant Industries, Inc., Ashland Inc., Valero Energy Corporation and Tesoro Corporation.

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 (or Approximate Dollar Value) of Shares that May Yet Be Purchased Under the Plans or Programs (2)
October 1, 2006 to October 31, 2006	354,300	$ 24.8123	354,300	9,606,848 shares
November 1, 2006 to November 30, 2006	-	-	-	$100 million
December 1, 2006 to December 31, 2006	-	-	-	$100 million
Total fourth quarter	354,300	$ 24.8123	354,300	$100 million

(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 32,000,000 shares (as adjusted for June 2005 and June 2006 stock splits). In November 2006, our Board of Directors approved a new $100 million share repurchase program, which replaced all existing repurchase authorizations and may be utilized for share repurchases in the near term (no shares had been repurchased under this new program as of December 31, 2006). No shares were purchased during the periods shown other than through publicly-announced programs.

(2) Shares shown in this column reflect authorized shares (or approximate dollar value) remaining which may be repurchased under the stock repurchase programs referenced in note 1 above (as adjusted for our two-for-one stock splits in June 2005 and June 2006).

Item 6. Selected Financial Data

Five Year Financial Data
(Unaudited)	Years Ended December 31,
	2006		2005			2004		2003		2002
			As Adjusted			As Adjusted		As Adjusted		As Adjusted
			(1)			(1)		(1)		(1)
	(Dollars in thousands, except per share amounts)
Revenues	$	4,795,953	$	4,001,162		$	2,861,716	$	2,170,503	$	1,813,750
Operating income		574,194		450,013			142,903		53,437		30,030
Cumulative effect of accounting		-		(2,503	)		-		-		-
change, net of income taxes (2)
Net income		379,277		275,158			69,392		4,200		2,300
Basic earnings per share:
Before cumulative effect of accounting change		3.40		2.51			0.65		0.04		0.02
Cumulative effect of accounting change		-		(0.02	)		-		-		-
Net income		3.40		2.49			0.65		0.04		0.02
Diluted earnings per share:
Before cumulative effect of accounting change		3.37		2.44			0.63		0.04		0.02
Cumulative effect of accounting change		-		(0.02	)		-		-		-
Net income		3.37		2.42			0.63		0.04		0.02
Working capital (current assets less current liabilities)		479,518		270,145			106,760		45,049		116,187
Total assets		1,523,925		1,223,057			770,177		662,495		646,350
Long-term debt		150,000		150,000			150,000		168,689		207,966
Shareholders’ equity		775,854		478,692			271,120		200,656		198,669
Dividends declared per common share		0.10		0.575			0.055		0.05		0.05

(1 ) In the fourth quarter of 2006, we adopted a change in accounting method for the costs of turnarounds from the accrual method to the deferral method. Each individual prior period presented above has been adjusted to reflect the period specific effects of applying the new accounting principle. See Note 3 in the “Notes to Consolidated Financial Statements.”

(2) As of December 31, 2005, we adopted FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations”. See Note 2 in the “Notes to Consolidated Financial Statements.”

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 . We make our web site content available for informational purposes only. It should not be relied upon for investment purposes, nor is it incorporated by reference in this Form 10-K.

Overview

Our Refineries have a total annual average crude oil capacity of 162,000 bpd. The four significant indicators of our profitability which are reflected and defined in the operating data at the end of this analysis, are the gasoline crack spread, the diesel crack spread, the light/heavy crude oil differential and the WTI/WTS crude oil differential. Other significant factors that influence our financial results are refinery utilization, crude oil price trends, asphalt and by-product margins and refinery operating expenses (including natural gas and maintenance). Under our first-in, first-out (“FIFO”) inventory accounting method, crude oil price trends can cause significant fluctuations in the inventory valuation of our crude oil, unfinished products and finished products, thereby resulting in FIFO inventory gains when crude oil prices increase and FIFO inventory losses when crude oil prices decrease during the reporting period. We typically do not use derivative instruments to offset price risk on our base level of operating inventories. See “Price Risk Management Activities” under Item 7A for a discussion of our utilization of futures trading.

The NYMEX crude oil price was volatile during 2006, beginning the year at $61.04 per barrel, reaching a 2006 high of $77.03 per barrel in mid-July, reducing to the annual low of $55.81 per barrel in mid-November and ending 2006 at $61.05 per barrel. Crude oil market fundamentals and geopolitical considerations have caused crude oil prices to be volatile and generally higher than historic averages. The increase in crude oil prices, along with additional production of heavy and/or sour crude oil, increased our crude oil differentials during the year ended December 31, 2006, when compared to the same period in 2005. Our 2006 gasoline and diesel crack spreads were the highest in our history, while 2005 gasoline and diesel crack spreads were the second highest in our history.

As discussed in Note 3 in the “Notes to Consolidated Financial Statements,” during the fourth quarter of 2006 we changed our accounting method for the costs for planned major maintenance (“turnarounds”) from the accrual method to the deferral method. Turnarounds are the scheduled and required shutdowns of refinery processing units for significant overhaul and refurbishment. Under the deferral method, the costs of turnarounds are deferred when incurred and amortized on a straight-line basis over the period of time estimated to lapse until the next turnaround occurs. We adopted this new method of accounting for turnarounds in order to adhere to FSP No. AUG AIR-1 “Accounting for Planned Maintenance Activities,” which prohibits the accrual method of accounting for planned major maintenance activities. The Company elected to early adopt the FSP during the fourth quarter of 2006. The comparative consolidated financial statements for 2005 and 2004 have been adjusted to reflect the period specific effects of applying the new accounting principle. Deferred charges related to these turnaround costs are included in our Consolidated Balance Sheets in “Deferred charges and other assets.” The associated amortization expenses are included in “Refinery operating expenses, excluding depreciation” in our Consolidated Statements of Income.

As discussed in Note 7 in the “Notes to Consolidated Financial Statements,” we effected stock splits on June 17, 2005 and June 26, 2006. All prior period share-related numbers have been revised to reflect the effect of the stock splits.

2006 Compared with 2005

(2005 as Adjusted)

Overview of Results

We had net income for the year ended December 31, 2006, of $379.3 million, or $3.37 per diluted share, compared to net income of $275.2 million, or $2.42 per diluted share, in the same period in 2005. Our operating income of $574.2 million for the year ended December 31, 2006, reflected an increase of $124.2 million from the $450.0 million operating income for the comparable period in 2005. The average diesel crack spread was higher during 2006 ($21.35 per barrel) than in 2005 ($17.13 per barrel). The average gasoline crack spread was also higher during 2006 ($14.10 per barrel) than in 2005 ($11.67 per barrel), and both the light/heavy and WTI/WTS crude oil differentials improved.

Specific Variances

Refined product revenues. Refined product revenues increased $759.7 million, or 39%, from $4.0 billion to $4.8 billion for the year ended December 31, 2006 compared to the same period in 2005. This increase was due to both an increase in average product sales prices ($8.81 higher per sales barrel) and an increase in product sales volumes in 2006 (1,657 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 6,776 bpd at the El Dorado Refinery while decreasing 3,669 bpd at the Cheyenne Refinery for the year ended December 31, 2006 compared to 2005. A Cheyenne Refinery turnaround in April 2006 caused yields to be lower during 2006 than during 2005, and an El Dorado Refinery turnaround from March 1 through April 5, 2005 caused yields to be lower in 2005 than 2006.

Other revenues. Other revenues increased $35.1 million to a $36.3 million gain for the year ended December 31, 2006, compared to a $1.2 million gain for the same period in 2005, the sources of which were $34.6 million in net gains from derivative contracts in the year ended December 31, 2006 compared to net derivative gains of $1.0 million for the same period in 2005 and $1.5 million in gasoline sulfur credit sales in 2006 (none in 2005). We utilized more derivative contracts during the year ended December 31, 2006 than in the comparable period in 2005, primarily due to derivative contracts to hedge Canadian in-transit crude oil for our El Dorado Refinery. See “Price Risk Management Activities” under Item 7A and Note 11 in the “Notes to Consolidated Financial Statements” for a discussion of our utilization of commodity derivative contracts.

Raw material, freight and other costs. Raw material, freight and other costs 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 $603.6 million, or 19%, during the year ended December 31, 2006, from $3.2 billion in 2005 to $3.9 billion in 2006. The increase in raw material, freight and other costs when compared to 2005 was due to higher average crude prices, higher crude oil charges on an overall combined basis, and FIFO inventory losses in the year ended December 31, 2006. We benefited from slightly improved crude oil differentials during the year ended December 31, 2006 compared to the same period in 2005. The average WTI crude oil priced at Cushing, Oklahoma (ConocoPhillips WTI crude oil posting plus) was $64.94 for the year ended December 31, 2006 compared to $55.77 for the year ended December 31, 2005. Crude oil charges were 154,473 bpd for the year ended December 31, 2006, compared to 152,649 bpd for the comparable period in 2005. For the year ended December 31, 2006, we realized an increase in raw material, freight and other costs as a result of net FIFO inventory losses of approximately $16.1 million after tax ($25.7 million pretax, comprised of a $31.7 million loss at the El Dorado Refinery and a $6.0 million gain at the Cheyenne Refinery) due to decreasing crude oil and refined product prices during the latter part of 2006. 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 for the El Dorado Refinery and $8.6 million for the Cheyenne Refinery) because of increasing crude oil and refined product prices.

The Cheyenne Refinery raw material, freight and other costs of $57.07 per sales barrel for the year ended December 31, 2006 increased from $48.49 per sales barrel in the same period in 2005 due to higher crude oil prices and a lower FIFO inventory gain, offset by fewer crude oil charges and the benefit of a slightly improved light/heavy crude oil differential. Crude oil charges of 45,999 bpd for the year ended December 31, 2006 were lower than the 46,922 bpd in the comparable period in 2005 because of the previously mentioned turnaround in 2006. The heavy crude oil utilization rate at the Cheyenne Refinery expressed as a percentage of the total crude oil charge decreased to 73% in the year ended December 31, 2006, from 82% in 2005 as we increased our charges of lighter crude oil to take advantage of favorable pricing opportunities for light crude purchases. The light/heavy crude oil differential for the Cheyenne Refinery averaged $16.21 per barrel in the year ended December 31, 2006 compared to $15.32 per barrel in the same period in 2005.

The El Dorado Refinery raw material, freight and other costs of $63.15 per sales barrel for the year ended December 31, 2006 increased from $54.01 per sales barrel in the same period in 2005 due to higher average crude oil prices and a FIFO inventory loss in 2006 compared to FIFO inventory gains in 2005. Crude oil charges were 108,475 bpd for the year ended December 31, 2006, compared to 105,727 bpd for the comparable period in 2005 because of the previously mentioned turnaround in 2005. In 2006, our El Dorado Refinery began charging Canadian heavy crude oil and achieved a light/heavy crude oil differential of $18.13 per barrel. For the year ended December 31, 2006, the heavy crude oil utilization rate at our El Dorado Refinery expressed as a percentage of the total crude oil charge was approximately 11%. The WTI/WTS crude oil differential increased from an average of $4.51 per barrel in the year ended December 31, 2005 to $5.22 per barrel in the same period in 2006.

Refinery operating expenses. Refinery operating expenses, excluding depreciation, include both the variable costs (energy and utilities) and the fixed costs (salaries, taxes, maintenance costs and other) of operating the Refineries. Refinery operating expenses, excluding depreciation, increased $35.7 million, or 15%, from $241.5 million in the year ended December 31, 2005 to $277.1 million in the comparable period of 2005.

The Cheyenne Refinery operating expenses, excluding depreciation, were $101.9 million in the year ended December 31, 2006, compared to $78.9 million in the comparable period of 2005. The increased expenses included higher maintenance costs ($8.1 million, with $3.0 million of the costs related to a plant-wide steam outage in February 2006, $1.2 million for slop oil centrifuging, $557,000 related to a September 2006 coker outage and $577,000 related to a butamer unit outage), increased environmental expenses ($5.8 million, including a $5.0 million accrual related to a potential waste-water pond clean up), higher salaries and benefits ($4.3 million, including $1.4 million in increased stock-based compensation costs and $787,000 additional bonus accruals), higher additive and chemical costs ($2.1 million, including increased wastewater treatment chemical use, cost of testing chemicals from a new vendor and increased usage of fresh fluid catalyst) and higher turnaround amortization ($1.0 million).

The El Dorado Refinery operating expenses, excluding depreciation, were $175.3 million in the year ended December 31, 2006, increasing from $162.5 million for the year ended December 31, 2005. The primary areas of increased costs were in electricity ($3.8 million), chemicals and additives ($4.1 million), maintenance ($6.2 million, including $1.8 million due to a fire on a distillate hydrotreater unit, $1.1 million for tank repairs and $1.0 million for a gofiner unit catalyst change-out), salaries and benefits ($1.1 million, including $767,000 in increased stock-based compensation costs), lease and rental equipment ($1.3 million, including higher cogeneration facility lease costs and rentals for a reverse osmosis trailer and filter), environmental ($827,000), insurance ($668,000) and non-maintenance contractors ($928,000). Electricity costs were higher during the year ended December 31, 2006, compared to the same period in 2005, as we produced electricity from our cogeneration facility in 2005 and did not do so in 2006. Chemicals and additive costs were higher during the year ended December 31, 2006, compared to the same period in 2005, as the fluid catalytic cracking unit consumed more additives and chemicals running for the full year in 2006, while it was down for turnaround work for approximately one month in 2005. We also purchased more nitrogen and oxygen during 2006 than in 2005 because the cogeneration facility provided us with some nitrogen and oxygen in 2005. We realized a $7.9 million reduction in natural gas costs due to lower natural gas prices and lower consumption in 2006 because we did not purchase natural gas for the cogeneration facility.

Selling and general expenses. Selling and general expenses, excluding depreciation, increased $21.8 million, or 71%, from $30.7 million for the year ended December 31, 2005 to $52.5 million for the year ended December 31, 2006, primarily due to a $15.0 million increase in salaries and benefits expense, which resulted from the adoption on January 1, 2006 of FAS No. 123(R), the issuance of additional stock-based compensation awards, the vesting of stock-based compensation upon the retirement of an executive officer as of March 31, 2006 and higher bonus accruals. See Note 7 under “Stock-based Compensation” in the “Notes to Consolidated Financial Statements” for a detailed discussion of our stock-based compensation. Stock-based compensation expense was $15.8 million for the year ended December 31, 2006 compared to $1.4 million for the comparable period in 2005. Beverly Hills litigation costs also increased by $6.2 million in the year ended December 31, 2006, compared to the year ended December 31, 2005, as the 2005 litigation costs were reduced by insurance recoveries and 2006 litigation costs increased in preparation for certain court proceedings which took place in the fourth quarter of 2006 and early 2007.

Depreciation and amortization. Depreciation and amortization increased $6.0 million, or 17%, for the year ended December 31, 2006 compared to the same period in 2005 because of increased capital investment in our Refineries, including the ultra low sulfur diesel projects.

Interest expense and other financing costs. Interest expense and other financing costs of $12.1 million for the year ended December 31, 2006 increased $1.8 million, or 17%, from $10.3 million in the comparable period in 2005. The increase was due to $1.5 million in accrued interest expense for income tax contingencies in 2006 ($163,000 in 2005) and $1.9 million in facility costs and financing expenses related to the Utexam Master Crude Oil Purchase and Sale Contract entered into in March 2006 (“Utexam Arrangement”) (see “Leases and Other Commitments” in Note 9 in the “Notes to Consolidated Financial Statements”), offset by $3.8 million of interest cost being capitalized in the year ended December 31, 2006, compared to only $2.6 million of interest cost being capitalized in the year ended December 31, 2005 and Revolving Credit Facility interest expense of $79,000 for the year ended December 31, 2006, decreasing by $298,000 from the $377,000 for the year ended December 31, 2005. Average debt outstanding (excluding amounts payable under the Utexam Arrangement) decreased to $151.7 million during the year ended December 31, 2006 from $161.0 million for the same period in 2005.

Interest and investment income. Interest and investment income increased $10.5 million, or 138%, from $7.6 million in the year ended December 31, 2005 to $18.1 million in the year ended December 31, 2006, 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, 2006 was $200.8 million on pretax income of $580.1 million (or 34.6%) compared to $170.0 million on pretax income of $447.3 million (or 37.9%) for the same period in 2005. The American Jobs Creation Act of 2004 (“the Act”) benefited both our 2006 and 2005 current income taxes payable by allowing us an accelerated depreciation deduction of 75% of qualified capital costs incurred to achieve low sulfur diesel fuel requirements (See “Environmental” under Note 9 in the “Notes to Consolidated Financial Statements”). 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 and for the year ended December 31, 2006 we realized a $22.4 million federal income tax credit ($14.5 million excess tax benefit). This credit greatly reduced our 2006 income taxes payable and reduced our overall effective income tax rate. Another provision of the Act which benefited our 2006 and 2005 income taxes payable by an estimated $5.7 million and $3.2 million, respectively, and reduced our overall effective tax rate in both of those years was the Section 199 production activities deduction for manufacturers. See Note 6 in the “Notes to Consolidated Financial Statements” for detailed information on our deferred tax assets. Our effective income tax rate for the year ended December 31, 2007 will be higher than that realized in the year ended December 31, 2006, as we only have approximately $8.4 million of ultra-low sulfur diesel production credits available for utilization in 2007.

2005 Compared with 2004

As Adjusted

Overview of Results

We had net income for the year ended December 31, 2005, of $275.2 million, or $2.42 per diluted share, compared to net income of $69.4 million, or $0.63 per diluted share, in the same period in 2004. Our operating income of $450.0 million for the year ended December 31, 2005, reflected an increase of $307.1 million from the $142.9 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 (4,392 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 increased 1,510 bpd at the El Dorado Refinery and 1,594 bpd at the Cheyenne Refinery for the year ended December 31, 2005 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 and Note 11 in the “Notes to Consolidated Financial Statements” for a discussion of our utilization of commodity derivative contracts.

Raw material, freight and other costs. Raw material, freight and other costs increased by $814.9 million during the year ended December 31, 2005, from $2.4 billion in 2004 to $3.2 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 $241.4 million in the year ended December 31, 2005 compared to $220.5 million in the comparable period of 2004.

The Cheyenne Refinery operating expenses, excluding depreciation, were $78.9 million in the year ended December 31, 2005, compared to $73.2 million in the comparable period of 2004. The increased expenses included higher electricity costs ($1.2 million), increased environmental expenses ($1.2 million), higher salaries and benefits ($850,000) 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 year ended December 31, 2004 included a $929,000 reduction of operating expenses related to a processing agreement which concluded during 2004.

The El Dorado Refinery operating expenses, excluding depreciation, were $162.5 million in the year ended December 31, 2005, increasing from $147.3 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), 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. Amortization of turnaround costs was lower by $1.1 million for the year ended December 31, 2005 when compared to the year ended December 31, 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 assets not fully depreciated 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 $169.6 million on pretax income of $447.3 million (or 37.9%). The 2005 provision reflects an estimated benefit from the Section 199 production activities deduction for manufacturers ($3.2 million), offset by the impact of permanent book tax differences. The income tax provision for the year ended December 31, 2004 was $42.1 million on pretax income of $111.5 million (or 37.7%) reflecting the net benefit of releasing our deferred tax valuation allowance. Our current income taxes payable for 2005 also benefited from the accelerated depreciation deduction of 75% of qualified capital costs incurred to achieve low sulfur diesel fuel requirements.

Liquidity and Capital Resources

Cash flows from operating activities. Net cash provided by operating activities was $340.5 million for the year ended December 31, 2006, compared to net cash provided by operating activities of $360.3 million during the year ended December 31, 2005. Improved results of operations increased cash flow significantly during 2006, but were more than offset by uses of cash for working capital changes.

Working capital changes used a total of $116.3 million of cash in the year ended December 31, 2006 while providing $6.4 million of cash in the comparable period in 2005. The uses of cash for working capital during the year ended December 31, 2006 included an increase in inventories of $127.0 million, an increase in other current assets of $10.5 million and an increase in trade, note and other receivables of $7.6 million. The increase in inventories was primarily due to an increased average price per barrel and increased crude oil in-transit inventories for the El Dorado Refinery since we began importing crude oil from Canada.

The most significant working capital item providing cash during the year ended December 31, 2006 was an increase in accounts payable of $23.2 million. This was due to increases in crude payables of $37.8 million which resulted from increased crude oil inventory volumes, offset by net decreases in trade and other payables of $14.6 million.

We made estimated federal and state income tax payments of $160.0 million and $23.6 million, respectively, during the year ended December 31, 2006. We received federal income tax refunds of $1.4 million during 2006, which represented refunds from amended returns filed in prior years. As of December 31, 2006, we have accrued estimated federal income taxes payable of $2.6 million and estimated state income taxes payable of $2.0 million. We also have estimated prepaid state income taxes of $1.4 million, which will be applied to the related states 2007 income tax liabilities.

At December 31, 2006, we had $405.5 million of cash and cash equivalents, working capital of $479.5 million and $181.8 million available for borrowings under our revolving credit facility. Our operating cash flows are affected by crude oil and refined product prices and other risks as discussed in Item 7A “Quantitative and Qualitative Disclosures About Market Risks.”

Cash flows used in investing activities. Capital expenditures during the year ended December 31, 2006, were $129.7 million and included approximately $74.2 million for the El Dorado Refinery, $55.3 million for the Cheyenne Refinery, and $153,000 for expenditures in our Denver and Houston offices and our share of crude oil pipeline projects. The $74.2 million of capital expenditures for our El Dorado Refinery included $27.7 million for the ultra low sulfur diesel project and $33.0 million for the crude vacuum expansion project, as well as operational, payout, safety, administrative, environmental and optimization projects. The $55.3 million of capital expenditures for our Cheyenne Refinery included approximately $10.1 million of capital for the ultra low sulfur diesel project and $21.6 million for the coker expansion project, as well as environmental, operational, safety, administrative and payout projects. We funded our 2006 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. Payments of $7.5 million each were required based on both 2004 and 2005 results, and were accrued as of December 31, 2004 and 2005 and paid in January 2005 and 2006, respectively. Such contingent earn-out payments are recorded as additional acquisition costs. Based on the results of operations for the year ended December 31, 2006, a payment of $7.5 million was required, and was accrued as of December 31, 2006, and paid in January 2007. Including the payment we made in early 2007, we have paid a total of $30.0 million for contingent earn-out payments.

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, 2006, we issued 842,800 shares of common stock due to stock option exercises by employees and members of our Board of Directors, for which we received $3.7 million in cash. During the year ended December 31, 2006, we received 141,738 shares ($4.8 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-based compensation.

In November 2006, our Board of Directors approved a new $100 million share repurchase program, which replaced all existing repurchase authorizations and may be utilized for share repurchases in the near-term (no shares had been repurchased under this new program as of December 31, 2006). During the year ended December 31, 2006, under previous share repurchase authorizations, we purchased 3,482,088 shares ($92.3 million) in open market transactions as well as paid $1.9 million for 2005 stock repurchases which did not settle until early 2006 and were accrued as of December 31, 2005.

As of December 31, 2006, we had $150.0 million of long-term debt, due 2011, and no borrowings under our $225.0 million revolving credit facility. We had $43.2 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, 2006. We had shareholders’ equity of $775.9 million as of December 31, 2006.

Our Board of Directors declared a quarterly cash dividend of $0.02 per share of common stock and a special cash dividend of $0.50 per share of common stock in December 2005, which was paid in January 2006. In March 2006, our Board of Directors declared quarterly cash dividends of $0.02 per share of common stock, which was paid in April 2006. Our Board of Directors declared quarterly cash dividends of $0.03 per share of common stock in June, September and December, 2006, which were paid in July 2006, October 2006, and January 2007, respectively. The total cash required for the dividend declared in December 2006 was approximately $3.3 million and was accrued as a dividend payable at year-end. “Accrued dividends” on the Consolidated Balance Sheets include dividends accrued to date on restricted stock, which are not paid until the restricted stock vests.

Future capital expenditures. Four major capital projects were started in 2006 which we expect to complete in 2007 and 2008. These projects include a $156.0 million crude unit and vacuum expansion with an associated metallurgy upgrade at our El Dorado Refinery and, at our Cheyenne Refinery, a $91.0 million coker expansion and revamp, an $11.5 million new amine unit and an $8.0 million crude fractionation project. The above amounts include estimated capitalized interest. At December 31, 2006, outstanding purchase commitments for the crude unit and vacuum tower expansion project at our El Dorado Refinery were $71.9 million. At our Cheyenne Refinery, the coker expansion project’s outstanding commitments at December 31, 2006 were $8.3 million.

Our Board of Directors has approved four additional major capital improvement projects for our El Dorado Refinery which are anticipated to be completed between 2008 and 2009. These projects include an $82 million gasoil hydrotreater revamp, an $80 million catalytic cracker expansion, a $60 million coke drum replacement, and a $36 million catalytic cracker regenerator emission control project. The above amounts include estimated capitalized interest. We may experience cost overruns and/or schedule delays on any of these projects because of strong industry demand for material, labor and engineering resources.

Capital expenditures aggregating approximately $325 million are currently planned for 2007, and include $198 million at our El Dorado Refinery, $118 million at our Cheyenne Refinery, $4.4 million for a buyout of a leased aircraft and $631,000 of capital expenditures for our Denver and Houston offices, and for our share of crude oil pipeline projects. These capital expenditures for 2007 also include $4.3 million for the acquisition ($3.1 million) of, and capital expenditure projects for, Ethanol Management Company, a 25,000 bpd products terminal and blending facility located near Denver, Colorado (see Note 12, “Subsequent Event - Acquisition of Ethanol Management Company” in the “Notes to Consolidated Financial Statements.”) The $198 million of planned capital expenditures for our El Dorado Refinery includes approximately $78 million on the crude unit and vacuum tower expansion, $40 million for coke drum replacement and $31 million for a gasoil hydrotreater revamp, as mentioned above, as well as environmental, operational, safety, administrative and payout projects. The $118 million of planned capital expenditures for our Cheyenne Refinery includes approximately $59 million on the coker expansion, $6 million on the new amine plant and $7 million on the crude fractionation project, as mentioned above, as well as environmental, operational, safety, administrative and payout projects. Our 2007 capital expenditures will be funded with cash generated by our operations and the utilization of a portion of our existing cash balance, if necessary.

The crude unit and vacuum tower expansion at the El Dorado Refinery will allow for higher crude charge rates (including a significantly greater percentage of heavy crude oil) and higher gasoline and distillate yields. This project also includes a significant metallurgical upgrade to the unit which will allow for running high napthenic acid crude oils, a characteristic typical of crude types found in Western Canada, West Africa and the North Sea. This project will likely be brought online 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 products. The new amine unit at the Cheyenne Refinery is intended to result in improved alkylation unit reliability and provide a partial backup unit if the main amine unit is not operating. The project is expected to be completed and start-up occurring in the latter half of 2007. The crude fractionation project at the Cheyenne Refinery will allow us to improve the recovery of diesel from the crude charged to the Refinery and is expected to be completed in 2007.

The gasoil hydrotreater revamp at the El Dorado Refinery is the key project to achieve gasoline sulfur compliance for our El Dorado Refinery (see “Environmental” in Note 9 in the “Notes to Consolidated Financial Statements.”) The project will also result in significant yield improvement for the catalytic cracking unit and is anticipated to be completed in the spring of 2009. The El Dorado Refinery catalytic cracker expansion project includes a revamp component and new technology which will increase charge rate and improve product yields and is also anticipated to be completed in the spring of 2009. The coke drum replacement project for our El Dorado Refinery includes safety and reliability components as well as overall throughput support for the Refinery and is expected to be completed by mid-2008. The El Dorado Refinery catalytic cracker regenerator emission control project, with a spring 2009 estimated completion date, will add a scrubber to improve the environmental performance of the unit, specifically as it relates to flue-gas emissions. This project is necessary to support the catalytic cracking expansion project and to meet a portion of the expected requirements of the EPA Petroleum Refining Initiative (see “Environmental” in Note 9 in the “Notes to Consolidated Financial Statements.”)

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 2007 through 2017, as well as an operating sublease for the use of the cogeneration facility at our El Dorado Refinery. The non-cancelable sublease, entered into in connection with the acquisition of our El Dorado Refinery in 1999, expires in 2016 with an option that allows us to renew the sublease for an additional eight years. This lease has both a fixed and a variable component.

Purchase obligations include agreements to purchase goods or services that are enforceable and legally binding and that specify terms, including fixed or minimum quantities to be purchased, fixed, minimum or variable price provisions, and the approximate timing of the transaction. Purchase obligations exclude agreements that are cancelable without penalty.

The amounts shown in the table on the following page for transportation, terminalling and storage contractual obligations include our anticipated commitments based on our agreements for shipping crude oil on the Express Pipeline, the Spearhead Pipeline and a new pipeline from Guernsey, Wyoming to our Cheyenne Refinery which is expected to first transport crude oil in mid-2007.

For more information on the agreements discussed above, see “Lease and Other Commitments” in Note 9 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	$	150,000	$	-	$	-	$	150,000	$	-
Interest on long-term debt		47,204		9,938		19,875		17,391		-
Operating leases		99,226		14,378		27,346		23,794		33,708
Purchase obligations:
Baytex crude supply (1)		290,829		290,829		-		-		-
Other crude supply, feedstocks and natural gas (1)		177,006		175,744		1,262		-		-
Transportation, terminalling and storage		318,780		41,900		86,854		68,573		121,453
Refinery capital projects (2)		85,570		85,570		-		-		-
Other goods and services		8,842		7,732		1,110		-		-
Total purchase obligations		881,027		601,775		89,226		68,573		121,453
Other long-term liabilities		13,746		-		8,521		1,014		4,211
Pension and post-retirement healthcare and other benefit plans funding requirements (3)		-		-		-		-		-
Total contractual cash	$	1,191,203	$	626,091	$	144,968	$	260,772	$	159,372

(1)

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, $208.8 million relate to January and February 2007 feedstock and natural gas requirements of the Refineries.

(2)

The $85.6 million of Refinery capital projects primarily consists of $71.9 million for the crude unit and vacuum tower expansion project at our El Dorado Refinery and $8.3 million for the coker expansion project at our Cheyenne Refinery. These amounts for refinery capital projects reflected here relate to current commitments not accrued as of December 31, 2006, not the total estimated costs of the projects.

(3)

No pension funding will be required in 2007 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 8 “Employee Benefit Plans” in the “Notes to Consolidated Financial Statements.”

Off-Balance Sheet Arrangements

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

Environmental

We will be making significant future capital expenditures to comply with various environmental regulations. See “Environmental” in Note 9 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. Normal maintenance and repairs are expensed as incurred. Planned major maintenance (“turnarounds”) is the scheduled and required shutdowns of refinery processing units for significant overhaul and refurbishment. Turnaround costs include contract services, materials and rental equipment. During the fourth quarter of 2006, we adopted a change in accounting method for the costs of turnarounds from the accrual method to the deferral method. Under the deferral method, the costs of turnarounds are deferred when incurred and amortized on a straight-line basis over the period of time estimated to lapse until the next turnaround occurs. These deferred charges are included in our Consolidated Balance Sheets in “Deferred charges and other assets” along with the cost of catalyst that is replaced at periodic intervals when the quality of the catalyst has deteriorated beyond its prescribed function. The catalyst costs are deferred when incurred and amortized on a straight-line basis over the estimated useful life of the specific catalyst. The amortization expenses are included in “Refinery operating expenses, excluding depreciation” in our Consolidated Statements of Income. See Note 3 “Change in Accounting Principle - Turnarounds” in the Notes to Consolidated Financial Statements for further information.

Inventories. Inventories of crude oil, unfinished products and all finished products are recorded at the lower of cost on a FIFO basis or market. Crude oil includes both domestic and foreign crude oil volumes at its cost and associated freight and other cost. Unfinished products (work in process) include any crude oil that has entered into the refining process, and other feedstocks that are not finished as far as refining operations are concerned. These include unfinished gasoline and diesel, blendstocks and other feedstocks. Finished product inventory includes saleable gasoline, diesel, jet fuel, chemicals, asphalt and other finished products. Unfinished and finished products inventory values have components of raw material, the associated raw material freight and other costs, and direct refinery operating expense allocated when refining begins relative to their proportionate market values. The FIFO method of accounting for inventories sometimes results in our recognizing substantial gains (in periods of rising prices) or losses (in periods of falling prices) from our inventories of crude oil and products. While we believe that this accounting method accurately reflects the results of our operations, many other refining companies instead utilize the last-in, first-out (“LIFO”) method of accounting for inventories. Thus, 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 the liability is incurred, with the associated asset retirement costs being capitalized as a part of the carrying amount of the long-lived asset. FAS No. 143 also includes disclosure requirements that provide a description of asset retirement obligations and reconciliation of changes in the components of those obligations.

In March 2005, the FASB issued FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations” (“FIN 47”). FIN 47 clarified that the term “conditional asset retirement obligation” as used in FAS No. 143 refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the reporting entity. Since the obligation to perform the asset retirement activity is unconditional, FIN 47 provides that a liability for the fair value of a conditional asset obligation should be recognized if that fair value can be reasonably estimated, even though uncertainty exists about the timing and/or method of settlement. FIN 47 also clarifies when an entity would have sufficient information to reasonably estimate the fair value of a conditional asset retirement obligation under FAS No. 143. We adopted FIN 47 as of December 31, 2005; in doing so, 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. At December 31, 2006, our asset retirement obligation was $6.0 million.

Asset retirement obligations are affected by regulatory changes and refinery operations as well as changes in pricing of services. In order to determine fair value, management must make certain estimates and assumptions, including, among other things, projected cash flows, a credit-adjusted risk-free interest rate, and an assessment of market conditions that could significantly impact the estimated fair value of the asset retirement obligation. These estimates and assumptions are subjective and are currently based on historical costs with adjustments for estimated future changes in the associated costs. Therefore, we expect the dollar amount of these obligations to change as more information is obtained. A 1% change in pricing of services would cause an approximate $50,000 change to the asset retirement obligation. We believe that we have adequately accrued for our asset retirement obligations at this time and that changes in estimates in future periods will not have a significant effect on our results of operations or financial condition. See “Significant Accounting Policies” in Note 2 in the “Notes to Consolidated Financial Statements” for further information on asset retirement obligations.

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

Pension and Other Post-retirement Benefit Obligations. We have significant pension and post-retirement benefit liabilities and costs that are developed from actuarial valuations. Inherent in these valuations are key assumptions, including discount rates, expected returns on plan assets and health care inflation rates. Changes in these assumptions are primarily influenced by factors outside of our control. These assumptions can have a significant effect on the amounts reported in our consolidated financial statements. See Note 8 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.”

Market Risks

See the Item 7A “Quantitative and Qualitative Disclosure about Market Risk” and Notes 2 and 11 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 related inventory in “Inventory of crude oil, products and other” on the Consolidated Balance Sheets and ultimately, when the inventory is charged or sold, in “Raw material, freight and other costs” on the Consolidated Statements of Income. 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 11 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 2006, 2005 and 2004. The statistical information includes the following terms:

·	WTI Cushing crude oil price - the benchmark West Texas Intermediate crude oil priced at Cushing, Oklahoma (ConocoPhillips WTI crude oil posting plus).

·	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 Cushing crude oil price.

·	Cheyenne light/heavy crude oil differential - the average differential between the WTI Cushing crude oil price and the heavy crude oil delivered to the Cheyenne Refinery.

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

El Dorado Refinery light/heavy crude oil differential - the average differential between the WTI Cushing crude oil price and the Canadian heavy crude oil delivered to the El Dorado Refinery. This differential is only applicable beginning in 2006 when we began utilizing Canadian crude oil at the El Dorado Refinery.

Consolidated:

Years Ended December 31,	2006		2005		2004
Charges (bpd)
Light crude		39,730		39,210		37,486
Heavy and intermediate crude		114,743		113,439		110,662
Other feed and blend stocks		17,346		15,955		16,609
Total		171,819		168,604		164,757

Manufactured product yields (bpd)
Gasoline		81,484		83,574		82,944
Diesel and jet fuel		57,678		55,151		53,093
Asphalt		6,032		7,434		7,475
Other		21,580		17,506		17,050
Total		166,774		163,665		160,562

Total product sales (bpd)
Gasoline		89,895		90,372		90,698
Diesel and jet fuel		57,326		54,350		52,818
Asphalt		6,138		7,526		7,427
Other		18,679		18,133		15,046
Total		172,038		170,381		165,989

Refinery operating margin information (per sales barrel)
Refined products revenue	$	75.80	$	64.32	$	47.27
Raw material, freight and other costs (FIFO inventory accounting)		61.33		52.22		40.04
Refinery operating expenses, excluding depreciation		4.41		3.88		3.63
Depreciation and amortization		0.65		0.56		0.53

Average WTI crude oil price at Cushing, OK (per barrel)	$	64.94	$	55.77	$	41.85
Average gasoline crack spread (per barrel)		14.10		11.67		8.61
Average diesel crack spread (per barrel)		21.35		17.13		7.35

Average sales price (per sales barrel)
Gasoline	$	80.79	$	69.09	$	51.70
Diesel and jet fuel		86.62		73.61		49.81
Asphalt		37.68		26.72		24.11
Other		31.11		28.28		23.10

Years Ended December 31,	2006		2005		2004
Cheyenne Refinery:
Charges (bpd)
Light crude		12,436		8,575		6,645
Heavy crude		33,563		38,347		38,408
Other feed and blend stocks		1,694		4,399		4,392
Total		47,693		51,321		49,445

Manufactured product yields (bpd)
Gasoline		19,089		21,035		20,039
Diesel		14,261		14,580		14,387
Asphalt		6,032		7,434		7,475
Other		6,283		6,285		5,839
Total		45,665		49,334		47,740

Total product sales (bpd)
Gasoline		26,569		27,186		26,744
Diesel		14,147		14,428		14,581
Asphalt		6,138		7,526		7,427
Other		4,662		6,124		5,044
Total		51,516		55,264		53,796

Refinery operating margin information (per sales barrel)
Refined products revenue	$	74.08	$	61.16	$	45.50
Raw material, freight and other costs (FIFO inventory accounting)		57.07		48.49		38.08
Refinery operating expenses, excluding depreciation		5.42		3.91		3.72
Depreciation and amortization		1.00		0.90		0.90

Average light/heavy crude oil differential (per barrel)	$	16.21	$	15.32	$	9.90
Average gasoline crack spread (per barrel)		15.58		13.17		9.33
Average diesel crack spread (per barrel)		24.35		19.40		9.34

Average sales price (per sales barrel)
Gasoline	$	83.35	$	71.14	$	53.28
Diesel		89.99		75.57		52.35
Asphalt		37.68		26.72		24.11
Other		20.91		25.29		15.98

El Dorado Refinery:
Charges (bpd)
Light crude		27,295		30,635		30,841
Heavy and intermediate crude		81,180		75,092		72,254
Other feed and blend stocks		15,652		11,556		12,218
Total		124,127		117,283		115,313

Manufactured product yields (bpd)
Gasoline		62,395		62,539		62,905
Diesel and jet fuel		43,417		40,572		38,706
Other		15,297		11,222		11,212
Total		121,109		114,333		112,823

Total product sales (bpd)
Gasoline		63,327		63,186		63,954
Diesel and jet fuel		43,179		39,922		38,237
Other		14,018		12,009		10,002
Total		120,524		115,117		112,193

Refinery operating margin information (per sales barrel)
Refined products revenue	$	76.53	$	65.83	$	48.12
Raw material, freight and other costs (FIFO inventory accounting)		63.15		54.01		40.98
Refinery operating expenses, excluding depreciation		3.98		3.87		3.59
Depreciation and amortization		0.50		0.40		0.35

Average WTI/WTS crude oil differential (per barrel)	$	5.22	$	4.51	$	3.74
Average light/heavy crude oil differential (per barrel)		18.13		-		-
Average gasoline crack spread (per barrel)		13.48		11.02		8.31
Average diesel crack spread (per barrel)		20.37		16.31		6.59

Average sales price (per sales barrel)
Gasoline	$	79.72	$	68.21	$	51.03
Diesel and jet fuel		85.51		72.90		48.84
Other		34.51		29.81		26.69

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, 2006 and 2005, 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, 2006. Our audits also included the financial statement schedules listed in the Index at Item 15. These consolidated financial statements and financial statement schedules are the responsibility of the Company’s management. Our responsibility is to express an opinion on the financial statements and financial statement schedules based on our audits.

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

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Frontier Oil Corporation and subsidiaries as of December 31, 2006 and 2005, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2006, 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 to the consolidated financial statements, on December 31, 2005, the Company adopted the provisions of Financial Accounting Standards Board (“FASB”) Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations.”

As discussed in Note 3 to the consolidated financial statements, during the fourth quarter of 2006, the Company changed its method of accounting for the costs of turnarounds from the accrual method to the deferral method to conform to FASB Staff Position No. AUG AIR-1, “Accounting for Planned Major Maintenance Activities” and, retrospectively, adjusted the 2005 and 2004 financial statements for the change.

As discussed in Note 7 to the consolidated financial statements, on January 1, 2006, the Company adopted the provisions of Statement of Financial Accounting Standards (“SFAS”) No. 123(R), “Share-Based Payment.”

As discussed in Note 8 to the consolidated financial statements, on December 31, 2006 the Company adopted the provisions of SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans.”

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, 2006, based on the criteria established in “Internal Control—Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 26, 2007 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

February 26, 2007

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, 2006. 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, 2006, the Company’s internal control over financial reporting is effective based on those criteria.

Frontier Oil Corporation’s independent registered public accounting firm has issued an audit report on our assessment of the Company’s internal control over financial reporting. This report appears on the following page.

February 23, 2007

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 and subsidiaries (the “Company”) maintained effective internal control over financial reporting as of December 31, 2006, 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, 2006, 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, 2006, 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, 2006 of the Company and our report dated February 26, 2007 expressed an unqualified opinion on those financial statements and financial statement schedules and included explanatory paragraphs regarding the Company’s adoption of Financial Accounting Standards Board Staff Position No. AUG AIR-1, “Accounting for Planned Major Maintenance Activities”, Statement of Financial Accounting Standards (“SFAS”) No. 123(R), “Share-Based Payment”, and SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans.”

DELOITTE & TOUCHE LLP

Houston, Texas

February 26, 2007

FRONTIER OIL CORPORATION AND SUBSIDIARIES
Consolidated Statements of Income

	Years Ended December 31,
	2006			2005 As Adjusted (Note 3)			2004 As Adjusted (Note 3)
	(in thousands, except per share data)
Revenues:
Refined products	$	4,759,661		$	3,999,935		$	2,871,592
Other		36,292			1,227			(9,876	)
		4,795,953			4,001,162			2,861,716

Costs and expenses:
Raw material, freight and other costs		3,850,937			3,247,372			2,432,461
Refinery operating expenses, excluding depreciation		277,129			241,445			220,427
Selling and general expenses, excluding depreciation		52,488			30,715			29,893
Merger termination and legal costs		-			48			3,824
Depreciation and amortization		41,213			35,213			32,208
Gains on sales of assets		(8	)		(3,644	)		-
		4,221,759			3,551,149			2,718,813

Operating income		574,194			450,013			142,903

Interest expense and other financing costs		12,139			10,341			37,573
Interest and investment income		(18,059	)		(7,583	)		(1,716	)
Gain on involuntary conversion of assets		-			-			(4,411	)
		(5,920	)		2,758			31,446

Income before income taxes		580,114			447,255			111,457
Provision for income taxes		200,837			169,594			42,065
Income before cumulative effect of accounting change		379,277			277,661			69,392
Cumulative effect of accounting change, net of income taxes of $1,530		-			(2,503	)		-
Net income	$	379,277		$	275,158		$	69,392


Basic earnings per share of common stock:
Before cumulative effect of accounting change	$	3.40		$	2.51		$	0.65
Cumulative effect of accounting change		-			(0.02	)		-
Net income	$	3.40		$	2.49		$	0.65

Diluted earnings per share of common stock:
Before cumulative effect of accounting change	$	3.37		$	2.44		$	0.63
Cumulative effect of accounting change		-			(0.02	)		-
Net income	$	3.37		$	2.42		$	0.63

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

FRONTIER OIL CORPORATION AND SUBSIDIARIES
Consolidated Balance Sheets
	December 31,
	2006			2005 As Adjusted (Note 3)
	(in thousands, except share data)
ASSETS
Current assets:
Cash and cash equivalents	$	405,479		$	356,065
Trade receivables, net of allowance of $500 in both years		135,111			122,051
Other receivables		2,351			7,584
Inventory of crude oil, products and other		374,576			247,621
Deferred tax assets		3,237			2,004
Other current assets		18,462			7,935
Total current assets		939,216			743,260
Property, plant and equipment, at cost:
Refineries, terminal equipment and pipelines		802,498			657,612
Furniture, fixtures and other equipment		11,084			10,510
		813,582			668,122
Less - accumulated depreciation and amortization		276,777			238,184
		536,805			429,938
Deferred financing costs, net of amortization
of $1,742 and $945 in 2006 and 2005, respectively		2,752			3,549
Commutation account		7,290			12,606
Prepaid insurance, net of amortization		2,120			3,331
Other intangible asset, net of amortization
of $264 and $158 in 2006 and 2005, respectively $158 and $53 in 2005 and 2004, respectively		1,316			1,422
Deferred charges and other assets		34,426			28,951
Total assets	$	1,523,925		$	1,223,057

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	390,019		$	359,577
Contingent income tax liabilities		28,271			21,517
Accrued dividends		3,486			58,726
Accrued interest		2,541			2,485
Accrued El Dorado Refinery contingent earn-out payment		7,500			7,500
Accrued liabilities and other		27,881			23,310
Total current liabilities		459,698			473,115

Long-term debt		150,000			150,000
Post-retirement employee liabilities		28,090			24,497
Other long-term liabilities		13,746			8,079
Deferred compensation liability		2,630			2,214
Deferred income taxes		93,907			86,460

Commitments and contingencies

Shareholders’ equity:
Preferred stock, $100 par value, 500,000 shares authorized,
no shares issued		-			-
Common stock, no par, 180,000,000 shares authorized, 134,509,256 and
133,629,396 shares issued in 2006 and 2005, respectively		57,802			57,780
Paid-in capital		181,386			157,910
Retained earnings		719,802			352,783
Accumulated other comprehensive income		256			27
Treasury stock, at cost, 24,164,808 and 20,930,828
shares at December 31, 2006 and 2005, respectively		(183,392	)		(86,870	)
Deferred compensation		-			(2,938	)
Total shareholders’ equity		775,854			478,692
Total liabilities and shareholders’ equity	$	1,523,925		$	1,223,057

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

FRONTIER OIL CORPORATION AND SUBSIDIARIES
Consolidated Statements of Cash Flows

	Years Ended December 31,
	2006			2005 As Adjusted (Note 3)			2004 As Adjusted (Note 3)
	(in thousands)
Cash flows from operating activities:
Net income	$	379,277		$	275,158		$	69,392
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		54,388			47,546			45,252
Deferred income taxes		6,073			30,259			24,731
Stock-based compensation expense		18,029			1,363			1,180
Excess income tax benefits of stock-based compensation		(8,881	)		-			-
Deferred financing cost and bond discount amortization		797			785			5,484
Gains on sales of assets		(8	)		(3,644	)		-
Gain on involuntary conversion of assets		-			-			(4,411	)
Long-term commutation account		5,316			3,832			3,712
Amortization of long-term prepaid insurance		1,211			1,211			1,451
Increase in long-term accrued liabilities		9,309			4,473			431
Changes in deferred charges and other		(18,844	)		(17,316	)		(8,055	)
Changes in components of working capital from operations:
Decrease (increase) in trade, note and other receivables		(7,633	)		(43,707	)		2,231
Increase in inventory		(126,955	)		(90,687	)		(32,935	)
Increase in other current assets		(10,527	)		(5,591	)		(370	)
Increase in accounts payable		23,187			117,275			58,138
Increase in accrued liabilities and other		15,778			36,877			11,668
Net cash provided by operating activities		340,517			360,337			177,899

Cash flows from investing activities:
Additions to property, plant and equipment		(129,703	)		(109,710	)		(46,502	)
Net proceeds from insurance - involuntary conversion claim		-			2,142			3,395
Proceeds from sale of assets		8			5,500			-
El Dorado Refinery contingent earn-out payment		(7,500	)		(7,500	)		-
Net cash used in investing activities		(137,195	)		(109,568	)		(43,107	)

Cash flows from financing activities:
Purchase of treasury stock		(98,950	)		(34,819	)		(3,029	)
Proceeds from issuance of common stock		3,672			23,616			3,923
Dividends paid		(67,498	)		(7,776	)		(5,664	)
Debt issue costs and other		(13	)		(114	)		(3,954	)
Excess income tax benefits of stock-based compensation		8,881			-			-
(Repayments) proceeds of revolving credit facility, net		-			-			(45,750	)
Proceeds from issuance of 6.625% Senior Notes		-			-			150,000
Repurchase of 11.75% Senior Notes		-			-			(170,449	)
Net cash used in financing activities		(153,908	)		(19,093	)		(74,923	)
Increase in cash and cash equivalents		49,414			231,676			59,869
Cash and cash equivalents, beginning of period		356,065			124,389			64,520
Cash and cash equivalents, end of period	$	405,479		$	356,065		$	124,389

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 As Adjusted (Note 3)			Retained Earnings As Adjusted (Note 3)			Number of Shares			Amount			Deferred Compensation			Accumulated Other Comprehensive Income (Loss)			Number of Shares			Amount As Adjusted (Note 3)
December 31, 2003, as reported		30,643,549	$	57,504	$	106,443					$	47,614			(4,264,673	)	$	(39,914	)	$	(1,446	)	$	(924	)		26,378,876		$	169,277
Adjustment for the 2005 and 2006 stock splits		91,930,647		-		-						-			(12,794,019	)		-			-			-			79,136,628			-
Change in accounting principle (Note 3)		-		-		-						31,379			-			-			-			-			-			31,379
December 31, 2003, as adjusted		122,574,196	$	57,504	$	106,443					$	78,993			(17,058,692	)	$	(39,914	)	$	(1,446	)	$	(924	)		105,515,504		$	200,656
Shares issued under stock-based compensation plans		4,103,900		103		7,914						-			12,000			13			-			-			4,115,900			8,030
Shares received under stock-based compensation plans															(1,507,176	)		(7,123	)								(1,507,176	)		(7,123	)
Comprehensive income:
Net income		-		-		-		$	69,392			69,392			-			-			-			-			-			69,392
Other comprehensive income:
Minimum pension liability, net of tax benefit of $166									(273	)
Other comprehensive income									(273	)														(273	)		-			(273	)
Comprehensive income								$	69,119
Income tax benefits of stock-based compensation		-		-		5,168						-			-			-			-			-			-			5,168
Stock-based compensation expense		-		-		-						-			-			-			1,180			-			-			1,180
Dividends declared		-		-		-						(5,910	)		-			-			-			-			-			(5,910	)
December 31, 2004		126,678,096	$	57,607	$	119,525					$	142,475			(18,553,868	)	$	(47,024	)	$	(266	)	$	(1,197	)		108,124,228		$	271,120
Shares issued under stock-based compensation plans		6,951,300		173		29,369									339,956			450			(2,810	)					7,290,896			27,182
Issue of restricted stock units to directors		-		-		1,224						-			-			-			(1,224	)		-			-			-
Shares received under:
Stock repurchase plans		-		-		-									(1,441,600	)		(24,596	)		-			-			(1,441,600	)		(24,596	)
Stock-based compensation plans		-		-		-									(1,274,956	)		(15,700	)		-			-			(1,274,956	)		(15,700	)
Net income		-		-		-		$	275,158			275,158			-			-			-			-			-			275,158
Other comprehensive income:
Minimum pension liability, net of tax liability of $755									1,224
Other comprehensive income									1,224															1,224			-			1,224
Comprehensive income								$	276,382
Income tax benefits of stock-based compensation, net of contingency		-		-		7,792						-			-			-			-			-			-			7,792
Stock-based compensation expense		-		-		-						-			-			-			1,362			-			-			1,362
Dividends declared		-		-		-						(64,850	)		-			-			-			-			-			(64,850	)
December 31, 2005		133,629,396	$	57,780	$	157,910					$	352,783			(20,930,828	)	$	(86,870	)	$	(2,938	)	$	27			112,698,568		$	478,692
Adoption of FAS No. 123(R)		-		-		(2,938	)					-			-			-			2,938			-			-			-
Shares issued under stock-based compensation plans and other		879,860		22		3,134						-			389,846			516			-			-			1,269,706			3,672
Shares received under:
Stock repurchase plans		-		-		-						-			(3,482,088	)		(92,273	)		-			-			(3,482,088	)		(92,273	)
Stock-based compensation plans		-		-		-						-			(141,738	)		(4,765	)		-			-			(141,738	)		(4,765	)
Net income and comprehensive income								$	379,277			379,277																		379,277
Adjustment to initially apply FAS No. 158, net of tax liability of $141		-		-		-						-			-			-			-			229			-			229
Income tax benefits of stock-based compensation, net of contingency		-		-		5,251						-			-			-			-			-			-			5,251
Stock-based compensation expense		-		-		18,029						-			-			-			-			-			-			18,029
Dividends declared		-		-		-						(12,258	)		-			-			-			-			-			(12,258	)
December 31, 2006		134,509,256	$	57,802	$	181,386					$	719,802			(24,164,808	)	$	(183,392	)		-		$	256			110,344,448		$	775,854

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

FRONTIER OIL CORPORATION AND SUBSID IARIES

Notes To Consolidated Financial Statements

For The Years Ended December 31, 2006, 2005 and 2004

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 $99,000 and $95,000 at December 31, 2006 and 2005, 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 were 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 (including payment terms and prices). Title primarily transfers at the refinery or terminal when the refined product is loaded into the common carrier pipelines, trucks or railcars (free on board origin). In some situations, title transfers at the customer’s destination (free on board destination). Nonmonetary product exchanges and certain buy/sell crude oil transactions which are entered into in the normal course of business are included on a net cost basis in “Raw material, freight and other costs” on the Consolidated Statements of Income. Taxes collected from customers and remitted to governmental authorities are not included in reported revenues.

Property, Plant and Equipment

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

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, 2006, 2005 and 2004 was $3.8 million, $2.6 million and $65,000, respectively.

Turnarounds

Normal maintenance and repairs are expensed as incurred. Planned major maintenance is the scheduled and required shutdowns of refinery processing units for significant overhaul and refurbishment (“turnarounds”). Turnaround costs include contract services, materials and rental equipment. During the fourth quarter of 2006, the Company adopted a change in accounting method for the costs of turnarounds from the accrual method to the deferral method. The costs of turnarounds are deferred when incurred and amortized on a straight-line basis over the period of time estimated to lapse until the next turnaround occurs. These deferred charges are included in the Company’s Consolidated Balance Sheets in “Deferred charges and other assets” along with the cost of catalyst that is replaced at periodic intervals when the quality of the catalyst has deteriorated beyond its prescribed function. The catalyst costs are deferred when incurred and amortized on a straight-line basis over the estimated useful life of the specific catalyst. The amortization expenses resulting from the turnaround costs are included in “Refinery operating expenses, excluding depreciation” in the Company’s Consolidated Statements of Income. See Note 3 “Change in Accounting Principle - Turnarounds” for further information.

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. 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 5 “Revolving Credit Facility.”) The components of inventory as of December 31, 2006 and 2005 were as follows:

	December 31,
	2006		2005
	(in thousands)
Crude oil	$	182,215	$	97,766
Unfinished products		84,682		53,200
Finished products		89,457		75,790
Process chemicals		1,009		5,441
Repairs and maintenance supplies and other		17,213		15,424
	$	374,576	$	247,621

Prepaid Insurance

The Company charges the amounts paid for insurance policies to expense over the term of the policy. Prepaid insurance related to policies with terms of one year or less are included in “Other current assets” on the Consolidated Balance Sheets. The loss mitigation insurance premium and related expenses (see “Litigation-Beverly Hills Lawsuits” under Note 9) 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, 2006 and 2005. 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 $4.3 million and $3.1 million at December 31, 2006 and 2005, 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 the financial statement carrying amounts of assets and liabilities and their respective tax bases. The Company recognizes liabilities for potential tax issues based on its estimate of whether, and the extent to which, additional taxes may be due. See Note 6 “Income Taxes” for further information.

Environmental Expenditures

Environmental expenditures are expensed or capitalized based upon their future economic benefit. Costs that improve a property’s pre-existing condition, and costs that prevent future environmental contamination, are capitalized. Remediation costs related to environmental damage resulting from operating activities subsequent to acquisition are expensed. Liabilities for these expenditures are recorded when it is probable that obligations have been incurred and the amounts can be reasonably estimated.

Price Risk Management Activities

The Company, at times, enters into commodity derivative contracts to manage its price exposure to its inventory positions, purchases of foreign crude oil and 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 initially in the related inventory in “Inventory of crude oil, products and other” on the Consolidated Balance Sheets, and ultimately, when the related inventory is charged or sold in “Raw material, freight and other costs” on the Consolidated Statements of Income. Gains and losses on transactions accounted for using mark-to-market accounting are reflected in “Other revenues” at each period end.

Stock-based Compensation

Effective January 1, 2006, the Company accounts for stock-based compensation in accordance with FAS No. 123(R), “Share-Based Payment,” which requires companies to recognize the fair value of stock options and other stock-based compensation in the financial statements. Prior to 2006, stock-based compensation was measured in accordance with Accounting Principles Board (“APB”) No. 25. Under this intrinsic value method, compensation cost was 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 and 2004. See Note 7 for detailed information on the Company’s stock-based compensation. Had compensation costs for share awards been determined based on the fair value at grant dates and amortized over the vesting period pursuant to FAS No. 123, the Company’s income and EPS would have been the pro forma amounts listed in the following table for the years ended December 31, 2005 and 2004. The pro forma compensation expense for the years ended December 31, 2005 and 2004 includes amortization for options granted in 2004, 2003 and prior years.

	Years Ended December 31,
	2005 As Adjusted (Note 3)			2004 As Adjusted (Note 3)
	( in thousands, except per share amounts )
Net income	$	275,158		$	69,392
Pro forma compensation expense, net of tax		(1,255	)		(2,029	)
Pro forma net income	$	273,903		$	67,363
Basic EPS:
As reported	$	2.49		$	0.65
Pro forma		2.47			0.63
Diluted EPS:
As reported	$	2.42		$	0.63
Pro forma		2.41			0.61

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 Consolidated Balance Sheets as of December 31, 2006 and 2005, recognized a net asset retirement obligation of $6.0 million and $5.5 million, respectively. At December 31, 2006, $520,000 of the $6.0 million was classified as current in “Accrued liabilities and other” and $5.4 million was included in “Other long-term liabilities.” Changes in the Company’s asset retirement obligations were as follows:

	Year ended December 31, 2006
	(in thousands)
Asset retirement obligation, beginning of period	$	5,468
Liabilities settled		(255	)
Accretion expense		366
Revisions to estimated cash flows		385
Asset retirement obligation, end of period	$	5,964

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.

Principles of Consolidation

The Consolidated Financial Statements include the accounts of FOC and all 100% owned subsidiaries, as well as the Company’s undivided interests in a crude oil pipeline and crude oil tanks. The Company utilizes the equity method of accounting for investments in entities in which it does not have the ability to exercise control. Entities in which the Company has the ability to exercise significant influence and control are consolidated. All intercompany transactions and balances are eliminated in consolidation.

Use of Estimates

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

Cash Equivalents

Highly liquid investments with maturity, when purchased, of three months or less are considered to be cash equivalents. Cash equivalents were $377.5 million and $345.6 million at December 31, 2006 and 2005, 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 Sheet at December 31, 2005. This loan was paid in full in May 2006.

Supplemental Cash Flow Information

Cash payments for interest, net of capitalized interest, during 2006, 2005 and 2004 were $8.4 million, $7.8 million and $20.0 million, respectively. Cash payments for income taxes during 2006, 2005 and 2004 were $183.6 million, $106.0 million and $21.6 million, respectively. Cash refunds of income taxes during 2006, 2005 and 2004 were $1.4 million, $3.6 million and $3.2 million, respectively.

Reclassifications

Certain prior year amounts have been reclassified to conform to the current period financial statement presentation. These reclassifications have no effect on previously reported net income.

New Accounting Pronouncements

In June 2006, the FASB issued FASB Interpretation No. 48, “Accounting for Uncertain Tax Positions - An Interpretation of FAS No. 109, Accounting for Income Taxes” (“FIN 48”). The interpretation clarifies the accounting for income taxes recognized and presents guidance on measurement for the financial statements and tax position taken or expected to be taken. FIN 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. The tax position is evaluated with a two step process. The first step is recognition: to determine whether it is “more likely than not” that a tax position will be upheld upon examination. The second step is measurement: if the position meets the “more likely than not” criteria in step one, step two is to determine the impact on the financial statements. This interpretation will apply to fiscal years beginning after December 15, 2006 . The cumulative effect of applying the provisions of FIN 48, if any, will be reported as an adjustment to the opening balance of retained earnings in the first quarter of 2007. The Company is currently evaluating its tax positions, but does not believe that the adoption of FIN 48 will have a material effect on the Company’s financial statements.

In September 2006, the FASB issued FASB Staff Position (“FSP”) No. AUG AIR-1, “Accounting for Planned Major Maintenance Activities.” This FSP addresses the accounting for planned major maintenance activities (“turnarounds”). Currently there are four alternative accounting methods for turnarounds: direct expense, built-in overhaul, deferral and accrual. The FSP eliminates the accrual method of accounting for turnarounds and requires the adoption of the provisions as a change in accounting principle through retrospective application as described in FAS No. 154, “Accounting Changes and Error Corrections.” The FSP has an effective date for fiscal years beginning after December 15, 2006 with earlier adoption allowed. The Company previously accounted for turnarounds on the accrual method. The Company has early adopted the deferral method and retrospectively applied the new accounting principle to 2005 and 2004 financial statements. See Note 3 “Change in Accounting Principle - Turnarounds” for further information.

In September 2006, the FASB issued FAS No. 157, “Fair Value Measurements” which establishes a framework for measuring fair value in GAAP and expands disclosures about fair value measurements. FAS No. 157 states that fair value is “the price that would be received to sell the asset or paid to transfer the liability (an exit price), not the price that would be paid to acquire the asset or received to assume the liability (an entry price).” The statement is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. The Company is currently evaluating the effect that this statement will have on the Company’s financial statements and any other factors influencing the overall business environment.

In Septemb er 2006, the FASB issued FAS No. 158 , “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans.” This statement requires an employer to: 1) recognize the funded status of a benefit plan (measured as the difference between plan assets at fair value and the benefit obligation) in its statement of financial position, 2) recognize as a component of other comprehensive income, net of tax, the gains or losses and prior service costs or credits that arise during the period but are not recognized as components of net period benefit cost, 3) measure defined benefit plan assets and obligations as of the date of the employer’s fiscal year-end statement of financial position, and 4) disclose in the notes to the financial statements additional information about certain effects on net periodic benefit cost for the next fiscal year that arise from delayed recognition of the gains or losses, prior service costs or credits, and transition assets or obligations. Frontier has recognized the funded status of its defined benefit plans and provided the required disclosures as of the year ending December 31, 2006. See Note 8 “Employee Benefit Plans” for further information.

The Securities and Exchange Commission (“SEC”) issued Staff Accounting Bulletin (“SAB”) No. 108 in September 2006. SAB No. 108 was issued to address diversity in practice in quantifying financial statement misstatements and the potential under current practice for the build up of improper amounts on the balance sheet. Registrants are to reflect the effects of applying the guidance issued in SAB No. 108 in annual financial statements covering the first fiscal year ending after November 15, 2006. The Company adopted SAB No. 108 at December 31, 2006 with no adjustments necessary.

3.	Change in Accounting Principle - Turnarounds

During the fourth quarter of 2006, the Company changed its accounting method for the costs of turnarounds from the accrual method to the deferral method. Turnarounds are the scheduled and required shutdowns of refinery processing units for significant overhaul and refurbishment. Under the deferral accounting method, the costs of turnarounds are deferred when incurred and amortized on a straight-line basis over the period of time estimated to lapse until the next turnaround occurs. The new method of accounting for turnarounds was adopted in order to adhere to FSP No. AUG AIR-1 “Accounting for Planned Major Maintenance Activities” which prohibits the accrual method of accounting for planned major maintenance activities. The Company elected to early adopt the FSP in the fourth quarter of 2006. The comparative financial statements for 2005 and 2004 have been adjusted to apply the new method retrospectively. As a result of the accounting change, retained earnings as of January 1, 2004, increased from $47.6 million, as originally reported using the accrual method, to $79.0 million using the deferral method. These deferred charges are included in the Company’s Consolidated Balance Sheets in “Deferred charges and other assets.” The amortization expenses are included in “Refinery operating expenses, excluding depreciation” in the Company’s Consolidated Statements of Income. The following consolidated financial statement line items as of December 31, 2005 and for the years ending December 31, 2005 and 2004 were affected by the change in accounting principle.

	Year ending December 31,
		2005									2004
		As Originally Reported			As Adjusted			Change			As Originally Reported			As Adjusted			Change
	(in thousands)
Consolidated Statements of Income:
Refinery operating expenses, excluding depreciation	$	245,449		$	241,445		$	(4,004	)	$	219,781		$	220,427		$	646

Income before income taxes		443,251			447,255			4,004			112,103			111,457			(646	)
Provision for income taxes		168,216			169,594			1,378			42,339			42,065			(274	)
Income before cumulative effect of accounting change		275,035			277,661			2,626			69,764			69,392			(372	)
Net income	$	272,532		$	275,158		$	2,626		$	69,764		$	69,392		$	(372	)

Basic earnings per share:
Before cumulative effect of accounting change	$	2.48		$	2.51		$	0.03		$	0.65		$	0.65		$	-
Cumulative effect of accounting change		(0.02	)		(0.02	)		-			-			-			-
Net income	$	2.46		$	2.49		$	0.03		$	0.65		$	0.65		$	-

Diluted earnings per share:
Before cumulative effect of accounting change	$	2.42		$	2.44		$	0.02		$	0.64		$	.63		$	(0.01	)
Cumulative effect of accounting change		(0.02	)		(0.02	)		-			-			-			-
Net income	$	2.40		$	2.42		$	0.02		$	0.64		$	.63		$	(0.01	)

Consolidated Statements of Cash Flows:
Net income	$	272,532		$	275,158		$	2,626		$	69,764		$	69,392		$	(372	)
Adjustments to reconcile net income to net income from operating activities:
Depreciation and amortization		35,213			47,546			12,333			32,208			45,252			13,044
Deferred income taxes		28,881			30,259			1,378			25,005			24,731			(274	)
Deferred charges and other		(271	)		(17,316	)		(17,045	)		2,458			(8,055	)		(10,513	)
Increase in long-term accrued liabilities		6,442			4,473			(1,969	)		(2,645	)		431			3,076
Increase in current accrued liabilities and other		34,200			36,877			2,677			16,629			11,668			(4,961	)

Net cash provided by operating activities	$	360,337		$	360,337		$	-		$	177,899		$	177,899		$	-

	December 31, 2005
	As Originally Reported		As Adjusted		Change
	(in thousands)
Consolidated Balance Sheet:
Deferred tax assets	$	6,819	$	2,004	$	(4,815	)
Deferred charges and other assets		2,588		28,951		26,363

Total assets	$	1,201,509	$	1,223,057	$	21,548

Accrued turnaround costs	$	12,696	$	-	$	(12,696	)
Long-term accrued turnaround costs		15,122		-		(15,122	)
Deferred income taxes		70,727		86,460		15,733

Retained earnings		319,150		352,783		33,633
Total shareholders ’ equity		445,059		478,692		33,633

Total liabilities and shareholders’ equity	$	1,201,509	$	1,223,057	$	21,548

4.	Long-term Debt

Schedule of Long-term Debt

	December 31,
	2006		2005
	(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 13 for consolidating financial statements). The Company used a portion of the net proceeds from this offering, together with other available funds, to fund a tender offer and consent solicitation for $64.9 million principal of its 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.

5.	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 availability amounts, of up to $225 million. The Facility size 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, 2006 or 2005 under the Facility. Standby letters of credit outstanding were $43.2 million and $69.5 million at December 31, 2006 and 2005, respectively. As of December 31, 2006, the Company had borrowing base availability of $181.8 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 2006 was 6.84%. 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, 2006.

6.	Income Taxes

The provision for income taxes is comprised of the following:

	Years ended December 31,
	2006		2005 As Adjusted (Note 3)		2004 As Adjusted (Note 3)
	(in thousands)
Current:
Federal	$	168,950	$	121,455	$	13,959
State		25,814		17,880		3,375
Total current provision		194,764		139,335		17,334
Deferred:
Federal		5,269		28,065		23,166
State		804		2,194		1,565
Total deferred provision		6,073		30,259		24,731
Total provision	$	200,837	$	169,594	$	42,065

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,
	2006			2005 As Adjusted (Note 3)			2004 As Adjusted (Note 3)
	(in thousands)
Provision based on statutory rates	$	203,040		$	156,539		$	39,010
Increase (decrease) resulting from:
State income taxes		26,618			20,074			4,940
Federal tax effect of state income taxes		(9,316	)		(7,026	)		(1,729	)
Benefit of the Section 199 manufacturers production activities deduction		(5,666	)		(3,229	)		-
Benefit of ultra-low sulfur diesel tax credit		(14,546	)		-			-
Release of valuation allowance		-			-			(955	)
Other, including permanent book-tax differences		707			3,236			799
Provision as reported	$	200,837		$	169,594		$	42,065

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

	December 31, 2006									December 31, 2005 As Adjusted (Note 3)
	State			Federal			Total			State			Federal			Total
	(in thousands)
Current deferred tax assets:
Gross current assets:
Accrued bonuses	$	545		$	4,240		$	4,785		$	356		$	2,772		$	3,128
Stock-based compensation		94			734			828			24			183			207
Other		235			2,505			2,740			212			1,793			2,005
Total gross deferred tax assets		874			7,479			8,353			592			4,748			5,340
Gross current liabilities:
Prepaid expenses		(374	)		(2,902	)		(3,276	)		(342	)		(2,663	)		(3,005	)
State income tax receivable or prepaid		-			(496	)		(496	)		-			(243	)		(243	)
State deferred taxes		-			(126	)		(126	)		-			(88	)		(88	)
Unrealized gain on derivative contracts		(139	)		(1,079	)		(1,218	)		-			-			-
Total current net deferred tax assets	$	361		$	2,876		$	3,237		$	250		$	1,754		$	2,004

Long-term deferred tax liabilities:
Gross long-term assets:
Pension and other post-retirement benefits	$	1,265		$	9,832		$	11,097		$	1,090		$	8,479		$	9,569
Stock-based compensation		628			4,878			5,506			-			-			-
Environmental liability accrual		315			2,450			2,765			67			525			592
Asset retirement obligations		254			1,974			2,228			231			1,800			2,031
Other		172			1,340			1,512			144			1,120			1,264
State deferred taxes		-			3,879			3,879			-			3,553			3,553
Total gross long-term assets		2,634			24,353			26,987			1,532			15,477			17,009
Gross long-term liabilities:
Depreciation		(12,606	)		(98,554	)		(111,160	)		(10,495	)		(82,560	)		(93,055	)
Deferred turnaround costs		(1,110	)		(8,624	)		(9,734	)		(1,187	)		(9,227	)		(10,414	)
Total long-term net deferred tax liabilities	$	(11,082	)	$	(82,825	)	$	(93,907	)	$	(10,150	)	$	(76,310	)	$	(86,460	)

The Company utilized all remaining alternative minimum tax carryforwards during 2005. The Company had no federal or state net operating loss carryforwards as of December 31, 2006.

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, 2006, amounts reserved for such contingencies were $28.3 million (including interest) and are included in “Contingent income tax liabilities” on the Consolidated Balance Sheets. One such contingency relates to the deductibility for income tax purposes of certain stock-based compensation for executives for the years 2003 through 2006. As of December 31, 2006 and 2005, the Company had accrued $24.4 million and $18.1 million, respectively, in contingent income taxes which may be due should the determination be made that this stock-based compensation is not deductible. Any income tax benefit allowed for this stock-based compensation would be recorded as an increase in additional paid-in capital. Another contingency is for a deduction taken in 2004 related to the Company’s prior oil and gas operations ($3.8 million and $3.6 million at December 31, 2006 and 2005, respectively). As of December 31, 2006, the Company also had an income tax contingency of $93,000 related to a 2005 state income tax business versus nonbusiness classification. The Company has not identified any other potential income tax contingencies that must be disclosed in accordance with FAS No. 5. Interest expensed during the year ended December 31, 2006 for these contingencies was $1.5 million and is included in “Interest expense and other financing costs” on the Consolidated Statements of Income.

As indicated in Note 2 “New Accounting Pronouncements,” FIN 48 will apply to fiscal years beginning after December 15, 2006 . The Company is currently evaluating its tax positions, but does not believe that the adoption of FIN 48 will have a material effect on the Company’s financial statements.

As of December 31, 2006, the Company had accrued federal income taxes payable of $2.6 million and state income taxes payable of $2.0 million, which are included in “Accrued liabilities and other” on the Consolidated Balance Sheet. The Company also has estimated overpayments of 2006 state income taxes of $1.4 million, which are included in “Other current assets” on the Consolidated Balance Sheet and which will be applied to the related states’ 2007 income tax liabilities. 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 $5.7 million in 2006 and $3.2 million in 2005 related to the new production activities deduction. The income tax provision for the year ended December 31, 2006, also included the excess $14.5 million income tax benefit of a $22.4 million credit for production of ultra low sulfur diesel fuel (see “Environmental” under Note 9 “Commitments and Contingencies.)

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, 2006.

The Company recognized income tax benefits related to the deductibility of stock-based compensation in the amounts of $5.3 million (net of contingency), $7.8 million and $5.2 million for the years ended December 31, 2006, 2005 and 2004, respectively. Such benefits were recorded as an increase in additional paid-in capital and a reduction of income taxes payable. 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 $141,000, $755,000 and ($166,000) for the years ended December 31, 2006, 2005 and 2004, respectively.

7.	Common Stock

Stock Splits

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.

The Company’s Board of Directors also approved in April 2006 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 90 million to 180 million, and the amendment was approved at a special shareholders’ meeting on June 9, 2006. The stock dividend was issued on June 26, 2006 to shareholders of record as of the close of business on June 19, 2006.

All prior period share related numbers included in this report have been revised to reflect both the 2005 and 2006 stock splits.

Dividends

The Company declared quarterly cash dividends of $0.02 per share of common stock for the quarter ended March 31, 2006. The quarterly cash dividend was $0.03 per share of common stock for the quarters ended June 30, 2006 through December 31, 2006.

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. Both the Revolving Credit Facility and the 6.625% Notes may limit dividends according to a restricted payments calculation.

Treasury stock

The Company accounts for its treasury stock under the cost method on a FIFO basis. In November 2006, the Company’s Board of Directors approved a new $100 million share repurchase program, which replaced all existing repurchase authorizations, and may be utilized for share repurchases in the near term (no shares had been repurchased under this new program as of December 31, 2006). During the year ended December 31, 2006, under previous share repurchase authorizations, the Company purchased 3,482,088 shares ($92.3 million) in open market transactions as well as paid $1.9 million (101,400 shares) for 2005 stock repurchases which did not settle until early 2006 and were accrued as of December 31, 2005. The Company received no shares in 2006, 381,916 shares ($3.6 million) in 2005 and 862,396 shares ($4.1 million) in 2004 of its common stock, now held as treasury stock, from employees in stock swaps where mature stock is surrendered by the employee to exercise the stock options, as provided for by the Company’s stock-based compensation plans. The Company received 141,738 shares ($4.8 million) in 2006, 893,040 shares ($12.1 million) in 2005 and 644,780 shares ($3.0 million) in 2004 of its common stock, now held as treasury stock, from employees to cover withholding taxes on stock-based compensation. As of December 31, 2006, the Company had 24,164,808 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, 2006, 2005 and 2004.

	2006						2005 As Adjusted (Note 3)						2004 As Adjusted (Note 3)
	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	$	379,277		111,408	$	3.40	$	275,158		110,724	$	2.49	$	69,392		106,692	$	0.65
Dilutive securities:
Stock options		-		565		-		-		2,792		-		-		2,871		-
Restricted stock		-		539		-		-		120		-		-		41		-
Diluted EPS:
Net income	$	379,277		112,512	$	3.37	$	275,158		113,636	$	2.42	$	69,392		109,604	$	0.63

For the year ended December 31, 2006, 493,226 outstanding stock options that could potentially dilute EPS in future years were not included in the computation of diluted EPS. For the years ended December 31, 2005 and 2004, there were no outstanding stock options that could potentially dilute EPS in future years that were not included in the computation of diluted EPS.

Stock-based Compensation

Effective January 1, 2006, the Company adopted FAS No. 123(R), “Share-Based Payment,” which requires companies to recognize the fair value of stock options and other stock-based compensation in the financial statements. The Company adopted FAS No. 123(R) using the modified prospective application method, and accordingly, prior period amounts have not been retrospectively adjusted. Upon adoption of FAS No. 123(R), deferred compensation recorded as contra-equity in prior periods was eliminated against the appropriate equity accounts. The Company evaluated the need for a cumulative effect of a change in accounting principle as of January 1, 2006, related to previously recognized compensation expense for previously forfeited awards or in recognition of an assumption for future forfeits, and determined that none was necessary. In 2006, the adoption of FAS No. 123(R) resulted in incremental stock-based compensation expense of $7.0 million. This incremental stock-based compensation reduced the Company’s net income by $4.3 million ($0.04 per basic and diluted share) for the year ended December 31, 2006. Cash provided by operating activities decreased $8.9 million and cash provided by financing activities increased by the same amount for the year ended December 31, 2006, due to excess income tax benefits from stock-based payment arrangements.

The Company also elected to use the FSP No. 123(R)-3’s simplified method of calculating the adoption-date additional paid-in capital pool. This is for the purposes of calculating the pool of excess income tax benefits available to absorb tax deficiencies subsequent to the adoption of FAS No. 123(R).

Stock-based compensation costs and income tax benefits recognized in the Consolidated Statements of Income for the years ended December 31, 2006, 2005 and 2004 are as follows:

	Years Ended December 31,
	2006		2005		2004
Restricted shares and units	$	8,539	$	1,362	$	1,180
Stock options		2,110		-		-
Performance-based awards		7,290		-		-
Stock grant to retiring executive (3,030 shares)		90		-		-
Total stock-based compensation expense	$	18,029	$	1,362	$	1,180

Income tax benefit recognized in the income statement	$	6,851	$	518	$	448

Omnibus Incentive Compensation Plan. The shareholders of the Company approved the Frontier Oil Corporation Omnibus Incentive Compensation Plan (the “Plan”) at the Annual Meeting of Shareholders held on April 26, 2006. The Plan is a broad-based incentive plan that provides for granting stock options, stock appreciation rights (“SAR”), restricted stock awards, performance awards, stock units, bonus shares, dividend equivalent rights, other stock-based awards and substitute awards (“Awards”) to employees, consultants and non-employee directors of the Company. The Plan amends and restates the Company’s previously approved 1999 Stock Plan and the Company’s Restricted Stock Plan, both of which were merged into the Omnibus Plan. The maximum number of shares of the Company’s common stock that may be issued under the Plan with respect to Awards is 12,000,000 shares, subject to certain adjustments as provided by the Plan. Awards issued under the prior plans between December 31, 2005 and April 26, 2006 reduced the number of shares available for Awards as though the awards had been issued after April 26, 2006. The number of shares available for Awards will be reduced by 1.7 times the number of shares for each stock-denominated award granted, other than an option or a SAR under the Plan, and will be reduced by 1.0 times the number of option shares or SARs granted. As of December 31, 2006, 7,514,254 shares were available to be awarded under the Plan assuming maximum payout is achieved on the performance awards made in 2006 for which restricted stock will be issued in 2007 (see “Performance Awards” below). For purposes of determining compensation expense, forfeitures are estimated at the time Awards are granted based on historical average forfeiture rates and the group of individuals receiving those Awards. The Plan provides that the source of shares for Awards may be either newly issued shares or treasury shares. As of December 31, 2006, there was $20.9 million of total unrecognized compensation cost related to the Plan including costs for stock options, restricted stock, restricted stock units and performance-based awards, which is expected to be recognized over a weighted-average period of 2.11 years.

Stock Options. Stock options are issued at the current market price of the Company’s common stock on the date of grant and generally vest ratably over three years and expire after five years. The grant date fair value is calculated using the Black-Scholes option pricing model. The Company uses historical employee exercise data, including post-vesting termination behavior, to estimate the expected life of the options. Expected volatility is calculated using the historical volatility of the price of the Company’s common stock. The risk-free interest rate is based on the U.S. Treasury yield curve in effect at the time of the grant. The $9.615 per share fair value of the five-year options granted during the year ended December 31, 2006 was estimated with the following assumptions: risk-free interest rate of 4.89%, expected volatility of 37.3%, expected life of 3.33 years and no dividend yield. The fair value for grants made during the years ended December 31, 2004 and 2003 was estimated with the following assumptions, 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%.

For the stock options granted in 2006, when common stock dividends are declared by the Company’s Board of Directors, dividend equivalents are accrued but not paid until the options are vested. After vesting, dividend equivalents will be paid concurrently with common stock dividends until the options are exercised or expire. Stock options issued prior to 2006 do not have any dividend equivalent rights.

Stock option changes during the years ended December 31, 2006, 2005 and 2004 are presented below:

	2006							2005					2004
	Number of Awards			Weighted-Average Exercise Price		Aggregate Intrinsic Value of Options ( *in thousands)*		Number of Awards			Weighted-Average Exercise Price		Number of Awards			Weighted-Average Exercise Price
Outstanding at beginning of year		1,381,700		$	4.3515				8,353,800		$	3.9935		12,286,100		$	3.3025
Granted		493,226			29.3850				-			-		180,000			4.6625
Exercised or issued		(842,800	)		4.3560				(6,935,300	)		3.9195		(4,103,900	)		1.9538
Expired		-			-				(36,800	)		4.5005		(8,400	)		5.4625
Outstanding at end of year		1,032,126				$	13,147		1,381,700			4.3515		8,353,800			3.9935
Vested or expected to vest at end of year		1,021,207				$	13,147		1,381,700					8,353,800
Exercisable at end of year		501,400				$	12,444		640,700			4.5115		5,840,200			3.7555
Weighted-average fair value of options granted during the year					9.615							-					1.9175

The Company received $3.7 million, $23.6 million and $3.9 million of cash for stock options exercised during the years ended December 31, 2006, 2005 and 2004, respectively. The total intrinsic value of stock options exercised during the years ended December 31, 2006, 2005 and 2004 were $22.4 million, $69.8 million and $12.2 million, respectively. The Company realized $9.5 million, $25.5 million and $4.7 million of income tax benefits during the years ended December 31, 2006, 2005 and 2004, respectively, substantially all of which were excess income tax benefits related to the exercises of stock options. Excess income tax benefits are the benefits from additional deductions allowed for income tax purposes in excess of expenses recorded in the financial statements. These excess income tax benefits are recorded as an increase to paid-in capital and the majority of these amounts, beginning in 2006 (as provided for in FAS No. 123(R)), are reflected as cash flows from financing activities in the Consolidated Statements of Cash Flows.

The following table summarizes information about stock options outstanding at December 31, 2006:

Stock Options Outstanding at December 31, 2006
Number Outstanding	Weighted-Average Remaining Contractual Life (Years)	Exercise Price	Exercisable
493,226	4.32	$ 29.3850	-
105,000	2.15	4.6625	67,500
399,100	1.14	4.1625	399,100
34,800	0.32	5.4625	34,800

Restricted Shares and Restricted Stock Units. Restricted shares and restricted stock units, when granted, are valued at the closing market value of the Company’s common stock on the date of issuance and amortized to compensation expense on a straight-line basis over the nominal vesting period of the stock, and for awards issued subsequent to the adoption of FAS No. 123(R), adjusted for retirement-eligible employees, as required. For awards granted prior to the adoption of FAS No. 123(R), $1.5 million of compensation costs were recognized during the year ended December 31, 2006, and continue to be recognized over the nominal vesting period. The restricted shares and restricted stock units have vesting dates up to three years from the issue date. When common stock dividends are declared by the Company’s Board of Directors, dividends are accrued on the issued restricted shares but are not paid until the shares vest. When common stock dividends are declared by the Company’s Board of Directors, dividend equivalents are accrued on the restricted stock units and paid when the common stock dividends are paid.

The following table summarizes the changes in the Company’s restricted shares and restricted stock units during the years ended December 31, 2006, 2005 and 2004.

	2006					2005					2004
	Shares/ Units			Weighted-Average Grant-Date Market Value		Shares/ Units			Weighted-Average Grant-Date Market Value		Shares/ Units			Weighted-Average Grant-Date Market Value
Nonvested at beginning of year		415,692		$	8.8870		218,792		$	4.8575		834,316		$	3.1569
Granted		459,966			26.4773		465,616			8.9124		-			-
Vested		(162,622	)		16.2865		(254,696	)		5.5057		(603,724	)		2.5074
Forfeited		-			-		(14,020	)		8.2750		(11,800	)		4.8575
Nonvested at e nd of year		713,036			18.5465		415,692			8.8870		218,792			4.8575

The total fair value of restricted shares and restricted stock units which vested during the years ended December 31, 2006, 2005 and 2004 was $4.5 million, $2.4 million and $2.8 million, respectively. The vesting for the year ended December 31, 2006 in the table above includes 128,596 shares of previously issued restricted stock and 34,026 restricted stock units (for which common stock was issued upon vesting). The vesting for the year ended December 31, 2005 in the table above includes 238,696 shares of previously issued restricted stock and 16,000 restricted stock units (for which common stock was issued upon vesting). The vesting for the year ended December 31, 2004 in the table above included all shares of previously issued restricted stock. The Company realized $1.7 million, $893,000 and $1.1 million of income tax benefits related to these vestings, of which $712,000, $361,000, and $495,000 was excess income tax benefits, for 2006, 2005 and 2004, respectively.

Performance Awards . On April 26, 2006, the Company granted up to 657,243 stock unit awards. Because performance goals were achieved for 2006, the stock unit awards were converted into restricted stock following certification of performance by the Compensation Committee of the Company’s Board of Directors, one-third will vest on June 30, 2007, one-third on June 30, 2008 and the final one-third on June 30, 2009. When common stock dividends are declared by the Company’s Board of Directors, dividend equivalents (on the stock unit awards) and dividends (once the stock unit awards are converted to restricted stock) are accrued but are not paid until the restricted stock vests. The stock unit awards were valued at the market value at the date of grant and amortized to compensation expense on a straight-line basis over the nominal vesting period, adjusted for retirement-eligible employees, as required under FAS No. 123(R).

8.	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, 2006, 2005 and 2004 was $6.4 million, $6.1 million and $5.6 million, respectively.

Deferred Compensation Plan

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

Executive Retiree Medical Benefit Plan

On February 22, 2006, the Compensation Committee of the Company’s Board of Directors approved the Executive Retiree Medical Benefit Plan. The Executive Retiree Medical Benefit Plan provides a post-retirement medical benefit for certain of the Company’s executive officers. Due to the plan design, the amount to be contributed by the retirees is expected to cover approximately the full cost of the plan. No cost had been incurred by the Company for this plan through December 31, 2006.

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 $9.7 million at December 31, 2006, 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, 2006 and 2005. 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. Post-retirement healthcare benefits provided for Medicare eligible retirees were reduced effective December 31, 2006 to levels stipulated at the time of the El Dorado Refinery acquisition.

In accordance with FAS No. 158, which the Company adopted as of December 31, 2006, Frontier is required to 1) recognize the funded status of a benefit plan (measured as the difference between plan assets at fair value and the benefit obligation) in its statement of financial position, 2) recognize as a component of other comprehensive income, net of tax, the gains or losses and prior service costs or credits that arise during the period but are not recognized as components of net period benefit cost, 3) measure defined benefit plan assets and obligations as of the date of the employer’s fiscal year-end statement of financial position, and 4) disclose in the notes to the financial statements additional information about certain effects on net periodic benefit cost for the next fiscal year that arise from delayed recognition of the gains or losses, prior service costs or credits, and transition assets or obligations.

The following tables set forth the funded status of the pension plan and post-retirement healthcare and other benefit plans change in benefit obligation, items not yet recognized as a component of net periodic benefit costs and reflected as a component of the ending balance of accumulated Other Comprehensive Income (“OCI”), net of tax, and the measurement of defined benefit plan assets and obligations as of December 31, 2006.

		Pension Benefits						Post-retirement Healthcare and Other Benefits (1)
	2006			2005			2006			2005
	(in thousands)
Change in benefit obligation:
Benefit obligation at January 1	$	9,942		$	11,810		$	41,181		$	29,039
Service cost		-			-			1,011			1,130
Interest cost		541			526			2,075			2,093
Plan participant contributions		-			-			49			25
Actuarial (gain)/losses		(246	)		(2,210	)		(2,772	)		9,077
Amendments		-			-			(13,115	)		-
Benefits paid		(266	)		(184	)		(206	)		(183	)
Benefit obligation at December 31	$	9,971		$	9,942		$	28,223		$	41,181

Change in plan assets:
Fair value of plan assets at January 1	$	8,279		$	6,915		$	-		$	-
Actual return on plan assets		963			374			-			-
Employer contribution		692			1,174			156			158
Plan participant contributions		-			-			50			25
Benefits paid		(266	)		(184	)		(206	)		(183	)
Fair value of plan assets at December 31	$	9,668		$	8,279		$	-		$	-

Funded status at December 31	$	(303	)	$	(1,663	)	$	(28,223	)	$	(41,181	)
Unrecognized net actuarial (gain) loss		-			(43	)		-			17,174
Net amount recognized	$	(303	)	$	(1,706	)	$	(28,223	)	$	(24,007	)

Amounts recognized in the balance sheets:
Current liabilities and other	$	-			n/a		$	(436	)		n/a
Post-retirement employee liabilities		(303	)		n/a			(27,787	)		n/a
Net amount recognized	$	(303	)		n/a		$	(28,223	)		n/a

Amounts recognized in accumulated OCI:
(Gain) loss	$	(611	)	$	(43	)	$	13,314		$	-
Amendments (gain) (3)		-			-			(13,115	)		-
	$	(611	)	$	(43	)	$	199		$	-

	Pension Benefits									Post-retirement Healthcare and Other Benefits
	2006			2005			2004			2006		2005		2004
	(in thousands)
Components of net periodic benefit cost for the year ended December 31:
Service cost	$	-		$	-		$	-		$	1,011	$	1,130	$	863
Interest cost		541			526			632			2,075		2,093		1,460
Expected return on plan assets		(640	)		(606	)		(479	)		-		-		-
Recognized net actuarial loss		-			-			22			1,087		1,525		490
Net periodic benefit cost	$	(99	)	$	(80	)	$	175		$	4,173	$	4,748	$	2,813

Weighted average assumptions:
Benefit obligation discount rate as of December 31	5.75	%	5.50	%	5.50	%	5.75	%	5.50	%	5.50	%
Net periodic benefit cost discount rate for the year ended December 31	5.50	%	5.50	%	6.00	%	5.50	%	5.50	%	6.00	%
Expected return on plan assets (2)	7.50	%	8.00	%	8.00	%	-		-		-
Salary increases	n/a		n/a		n/a		-		-		-

(1)

The disclosed post-retirement healthcare obligations and net periodic costs for 2006 and 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, 2006 and 2005, by approximately $5.3 million and $4.8 million, respectively.

(2)	The cash balance pension plan assumes a 7.5% 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 the same as expected returns for the two years ended December 31, 2006.

(3) None of the pension gain of $611,000 will be recognized in the pension benefit cost in 2007. For the post-retirement healthcare and other benefits, $1.1 million of the $13.3 million net loss and $1.9 million of the $13.1 million amendment gain will be recognized in the benefit cost in 2007.

	Post-retirement Healthcare and Other Benefits
	2006			2005			2004
	(dollars in thousands)
Healthcare cost-trend rate:		10.00	%		11.00	%		13.00	%
		ratable to			ratable to			ratable to
		5.00	%		5.00	%		5.00	%
		from 2012			from 2008			from 2008
Sensitivity Analysis:
Effect of 1% (-1%) change in healthcare cost-trend rate:
Year-end benefit obligation	$	4,761		$	8,641		$	6,094
		(3,852	)		(6,784	)		(4,767	)
Total service and interest cost		662			720			502
		(519	)		(560	)		(392	)

At December 31, 2006, the estimated future benefit payments to be paid over the next ten years are as follows:

Estimated future benefit payments for years ending December 31, *(in thousands)*	Pension Benefits		Post-retirement Healthcare and Other Benefits
	Payment		Payment		Subsidy Receipts
2007	$	189	$	436	$	-
2008		151		693		21
2009		245		992		28
2010		352		1,294		41
2011		512		1,653		53
Next 5 fiscal years thereafter		5,620		12,581		662

The following table provides information regarding the incremental effect of applying FAS No. 158 on individual line items in the consolidated balance sheet as of December 31, 2006.

December 31, 2006:	Before Application of FAS No. 158		Adjustments			After Application of FAS No. 158
	(in thousands)
Post-retirement employee liabilities	$	28,460	$	(370	)	$	28,090
Deferred income taxes		93,766		141			93,907
Accumulated other comprehensive income		27		229			256
Total shareholders’ equity		775,625		229			775,854

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, 2006 and 2005, by asset category are as follows:

	Percentage of Plan Assets at December 31,
	2006			2005
Asset Category:
Cash equivalents		7	%		10	%
Equity common trust funds		69	%		52	%
Fixed income common trust funds		24	%		26	%
Stock fund common trust funds		-			8	%
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 $692,000 to the Fund during 2006 and is not required to, but may choose to, contribute to the Fund during the year ending December 31, 2007.

9.	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 2006 results, and was accrued at December 31, 2006 and was paid in January 2007. A contingent earn-out payment of $7.5 million was required based on 2005 results and was paid in January 2006. Including the payment made in early 2007, the Company has paid a total of $30.0 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, which has both a fixed and a variable component, expires in 2016, although the Company has the option to renew the sublease for an additional eight years. At the end of the renewal period, the Company has the option to purchase the cogeneration facility for the greater of fair value or $22.3 million. The Company also has building, equipment, aircraft and vehicle operating leases that expire from 2006 through 2017. Operating lease rental expense was approximately $13.8 million, $13.5 million and $10.4 million for the years ended December 31, 2006, 2005 and 2004, respectively. The approximate future minimum lease payments for operating leases as of December 31, 2006 are $14.4 million for 2007, $13.7 million for 2008, $13.7 million for 2009, $13.2 million for 2010, $10.6 million for 2011 and $33.7 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 heavy Canadian 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, Canada to Guernsey, Wyoming, less $0.25 per barrel. The agreement expires on December 31, 2007.

The Company has commitments for crude oil pipeline capacity on three pipelines (see below) totaling approximately $19.6 million in 2007, an average of $32.0 million for each of the years 2008 through 2011, an average of $27.8 million for each of the years 2012 through 2014, $23.5 million in 2015 and approximately $7.2 million in 2016.

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 temporarily 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.

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 (“Cushing”) once the reversal of the pipeline was completed. Enbridge Energy Company completed the reversal of the Spearhead Pipeline and began accepting line fill volumes in December 2005. Deliveries into Cushing started during March 2006. In November 2006, we increased our crude oil volumes on the Spearhead Pipeline from 20,000 bpd to 38,000 bpd. 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 of March 2006, although the Company has the right to extend the Agreement for an additional ten-year term and increase the volume transported.

The Company entered into a definitive agreement with Rocky Mountain Pipeline System LLC (“Rocky Mountain”), now owned by Plains All American Pipeline, L.P. on March 31, 2006 to support construction of a new crude pipeline from Guernsey, Wyoming to Rocky Mountain’s Fort Laramie, Wyoming tank farm and then to the Cheyenne Refinery. The Company made a ten-year commitment to ship 35,000 bpd based on a filed tariff on the new pipeline and will concurrently lease approximately 300,000 barrels of dedicated storage capacity in the Rocky Mountain tank farm. The pipeline, which is designed to transport 55,000 bpd of heavy crude and is expandable to 90,000 bpd, is expected to first transport crude oil in mid-2007.

Effective March 10, 2006, the Company’s subsidiary, Frontier Oil and Refining Company (“FORC”), entered into a Master Crude Oil Purchase and Sale Contract (“Contract”) with Utexam. Under this $165.0 million Contract, Utexam will purchase, transport and subsequently sell crude oil to FORC at a location near Cushing, Oklahoma or other locations as agreed. Utexam will be the owner of record of the crude oil as it is transported from the point of injection, which is expected to be Hardisty, Alberta, Canada to the point of ultimate sale to FORC. The Company has provided a guarantee of FORC’s obligations under this Contract, primarily to receive crude oil and make payment for crude oil purchases arranged under this Contract. As of December 31, 2006, FORC and Utexam had entered into certain commitments to purchase and sell crude oil in January 2007 under this Contract; however, neither party has a continuing commitment to purchase or sell crude oil in the future. The Company accounts for the transactions under this Contract as a financing arrangement, whereby the inventory and the associated liability are recorded in the Company’s financial statements when the crude oil is injected into the pipeline in Canada.

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 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, three other oil and gas companies (and their related companies), and one company (and its related companies) involved in owning or operating a power plant adjacent to the Beverly Hills High School. 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 lawsuits and two lawsuits that do not name Wainoco Oil & Gas Company or Frontier as defendants 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 was entered pursuant to which 12 plaintiffs were selected as the initial group of plaintiffs to proceed to trial.

On October 27, 2006, the Los Angeles Superior Court granted summary judgment in favor of the parent, Frontier Oil Corporation. As a result of this order, the plaintiffs in all of the lawsuits in which Frontier is a defendant can no longer prosecute claims against Frontier Oil Corporation, either for Frontier Oil Corporation’s alleged direct liability or for any of the plaintiffs’ claims against its subsidiary. The order does not affect unresolved indemnity claims asserted by or against Frontier Oil Corporation. In addition, on November 22, 2006, the Court entered a ruling granting summary judgment in favor of all of the defendants, including Wainoco Oil & Gas Company and Frontier Oil Corporation, against the initial 12 trial plaintiffs . On January 9, 2007, the Court entered a ruling granting summary judgment in favor of the City of Beverly Hills, concluding the City has no liability to the plaintiffs in all of the lawsuits in which the City is a defendant under the California governmental tort liability statutes. The entry of a final judgment by the Court in favor of the defendants on all of these recent rulings will likely be appealed by the plaintiffs.

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, which 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, 2006, the commutation account balance was approximately $7.3 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 $1.9 million as of December 31, 2006, 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.

In accordance with FAS No. 5, “Accounting for Contingencies,” Frontier has not accrued for a loss contingency relating to the Beverly Hills litigation because Frontier believes that, although unfavorable outcomes in the proceedings may be reasonably possible, Frontier does not consider them to be probable or reasonably estimable. 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.

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 executed in conjunction with the purchase of the El Dorado Refinery in 1999. Beginning in 2000, the Company retained and marketed 5,000 bpd of the El Dorado Refinery’s gasoline and diesel production. The retained portion is scheduled to increase by 5,000 bpd each year for ten years. In 2006, Frontier retained 35,000 bpd of the Refinery’s gasoline and diesel production. Shell has also agreed to purchase all jet fuel production from the El Dorado Refinery through the offtake agreement term. The Company retains and markets all by-products produced from the El Dorado Refinery. The Company made sales to Shell of approximately $2.1 billion, $1.8 billion and $1.4 billion in the years 2006, 2005 and 2004, respectively, which accounted for 44%, 46% and 49% of consolidated refined products revenues in 2006, 2005 and 2004, respectively.

The Company extends credit to its customers based on ongoing credit evaluations. An allowance for doubtful accounts is provided based on the current evaluation of each customers’ credit risk, past experience and other factors. A bad debt loss of $26,000 was recorded in the year ended December 31, 2006. No bad debt losses were recorded during the years ended December 31, 2005 or 2004.

Environmental

The Company’s operations and many of its manufactured products are specifically subject to certain requirements of the Clean Air Act (“CAA”) and related state and local regulations. The 1990 amendments to the CAA contain provisions that will require capital expenditures for the production of cleaner transportation fuels and the installation of certain air pollution control devices at the Refineries during the next several years.

The Environmental Protection Agency (“EPA”) has promulgated regulations requiring the phase-in of gasoline sulfur standards, which began January 1, 2004 and 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 complied 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 $9.0 million in estimated costs to meet the final standard, and $6.0 million for facilities to handle intermediate inventories, for the Cheyenne Refinery are expected to be incurred between 2008 and 2010. Total capital expenditures estimated as of December 31, 2006, for the El Dorado Refinery to comply with the final gasoline sulfur standard are approximately $83.0 million, including capitalized interest, and are expected to be incurred between 2006 and 2009. Substantially all of the estimated $83.0 million of expenditures is included in the Company’s potential El Dorado gasoil hydrotreater revamp project. The gasoil hydrotreater revamp project will address most of the Refinery modifications needed to achieve gasoline sulfur compliance while providing substantial economic benefit to the El Dorado Refinery.

The EPA has promulgated regulations that limit the sulfur content of highway diesel fuel beginning in mid-2006. As indicated above, Frontier elected to comply with the highway diesel sulfur standard by June 2006 and had completed the necessary capital projects to achieve the standard at both Refineries by early June. As of December 31, 2006, capital costs, including capitalized interest, for the ultra low sulfur diesel projects, including 2004, 2005 and 2006 expenditures, were $105.4 million, including $27.6 million paid in 2006, at the El Dorado Refinery and $16.3 million, including $10.1 million paid in 2006, at the Cheyenne Refinery. Certain provisions of the American Jobs Creation Act of 2004 are providing federal income tax benefits to Frontier by allowing the Company an accelerated depreciation deduction on 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 produced up to an amount equal to the remaining 25% of these qualified capital costs. The Company reduced its federal income tax provision for the year ended December 31, 2006 by $22.4 million by using income tax credits from these qualified capital costs and has approximately $8.4 million of credits remaining to take in 2007.

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. Prior to June 30, 2006, the Company participated 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 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 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 to either postpone the new sulfur limits or, if the small refiner chooses to meet the new limit on the national schedule, to increase their gasoline sulfur limits by 20%. Frontier chose to install equipment to desulfurize all of its diesel fuel, including non-road, to the 15 ppm sulfur standard by June 2006, resulting in early compliance with the non-road standard. This gives the Company the option of selling its historic non-road diesel fuel volume into either the current non-road market or the 15 ppm sulfur on-road market, depending on economics. The new regulation also clarifies that EPA-approved small business refiners will be allowed to exceed both the small refiner maximum capacity and/or employee criteria through merger with or acquisition of another approved small business refiner without loss of small refiner regulatory status. The loss of such status through merger, acquisition or non-compliance with the enabling regulations could result in the loss of the benefits described in the above paragraphs and the possible acceleration of certain associated expenditures.

The EPA has embarked on a Petroleum Refining Initiative (“Initiative”) alleging industry-wide noncompliance with certain longstanding regulatory programs. These programs are:

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

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

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

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

The Initiative has resulted in many refiners entering into consent decrees typically requiring substantial expenditures for penalties and additional pollution control equipment. In anticipation of such a consent decree, the Company has undertaken certain modifications at each of the Company’s refineries. At the Cheyenne Refinery, the Company has spent $4.6 million on the flare system, of which $223,000 was spent in 2004, $4.1 million in 2005 and the remaining $315,000 was incurred in 2006. At the El Dorado Refinery, through December 31, 2006, the Company has incurred $2.6 million, and it expects to spend an additional $1.9 million during 2007 to complete the flare system. In addition to Frontier’s expenditures, Shell Oil Products US (“Shell”) reimbursed Frontier $5.0 million in the fourth quarter of 2006 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. Settlement negotiations with the EPA and state regulatory agencies regarding additional regulatory issues associated with the Initiative are underway. The Company now estimates that, in addition to the flare gas recovery systems discussed above, capital expenditures totaling approximately $47 million at the Cheyenne Refinery and $67 million at the El Dorado Refinery will be required prior to 2015 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 estimable.

The EPA has proposed regulations to enact the provisions of the Energy Bill regarding the mandated blending of renewable fuels in gasoline. The Bill requires gasoline refiners, blenders and importers, as a group, to blend increasing amounts of ethanol in the country’s gasoline supply, beginning in 2006 with 4.0 billion gallons and escalating to 7.5 billion gallons in 2012. If promulgated as proposed, the Company as a small refiner will be exempt until 2012 from these requirements, but will be able to generate and sell credits for ethanol blended during this period. It is not known what, if any, value such credits may have.

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 $250,000 in annual operating and maintenance costs will be required for approximately ten more years. As of December 31, 2006 and December 31, 2005, the Company had a reserve included on the Consolidated Balance Sheets in “Other long-term liabilities” of $2.0 million and $1.5 million, respectively, in environmental liabilities reflecting the estimated present value of these expenditures ($2.9 million discounted at a rate of 7.0%, and $2.0 million discounted at a rate of 5.0%, as of December 31, 2006 and 2005, respectively). In addition to this reserve, the Company had accrued $5.0 million as of December 31, 2006, also included in “Other long-term liabilities,” for the cleanup of a waste water treatment pond located on land historically leased from an adjacent landowner. The Company allowed the lease to expire and ceased use of the pond on the scheduled expiration date of June 30, 2006. The waste water pond will be cleaned up pursuant to the aforementioned agreement with the State of Wyoming. Depending upon the results of the ongoing investigation, or by a subsequent administrative order or permit, additional remedial action and costs could be required.

The Company has completed the negotiation of a settlement of a Notice of Violation (“NOV”) from the Wyoming Department of Environmental Quality alleging non-compliance with certain refinery waste management requirements. The Company has estimated that the capital cost for required corrective measures will be approximately $1.5 million. In addition, the Company had accrued an additional $1.2 million for expense work as of December 31, 2006 (included in “Other long-term liabilities” on the Consolidated Balance Sheets) and December 31, 2005 (included in “Accrued liabilities and other” on the Consolidated Balance Sheets). As of December 31, 2006, the anticipated timing of these expenditures had changed from that estimated as of December 31, 2005, resulting in the change from a short-term liability to a long-term liability. A penalty in the amount of $631,000 has been negotiated as part of the settlement of this NOV and is anticipated to be remitted to the State by the end of the first quarter of 2007 in accordance with the settlement agreement. This amount had been accrued by the Company as of December 31, 2006, and was included in “Accrued liabilities and other” on the Consolidated Balance Sheets as of December 31, 2006.

The Company has agreed to contribute $1.5 million toward a city of Cheyenne project (estimated to take place by the end of 2007) to relocate a city storm water conveyance pipe, which is presently located on Refinery property and therefore potentially subject to contaminants from Refinery operations. This is double the $750,000 originally accrued as of December 31, 2005, in recognition of cost overruns encountered by the city. The amount originally accrued as of December 31, 2005 was included in “Other long-term liabilities” on the Consolidated Balance Sheet and the revised estimate of $1.5 million is included in “Accrued liabilities and other” on the Consolidated Balance Sheet as of December 31, 2006.

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.

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. The current contract between the Company, the USW, and its Local 8-0574 (which represents approximately 150 workers at the Cheyenne Refinery) expires in July 2009. The current contract between the Company, the USW, and its Local 5-241 (which represents approximately 250 workers at the El Dorado Refinery) expires in January 2009.

10.

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, 2006 and 2005, the carrying amounts of long-term debt instruments were $150.0 million, and the estimated fair values were $148.9 million and $153.8 million, respectively. For cash and cash equivalents, trade receivables, inventory and accounts payable, the carrying amount is a reasonable estimate of fair value.

11.

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 creditworthy 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 the related inventory in “Inventory of crude oil, products and other” on the Consolidated Balance Sheets and ultimately, when the inventory is charged or sold, in “Raw material, freight and other costs” on the Consolidated Statements of Income. Gains and losses on transactions accounted for using mark-to-market accounting are reflected in “Other revenues” at each period end. The Company has

derivative contracts which it holds directly and also derivative contracts held on Frontier’s behalf by Utexam Limited (“Utexam”), a wholly-owned subsidiary of BNP Paribas Ireland, in connection with the Master Crude Oil Purchase and Sale Contract (see Note 9 “Lease and Other Commitments”). The market value of open derivative contracts is included on the Consolidated Balance Sheets in “Other current assets” when the unrealized value is a gain ($2.5 million at December 31, 2006), or in “Accrued liabilities and other” when the unrealized value is a loss ($854,000 at December 31, 2005).

Trading Activities

During 2006, 2005 and 2004, 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, 2006, the Company had open derivative contracts held on Frontier’s behalf by Utexam on 1,050,000 barrels of crude oil to hedge in-transit Canadian crude oil costs for the El Dorado Refinery. At December 31, 2006, these positions had a $1.2 million unrealized gain. During the year ended December 31, 2006, the Company reported in “Other revenues” $14.6 million (including the previously mentioned $1.2 million unrealized amount), in net gains on positions to hedge in-transit crude oil, mainly Canadian crude oil for the El Dorado Refinery. During the year ended December 31, 2005, the Company reported in “Other revenues” a net $461,000 loss 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, 2006, the Company had open derivative contracts on 1,649,000 barrels of crude oil to hedge crude oil, intermediate or finished product inventory. At December 31, 2006, these positions had a $1.3 million unrealized gain. During the year ended December 31, 2006, the Company reported in “Other revenues” $15.9 million (including the previously mentioned $1.3 million unrealized amount), in net gains on positions to hedge crude oil, intermediate or finished product inventory. During the years ended December 31, 2005 and 2004, the Company recorded a $1.4 million gain and an $8.1 million loss, respectively, 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 years ended December 31, 2006 and 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.

Hedging Activities

During the year ended December 31, 2006, the Company had the following derivatives which were appropriately designated and accounted for as hedges.

Crude purchases in-transit. As of December 31, 2006, the Company had no open derivative contracts accounted for as hedges. During the year ended December 31, 2006, the Company recorded $10.9 million in net losses on derivative contracts to hedge in-transit Canadian crude oil, primarily for the El Dorado Refinery, of which $15.0 million increased crude costs (“Raw material, freight and other costs”) and $4.1 million increased income which was reflected in “Other revenues” in the Consolidated Statements of Income for the ineffective portion of these hedges. 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 were 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.

12. Subsequent Event - Acquisition of Ethanol Management Company

On February 16, 2007, the Company acquired Ethanol Management Company (“EMC”) for approximately $3.1 million cash. EMC’s primary assets are a 25,000 bpd products terminal and blending facility located near Denver, Colorado.

13. 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 the guarantors are all direct or indirect 100% owned subsidiaries of Frontier, and all of the guarantees are full and unconditional on a joint and several basis. The Company files a consolidated U.S. federal income tax return and consolidated state income tax returns in the majority of states in which it does business. 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, 2006
(in thousands)
	FOC (Parent)			FHI (Guarantor Subsidiaries)			Other Non-Guarantor Subsidiaries		Eliminations			Consolidated
Revenues:
Refined products	$	-		$	4,759,661		$	-	$	-		$	4,759,661
Other		4			36,146			142		-			36,292
		4			4,795,807			142		-			4,795,953

Costs and expenses:
Raw material, freight and other costs		-			3,850,937			-		-			3,850,937
Refinery operating expenses, excluding depreciation		-			277,129			-		-			277,129
Selling and general expenses, excluding depreciation		30,194			22,294			-		-			52,488
Depreciation and amortization		88			41,502			-		(377	)		41,213
Gains on sales of assets		(8	)		-			-		-			(8	)
		30,274			4,191,862			-		(377	)		4,221,759

Operating income (loss)		(30,270	)		603,945			142		377			574,194

Interest expense and other financing costs		11,978			3,835			-		(3,674	)		12,139
Interest and investment income		(12,102	)		(5,957	)		-		-			(18,059	)
Equity in earnings of subsidiaries		(609,265	)		-			-		609,265			-
		(609,389	)		(2,122	)		-		605,591			(5,920	)

Income before income taxes		579,119			606,067			142		(605,214	)		580,114
Provision for income taxes		199,842			209,951			55		(209,011	)		200,837
Net income	$	379,277		$	396,116		$	87	$	(396,203	)	$	379,277

FRONTIER OIL CORPORATION
Condensed Consolidating Statement of Income
For the Year Ended December 31, 2005 As Adjusted (Note 3)
(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		-			241,445			-		-			241,445
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			3,536,910			-		(556	)		3,551,149

Operating income (loss)		(14,801	)		464,168			90		556			450,013

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		(462,027	)		-			-		462,027			-
		(457,339	)		331			-		459,766			2,758

Income before income taxes		442,538			463,837			90		(459,210	)		447,255
Provision for income taxes		168,910			171,921			-		(171,237	)		169,594
Income before cumulative effect of accounting change		273,628			291,916			90		(287,973	)		277,661
Cumulative effect of accounting change, net of income taxes		1,530			(2,503	)		-		(1,530	)		(2,503	)
Net income	$	275,158		$	289,413		$	90	$	(289,503	)	$	275,158

FRONTIER OIL CORPORATION
Condensed Consolidating Statement of Income
For the Year Ended December 31, 2004 As Adjusted (Note 3)
(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		-			220,427			-		-			220,427
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			2,699,879			-		(555	)		2,718,813

Operating income (loss)		(19,495	)		161,781			62		555			142,903

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		(164,392	)		-			-		164,392			-
Gain on involuntary conversion of assets		-			(4,411	)		-		-			(4,411	)
		(130,933	)		(1,973	)		-		164,352			31,446

Income before income taxes		111,438			163,754			62		(163,797	)		111,457
Provision for income taxes		42,046			62,155			-		(62,136	)		42,065
Net income	$	69,392		$	101,599		$	62	$	(101,661	)	$	69,392

FRONTIER OIL CORPORATION
Condensed Consolidating Balance Sheet
As of December 31, 2006
(in thousands)
	FOC (Parent)		FHI (Guarantor Subsidiaries)		Other Non-Guarantor Subsidiaries		Eliminations			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	215,049	$	190,430	$	-	$	-		$	405,479
Trade and other receivables		1,363		136,099		-		-			137,462
Receivable from affiliated companies		-		1,254		251		(1,505	)		-
Inventory		-		374,576		-		-			374,576
Deferred tax assets		3,237		7,846		-		(7,846	)		3,237
Other current assets		2,082		16,380		-		-			18,462
Total current assets		221,731		726,585		251		(9,351	)		939,216
Property, plant and equipment, at cost:		1,301		817,332		-		(5,051	)		813,582
Less - accumulated depreciation and amortization		1,054		284,034		-		(8,311	)		276,777
		247		533,298		-		3,260			536,805
Deferred financing costs, net		2,293		459		-		-			2,752
Commutation account		7,290		-		-		-			7,290
Prepaid insurance, net		2,120		-		-		-			2,120
Other intangible assets, net		-		1,316		-		-			1,316
Deferred charges and other assets		2,734		31,692		-		-			34,426
Investment in subsidiaries		831,082		-		-		(831,082	)		-
Total assets	$	1,067,497	$	1,293,350	$	251	$	(837,173	)	$	1,523,925


Current Liabilities:
Accounts payable	$	1,436	$	388,583	$	-	$	-		$	390,019
Contingent income tax liabilities		28,271		-		-		-			28,271
Accrued dividends		3,486		-		-		-			3,486
Accrued interest		2,484		57		-		-			2,541
Accrued liabilities and other		7,924		27,268		189		-			35,381
Total current liabilities		43,601		415,908		189		-			459,698

Long-term debt		150,000		-		-		-			150,000
Long-term accrued and other liabilities		-		41,836		-		-			41,836
Deferred compensation liability and other		2,630		-		-		-			2,630
Deferred income taxes		93,907		97,620				(97,620	)		93,907
Payable to affiliated companies		1,505		44,644		55		(46,204	)		-

Shareholders’ equity		775,854		693,342		7		(693,349	)		775,854
Total liabilities and shareholders’ equity	$	1,067,497	$	1,293,350	$	251	$	(837,173	)	$	1,523,925

FRONTIER OIL CORPORATION
Condensed Consolidating Balance Sheet
As of December 31, 2005
As Adjusted (Note 3)
(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		2,004		2,699		-		-2,699			2,004
Other current assets		499		7,436		-		-			7,935
Total current assets		253,241		497,274		189		-7,444			743,260
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
Deferred charges and other assets		2,508		26,443		-		-			28,951
Investment in subsidiaries		537,947		-		-		-537,947			-
Total assets	$	812,655	$	956,395	$	189		($546,182	)	$	1,223,057

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities:
Accounts payable	$	2,480	$	357,097	$	-	$	-		$	359,577
Contingent income tax liabilities		21,517		-		-		-			21,517
Accrued dividends		58,726		-		-		-			58,726
Accrued interest		2,485		-		-		-			2,485
Accrued liabilities and other		5,336		25,205		269		-			30,810
Total current liabilities		90,544		382,302		269		-			473,115

Long-term debt		150,000		-		-		-			150,000
Long-term accrued and other liabilities		-		32,576		-		-			32,576
Deferred compensation liability and other		2,214		-		-		-			2,214
Deferred income taxes		86,460		87,296		-		-87,296			86,460
Payable to affiliated companies		4,745		7,026		-		-11,771			-

Shareholders’ equity		478,692		447,195		-80		-447,115			478,692
Total liabilities and shareholders’ equity	$	812,655	$	956,395	$	189		($546,182	)	$	1,223,057

FRONTIER OIL CORPORATION
Condensed Consolidating Statement of Cash Flows
For the Year Ended December 31, 2006
(in thousands)
	FOC (Parent)			FHI (Guarantor Subsidiaries			Other Non-Guarantor Subsidiaries			Eliminations			Consolidated
Cash flows from operating activities:
Net income	$	379,277		$	396,116		$	87			($396,203	)	$	379,277
Adjustments to reconcile net income to net cash from operating activities:
Equity in earnings of subsidiaries		(609,265	)		-			-			609,265			-
Depreciation and amortization		88			54,677			-			(377	)		54,388
Deferred income taxes		6,073			-			-			-			6,073
Stock-based compensation expense		18,029			-			-			-			18,029
Excess income tax benefits of stock-based compensation		(8,881	)		-			-			-			(8,881	)
Income taxes eliminated in Consolidation		-			208,956			55			(209,011	)		-
Deferred finance cost amortization		482			315			-			-			797
Gains on sales of assets		(8	)		-			-			-			(8	)
Long-term commutation account		5,316			-			-			-			5,316
Amortization of long-term prepaid insurance		1,211			-			-			-			1,211
Increase in long-term accrued liabilities		416			8,893			-			-			9,309
Deferred charges and other		(420	)		(18,424	)		-			-			(18,844	)
Changes in components of working capital		19,089			(124,306	)		(80	)		(853	)		(106,150	)
Net cash provided by (used in) operating activities		(188,593	)		526,227			62			2,821			340,517

Cash flows from investing activities:
Additions to property, plant and equipment		(88	)		(126,794	)		-			(2,821	)		(129,703	)
El Dorado Refinery contingent earn-out payment		-			(7,500	)		-			-			(7,500	)
Proceeds from sale of assets		8			-			-			-			8
Net cash used in investing activities		(80	)		(134,294	)		-			(2,821	)		(137,195	)

Cash flows from financing activities:
Excess income tax benefits of stock-based compensation		8,881			-			-			-			8,881
Proceeds from issuance of common stock		3,672			-			-			-			3,672
Purchase of treasury stock		(98,950	)		-			-			-			(98,950	)
Dividends paid		(67,498	)		-			-			-			(67,498	)
Other		-			(13	)		-			-			(13	)
Intercompany transactions		313,260			(313,198	)		(62	)		-			-
Net cash provided by (used in) financing activities		159,365			(313,211	)		(62	)		-			(153,908	)
Increase in cash and cash equivalents		(29,308	)		78,722			-			-			49,414
Cash and cash equivalents, beginning of period		244,357			111,708			-			-			356,065
Cash and cash equivalents, end of period	$	215,049		$	190,430		$	-		$	-		$	405,479

FRONTIER OIL CORPORATION
Condensed Consolidating Statement of Cash Flows
For the Year Ended December 31, 2005 - As Adjusted (Note 3)
(in thousands)
	FOC (Parent)			FHI (Guarantor Subsidiaries)			Other Non-Guarantor Subsidiaries			Eliminations			Consolidated

Cash flows from operating activities:
Net income	$	275,158		$	289,413		$	90		$	(289,503	)	$	275,158
Adjustments to reconcile net income to net cash from operating activities:
Equity in earnings of subsidiaries		(462,027	)		-			-			462,027			-
Cumulative effect of accounting change, net of income taxes		(1,530	)		2,503			-			1,530			2,503
Depreciation and amortization		69			48,033			-			(556	)		47,546
Deferred income taxes		30,259			-			-			-			30,259
Income taxes eliminated in consolidation		-			171,237			-			(171,237	)		-
Deferred finance cost amortization		483			302			-			-			785
Stock-based compensation expense		1,363			-			-			-			1,363
Gains on sales of assets		(3	)		(3,641	)		-			-			(3,644	)
Long-term commutation account		3,832			-			-			-			3,832
Amortization of long-term prepaid insurance		1,211			-			-			-			1,211
Increase in long-term accrued liabilities		698			3,775									4,473
Deferred charges and other		(206	)		(17,110	)		-			-			(17,316	)
Changes in components of working capital		32,645			(18,478	)		-			-			14,167
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 Refinery 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 - As Adjusted (Note 3)
(in thousands)
	FOC (Parent)			FHI (Guarantor Subsidiaries)			Other Non-Guarantor Subsidiaries			Eliminations			Consolidated

Cash flows from operating activities:
Net income	$	69,392		$	101,599		$	62			($101,661	)	$	69,392
Adjustments to reconcile net income to net cash from operating activities:
Equity in earnings of subsidiaries		(164,392	)		-			-			164,392			-
Depreciation and amortization		75			45,732			-			(555	)		45,252
Deferred income taxes		24,731			-			-			-			24,731
Income taxes eliminated in consolidation		-			62,136			-			(62,136	)		-
Deferred finance cost and bond discount amortization		5,180			304			-			-			5,484
Stock-based compensation expense		1,180			-			-			-			1,180
Gain on involuntary conversion of assets		-			(4,411	)		-			-			(4,411	)
Long-term commutation account		3,712			-			-			-			3,712
Amortization of long-term prepaid insurance		1,451			-			-			-			1,451
Increase (decrease) in long-term accrued liabilities		(2,207	)		2,638			-			-			431
Deferred charges and other		2,789			(10,844	)		-			-			(8,055	)
Changes in components of working capital		(496	)		39,231			(3	)		-			38,732
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

14. Selected Quarterly Financial and Operating Data

As adjusted, except for the fourth quarter of 2006 (3)
(Dollars in thousands, except per share and per bbl)
	2006								2005
Unaudited	Fourth		Third		Second		First		Fourth			Third		Second		First
Revenues	$	1,087,267	$	1,381,127	$	1,315,366	$	1,012,193	$	1,150,315		$	1,185,927	$	972,280	$	692,640
Operating income		75,486		180,762		226,355		91,591		103,466			178,656		108,145		59,746
Cumulative effect of accounting change		-		-		-		-		(2,503	)		-		-		-
Net income		52,434		123,626		145,864		57,353		63,043			110,148		66,243		35,724
Basic earnings per share:
Before cumulative effect of accounting change		0.48		1.11		1.30		0.51		0.58			0.98		0.60		0.33
Cumulative effect of accounting change		-		-		-		-		(0.02	)		-		-		-
Net income		0.48		1.11		1.30		0.51		0.56			0.98		0.60		0.33
Diluted earnings per share:
Before cumulative effect of accounting change		0.47		1.10		1.29		0.51		0.57			0.96		0.58		0.32
Cumulative effect of accounting change		-		-		-		-		(0.02	)		-		-		-
Net income		0.47		1.10		1.29		0.51		0.55			0.96		0.58		0.32
Refining operations:
Total charges (bpd) (1)		173,613		175,907		171,426		166,202		175,589			176,566		171,316		150,580
Gasoline yields (bpd) (2)		83,283		79,298		79,817		83,564		92,850			85,827		88,306		67,006
Diesel and jet fuel yields (bpd) (2)		60,950		62,137		54,857		52,627		57,926			55,409		58,060		49,111
Total product sales (bpd)		174,252		174,803		173,642		164,661		181,437			177,196		176,514		145,911
Average gasoline crack spread (per bbl)	$	7.96	$	18.38	$	20.92	$	9.22	$	8.59		$	18.11	$	12.50	$	7.28
Average diesel crack spread (per bbl)		20.21		26.21		23.49		15.51		24.69			18.38		15.51		9.92
Cheyenne average light/heavy crude oil differential (per bbl)		14.35		16.30		15.19		18.99		18.11			14.93		14.15		14.10
Average WTI/WTS crude oil differential (per bbl)		4.84		4.69		5.04		6.44		5.56			3.13		4.67		4.68

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

(2)	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.

(3)

During the fourth quarter of 2006, the Company adopted a change in accounting method for the costs for turnarounds from the accrual method to the deferral method. The new method of accounting for turnarounds was in order to adhere to FSP No. AUG AIR-1 “Accounting for Planned Major Maintenance Activities” which prohibits the accrual method of accounting for planned major maintenance activities. The Company elected to early adopt the FSP. See Note 3 in the “Notes to the Consolidated Financial Statements” for further information. The following consolidated financial statement line items for each of the quarters 2005 and the first three quarters of 2006 were affected by the change in accounting principle.

	2006
Unaudited	Third Quarter						Second Quarter
	As Originally Reported		As Adjusted		Change		As Originally Reported		As Adjusted		Change
	(in thousands, except per share amounts)
Operating income	$	176,501	$	180,762	$	4,261	$	222,291	$	226,355	$	4,064
Net income		120,884		123,626		2,742		143,342		145,864		2,522
Basic earnings per share		1.09		1.11		0.02		1.28		1.30		0.02
Diluted earnings per share		1.08		1.10		0.02		1.26		1.29		0.03

Unaudited	First Quarter 2006
	As Originally Reported		As Adjusted		Change
	(in thousands, except per share amounts)
Operating income	$	92,021	$	91,591	$	(430	)
Net income		57,620		57,353		(267	)
Basic earnings per share		0.51		0.51		-
Diluted earnings per share		0.51		0.51		-

	2005
Unaudited	Fourth Quarter						Third Quarter
	As Originally Reported		As Adjusted		Change		As Originally Reported		As Adjusted		Change
	(in thousands, except per share amounts)
Operating income	$	103,408	$	103,466	$	58	$	177,250	$	178,656	$	1,406
Net income		62,950		63,043		93		109,185		110,148		963
Basic earnings per share		0.56		0.56		-		0.98		0.98		-
Diluted earnings per share		0.55		0.55		-		0.95		0.96		0.01

	2005
Unaudited	Second Quarter						First Quarter
	As Originally Reported		As Adjusted		Change		As Originally Reported		As Adjusted		Change
	(in thousands, except per share amounts)
Operating income	$	107,688	$	108,145	$	457	$	57,663	$	59,746	$	2,083
Net income		65,961		66,243		282		34,436		35,724		1,288
Basic earnings per share		0.60		0.60		-		0.32		0.33		0.01
Diluted earnings per share		0.58		0.58		-		0.31		0.32		0.01

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, and that such information is accumulated and communicated to management, including the Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. Management necessarily applies its judgment in assessing the costs and benefits of such controls and procedures, which, by their nature, can provide only reasonable assurance regarding management's control objectives.

As of the end of the period covered by this report, we evaluated, under the supervision and with the participation of our management, including our 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.

Our “Management’s Report on Internal Control Over Financial Reporting” and the related “Report of Independent Registered Public Accounting Firm” on our report are include on pages 29 and 30.

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

Reports of Independent Registered Public Accounting Firm

Management’s Report on Internal Controls

Consolidated Statements of Income

Consolidated Balance Sheets

Consolidated Statements of Cash Flows

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

Notes to Consolidated Financial Statements

(a)2. Financial Statements Schedules

Schedule I - Condensed Financial Information of Registrant

Schedule II - Valuation and Qualifying Accounts

Other Schedules are omitted because of the absence of the conditions under which they are required or because the required information is included in the financial statements or notes thereto.

(a)3. List of Exhibits

2.1

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

3.1

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

3.2

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

3.3

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

3.4

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

3.5

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

3.6

Articles of Amendment to the Restated Articles of Incorporation of Frontier Oil Corporation dated June 12, 2006 (Exhibit 3.1 to Form 8-K, File Number 1-07627, filed June 15, 2006).

3.7

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).

* 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

Executive Change in Control Severance Agreement, effective December 30, 2005, between the Company and Leo J. Hoonakker (Exhibit 10.1 to Form 8-K, File Number 1-07627, filed March 9, 2006).

* ²

10.18

Executive Change in Control Severance Agreement, effective as of May 30, 2006, by and between the Company and W. Paul Eisman (Exhibit 10.1 to Form 8-K, filed May 31, 2006).

* ²

10.19

Form of Executive Severance Agreement, effective as of May 30, 2006, by and between the Company and each of James R. Gibbs, W. Paul Eisman, Michael C. Jennings, Doug S. Aron, J. Currie Bechtol, Gerald B. Faudel, Jon D. Galvin, Nancy J. Zupan, Leo J. Hoonakker, Penny S. Newmark, Lloyd J. Nordhausen, Kent A. Olsen, Joel W. Purdy, Billy N. Rigby, and James M. Stump (Exhibit 10.2 to Form 8-K, File Number 1-07627, filed May 31, 2006).

10.20

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.

10.21

Master Crude Oil Purchase and Sale Contract, dated March 10, 2006, among Utexam Limited, Frontier Oil and Refining Company and the Company (Exhibit 10.1 to Form 8-K, File Number 1-07627, filed March 14, 2006).

10.22

Guaranty, dated March 10, 2006, by the Company in favor of Utexam Limited (Exhibit 10.2 to Form 8-K, File Number 1-07627, filed March 14, 2006).

10.23

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).

10.24

First Amendment to S econd Amended and Restated Revolving Credit Agreement, dated February 3, 2006, by Frontier Oil and Refining Company, the Company, each of the financial institutions party thereto and Union Bank of California, N.A. (Exhibit 10.1 to Form 10-Q, File Number 1-07627, filed May 8, 2006).

10.25

Second Amendment to Second Amended and Restated Revolving Credit Agreement, dated March 10, 2006, by Frontier Oil and Refining Company, the Company, each of the financial institutions party thereto and Union Bank of California, N.A. (Exhibit 10.2 to Form 10-Q, File Number 1-07627, filed May 8, 2006).

* ²

10.26

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

* ²

10.27

Frontier Oil Corporation Omnibus Incentive Compensation Plan (Annex A to Proxy Statement, File Number 1-07627, filed March 21, 2006).

* ²

10.28

Form of Frontier Oil Corporation Omnibus Incentive Compensation Plan Stock Unit/Restricted Stock Agreement (Exhibit 4.8 to Form S-8, File Number 333-133595, filed April 27, 2006).

* ²

10.29

Form of Frontier Oil Corporation Omnibus Incentive Compensation Plan Nonqualified Stock Option Agreement (Exhibit 4.9 to Form S-8, File Number 333-133595, filed April 27, 2006).

* ²

10.30

Form of Non-Employee Director Restricted Stock Unit Grant Agreement (Exhibit 10.1 to Form 8-K, File Number 1-07627, filed April 7, 2006).

* ²

10.31

Form of First Amendment to Restricted Stock Unit Grant (Exhibit 10.1 to Form 10-Q, File Number 1-07627, filed August 7, 2006).

* ²

10.32

Form of Restricted Stock Agreement (Exhibit 10.2 to Form 8-K, File Number 1-07627, filed April 7, 2006).

* ²

10.33

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

* ²

10.34

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

10.35

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).

* ²

10.36

Separation Agreement and Release, effective as of March 7, 2006, between W. Reed Williams and the Company (Exhibit 10.1 to Form 8-K, File Number 1-07627, filed March 15, 2006).

* ²

10.37

Executive Retiree Medical Benefit Plan (Exhibit 10.3 to Form 10-Q, File Number 1-07627, filed May 8, 2006).

* ²

10.38

Management Incentive Compensation Plan for 2006 (Exhibit 10.1 to Form 8-K, File Number 1-07627, filed February 28, 2007).

10.39

Summary of Compensation for Non-Employee Directors.

10.40

Summary of Compensation for Executive Officers.

10.41

Form of Indemnification Agreement by and between the Company and each of its officers and directors.

Subsidiaries of the Registrant.

Consent of Deloitte & Touche LLP.

31.1

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

31.2

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

32.1

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

32.2

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

* Asterisk indicates exhibits incorporated by reference as shown .

² Diamond indicates management contract or compensatory plan or arrangement.

(b)

Exhibits

The Company’s 2007 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 Sheets


	Schedule I
	December 31,
	2006		2005 As Adjusted (Note 3)
ASSETS	(in thousands)
Current assets:
Cash and cash equivalents	$	215,049	$	244,357
Trade and other receivables		1,363		6,381
Deferred tax assets		3,237		2,004
Other current assets		2,082		499
Total current assets		221,731		253,241
Property, plant and equipment, at cost:
Furniture, fixtures and other		1,301		1,235
Less - accumulated depreciation		1,054		988
		247		247
Deferred financing costs, net		2,293		2,775
Commutation account		7,290		12,606
Prepaid insurance, net		2,120		3,331
Other assets		2,734		2,508
Investment in subsidiaries		831,082		537,947

Total assets	$	1,067,497	$	812,655

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Contingent income tax liabilities	$	28,271	$	21,517
Accounts payable		1,436		2,480
Accrued interest		2,484		2,485
Accrued dividends		3,486		58,726
Accrued liabilities and other		7,924		5,336
Total current liabilities		43,601		90,544

Long-term debt		150,000		150,000
Deferred compensation liability		2,630		2,214
Deferred income taxes		93,907		86,460
Payable to affiliated companies		1,505		4,745

Shareholders’ equity		775,854		478,692

Total liabilities and shareholders’ equity	$	1,067,497	$	812,655

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,
	2006			2005 As Adjusted (Note 3)			2004 As Adjusted (Note 3)
	(in thousands)

Revenues	$	4		$	(6	)	$	(6	)
		4			(6	)		(6	)
Costs and expenses:
Selling and general expenses, excluding depreciation		30,194			14,681			15,590
Merger termination and legal costs		-			48			3,824
Depreciation		88			69			75
Gain on sale of assets		(8	)		(3	)		-
		30,274			14,795			19,489

Operating income		(30,270	)		(14,801	)		(19,495	)

Interest expense and other financing costs		11,978			10,593			35,004
Interest and investment income		(12,102	)		(5,905	)		(1,545	)
Equity in earnings of subsidiaries		(609,265	)		(462,027	)		(164,392	)
		(609,389	)		(457,339	)		(130,933	)

Income before income taxes		579,119			442,538			111,438
Provision for income taxes		199,842			168,910			42,046

Income before cumulative effect of accounting change		379,277			273,628			69,392
Income tax benefit for cumulative effect of accounting change		-			1,530			-
Net income	$	379,277		$	275,158		$	69,392

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,
	2006			2005 As Adjusted (Note 3)			2004 As Adjusted (Note 3)
	(in thousands)
Operating Activities
Net income	$	379,277		$	275,158		$	69,392
Equity in earnings of subsidiaries		(609,265	)		(462,027	)		(164,392	)
Cumulative effect of accounting change, net of income taxes		-			(1,530	)		-
Depreciation		88			69			75
Deferred income taxes		6,073			30,259			24,731
Stock-based compensation expense		18,029			1,363			1,180
Excess income tax benefits of stock-based compensation		(8,881	)		-			-
Deferred finance cost and bond discount amortization		482			483			5,180
Long-term commutation account		5,316			3,832			3,712
Amortization of long-term prepaid insurance		1,211			1,211			1,451
Increase (decrease) in long-term accrued liabilities		416			698			(2,207	)
Other		(428	)		(209	)		2,789
Changes in components of working capital		19,089			32,645			(496	)
Net cash used by operating activities		(188,593	)		(118,048	)		(58,585	)

Investing Activities
Additions to property, plant and equipment		(88	)		(143	)		(3	)
Proceeds from sale of assets		8			3			-
Net cash used by investing activities		(80	)		(140	)		(3	)

Financing Activities
Proceeds from issuance of common stock		3,672			23,616			3,923
Purchase of treasury stock		(98,950	)		(34,819	)		(3,029	)
Dividends paid to shareholders		(67,498	)		(7,776	)		(5,664	)
Intercompany transactions, net		(3,240	)		4,215			(202	)
Dividends received from subsidiaries		316,500			272,000			132,851
Excess income tax benefits of stock-based compensation		8,881			-			-
Debt issue costs		-			(100	)		(3,279	)
Proceeds from issuance of 6.625% Senior Notes		-			-			150,000
Repurchases of 11.75% Senior Notes		-			-			(170,449	)
Net cash provided by financing activities		159,365			257,136			104,151

Increase (decrease) in cash and cash equivalents		(29,308	)		138,948			45,563
Cash and cash equivalents, beginning of period		244,357			105,409			59,846

Cash and cash equivalents, end of period	$	215,049		$	244,357		$	105,409

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)
2006
Allowance for doubtful accounts	$	500	$	26	$	26	$	500

2005
Allowance for doubtful accounts		500		-		-		500

2004
Allowance for doubtful accounts		500		-		-		500
Valuation allowance on deferred tax assets		1,555		-		1,555		-

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: February 28, 2007

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: February 28, 2007

Exhibit 10.39

Summary of Compensation for Non-Employee Directors

Effective January 1, 2007

Annual Board Retainer	$ 40,000
Board Meeting Fee	$ 1,500 per meeting attended
Committee Chair Annual Retainer
Audit/Compensation	$ 15,000
Committee Chair Annual Retainer
Other Committees	$ 5,000
Committee Meeting Fee	$ 1,500 per meeting attended
Annual Equity Grant (1)	$ 125,000

Exhibit 10.40

Summary of Compensation for Executive Officers

The executive officers of Frontier Oil Corporation (“Frontier”) are “at will” employees, and none of them has an employment agreement. The unwritten arrangements under which Frontier’s executive officers are compensated include:

·	a salary, reviewed annually by the Compensation Committee of the Board of Directors of Frontier;

·	eligibility for an annual cash bonus, as determined by the Compensation Committee;

·	eligibility for awards under Frontier’s Omnibus Incentive Compensation Plan, as determined by the Compensation Committee;

·	health, life, disability, death and other insurance and/or benefits;

·	defined contribution pension and savings plan; and

·	vacation, paid sick leave and all other employee benefits.

In addition, each of the executive officers of Frontier have entered into an Executive Change in Control Severance Agreement and an Executive Severance Agreement. Messrs. Gibbs, Eisman and Jennings also participate in an Executive Retiree Medical Benefit Plan.

The table below sets forth the base salaries, effective as of January 1, 2007, for the executive officers of Frontier who held office as of January 1, 2007, as well as their incentive target for 2007 (as a percentage of base salary).

Executive Officer	2007 Annual Base Salary	Incentive Target for 2007 (Percentage of Base Salary)
James R. Gibbs Chairman of the Board, Chief Executive Officer and President	$885,000	100%
Michael C. Jennings Executive Vice President-Chief Financial Officer	$415,000	70%
W. Paul Eisman Executive Vice President-Refining & Marketing	$430,000	70%
Jon D. Galvin Vice President	$280,000	50%
Nancy J. Zupan Vice President-Controller	$280,000	50%
J. Currie Bechtol Vice President-General Counsel & Secretary	$300,000	50%
Gerald B. Faudel Vice President-Corporate Relations and Environmental Affairs	$220,000	40%
Doug S. Aron Vice President-Corporate Finance	$185,000	40%

Exhibit 10.41

INDEMNIFICATION AGREEMENT

This INDEMNIFICATION AGREEMENT (“Agreement”), effective as of ___________, is by and between Frontier Oil Corporation, a Wyoming corporation (“Company”), and the undersigned individual (“Individual”).

WITNESSETH:

WHEREAS, Company desires to indemnify Individual against certain losses in order to induce Individual to continue to serve as a director or officer of Company or of an affiliate of the Company (“Company Affiliate” which for purposes hereof shall mean any company or entity that directly or indirectly controls, is controlled by or is under common control with the Company);

NOW, THEREFORE, in consideration of the premises and the mutual benefits to be derived, the parties agree as follows:

1. Third Party Proceedings . Company shall indemnify any Individual who was or is party to or is threatened to be made party to any threatened, pending or completed action, suit, or proceeding, whether civil, criminal, administrative, or investigative, whether formal or informal, any appeal in such action, suit or proceeding, and any inquiry or investigation that could lead to such an action, suit or proceeding, (other than an action by or in the right of Company or a Company Affiliate), (i) by reason of the fact that Individual is or was a director or officer of Company or a Company Affiliate or advisory director or officer of Company or Company Affiliate, (ii) by reason of the activities of Individual in such capacity, including without limitation by reason of serving at the request of Company or a Company Affiliate as a director, officer, partner, venturer, proprietor, trustee, employee, agent, or similar functionary of another foreign or domestic corporation, partnership, joint venture, trust, employee benefit plan, or other enterprise, or (iii) any person nominated or designated by (or pursuant to authority granted by) the board of directors or any committee thereof to serve in any of the capacities referred to in clauses (i) and (ii) hereof, against any and all reasonable expenses (including court costs and attorneys' fees), judgments, penalties, fines, and reasonable amounts paid in settlement (if such settlement is approved in advance by a majority of the directors of Company then in office, with a view to curtailment of the costs of litigation) actually incurred by Individual in connection with or in anticipation of such action, suit, or proceeding, if he conducted himself in good faith and in a manner which he reasonably believed to be in or not opposed to the best interests of Company and any Company Affiliate and, with respect to any criminal action or proceeding, that he had no reasonable cause to believe that his conduct was unlawful.

2. Proceedings By or in the Right of Company . Company shall indemnify Individual if Individual was or is a party or is threatened to be made a party to any threatened, pending or completed action or suit by or in the right of Company or a Company Affiliate to procure a judgment in its favor by reason of the fact that Individual is or was an officer or director of Company or a Company Affiliate, or by reason of any action or inaction on the part of Individual while an officer or director of Company or a Company Affiliate, or by reason of the fact that Individual is or was serving at the request of Company or a Company Affiliate as a director, officer, employee or agent of another domestic or foreign corporation, partnership, joint venture, trust or other enterprise against expenses (including court costs and attorneys' fees) and, to the fullest extent permitted by law, amounts paid in settlement, in each case to the extent actually and reasonably incurred by Individual in connection with the defense or settlement of such action or suit if Individual conducted himself in good faith and in a manner Individual reasonably believed to be in or not opposed to the best interests of Company, the Company Affiliate and their shareholders, except that no indemnification shall be made in respect of any claim, issue or matter as to which Individual shall have been adjudged by a court of competent jurisdiction, after exhaustion of all appeals therefrom, to be liable to Company or a Company Affiliate in the performance of Individual's duty to Company, the Company Affiliate and their shareholders unless and only to the extent that the court in which such action or suit is or was pending, or other court of competent jurisdiction, shall determine upon application that, in view of all the circumstances of the case, Individual is fairly and reasonably entitled to indemnity for expenses and then only to the extent that the court shall determine.

For purposes of section 1 and 2, the termination of any action, suit, or proceeding by judgment, order, settlement, conviction, or upon a plea of nolo contendere or its equivalent, is not of itself determinative that Individual did not conduct himself in good faith and in a manner which he reasonably believed to be in or not opposed to the best interests of Company or a Company Affiliate or, with respect to any criminal action or proceeding, that he had reasonable cause to believe that his conduct was unlawful.

3. Payments . Upon written request by Individual submitted to Company in accordance with this section 3, Company shall pay Individual all amounts he is entitled to receive pursuant to section 1 or 2 (“Indemnified Amounts”). Each written request for payment shall include an itemized list setting forth in detail the dollar amounts expended (or incurred and expected to be expended), shall be supported by copies of the relevant bills, agreements, and other documentation, and shall state that he conducted himself in good faith and in a manner which he reasonably believed to be in or not opposed to the best interests of Company or any Company Affiliate and, with respect to a criminal action or proceeding, that he had no reasonable cause to believe that his conduct was unlawful.

4. Selection of Counsel . In the event of the commencement or threat of commencement of any action, suit or proceeding for which Individual may be entitled to indemnification hereunder, Company shall have the right to select counsel for Individual; provided that counsel selected by Company to represent Individual (i) shall have a national reputation in handling matters similar to the matter that is the subject of the indemnification and (ii) shall advise Individual that, in such counsel's opinion, the representation by such counsel of other parties that may have an interest in the matter that is the subject of the indemnification does not present a conflict of interest. In the event counsel selected by the Company to represent Individual at any time cannot, during the course of representation of Individual, continue to advise Individual as provided in clause (ii) of the proviso of the foregoing sentence, then Individual may select his own counsel, whose expenses shall be advanced and indemnified as provided in this Agreement. Nothing in this Section 4 shall limit the ability of the Individual to engage separate counsel in connection with the indemnified matter at the expense of the Individual.

5. Advancement of Indemnified Amounts . (a) Company shall pay Indemnified Amounts in advance of the final disposition of the related action, suit, or proceeding, upon written request by Individual submitted to Company, within 30 days of receipt of such request. Each such request shall include (i) an affirmation by Individual of his good faith belief that he has met the standard of conduct necessary for indemnification by Company as stated in sections 1 and 2, (ii) an itemized list and the supporting documentation described in section 3(a) and (iii) an undertaking by Individual, or on his behalf, to repay the Indemnified Amount if Individual ultimately is found not to be entitled to indemnification pursuant to section 1 or 2. Individual may make as many requests for advancements as he deems reasonably necessary, except that each such request shall be for an Indemnified Amount of at least $3,000.

(b) Unless Individual ultimately is found not to be entitled to indemnification pursuant to section 1 or 2, Individual later may request payment of the portion of the Indemnified Amounts which exceeds the advancements received pursuant to section 5(a) by following the procedure described in section 3. In such a case, the itemized list with respect to such request shall set forth each and every advancement received as of the date of such request. Conversely, if the total of the advancements received by Individual as of the date of his request exceeds the total of the Indemnified Amounts, then Individual shall repay such excess promptly upon the determination of the amount thereof.

6. Exceptions . Any other provision herein to the contrary notwithstanding, Company shall not be obligated pursuant to the terms of this Agreement:

(a) Claims Initiated by Individual . To indemnify or advance expenses to Individual with respect to proceedings or claims initiated or brought voluntarily by Individual and not by way of defense, except with respect to proceedings brought in Company's or a Company Affiliate's name or behalf, or to establish or enforce a right to indemnification under this agreement or any other statute or law; or

(b) Lack of Good Faith . To indemnify Individual for any expenses incurred by Individual with respect to any proceeding instituted by Individual to enforce or interpret this Agreement, if a court of competent jurisdiction determines that the material assertions made by the Individual in such proceeding were not made in good faith or were frivolous; or

(c) Insured Claims . To indemnify Individual for expenses or liabilities of any type whatsoever (including, but not limited to, judgments, fines, ERISA excise taxes or penalties, and amounts paid in settlement) which have been paid directly to Individual by an insurance carrier under a policy of officers' and directors' liability insurance maintained by Company or a Company Affiliate; or

(d) Claims Under Section 16(b) . To indemnify Individual for expenses and the payment of profits arising from purchases and sales by Individual of securities in violation of Section 16(b) of the Securities and Exchange Act of 1934, as amended, or any similar successor statute.

7. Indemnification Not Exclusive; Subrogation Rights . (a) The indemnification provided by sections 1 and 2 shall not be deemed exclusive of, or to preclude, any other rights to which Individual may be entitled under the common law or any, statute, ordinance, regulation, agreement, article of incorporation, bylaw provision, partnership agreement, vote of shareholders or disinterested directors, or otherwise, both as to the activities of Individual in his capacity as a director or officer of Company or any Company Affiliate and as to his activities in another capacity while serving in such position, and shall continue as to Individual after he ceases to be a director or officer of Company or any Company Affiliate.

(b) If Individual receives any payments from an insurance carrier, or from the plaintiff in any action, suit, or proceeding against Individual, in respect of Indemnified Amounts after payments of all or a portion of such Indemnified Amounts have been made by Company pursuant hereto, Individual shall repay the amount by which the sum of the payments by such insurance carrier or plaintiff and the payments by Company exceeds the Indemnified Amounts; provided, however, that any portion of such payments that is required to be paid to the insurance carrier under the terms of its insurance policy shall not be deemed to be payments to Individual hereunder.

(c) Upon payment of Indemnified Amounts hereunder, Company shall be subrogated to the rights of Individual (to the extent thereof) against any insurance carrier in respect of such Indemnified Amounts (to the extent permitted under such insurance policies). This right of subrogation shall terminate upon receipt by Company of the amount to be paid by Individual pursuant to section 7(b).

8. Successors; Binding Agreement . This Agreement shall inure to the benefit of and be enforceable by the personal and legal representatives, executors, administrators, successors, heirs, distributees, devisees, and legatees of Individual. If Individual dies while any Indemnified Amounts are payable hereunder, such Indemnified Amounts shall be paid in accordance with the terms of this Agreement to the devisee, legatee, or other designee of the Individual, or if there is no such designee, to his estate.

9. Enforcement . (a) If either party to this Agreement is required to bring any action against the other to enforce their respective rights or to collect moneys due under this Agreement and is successful in such action, such successful party shall be reimbursed by the other party for any and all reasonable expenses (including court costs and attorneys' fees) actually incurred by such successful party in bringing and pursuing such action, in addition to any other damages to which such party is entitled.

(b) The invalidity or unenforceability of any provision of this Agreement shall not affect the validity or enforceability of any other provision of this Agreement, which shall remain in full force and effect. If any provision of this Agreement shall be invalid or unenforceable, such invalidity or unenforceability shall not create a damage claim against the Company.

10. Amendment; Waiver . No provision of this Agreement may be amended, modified, waived, or discharged unless such amendment, waiver, modification, or discharge is agreed to in writing by Individual and either the president of Company or another duly authorized officer of Company. No waiver by a party of any breach by the other party of, or of any compliance by the other party with, any condition or provision of this Agreement shall be deemed a waiver of similar or dissimilar conditions or provisions at the same time or at any prior or subsequent time.

11. Entire Agreement . This Agreement constitutes the entire agreement between the parties concerning, the subject matter hereof. This Agreement further supersedes any prior agreements between the parties concerning the subject matter hereof. No agreements or representations, oral or written, express or implied, other than those set forth herein have been made by either party with respect to the subject matter hereof.

12. Authority . This Agreement is entered into in accordance with Section 7.7 of the Bylaws of Company.

13. Governing Law . This Agreement shall be governed by the laws of the State of Wyoming.

14. Counterparts . This Agreement may be executed in one or more counterparts, each of which shall be deemed to be an original but all of which together shall constitute one and the same instrument.

IN WITNESS WHEREOF, the parties have executed this Agreement as of the day of ____ day of _______, ______.

	FRONTIER OIL CORPORATION

	By: __________________________________
	Name:
	Title:


	__________________________________________
	Officer/Director

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.

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. 333-59290 on Form S-8, Registration Statement No. 333-120643 on Form S-4, Registration Statement No. 333-130292 on Form S-3ASR, and Registration Statement No. 333-133595 on Form S-8 of our reports dated February 26, 2007, relating to the financial statements and financial statement schedules of Frontier Oil Corporation (which included explanatory paragraphs regarding the Company’s adoption of Financial Accounting Standards Board (“FASB”) Interpretation No. 47, “Accounting for Conditional Asset Obligations,” FASB Staff Position No. AUG AIR-1, “Accounting for Planned Major Maintenance Activities”, Statement of Financial Accounting Standards (“SFAS”) No. 123(R), “Share-Based Payment”, and SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans,” and management’s report on the effectiveness of internal control over financial reporting appearing in the Annual Report on Form 10-K of Frontier Oil Corporation for the year ended December 31, 2006.

DELOITTE & TOUCHE LLP

Houston, Texas

February 2 6, 2007

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;

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:

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;

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;

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

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

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.

February 28, 2007

/s/ James R. Gibbs

James R. Gibbs

Chairman of the Board, President

and Chief Executive Officer

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;

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:

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;

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

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.

February 28, 2007

/s/ Michael C. Jennings

Michael C. Jennings

Executive Vice President -

Chief Financial Officer

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, 2006 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

February 28, 2007

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, 2006 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

February 28, 2007