10-K 1 form10k.htm FORM 10-K Form 10-K


 
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.
 
 
 
 
 
 
 
 
Item 1A.
Item 1B.
Item 2.
Item 3.
Item 4.
   
 
   
Part II
 
Item 5.
 
Item 6.
Item 7.
Item 7A.
Item 8.
Item 9.
Item 9A.
Item 9B.
   
 
   
Part IV
 
Item 15
 
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
 
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.
 
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.

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.
 
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.
 
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.
 
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.
 

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.
 
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.


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.


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.”


None.
 
We file reports with the SEC, including annual reports on Form 10-K, quarterly reports on Form 10-Q and other reports from time to time. The public may read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Room 1580, Washington, DC, 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. We are an electronic filer, and the SEC’s Internet site at http://www.sec.gov contains the reports, proxy and information statements, and other information filed electronically.
As required by Section 402 of the Sarbanes-Oxley Act of 2002, we have adopted a code of ethics that applies to our chief executive officer, chief financial officer and principal accounting officer. This code of ethics is posted on our web site. Our web site address is: http://www.frontieroil.com. We make our web site content available for informational purposes only. It should not be relied upon for investment purposes, nor is it incorporated by reference in this Form 10-K. We make available on this web site under “Investor Relations,” free of charge, our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports as soon as reasonably practicable after we electronically file those materials with, or furnish those materials to, the SEC.
We filed our 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


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




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




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



 
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.

 




 
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.



 
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.



 

 
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