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, 2005
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, 2005 was $1.6 billion.
 
The number of shares of common stock outstanding as of February 22, 2006 was 56,195,790.
 
DOCUMENTS INCORPORATED BY REFERENCE
 
Portions of the Annual Proxy Statement for the registrant’s 2006 annual meeting of shareholders are incorporated by reference into Items 10 through 14 of Part III.
 

 

TABLE OF CONTENTS
 
 Part I  
 Item 1.  Business
 
 
 
 
 
 
 
 
 Item 1A.  Risk Factors Relating to Our Business
 Item 1B.  Unresolved Staff Comments
 Item 2.  Properties
 Item 3.  Legal Proceedings
 Item 4.  Submission of Matters to a Vote of Security Holders
 
 
 
 Part II  
 Item 5.  Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchasers of Equity Securities
 Item 6.  Selected Financial Data
 Item 7.  Management’s Discussion and Analysis of Financial Condition and Results of Operations
 Item 7A.  Quantitative and Qualitative Disclosures About Market Risk
 Item 8.  Financial Statements and Supplementary Data
 Item 9.  Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
 Item 9A.  Controls and Procedures
 Item 9B.  Other Information
 Part III  
 Part IV  
 Item 15.  Exhibits and Financial Statement Schedules
 
  
 
Forward-Looking Statements
This Form 10-K contains “forward-looking statements” as defined by the Securities and Exchange Commission (“SEC”). Such statements are those concerning contemplated transactions and strategic plans, expectations and objectives for future operations. These include, without limitation:
·  
statements, other than statements of historical fact, that address activities, events or developments that we expect, believe or anticipate will or may occur in the future;
·  
statements relating to future financial performance, future capital sources and other matters; and
·  
any other statements preceded by, followed by or that include the words “anticipates,” “believes,” “expects,” “plans,” “intends,” “estimates,” “projects,” “could,” “should,” “may,” or similar expressions.
Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this Form 10-K are reasonable, we can give no assurance that such plans, intentions or expectations will be achieved. These statements are based on assumptions made by us based on our experience and perception of historical trends, current conditions, expected future developments and other factors that we believe are appropriate in the circumstances. Such statements are subject to a number of risks and uncertainties, many of which are beyond our control. You are cautioned that any such statements are not guarantees of future performance and that actual results or developments may differ materially from those projected in the forward-looking statements.
All forward-looking statements contained in this Form 10-K only speak as of the date of this document. We undertake no obligation to update or revise publicly any revisions to any such forward-looking statements that may be made to reflect events or circumstances after the date of this Form 10-K, or to reflect the occurrence of unanticipated events.
 
 
 
 
The terms “Frontier,” “we,” “us” and “our” as used in this Form 10-K refer to Frontier Oil Corporation and its subsidiaries, except where it is clear that those terms mean only the parent company. When we use the term “Rocky Mountain region,” we refer to the states of Colorado, Wyoming, Montana and Utah, and when we use the term “Plains States,” we refer to the states of Kansas, Oklahoma, Nebraska, Iowa, Missouri, North Dakota and South Dakota.
 
Overview
We are an independent energy company engaged in crude oil refining and the wholesale marketing of refined petroleum products. We operate refineries (the “Refineries”) in Cheyenne, Wyoming and El Dorado, Kansas with a total annual average crude oil capacity of 162,000 barrels per day (“bpd”). Both of our Refineries are complex refineries, which means that they can process heavier, less expensive types of crude oil and still produce a high percentage of gasoline, diesel fuel and other high margin refined products. We focus our marketing efforts in the Rocky Mountain region and the Plains States, which we believe are among the most attractive refined products markets in the United States. The operations of refining and marketing of petroleum products are considered part of one reporting segment.
Cheyenne Refinery. Our Cheyenne Refinery has a permitted crude capacity of 52,000 bpd on a twelve-month average. We market its refined products primarily in the eastern slope of the Rocky Mountain region, which encompasses eastern Colorado (including the Denver metropolitan area), eastern Wyoming and western Nebraska (the “Eastern Slope”). The Cheyenne Refinery has a coking unit, which allows the refinery to process extensive amounts of heavy crude oil for use as a feedstock. The ability to process heavy crude oil lowers our raw material costs because heavy crude oil is generally less expensive than lighter types of crude oil. For the year ended December 31, 2005, heavy crude oil constituted approximately 82% of the Cheyenne Refinery’s total crude oil charge. For the year ended December 31, 2005, the Cheyenne Refinery’s product yield included gasoline (43%), diesel fuel (30%) and asphalt and other refined petroleum products (27%).
El Dorado Refinery. The El Dorado Refinery is one of the largest refineries in the Plains States and the Rocky Mountain region with a crude capacity of 110,000 bpd. The El Dorado Refinery can select from many different types of crude oil because of its direct access to Cushing, Oklahoma, which is connected by pipeline to the Gulf Coast, and starting in 2006, to Canada. This access, combined with the El Dorado Refinery’s complexity (including a coking unit), gives it the flexibility to refine a wide variety of crude oils. In connection with our acquisition of the El Dorado Refinery in late 1999, we entered into a 15-year refined product offtake agreement for gasoline and diesel production at this refinery with Shell Oil Products US (“Shell”). Shell will also purchase all jet fuel production until the end of the product offtake agreement. As our deliveries to Shell under the refined product offtake agreement have declined, we have marketed an increasing portion of the El Dorado Refinery’s gasoline and diesel in the same markets where Shell currently sells the El Dorado Refinery’s products, primarily in Denver and throughout the Plains States. For the year ended December 31, 2005, the El Dorado Refinery’s product yield included gasoline (55%), diesel and jet fuel (35%) and chemicals and other refined petroleum products (10%).
Other Assets. We also own a 34.72% interest in a crude oil pipeline in Wyoming and a 50% interest in two crude oil tanks in Guernsey, Wyoming.
 
Varieties of Crude Oil and Products. Traditionally, crude oil has been classified within the following types:
·  
sweet (low sulfur content),
·  
sour (high sulfur content),
·  
light (high gravity),
·  
heavy (low gravity) and
·  
intermediate (if gravity or sulfur content is in between).
For the most part, heavy crude oil tends to be sour and light crude oil tends to be sweet. When refined, light crude oil produces a higher proportion of high margin refined products such as gasoline, diesel and jet fuel and as a result, is more expensive than heavy crude oil. In contrast, heavy crude oil produces more low margin by-products and heavy residual oils. The discount at which heavy crude oil sells compared to light crude oil is known in the industry as the light/heavy spread or differential. Coking units, such as the ones at our Refineries, can process certain by-products and heavy residual oils to produce additional volumes of gasoline and diesel, thus increasing the aggregate yields of higher margin refined products from the same initial volume of crude oil.
Refineries are frequently classified according to their complexity, which refers to the number, type and capacity of processing units at the refinery. Each of our refineries possesses a coking unit, which provides substantial upgrading capacity. Upgrading capacity refers to the ability of a refinery to produce high yields of high margin refined products such as gasoline and diesel from heavy and intermediate crude oil. In contrast, refiners with low upgrading capacity must process primarily light, sweet crude oil to produce a similar yield of gasoline and diesel. Some low complexity refineries may be capable of processing heavy and intermediate crude oil, but they will produce large volumes of by-products, including heavy residual oils and asphalt. Because gasoline, diesel and jet fuel sales generally achieve higher margins than are available on other refined products, we expect that these products will continue to make up the majority of our production.
Refinery Maintenance. Each of the operating units at our Refineries requires regular maintenance and repair shutdowns (referred to as “turnarounds”) during which the unit is not in operation. Turnaround cycles vary for different units but are generally required every one to five years. In general, turnarounds at our Refineries are managed so that some units continue to operate while others are down for scheduled maintenance. We also coordinate operations by staggering turnarounds between our two Refineries. Maintenance turnarounds are implemented using our regular personnel as well as additional contract labor. Once started, turnaround work typically proceeds 24 hours per day to minimize unit downtime. We accrue for our turnaround costs over the period from the prior turnaround to the next scheduled turnaround. We normally schedule our maintenance turnaround work during the spring or fall of each year. When we perform a turnaround, we may increase product inventories prior to the turnaround to minimize the impact of the turnaround on our sales of refined products.
During 2005 at the El Dorado Refinery, we had a major turnaround on the fluid catalytic cracking unit (“FCCU”) and installed a new main fractionator for the FCCU. In connection with the FCCU turnaround we also performed a turnaround on the FCCU gas oil hydrotreater. We have no major turnaround work scheduled for the El Dorado Refinery during 2006. However, an existing distillate hydrotreater will be revamped and loaded with new catalyst in preparation for the production of ultra-low sulfur diesel (“ULSD”). Also, construction of a new hydrogen manufacturing plant and a new distillate hydrotreater will be completed during the second quarter of 2006. Those units will be brought on-line and will complete plant modifications necessary to fully comply with the 2006 regulations pertaining to the production of ULSD. During 2005, the only turnaround at the Cheyenne Refinery was on the coker, which had an abbreviated work scope since we are expanding the unit and replacing all three drums in 2007. The major turnaround work to be performed at the Cheyenne Refinery during 2006 is on the alkylation plant. However, the distillate hydroteater unit at the Cheyenne Refinery will also be revamped in preparation for the production of ULSD, including the modification of an existing reactor and addition of a new reactor and furnace. The FCCU turnaround cycle for the Cheyenne Refinery has been deferred from 2006 to 2007 and will be performed concurrent with the crude unit turnaround and the coker expansion.
 
Cheyenne Refinery. The primary market for the Cheyenne Refinery’s refined products is the Eastern Slope. For the year ended December 31, 2005, we sold approximately 86% of the Cheyenne Refinery’s gasoline sales volumes in Colorado and 10% in Wyoming. For the year ended December 31, 2005, we sold approximately 30% of the Cheyenne Refinery’s diesel in Colorado and 62% in Wyoming. Because of the location of the Cheyenne Refinery, we are able to sell a significant portion of its diesel product from the truck rack at the Refinery, thereby eliminating transportation costs. The gasoline and remaining diesel produced by this Refinery are primarily shipped via pipeline to terminals for distribution by truck or rail. Pipeline shipments from the Cheyenne Refinery are handled mainly by the Rocky Mountain pipeline, serving Denver and Colorado Springs, Colorado, and the ConocoPhillips pipeline, serving Sidney, Nebraska.
We sell refined products from our Cheyenne Refinery to a broad base of independent retailers, jobbers and major oil companies. Refined product prices are determined by local market conditions at distribution centers known as “terminal racks.” The customer at a terminal rack typically supplies its own truck transportation. Prices at the terminal rack are posted daily by sellers. In the year ended December 31, 2005, approximately 85% of the Cheyenne Refinery’s sales were made to its 25 largest customers. Occasionally, marketing volumes exceed the Refinery’s production, in which case we purchase product in the spot market as needed.


El Dorado Refinery. The primary markets for the El Dorado Refinery’s refined products are Colorado and the Plains States, which include the Kansas City metropolitan area. The gasoline, diesel and jet fuel produced by the El Dorado Refinery are primarily shipped via pipeline to terminals for distribution by truck or rail. The Valero pipeline, serving the northern Plains States, the Magellan Pipeline Company, L.P. (“Magellan”) mountain pipeline serving Denver, Colorado, and the Magellan mid-continent pipeline serving the Plains States handle shipments from our El Dorado Refinery.
In connection with our late 1999 acquisition of the El Dorado Refinery, we entered into a 15-year refined product offtake agreement with Shell. For the year ended December 31, 2005, Shell was the El Dorado Refinery’s largest customer, representing 67% of total sales. Under the offtake agreement, Shell purchases gasoline, diesel and jet fuel produced by the El Dorado Refinery at market-based prices. Initially in 1999, Shell purchased all of the El Dorado Refinery’s production of these products. Beginning in 2000, we retained and marketed 5,000 bpd of the Refinery’s gasoline and diesel production. The retained portion is scheduled to increase by 5,000 bpd each year for ten years. In 2005, we retained 30,000 bpd of the Refinery’s gasoline and diesel production. Shell will continue to purchase all jet fuel production for the remainder of the original 15-year product offtake agreement term. As our sales to Shell under this agreement decrease, we intend to sell the gasoline and diesel produced by the El Dorado Refinery in the same general markets as Shell currently does, as described above.
 
Cheyenne Refinery. The most competitive market for the Cheyenne Refinery is the Denver metropolitan area. Other than the Cheyenne Refinery, three principal refineries serve the Denver market: a 70,000 bpd refinery near Rawlins, Wyoming and a 25,000 bpd refinery in Casper, Wyoming, both owned by Sinclair Oil Company (“Sinclair”); and a 90,000 bpd refinery located in Denver and owned by Suncor Energy (U.S.A.) Inc. (“Suncor”). Five product pipelines also supply Denver, including three from outside the region that enable refined products from other regions to be sold in the Denver market. Refined products shipped from other regions typically bear the burden of higher transportation costs.
The Suncor refinery located in Denver has lower product transportation costs to serve the Denver market than we do. However, the Cheyenne Refinery has lower crude oil transportation costs because of its proximity to the Guernsey, Wyoming hub, the major crude oil pipeline hub in the Rocky Mountain region, and because of our ownership interest in the Centennial pipeline, which runs from Guernsey to the Cheyenne Refinery. Moreover, unlike Sinclair and Suncor, we only sell our products to the wholesale market. We believe that our commitment to the wholesale market gives us a marketing advantage over our principal competitors in the Eastern Slope area, all of which also have retail outlets, because we do not compete directly with independent retailers of gasoline and diesel.
El Dorado Refinery. The El Dorado Refinery faces competition from other Plains States and mid-continent refiners, but the principal competitors for the El Dorado Refinery are Gulf Coast refiners. Although our Gulf Coast competitors typically have lower production costs because of their size (economies of scale) than the El Dorado Refinery, we believe that our competitors’ higher refined product transportation costs allow our El Dorado Refinery to compete effectively in the Plains States and Rocky Mountain region with the Gulf Coast refineries. The Plains States and mid-continent regions are supplied by three product pipelines that originate from the Gulf Coast.
 
Cheyenne Refinery. In the year ended December 31, 2005, we obtained approximately 24% of the Cheyenne Refinery’s crude oil charge from Wyoming, 61% from Canada and 15% from Colorado. During the same period, heavy crude oil constituted approximately 82% of the Cheyenne Refinery’s total crude oil charge. Cheyenne is 88 miles south of Guernsey, Wyoming, the main hub and crude oil trading center for the Rocky Mountain region. We transport up to 25,000 bpd of crude oil from Guernsey to the Cheyenne Refinery through the Centennial pipeline. Additional crude oil volumes are transported on an alternative common carrier pipeline. Ample quantities of heavy crude oil are available at Guernsey, including both locally produced Wyoming general sour and imported Canadian heavy crude oil, which is supplied by the Express pipeline system and the Poplar and Butte pipelines. The Cheyenne Refinery’s ability to process 82% heavy crude oil in 2005 gave us a distinct advantage over the three other Eastern Slope refineries, none of which has the necessary upgrading capacity to process such high volumes of heavy crude oil.
We purchase crude oil for the Cheyenne Refinery from several suppliers, including major oil companies, marketing companies and large and small independent producers, under arrangements which contain market-responsive pricing provisions. Many of these arrangements are subject to cancellation by either party or have terms that are not in excess of one year and are subject to periodic renegotiation. In October 2002, we entered into a five-year crude oil supply agreement with Baytex Energy Ltd., a Canadian crude oil producer. On November 28, 2002, Baytex Energy Ltd. assigned this agreement to its wholly-owned subsidiary, Baytex Marketing Ltd. This agreement, effective January 1, 2003, provides for the purchase of up to 20,000 bpd of a Lloydminster crude oil blend, a heavy Canadian crude. This type of crude oil typically sells at a discount to lighter crude oils. Our price for crude oil under the agreement is equal to 71% of the simple average of the near month settlement prices of the NYMEX light sweet crude oil contracts during the month of delivery, plus the cost of transportation based on the Express Pipeline tariff from Hardisty, Alberta to Guernsey, Wyoming, less $0.25 per barrel. The term of the agreement runs through December 31, 2007.
El Dorado Refinery. In the year ended December 31, 2005, we obtained approximately 73% of the El Dorado Refinery’s crude oil charge from Texas, 10% from Kansas, 8% from Louisiana, 7% from the North Sea and the remaining from the Middle East and Russia. El Dorado is 125 miles north of Cushing, Oklahoma, a major crude oil hub. The Cushing hub is supplied by the Seaway pipeline, which runs from the Gulf Coast; the Basin pipeline, which runs through Wichita Falls from West Texas; and the Mobil pipeline, which originates at the Gulf Coast and connects to the Basin pipeline at Wichita Falls. The Osage pipeline runs from Cushing to El Dorado and transported approximately 90% of our crude oil charge during the year ended December 31, 2005. The remainder of our crude oil charge was transported to the El Dorado Refinery through Kansas gathering system pipelines. During 2004, we entered into a Transportation Services Agreement (“Agreement”) to transport 20,000 bpd of crude oil on the Spearhead Pipeline from Griffith, Indiana to Cushing, Oklahoma once reversal of the pipeline was completed. Enbridge Energy Company completed this reversal of the Spearhead Pipeline and has been accepting line fill volumes since December 2005. Deliveries into Cushing are scheduled to start during March of 2006. This pipeline will enable us to transport heavy Canadian crude oil to our El Dorado Refinery. The initial term of this Agreement is for a period of ten years from the actual commencement date (expected to be March 2006). We have the right to extend the Agreement for an additional ten years and increase the volume transported under the preferential tariff to 50,000 bpd.
 
We are subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) and comparable state occupational safety statutes. We believe that we have operated in substantial compliance with OSHA requirements, including general industry standards, recordkeeping and reporting, hazard communication and process safety management. The nature of our business may result from time to time in industrial accidents. It is possible that changes in safety and health regulations or a finding of non-compliance with current regulations could result in additional capital expenditures or operating expenses, as well as fines and penalties.
The Cheyenne Refinery’s OSHA recordable incident rate in 2005 of 1.07 continues to be below the industry average of 1.16 as compiled by the National Petrochemical and Refiner’s Association (“NPRA”). For their continued improvement in safety, the personnel at Cheyenne will be awarded four safety awards by the NPRA, which are:
(1)  
an award for Meritorious Safety Performance for achieving a recordable incidence rate of 1.2 or less,
(2)  
the Gold Award for a 25% or greater reduction in the recordable rate as compared to the three-year average,
(3)  
the Award for Safety Achievement in Hours for 1.9 million hours worked without a lost time accident, and
(4)  
the Award for Safety Achievement in Years for 3.25 years worked without a lost time accident.
Our behavioral safety program initiated in 2000, our Safety Training Observation Program started in 2002, and our supervisor’s safety training program added in 2003 have contributed to a very positive safety trend at the Cheyenne Refinery. The combination of our behavioral safety program with the management driven safety programs has significantly improved the safety culture for our entire workforce at the Cheyenne Refinery. We are determined not only to sustain our safety record at the Cheyenne Refinery, but to further improve it.
Because our contractor injury rate is higher than our employee injury rate at our Cheyenne Refinery, we increased our efforts on contractor safety in 2005. In addition to the local safety training provided to contractors, personnel at the Cheyenne Refinery assisted the Wyoming-Montana Safety Council in obtaining accreditation by the Association to Reciprocal Safety Councils that allows them to provide contractor safety training with nation-wide reciprocity. The growth of the program was successful in our geographic region during 2005. By improving the training of the contractor workforce in general, we expect to improve the safety of the outside labor we hire at our Cheyenne Refinery as well as that of other industrial facilities in our geographic region.
The El Dorado Refinery dramatically improved its safety record last year, from an OSHA recordable incident rate of 1.94 in 2004 to zero for 2005, which is much better than the NPRA industry average of 1.16. For their outstanding improvement in safety, the personnel at El Dorado will be awarded three safety awards by the NPRA, which are:
(1)  
an award for Meritorious Safety Performance for achieving the recordable incidence rate of 1.2 or less,
(2)  
the Gold Award for a 25% or greater reduction in the recordable rate as compared to the three-year average, and
(3)  
the Award for Safety Achievement in Years for one or more years worked without a lost time accident.
Our employees and management continue to dedicate their efforts to a balanced safety program that combines individual behavioral elements in a safety-coaching environment with very structured management driven programs to improve the safety of the facility and operating procedures. Our objective is a safe working environment for employees who know how to work safely. Management believes that our implementation of the Active Safety Participation program introduced in 2004 drove the excellent results for 2005. Encouraging all employees to contribute toward improving safety performance through personal involvement in safety-related activities is an industry-proven way to reduce injuries.
Achieving a zero OSHA recordable rate during 2005 is a tremendous accomplishment for our El Dorado refinery employees. While we are very proud of the safety performance of our employees during 2005, we also recognize a need to assist our contractors to improve their safety performance. We have implemented two initiatives in 2006 to help our contractors. First, we are working to start a Safety Council for Kansas and Oklahoma as we did in Wyoming and Montana. The Safety Council of Kansas and Oklahoma will provide consistent and high quality safety training for the employees of all contractors in this geographic area. Second, the personnel at the El Dorado Refinery have been very successful with our Brothers Keeper Program, which is a peer safety observation and feedback process. We are transferring this behavioral training approach to our contractors so their employees can use the same peer review process that has produced positive results for us. These and other cooperative programs should increase the active participation of contractor employees and help our contractors to improve their safety performance during 2006.
 
Environmental Matters. 

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

Centennial Pipeline Regulation. We have a 34.72% undivided ownership interest in the Centennial pipeline, which runs approximately 88 miles from Guernsey to Cheyenne, Wyoming. Suncor Pipe Line Company is the sole operator of the Centennial pipeline and holds the remaining ownership interest. The Cheyenne Refinery receives up to 25,000 bpd of crude oil feedstock through the Centennial pipeline. Under the terms of the operating agreement for the Centennial pipeline, the costs and expenses incurred to operate and maintain the Centennial pipeline are allocated to us on a combined basis, based on our throughput and ownership interest. The Centennial pipeline is subject to numerous federal, state and local laws and regulations relating to the protection of health, safety and the environment. We believe that the Centennial pipeline is operated in accordance with all applicable laws and regulations. We are not aware of any material pending legal proceedings to which the Centennial pipeline is a party.
 
At December 31, 2005, we employed approximately 727 full-time employees: 78 in the Houston and Denver offices, 267 at the Cheyenne Refinery, and 382 at the El Dorado Refinery. The Cheyenne Refinery employees include 94 administrative and technical personnel and 173 union members. The El Dorado Refinery employees include 138 administrative and technical personnel and 244 union members. The union members at our El Dorado Refinery are represented by the United Steel, Paper and Forestry, Rubber, Manufacturing, Energy, Allied Industrial and Service Workers International Union (“USW”). The union members at our Cheyenne Refinery are represented by seven bargaining units, the largest being the USW.
In September 2005, the Company, the USW, and its Local 8-0574 (which represents approximately 150 workers at the Cheyenne Refinery) entered into an extension agreement of the previous contract. This extension represents an early settlement of the Cheyenne Refinery contract, which was set to expire in July 2006. The new agreement, which reflects the “national pattern” for the USW, extends the contract until July 2009.
In April 2005, the Company, the USW, and its Local 5-241 (which represents approximately 250 workers at the El Dorado Refinery) entered into an extension agreement of its previous contract. This extension represents an early settlement of the El Dorado Refinery contract, which was set to expire January 31, 2006. The new agreement, which reflects the “national pattern” for the USW, extends the contract until January 31, 2009.

Item 1A.    Risk Factors Relating to Our Business

Crude oil prices and refining margins significantly impact our cash flow and have fluctuated substantially in the past.
Our cash flow from operations is primarily dependent upon producing and selling refined products at margins that are high enough to cover our fixed and variable expenses. In recent years, crude oil costs and crack spreads (the difference between refined product sales prices and crude oil prices) have fluctuated substantially. Factors that may affect crude oil costs and refined product prices include:
·  
overall demand for crude oil and refined products;
·  
general economic conditions;
·  
the level of foreign and domestic production of crude oil and refined products;
·  
the availability of imports of crude oil and refined products;
·  
the marketing of alternative and competing fuels;
·  
the extent of government regulation;
·  
global market dynamics;
·  
product pipeline capacity;
·  
local market conditions; and
·  
the level of operations of competing refineries.
Crude oil supply contracts are generally short-term contracts with price terms that change as market prices change. Our crude oil requirements are supplied from sources that include:
·  
major oil companies;
·  
crude oil marketing companies;
·  
large independent producers; and
·  
smaller local producers.
The price at which we can sell gasoline and other refined products is strongly influenced by the price of crude oil. Generally, an increase or decrease in the price of crude oil results in a corresponding increase or decrease in the price of gasoline and other refined products. However, if crude oil prices increase significantly, our operating margins would fall unless we could pass along these price increases to our customers. From time to time, we purchase forward crude oil supply contracts, enter into forward product agreements to hedge excess inventories and/or hedge our refined product margins.
In addition, our Refineries maintain inventories of crude oil, intermediate products and refined products, the value of each being subject to fluctuations in market prices. Our inventories of crude oil, unfinished products and finished products are recorded at the lower of cost on a first-in, first-out (“FIFO”) basis or market prices. As a result, a rapid and significant increase or decrease in the market prices for crude oil or refined products could have a significant short-term impact on our earnings and cash flow.

Our profitability is affected by crude oil differentials, which increased significantly in 2005 over 2004 levels.
The light/heavy crude oil differential that we report is the average differential between the benchmark West Texas Intermediate (“WTI”) crude oil priced at Cushing, Oklahoma and the heavy crude oil priced delivered to our Cheyenne Refinery. The WTI/WTS (sweet/sour) crude oil differential is the average differential between benchmark WTI crude oil priced at Cushing, Oklahoma and West Texas sour crude oil priced at Midland, Texas. Our profitability at our Cheyenne Refinery is linked to the light/heavy crude oil differential, and our profitability at our El Dorado Refinery is linked to the WTI/WTS crude oil differential. Starting in March 2006, when we anticipate that our El Dorado Refinery will begin receiving heavy Canadian crude oil through the Spearhead Pipeline, its profitability will also benefit from the light/heavy crude oil differential. We prefer to refine heavy crude oil at the Cheyenne Refinery and sour crude oil at the El Dorado Refinery because they provide a higher refining margin than light or sweet crude oil does. Accordingly, any tightening of these crude oil differentials will reduce our profitability. The light/heavy crude oil differential averaged $15.32 per barrel in the year ended December 31, 2005, compared to $9.90 per barrel in the same period in 2004. The WTI/WTS crude oil differential averaged $4.51 per barrel in the year ended December 31, 2005, compared to $3.74 per barrel in the same period in 2004. Crude oil prices were historically high during 2005, which resulted in both attractive light/heavy crude oil differentials and WTI/WTS crude oil differentials. However, crude oil prices may not remain at current levels, and the crude oil differentials may decline in the future.

External factors beyond our control can cause fluctuations in demand for our products, our prices and margins, which may negatively affect income and cash flow.
External factors can also cause significant fluctuations in the demand for our products and volatility in the prices for our products and other operating costs and can magnify the impact of economic cycles on our business. Examples of external factors include:
·  
general economic conditions;
·  
competitor actions;
·  
availability of raw materials;
·  
international events and circumstances; and
·  
governmental regulation in the United States and abroad, including changes in policies of the Organization of Petroleum Exporting Countries (“OPEC”).
Demand for our products is influenced by general economic conditions. For example, near record level refined product margins and crude oil differentials in 2001 declined substantially in 2002. This decline was attributed to unusually high prices for oil, reduced market demand for refined products and greater imports of competitive products, all of which adversely affected our results of operations in 2002. In 2003, refined product margins and crude oil differentials returned closer to historical average levels. In 2004 and 2005, crude oil differentials reached record levels, and refined product margins exceeded historical average levels. However, the recurrence of weaker economic and market conditions in the future may have a negative impact on our business and financial results.

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

Our Refineries face operating hazards, and the potential limits on insurance coverage could expose us to significant liability costs.
Our operations could be subject to significant interruption, and our profitability could be impacted if any of our Refineries experienced a major accident or fire, was damaged by severe weather or other natural disaster, or was otherwise forced to curtail its operations or shut down. If a pipeline became inoperative, crude oil would have to be supplied to our Refineries through an alternative pipeline or from additional tank trucks to the Refineries, which could hurt our business and profitability. In addition, a major accident, fire or other event could damage a Refinery or the environment or cause personal injuries. If either of our Refineries experiences a major accident or fire or other event or an interruption in supply or operations, our business could be materially adversely affected if the damage or liability exceeds the amounts of business interruption, property, terrorism and other insurance that we maintain against these risks.
Our Refineries consist of many processing units, a number of which have been in operation for many years. One or more of the units may require additional unscheduled down time for unanticipated maintenance or repairs that are more frequent than our scheduled turnaround for such units. Scheduled and unscheduled maintenance could reduce our revenues during the period of time that our units are not operating.

We face substantial competition from other refining and pipeline companies, and an increase in competition in the markets in which we sell refined product could adversely affect our sales and profitability.
The refining industry is highly competitive. Many of our competitors are large, integrated, major or independent oil companies that, because of their more diverse operations, larger refineries and stronger capitalization, may be better positioned than we are to withstand volatile industry conditions, including shortages or excesses of crude oil or refined products or intense price competition at the wholesale level. Many of these competitors have financial and other resources substantially greater than ours.
We are not engaged in the petroleum exploration and production business and therefore do not produce any of our crude oil feedstocks. We do not have a retail business and therefore are dependent upon others for outlets for our refined products. Certain of our competitors, however, obtain a portion of their feedstocks from company-owned production and have retail outlets. Competitors that have their own production or extensive retail outlets, with brand-name recognition, are at times able to offset losses from refining operations with profits from producing or retailing operations, and may be better positioned to withstand periods of depressed refining margins or feedstock shortages. In addition, we compete with other industries that provide alternative means to satisfy the energy and fuel requirements of our industrial, commercial and individual consumers. If we are unable to compete effectively with these competitors, both within and outside of our industry, there could be a material adverse effect on our business, financial condition and results of operations.

Our operating results are seasonal and generally lower in the first and fourth quarters of the year.
Demand for gasoline and asphalt products is generally higher during the summer months than during the winter months due to seasonal increases in highway traffic and road construction work. As a result, our operating results for the first and fourth calendar quarters are generally lower than those for the second and third quarters. Diesel demand has historically been more stable because two major east-west truck routes and two major railroads cross one of our principal marketing areas for our Cheyenne Refinery. However, reduced road construction and agricultural work during the winter months somewhat depresses demand for diesel in the winter months.

Our operations involve environmental risks that may require us to make substantial capital expenditures to remain in compliance or that could give rise to material liabilities.
Our results of operations may be affected by increased costs resulting from compliance with the extensive environmental laws to which our business is subject and from any possible contamination of our facilities as a result of accidental spills, discharges or other releases of petroleum or hazardous substances.
Our operations are subject to extensive federal, state and local environmental and health and safety laws and regulations relating to the protection of the environment, including those governing the emission or discharge of pollutants into the air and water, product specifications and the generation, treatment, storage, transportation and disposal, or remediation of solid and hazardous waste and materials. Environmental laws and regulations that affect the operations, processes and margins for our refined products are extensive and have become progressively more stringent. Additional legislation or regulatory requirements or administrative policies could be imposed with respect to our products or activities. Compliance with more stringent laws or regulations or more vigorous enforcement policies of the regulatory agencies could adversely affect our financial position and results of operations and could require us to make substantial expenditures. Any noncompliance with these laws and regulations could subject us to material administrative, civil or criminal penalties or other liabilities.
We are a defendant in a series of lawsuits alleging, among other things, that emissions from an oil field or the production facilities thereon at the campus of the Beverly Hills High School, which were owned and operated by one of our subsidiaries between 1985 and 1995, caused the plaintiffs to develop cancers or various health problems. We could be subject to liability if these lawsuits are resolved adversely to us and the amount of the liability exceeds both the loss mitigation insurance we have purchased and any coverage under insurance policies that were in effect at the time that the alleged incidents occurred. See Note 8 in the “Notes to Consolidated Financial Statements” for more information on these lawsuits.
Our business is inherently subject to accidental spills, discharges or other releases of petroleum or hazardous substances. Past or future spills related to any of our operations, including our Refineries, pipelines or product terminals, could give rise to liability (including potential cleanup responsibility) to governmental entities or private parties under federal, state or local environmental laws, as well as under common law. This could involve contamination associated with facilities that we currently own or operate, facilities that we formerly owned or operated and facilities to which we sent wastes or by-product for treatment or disposal and other contamination. Accidental discharges could occur in the future, future action may be taken in connection with past discharges, governmental agencies may assess penalties against us in connection with past or future contamination and third parties may assert claims against us for damages allegedly arising out of any past or future contamination. The potential penalties and clean-up costs for past or future releases or spills, the failure of some prior owners of our facilities to complete their clean-up obligations, the liability to third parties for damage to their property, or the need to address newly-discovered information or conditions that may require a response could be significant, and the payment of these amounts could have a material adverse effect on our business, financial condition and results of operations.
 
We could incur substantial costs or disruptions in our business if we cannot obtain or maintain necessary permits and authorizations.
Our operations require numerous permits and authorizations under various laws and regulations, including environmental and health and safety laws and regulations. These authorizations and permits are subject to revocation, renewal or modification and can require operational changes, which may involve significant costs, to limit impacts or potential impacts on the environment and/or health and safety. A violation of these authorization or permit conditions or other legal or regulatory requirements could result in substantial fines, criminal sanctions, permit revocations, injunctions and/or refinery shutdowns. In addition, major modifications of our operations could require modifications to our existing permits or expensive upgrades to our existing pollution control equipment, which could have a material adverse effect on our business, financial condition or results of operations.

Hurricanes along the Gulf Coast could disrupt our supply of crude oil and our ability to complete capital improvement projects in a timely manner.
In August and September of 2005, Hurricanes Katrina and Rita and related storm activity, such as windstorms, storm surges, floods and tornadoes, caused extensive and catastrophic physical damage in and to coastal and inland areas located in the Gulf Coast region of the United States (parts of Texas, Louisiana, Mississippi and Alabama) and certain other parts of the southeastern parts of the United States. Some of the materials we use for our capital projects are fabricated at facilities located along the Gulf Coast. Should other storms of this nature occur in the future, it is possible that the storms and their collateral effects could result in delays or cost increases for our planned capital projects.
In addition, supplies of crude oil to our El Dorado Refinery are sometimes shipped from Gulf Coast production or terminaling facilities. This crude oil supply source would be potentially threatened in the event of future catastrophic damage.

We may have labor relations difficulties with some of our employees represented by unions.
Approximately 57 percent of our employees were covered by collective bargaining agreements at December 31, 2005. We believe that our current relations with our employees are good. However, employees may conduct a strike at some time in the future, which may adversely affect our operations. See Item 1 “Business-Employees.”

Terrorist attacks and threats or actual war may negatively impact our business.
Terrorist attacks in the United States and the war in Iraq, as well as events occurring in response to or in connection with them, including future terrorist attacks against U.S. targets, rumors or threats of war, actual conflicts involving the United States or its allies, or military or trade disruptions affecting our suppliers or our customers, could adversely impact our operations. In addition, any terrorist attack could have an adverse impact on energy prices, including prices for our crude oil and refined products, and an adverse impact on the margins from our refining and marketing operations. As a result, there could be delays or losses in the delivery of supplies and raw materials to us, decreased sales of our products and extension of time for payment of accounts receivable from our customers.
 
Item 1B.    Unresolved Staff Comments

None.

Item 2.    Properties
 
Refining Operations
We own the 125 acre site of the Cheyenne Refinery in Cheyenne, Wyoming and the approximately 1,000 acre site of the El Dorado Refinery in El Dorado, Kansas.
 
Other Properties
We lease approximately 6,500 square feet of office space in Houston, Texas for our corporate headquarters under a lease expiring in October 2009. We also lease approximately 28,000 square feet of office space in Denver, Colorado under a sublease expiring in December 2006 for our refining, marketing and raw material supply operations. We are in the process of renegotiating this lease or securing a lease on similar office space before the end of 2006.


See Note 8 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 2005 annual CEO certification with the New York Stock Exchange (“NYSE”) on May 2, 2005. We anticipate filing our 2006 annual CEO certification with the NYSE on or about May 2, 2006. In addition, we filed with the SEC as exhibits to our Form 10-K for the year ended December 31, 2004 the CEO and CFO certifications required under Section 302 of the Sarbanes-Oxley Act of 2002.


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

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

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

The approximate number of holders of record for our common stock as of February 16, 2006 was 912. Quarterly cash dividends of $0.025 per share have been declared on our common stock for each quarter beginning with the quarter ended June 2001 and through the quarter ended June 30, 2004. The quarterly cash dividend was $0.03 per share for the quarters ended September 30, 2004 through March 31, 2005. The quarterly cash dividend was $0.04 per share for the quarters ended June 30, 2005 through December 31, 2005. In addition, a special cash dividend of $1.00 per share was declared for the quarter ended December 31, 2005 and paid on January 11, 2006, to shareholders of record on December 15, 2005. The 6.625% Notes may restrict dividend payments based on the covenants related to interest coverage and restricted payments.

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

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

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

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


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

(1)
Adjusted EBITDA represents income before cumulative effect of accounting change, interest expense, interest and investment income, merger financing termination costs (includes both interest expense and income), income tax, and depreciation and amortization. Adjusted EBITDA is not a calculation based upon generally accepted accounting principles; however, the amounts included in the adjusted EBITDA calculation are derived from amounts set forth in our consolidated financial statements included in Item 8 of this Form 10-K. Adjusted EBITDA should not be considered as an alternative to net income or operating income, as an indication of our operating performance, or as an alternative to operating cash flow as a measure of liquidity. Adjusted EBITDA is not necessarily comparable to similarly titled measures of other companies. Adjusted EBITDA is presented here because we believe that it enhances an investor’s understanding of our ability to satisfy principal and interest obligations with respect to our indebtedness and to use cash for other purposes, including capital expenditures. Adjusted EBITDA is also used for internal analysis and as a basis for financial covenants. Our adjusted EBITDA is reconciled to net income as follows:

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

 
 Item 7.    Management’s Discussion and Analysis of Financial Condition and Results of Operations
 
General
Frontier operates Refineries in Cheyenne, Wyoming and El Dorado, Kansas as previously discussed in Part I, Item 1 of this Form 10-K. We focus our marketing efforts in the Rocky Mountain and Plains States regions of the United States. We purchase crude oil to be refined and market refined petroleum products including various grades of gasoline, diesel, jet fuel, asphalt and other by-products.
 
Results of Operations
To assist in understanding our operating results, please refer to the operating data at the end of this analysis which provides key operating information for our Refineries. Refinery operating data is also included in our quarterly reports on Form 10-Q and on our web site address: http://www.frontieroil.com.

Overview
Our Refineries have a total annual average permitted crude capacity of 162,000 bpd. The four significant indicators of our profitability, reflected and defined in the operating data at the end of this analysis, are the gasoline crack spread, the diesel crack spread, the light/heavy crude oil differential and the WTI/WTS crude oil differential. Other significant factors that influence our results are refinery utilization, crude oil price trends, asphalt and by-product margins and refinery operating expenses (including natural gas prices and turnaround, or planned maintenance activity). We typically do not use derivative instruments to offset price risk on our base level of operating inventories. Under our first-in, first-out (“FIFO”) inventory accounting method, crude oil price trends can cause significant fluctuations in the inventory valuation of our crude oil, unfinished products and finished products, thereby resulting in FIFO inventory gains when crude oil prices increase and FIFO inventory losses when crude oil prices decrease during the reporting period. See “Price Risk Management Activities” under Item 7A for a discussion of our utilization of futures trading.
During 2005, the price of crude oil on the New York Mercantile Exchange continued the upward trend, which began during 2004. The crude oil price began the 2005 year at $43.45 per barrel, reached a high of $69.81 per barrel in late August, and ended the year at $61.04 per barrel. The crude oil market fundamentals and geopolitical considerations continued to support prices higher than historic averages. The increase in crude oil prices, along with additional crude oil production being significantly heavy and/or sour crude oil, increased our crude oil differentials during the year ended December 31, 2005, when compared to the same period in 2004. Our 2005 gasoline and diesel crack spreads were the highest in our history. Higher demand for gasoline and diesel along with product supply constraints are reasons for our improved gasoline and diesel crack spreads, especially after the damage to Gulf Coast refineries caused by Hurricanes Katrina and Rita.
As discussed in Note 6 in the “Notes to Consolidated Financial Statements”, we effected a stock split on June 17, 2005. All prior period share related numbers have been revised to reflect the effect of the split.
 
2005 Compared with 2004

Overview of Results

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

Specific Variances

Refined product revenues. Refined product revenues increased $1.1 billion, or 39%, from $2.9 billion to $4.0 billion for the year ended December 31, 2005 compared to the same period in 2004. This increase was primarily due to a significant increase in average product sales prices ($17.05 higher per sales barrel), and higher product sales volumes in 2005 (4,391 more bpd). Sales prices increased primarily as a result of increased crude oil prices and improvements in the gasoline and diesel crack spreads.
Manufactured product yields. Manufactured product yields (“yields”) are the volumes of specific materials that are obtained through the distilling of crude oil and the operations of other refinery process units. Yields increased 1,510 bpd at the El Dorado Refinery and 1,594 bpd at the Cheyenne Refinery for the year ended December 31, 2005 as compared to 2004.
Other revenues. Other revenues increased $11.1 million to a $1.2 million gain for the year ended December 31, 2005, compared to a $9.9 million loss for the same period in 2004, the source of which was $1.0 million in net gains from derivative contracts accounted for using mark-to-market accounting in the year ended December 31, 2005, compared to net derivative losses of $10.3 million for the same period in 2004. See “Price Risk Management Activities” under Item 7A for a discussion of our utilization of commodity derivative contracts.
Raw material, freight and other costs. Raw material, freight and other costs include crude oil and other raw materials used in the refining process, purchased products and blendstocks, freight costs for FOB destination sales, as well as the impact of changes in inventory under the FIFO inventory accounting method. Raw material, freight and other costs increased by $814.9 million during the year ended December 31, 2005, from $2.4 billion in 2004 to $3.3 billion in 2005. The increase in raw material, freight and other costs was due to higher average crude prices and higher crude oil charges, reduced by higher FIFO inventory gains from rising prices in the year ended December 31, 2005 compared to the year ended December 31, 2004. We also benefited from improved crude oil differentials during the year ended December 31, 2005 when compared to the same period in 2004. For the year ended December 31, 2005, we realized a reduction in raw material, freight and other costs as a result of FIFO inventory gains of approximately $29.4 million after tax ($47.6 million pretax, comprised of $39.0 million at the El Dorado Refinery and $8.6 million at the Cheyenne Refinery) due to increasing crude oil and refined product prices. For the year ended December 31, 2004, we realized a reduction in raw material, freight and other costs as a result of FIFO inventory gains of approximately $19.8 million after tax ($32.0 million pretax, comprised of $25.9 million for the El Dorado Refinery and $6.1 million for the Cheyenne Refinery) because of increasing crude oil and refined product prices.
The Cheyenne Refinery raw material, freight and other costs of $48.49 per sales barrel for the year ended December 31, 2005 increased from $38.08 per sales barrel in the same period in 2004 due to higher crude oil prices partially offset by higher FIFO inventory gains and an improved light/heavy crude oil differential. The heavy crude oil utilization rate at the Cheyenne Refinery expressed as a percentage of the total crude oil charge decreased to 82% in the year ended December 31, 2005 from 85% in 2004 as we increased our charges of lighter crude oil to take advantage of market opportunities. The light/heavy crude oil differential for the Cheyenne Refinery averaged $15.32 per barrel in the year ended December 31, 2005 compared to $9.90 per barrel in the same period in 2004.
The El Dorado Refinery raw material, freight and other costs of $54.01 per sales barrel for the year ended December 31, 2005 increased from $40.98 per sales barrel in the same period in 2004 due to higher average crude oil prices partially offset by higher FIFO inventory gains and an improved WTI/WTS crude oil differential. The WTI/WTS crude oil differential increased from an average of $3.74 per barrel in the year ended December 31, 2004 to $4.51 per barrel in the same period in 2005.
Refinery operating expenses. Refinery operating expenses, excluding depreciation, include both the variable costs (energy and utilities) and the fixed costs (salaries, taxes, maintenance costs and other) of operating the Refineries. Refinery operating expenses, excluding depreciation, were $245.5 million in the year ended December 31, 2005 compared to $219.8 million in the comparable period of 2004.
The Cheyenne Refinery operating expenses, excluding depreciation, were $81.1 million in the year ended December 31, 2005, compared to $72.4 million in the comparable period of 2004. The increased expenses included higher turnaround accruals ($3.2 million), higher electricity costs ($1.2 million), increased environmental expenses ($1.2 million) and higher natural gas costs ($810,000). The higher natural gas costs resulted primarily from an average price increase of $2.72 per MMbtu, materially offset by our using approximately 27% less natural gas during the year ended December 31, 2005 when compared to the same period in 2004.
The El Dorado Refinery operating expenses, excluding depreciation, were $164.4 million in the year ended December 31, 2005, increasing from $147.4 million for the year ended December 31, 2004. The increased expenses included higher salaries and benefits ($4.2 million), natural gas ($3.6 million), electricity ($3.3 million), turnaround costs in excess of accruals ($2.6 million), maintenance ($2.3 million) and additives and chemicals ($2.2 million). The higher natural gas costs resulted primarily from an average price increase of $1.50 per MMbtu, partially offset by our using approximately 12% less natural gas during the year ended December 31, 2005, when compared to the same period in 2004.
Selling and general expenses. Selling and general expenses, excluding depreciation, increased $822,000, or 3%, from $29.9 million for the year ended December 31, 2004 to $30.7 million for the year ended December 31, 2005 due to higher salaries and benefits ($3.1 million, primarily due to bonuses) partly offset by lower costs related to the Beverly Hills litigation during the year ended December 31, 2005, when compared to 2004, as the 2005 litigation costs were reduced by insurance recoveries.
Merger termination and legal costs. Merger termination and legal costs include legal costs associated with the termination of the 2003 Holly merger and the now-concluded lawsuit. These costs were $48,000 for the year ended December 31, 2005, compared to $3.8 million in 2004.
Depreciation and amortization. Depreciation and amortization increased $3.0 million, or 9%, for the year ended December 31, 2005 compared to the same period in 2004 because of increased capital investment in our Refineries, the 2004 El Dorado Refinery contingent earn-out payment and the write-off of undepreciated assets which were retired and replaced during 2005.
Interest expense and other financing costs. Interest expense and other financing costs of $10.3 million for the year ended December 31, 2005 decreased $27.2 million, or 72%, from $37.6 million in the comparable period in 2004. This decrease was primarily due to the refinancing in late 2004 of our 11.75% Senior Notes with $150.0 million of 6.625% Senior Notes. The interest expense and other financing costs for year ended December 31, 2004, also included $14.9 million in redemption-related costs. Average debt outstanding decreased to $161 million during the year ended December 31, 2005 from $209 million for the same period in 2004. Capitalized interest, which reduced interest expense and other financing costs, was $2.6 million for the year ended December 31, 2005, compared to $65,000 in the comparable period of 2004 primarily due to the ultra low sulfur diesel capital projects which commenced in 2005.
Interest and investment income. Interest and investment income increased $5.9 million, or 342%, from $1.7 million in the year ended December 31, 2004 to $7.6 million in the year ended December 31, 2005, due to larger cash balances and higher interest rates on invested cash.
Provision for income taxes. The provision for income taxes for the year ended December 31, 2005 was $168.2 million on pretax income of $443.3 million (or 37.95%). The 2005 provision reflects an estimated benefit from the American Jobs Creation Act of 2004 (“the Act”) production activities deduction for manufacturers ($3.2 million), offset by the impact of permanent book tax differences from our current estimated statutory tax rate of 37.92%. See Note 5 in the “Notes to Consolidated Financial Statements” for detailed information on our deferred tax assets. The income tax provision for the year ended December 31, 2004 was $42.3 million on pretax income of $112.1 million (or 37.77%) reflecting the net benefit of releasing our deferred tax valuation allowance. Another provision of the Act benefited our current income taxes payable for 2005 by allowing us an accelerated depreciation deduction of 75% of qualified capital costs incurred to achieve low sulfur diesel fuel requirements. The Act also provides for a $0.05 per gallon credit on compliant diesel fuel up to an amount equal to the remaining 25% of these qualified capital costs for federal income tax purposes. (See “Environmental” under Note 8 in the “Notes to Consolidated Financial Statements”).
 
2004 Compared with 2003

Overview of Results

We had net income for the year ended December 31, 2004 of $69.8 million, or $1.27 per diluted share, compared to net income of $3.2 million, or $0.06 per diluted share, in the same period in 2003. Our operating income of $143.5 million for the year ended December 31, 2004, represented an increase of $91.7 million from the $51.9 million operating income for the comparable period in 2003. The average diesel crack spread was significantly higher during 2004 ($7.35 per barrel) than in 2003 ($5.05 per barrel). The average gasoline crack spread was also higher during 2004 ($8.61 per barrel) than in 2003 ($7.00 per barrel), and both the light/heavy and WTI/WTS crude oil differentials improved.
Our net income for the year ended December 31, 2004 was reduced by $14.9 million pretax ($9.2 million after tax) in additional costs associated with the redemption of our 11.75% Senior Notes. We used available cash and proceeds from a new $150.0 million 6.625% Senior Notes offering to redeem the 11.75% Senior Notes. Our net income for the year ended December 31, 2004 was also reduced by the legal costs associated with the termination of the Holly merger and the Beverly Hills litigation. On March 31, 2003, we announced that we had entered into an agreement with Holly pursuant to which the two companies would merge. On August 20, 2003, we announced that Holly had advised us that it was not willing to proceed with our merger agreement on the agreed terms. As a result, we filed suit against Holly for damages in Delaware. Merger termination and legal costs reduced earnings in the year ended December 31, 2004 by $3.8 million pretax ($2.4 million after tax), and costs related to the Beverly Hills litigation reduced earnings in the year ended December 31, 2004 by an additional $5.6 million pretax ($3.4 million after tax). Our net income for the year ended December 31, 2004 was increased by $4.4 million pretax ($2.7 million after tax) from the gain on involuntary conversion of assets related to the fire that occurred on January 19, 2004 in the furnaces of the Cheyenne Refinery coker.

Specific Variances

Refined product revenues. Refined product revenues increased $702.0 million, or 32%, from $2.2 billion to $2.9 billion for the year ended December 31, 2004 compared to the same period in 2003. This increase was due to higher sales prices ($11.39 higher average per sales barrel), and slightly higher sales volumes in 2004 (322 more bpd). Sales prices increased primarily as a result of increased crude oil prices and improvements in the gasoline and diesel crack spreads.
Manufactured product yields. Yields for the year ended December 31, 2004 for the El Dorado Refinery increased 224 bpd from the year ended December 31, 2003. Yields for the year ended December 31, 2004 for the Cheyenne Refinery were 2,174 bpd less than in the same period in 2003 because of the Coker furnace fire.
Other revenues. Other revenues decreased $10.8 million to a $9.9 million loss for the year ended December 31, 2004 compared to income of nearly $1.0 million for the same period in 2003 due to $10.3 million in net losses from derivative contracts accounted for using mark-to-market accounting in the year ended December 31, 2004, compared to net losses of $268,000 for the same period in 2003. See “Price Risk Management Activities” under Item 7A for a discussion of our utilization of commodity derivative contracts.
Raw material, freight and other costs. Raw material, freight and other costs increased by $571.7 million during the year ended December 31, 2004 when compared to the same period in 2003. The increase in raw material, freight and other costs was due to higher crude prices and more crude oil charges, offset by higher FIFO inventory gains from rising prices in the year ended December 31, 2004 compared to the year ended December 31, 2003. We also benefited from improved crude oil differentials during the year ended December 31, 2004 when compared to the same period in 2003. For the year ended December 31, 2004, we realized a reduction in raw material, freight and other costs as a result of FIFO inventory gains of approximately $19.8 million after tax ($32.0 million pretax, comprised of $25.9 million at the El Dorado Refinery and $6.1 million at the Cheyenne Refinery) because of increasing crude oil and refined product prices. For the year ended December 31, 2003, we realized a reduction in raw material, freight and other costs as a result of FIFO inventory gains of approximately $4.4 million after tax ($7.2 million pretax, comprised of a $4.2 million gain for the El Dorado Refinery and a $3.0 million gain for the Cheyenne Refinery).
The Cheyenne Refinery raw material, freight and other costs of $38.08 per sales barrel for the year ended December 31, 2004 increased from $29.40 per sales barrel in the same period in 2003 due to higher crude oil prices offset by higher FIFO inventory gains and an improved light/heavy crude oil differential. The heavy crude oil utilization rate at the Cheyenne Refinery expressed as a percentage of the total crude oil charge decreased to 85% in the year ended December 31, 2004 from 88% in 2003, as we processed more light crude oil due to the coker being out of service for approximately one month. The light/heavy crude oil differential for the Cheyenne Refinery averaged $9.90 per barrel in the year ended December 31, 2004 compared to $7.10 per barrel in the same period in 2003.
The El Dorado Refinery raw material, freight and other costs of $40.98 per sales barrel for the year ended December 31, 2004 increased from $31.43 per sales barrel in the same period in 2003 due to higher average crude oil prices offset by higher FIFO inventory gains and an improved WTI/WTS crude oil differential. The WTI/WTS crude oil differential increased from an average of $2.68 per barrel in the year ended December 31, 2003 to $3.74 per barrel in the same period in 2004.
Refinery operating expenses. Refinery operating expenses, excluding depreciation, were $219.8 million, or $3.62 per sales barrel, in the year ended December 31, 2004 compared to $200.4 million, or $3.31 per sales barrel, in the comparable period of 2003.
The Cheyenne Refinery operating expenses, excluding depreciation, were $72.4 million in the year ended December 31, 2004 compared to $61.4 million in the comparable period of 2003. The increased expenses included higher costs in natural gas ($3.1 million), maintenance ($3.2 million), salaries ($1.5 million), a 2004 bonus accrual ($1.3 million) and increased environmental expenses ($2.0 million). The higher natural gas costs resulted primarily from an average increase in price of $1.21 per MMbtu, along with utilizing approximately 11% more natural gas during the year ended December 31, 2004 when compared to the same period in 2003.
The El Dorado Refinery operating expenses, excluding depreciation, were $147.4 million in the year ended December 31, 2004, increasing from $139.0 million for the year ended December 31, 2003 primarily due to higher costs in natural gas ($6.3 million), a 2004 bonus accrual ($1.9 million) and higher salaries and benefits ($1.0 million), offset by reduced costs in consulting and legal ($1.0 million). The higher natural gas costs resulted primarily from an average increase in price of $0.87 per MMbtu, along with utilizing approximately 2% more natural gas during the year ended December 31, 2004 when compared to the same period in 2003.
Selling and general expenses. Selling and general expenses, excluding depreciation, increased $10.0 million, or 50%, from $19.9 million for the year ended December 31, 2003 to $29.9 million for the year ended December 31, 2004 due to increased costs related to the Beverly Hills litigation and increases in salaries. Costs related to the Beverly Hills litigation during the year ended December 31, 2004 were $5.6 million ($4.1 million in legal costs, substantially all of which were paid from the commutation account (discussed in Note 8 in the “Notes to Consolidated Financial Statements”) and $1.5 million amortization of the previously purchased loss mitigation insurance premium), as opposed to $1.8 million in the same period in 2003. Salaries increased by $5.5 million for the year ended December 31, 2004 compared to the same period in 2003, primarily due to $3.8 million in bonuses being accrued in 2004, while none were accrued in 2003.
Merger termination and legal costs. Merger termination and legal costs of $3.8 million for the year ended December 31, 2004 included legal costs associated with the termination of the anticipated 2003 Holly merger and resulting lawsuit, compared to $8.7 million in merger termination and legal costs for the comparable period in 2003.
Depreciation and amortization. Depreciation and amortization increased $3.4 million, or 12%, for the year ended December 31, 2004 compared to the same period in 2003 because of increased capital investment in our Refineries.
Interest expense and other financing costs. Interest expense and other financing costs of $37.6 million for the year ended December 31, 2004 increased $8.8 million, or 31%, from $28.7 million in the comparable period in 2003. Interest expense and other financing costs for the year ended December 31, 2004 included $14.9 million in costs related to the redemption of our 11.75% Senior Notes and subsequent reduced interest expense on our new $150.0 million 6.625% Senior Note debt issuance. The $14.9 million in redemption-related costs includes $10.4 million of premium, the write-off at redemption of the remaining unamortized $1.5 million of issue discount, $2.7 million for the write-off at redemption of the remaining unamortized debt issue costs, and $0.3 million of legal and administrative costs to facilitate the tender offer and redemption. We also had no interest on the 9.125% Senior Notes during the year ended December 31, 2004, as they were redeemed in December 2003 ($3.5 million in interest expense for the year ended December 31, 2003). Interest expense and other financing costs for the year ended December 31, 2003 also included $1.2 million of premium paid upon redemption of our 9.125% Senior Notes in December 2003. Average debt outstanding decreased to $209 million during the year ended December 31, 2004 from $236 million (excluding merger debt) for the same period in 2003. Capitalized interest, which reduced interest expense and other financing costs, was $65,000 during the year ended December 31, 2004 compared to $586,000 in the comparable period of 2003.
Interest and investment income. Interest and investment income increased $607,000, or 55%, from $1.1 million in the year ended December 31, 2003 to $1.7 million in the year ended December 31, 2004, as we had more cash available to invest.
Gain on involuntary conversion of assets. The gain on involuntary conversion of assets related to the fire that occurred on January 19, 2004 in the furnaces of the coking unit at the Cheyenne Refinery. For the year ended December 31, 2004, the gain represented the settlement proceeds of $7.1 million from our insurers less $1.6 million of expenses related to clean-up costs and $1.1 million of net property, plant and equipment written-off due to the fire.
Merger financing termination costs, net. The merger financing termination costs, net, during the year ended December 31, 2003 were $18.0 million, which related to the 8% Senior Notes issued to finance the contemplated Holly merger and included interest expense, issue discount, financing issue costs and redemption premium, net of $752,000 interest income earned on the escrow account.
Provision for income taxes. The provision for income taxes for the year ended December 31, 2004 was $42.3 million on pretax income of $112.1 million (or 37.8%) reflecting the net benefit of releasing our deferred tax valuation allowance offset by the effect of the permanent book versus tax differences and prior year adjustments from our current estimated effective tax rate of 38.2% The income tax provision for the year ended December 31, 2003 was $3.0 million on pretax income of $6.2 million (or 47.8%) due to one-time adjustments for permanent book versus tax differences and an increase of $280,000 in the income tax provision for the year ended December 31, 2003 resulting from an adjustment to the 2002 tax provision.
 
Liquidity and Capital Resources

Cash flows from operating activities. Net cash provided by operating activities was $360.3 million for the year ended December 31, 2005, compared to net cash provided by operating activities of $177.9 million during the year ended December 31, 2004. Improved results of operations increased cash flow significantly during 2005, but were partially offset by uses of cash for working capital changes.
Working capital changes provided a total of $9.4 million of cash in the year ended December 31, 2005 while providing $38.6 million of cash in the comparable period in 2004. The uses of cash for working capital during the year ended December 31, 2005, included an increase in inventories of $90.7 million and an increase in trade and other receivables of $43.7 million. The increase in both receivables and inventories was due to the significant increases in crude oil and product prices during 2005. The average per barrel cost of inventories in the year ended December 31, 2005, increased by $14.45 per barrel compared to only a $5.76 per barrel increase in the comparable period in 2004.
The most significant working capital item providing cash during the year ended December 31, 2005 was an increase in trade and crude payables of $117.3 million. This was due to increases in crude payables of $103.5 million which resulted from increased crude oil inventory volumes, higher crude oil prices and increases in trade and other payables of $13.8 million.
We made estimated federal and state income tax payments of $92.5 million and $13.5 million, respectively, during the year ended December 31, 2005, which will be applied to our 2005 income tax liabilities. We also made state income tax payments during the year ended December 31, 2005 of $218,000, which were applied to our 2004 income tax liabilities. We received federal income tax refunds of $3.6 million during 2005, which represented a portion of our overpayment of our 2004 federal income tax liability. We have applied $1.4 million of 2004 state income tax overpayments and $122,000 of 2004 federal income tax overpayments to our estimated 2005 income tax liabilities. As of December 31, 2005, we have accrued estimated federal income taxes payable of $18.5 million and estimated state income taxes payable of $1.9 million.
At December 31, 2005, we had $356.1 million of cash and cash equivalents, working capital of $262.3 million and $155.5 million availability for borrowings under our revolving credit facility. Our operating cash flows are affected by crude oil and refined product prices and other risks as discussed in Item 7A “Quantitative and Qualitative Disclosures About Market Risks.”
Cash flows used in investing activities. Capital expenditures during the year ended December 31, 2005, were $109.7 million and included approximately $89.8 million for the El Dorado Refinery, $19.4 million for the Cheyenne Refinery, and $582,000 for expenditures in our Denver and Houston offices, and our share of crude oil pipeline projects. The $89.8 million of capital expenditures for our El Dorado Refinery included $71.8 million for the ultra low sulfur diesel project (discussed below), as well as operational, payout, safety, administrative, environmental and optimization projects. The $19.4 million of capital expenditures for our Cheyenne Refinery included approximately $5.9 million of capital for the ultra low sulfur diesel project, as well as environmental, operational, safety, administrative and payout projects. We funded our 2005 capital expenditures with cash generated from our operations.
Under the provisions of the purchase agreement with Shell for our El Dorado Refinery, we have made, or may be required to make, contingent earn-out payments for each of the years 2000 through 2007 equal to one-half of the excess over $60.0 million per year of the El Dorado Refinery’s annual revenues less its raw material, freight and other costs and refinery operating expenses, excluding depreciation. The total amount of these contingent earn-out payments is capped at $40.0 million, with an annual cap of $7.5 million. A payment of $7.5 million was required based on 2004 results, and was accrued as of December 31, 2004 and paid in January 2005. Such contingent earn-out payments are recorded as additional acquisition costs. Based on the results of operations for the year ended December 31, 2005, a payment of $7.5 million was required, and was accrued as of December 31, 2005, and paid in January 2006. Including the payment we made in early 2006, we have paid a total of $22.5 million for contingent earn-out payments.
During the first quarter of 2005, we received the remaining payments aggregating $2.1 million from our insurance companies related to the 2004 coker fire at our Cheyenne Refinery.
During the year ended December 31, 2005, we received net proceeds of $5.5 million from the sales of assets, including the sale of FGI, LLC, our asphalt terminal and storage facility located in Grand Island, Nebraska, during the fourth quarter of 2005.
Cash flows used in financing activities. During the year ended December 31, 2005, we issued 3,467,650 shares of common stock due to stock option exercises by employees and members of our Board of Directors, for which we received $23.6 million in cash and 190,958 shares ($3.6 million) of our common stock, now held as treasury stock. During the year ended December 31, 2005, we received another 409,156 shares ($11.5 million) of our common stock, now held as treasury stock, from employees and members of our Board of Directors who surrendered stock to pay withholding taxes related to stock option exercises. We also acquired 37,364 shares ($615,000) of our common stock, now held as treasury stock, from employees who surrendered stock to pay withholding taxes on shares of restricted stock that vested during the first quarter of 2005.
We have authorization from our Board of Directors to repurchase up to 16 million shares of our common stock. Through December 2004, we had purchased 8,734,732 shares of common stock under this stock repurchase program. During the year ended December 31, 2005, we purchased an additional 720,800 shares ($24.6 million) in open market transactions under this program, $1.9 million of which did not settle until early 2006 and were accrued as of December 31, 2005. At December 31, 2005, we had authorization remaining under this program to purchase an additional 6,544,468 shares. On November 30, 2005, our Board of Directors confirmed utilizing up to $100 million for share repurchases in the near-term (which we anticipate continuing throughout 2006) under this program, and as of December 31, 2005, $7.6 million (195,800 shares) of the $100 million had been utilized for repurchases. During January and February 2006, we purchased an additional 153,494 shares ($6.4 million) under this program.
As of December 31, 2005, we had $150.0 million of long-term debt and no borrowings under our $225 million revolving credit facility. We had $69.5 million of outstanding letters of credit under our revolving credit facility. We were in compliance with the financial covenants of our revolving credit facility as of December 31, 2005. We had shareholders’ equity of $445.1 million as of December 31, 2005.
Our Board of Directors declared quarterly cash dividends of $0.03 per share of common stock  in December 2004 and March 2005, which were paid in January 2005 and April 2005, respectively. Our Board of Directors declared quarterly cash dividends of $0.04 per share of common stock in June 2005 and September 2005, which were paid in July 2005 and October 2005, respectively. Our Board of Directors declared a quarterly cash dividend of $0.04 per share of common stock and a special cash dividend of $1.00 per share of common stock in December 2005, which was paid in January 2006. The total cash required for the dividend declared in December 2005 was approximately $58.7 million and was accrued as a dividend payable at quarter-end.
Future capital expenditures. Compliance with the upcoming ultra low sulfur diesel requirements affecting our Refineries will require additional capital expenditures through mid-2006. Total capital, including capitalized interest, that we will spend to comply with these regulations is currently estimated to be approximately $106.5 million at the El Dorado Refinery and $16.3 million at the Cheyenne Refinery. Expenditures for the ultra low sulfur diesel projects through December 31, 2005 (including 2004 and 2005 expenditures) were $77.8 million at the El Dorado Refinery and $6.2 million at the Cheyenne Refinery. The remaining costs for the ultra low sulfur diesel projects at both Refineries will be incurred before mid-2006. The American Jobs Creation Act of 2004 allows us, as a small business refiner, to deduct for federal income tax purposes 75% of the qualified costs related to these low sulfur diesel expenditures in the years incurred and will provide income tax credits based on the resulting production of ultra low sulfur diesel for up to 25% of the remaining qualified costs. Production of ultra low sulfur diesel is expected to begin by mid-2006 at our Refineries.
Capital expenditures aggregating approximately $205.7 million are currently planned for 2006, and include $104.0 million at our El Dorado Refinery, $101.0 million at our Cheyenne Refinery, and $658,000 for capital expenditures in our Denver and Houston offices, and for our share of crude oil pipeline projects. The $104.0 million of planned capital expenditures for our El Dorado Refinery includes approximately $28.7 million for the ultra low sulfur diesel project discussed above, $46.5 million on the crude unit and vacuum tower expansion, discussed below, as well as environmental, operational, safety, administrative and payout projects. The $101.0 million of planned capital expenditures for our Cheyenne Refinery includes approximately $10.1 million for the ultra low sulfur diesel project discussed above, $50.8 million on the coker expansion and $5.1 million on the crude fractionation project, both discussed below, as well as environmental, operational, safety, administrative and payout projects. Our 2006 capital expenditures will be funded with cash generated by our operations and the utilization of a portion of our existing cash balance, if necessary.
Our Board of Directors, in November 2005, approved three capital improvement projects which are anticipated to be completed between 2007 and 2008. These projects include a $150 million crude unit and vacuum tower expansion at our El Dorado Refinery, a $78.5 million coker expansion and revamp at our Cheyenne Refinery and an $8.2 million crude fractionation project at our Cheyenne Refinery. The above amounts include estimated capitalized interest. The crude unit and vacuum tower expansion at the El Dorado Refinery will allow for higher crude charge rates (including a much greater percentage of heavy crude oil) and higher gasoline and distillate yields. This project will likely be implemented in the spring of 2008 during the next planned turnaround for the crude/vacuum unit complex. The coker expansion at the Cheyenne Refinery, which is anticipated to be completed in 2007, will significantly decrease the amount of asphalt produced and increase the amount of higher margin light products such as gasoline and diesel. The crude fractionation project at the Cheyenne Refinery will allow us to replace light crude purchases with less expensive heavier crude oil while maintaining gasoline and diesel yields. We expect to fund these projects with existing cash and internally generated cash flow.
The Energy Tax Incentives Act of 2005 (the “Act”) contains provisions that may affect certain of our financial or operational considerations in the coming years. The Act includes a provision that would allow a refiner to expense capital costs associated with expansion of refining capacity, as determined by the manufacture of liquid products other than asphalt and lube oil, in excess of 5% above previously produced volumes. The Act also requires that refiners, importers and blenders ensure that renewable fuel (e.g., ethanol) is blended into the nation’s gasoline pool at escalating, prescribed rates beginning with a 4.0 billion gallon requirement in 2006 and increasing to 7.5 billion gallons in 2012. We are currently evaluating the potential consequence that these and other provisions of the Act may have on our future operations.
 
Contractual Cash Obligations
The table on the following page lists the contractual cash obligations we have by period. These items include our long-term debt based on their maturity dates, our operating lease commitments, purchase obligations and other long-term liabilities.
Our operating leases include building, equipment, aircraft and vehicle leases, which expire from 2006 through 2011, as well as an operating sublease for the use of the cogeneration facility at our El Dorado Refinery. The non-cancelable sublease, entered into in connection with the acquisition of our El Dorado Refinery in 1999, expires in 2016 with an option that allows us to renew the sublease for an additional eight years.
Purchase obligations include agreements to purchase goods or services that are enforceable and legally binding and that specify terms, including fixed or minimum quantities to be purchased, fixed, minimum or variable price provisions, and the approximate timing of the transaction. Purchase obligations exclude agreements that are cancelable without penalty.
We have a five-year crude oil supply agreement, which began in 2003, with Baytex Marketing Ltd. (“Baytex”), a Canadian crude oil producer. We also have two contracts that obligate us for crude oil pipeline capacity into 2015 on the Express Pipeline from Hardisty, Alberta to Guernsey, Wyoming from which we then have pipeline access to take the crude oil to our Cheyenne Refinery. We were allowed to assign a portion of our capacity in earlier years for additional capacity in later years with this first contract. Our crude oil supply agreement with Baytex includes an assignment of a portion of our pipeline capacity obligation to it. The amounts shown in the table on the following page for transportation, terminalling and storage contractual obligations are net of $14.4 million, the approximate cost of the pipeline capacity assigned to other parties for the term of that agreement.
During 2004, we entered into a Transportation Services Agreement (“Agreement”) to transport 20,000 bpd of crude oil on the Spearhead Pipeline from Griffith, Indiana to Cushing, Oklahoma once the reversal of the pipeline was completed. Enbridge Energy Company completed the reversal of the Spearhead Pipeline and has been accepting line fill volumes since December 2005. Deliveries into Cushing are scheduled to start during March 2006. The amounts shown in the table on the following page for transportation, terminalling and storage contractual obligations include our anticipated commitments on the Spearhead Pipeline.
For more information on the agreements discussed above, see “Lease and Other Commitments” in Note 8 in the “Notes to Consolidated Financial Statements.”


Contractual Cash Obligations
  
Payments Due by Period
  
   
Total
  
Within
1 Year
  
Within
2-3 years
  
Within
4-5 years
  
After
5 years
  
   
(in thousands)
 
  
Long-term debt (1)
  
$
150,000
  
$
-
  
$
-
  
$
-
  
$
150,000
  
Operating leases
    
93,673
    
13,371
    
21,990
    
21,356
    
36,956
  
Purchase obligations:
                                
Baytex crude supply (2)
    
675,741
    
336,863
    
338,878
    
-
    
-
  
Other crude supply, feedstocks and
natural gas (2)
    
404,545
    
404,084
    
461
    
-
   
-
  
Transportation, terminalling and storage
    
159,537
    
22,860
    
34,206
    
36,679
    
65,792
  
Ultra low sulfur diesel refinery projects (3)
    
11,636
    
11,636
    
-
    
-
    
-
  
Other goods and services
    
9,869
    
7,443
    
1,523
    
903
    
-
  
Total purchase obligations (4)
    
1,261,328
    
782,886
    
375,068
    
37,582
    
65,792
  
Long-term accrued turnaround cost
    
15,122
    
-
    
11,621
    
3,501
    
-
  
Pension funding requirement (5)
    
1,173
    
1,173
    
-
    
-
    
-
  
Other long-term liabilities
    
8,079
    
-
    
2,912
    
575
    
4,592
  
Total contractual cash
  
$
1,529,375
  
$
797,430
  
$
411,591
  
$
63,014
  
$
257,340
  

(1)
Cash requirements for interest on the long-term debt are approximately $9.9 million per year.
(2)
Baytex crude supply and other crude supply, feedstocks and natural gas future obligations were calculated using current market prices and/or prices established in applicable contracts. Of these obligations, $422.1 million relate to January and February 2006 feedstock and natural gas requirements of the Refineries.
(3)  
The amounts for ultra low sulfur diesel refinery projects reflected here relate to our current commitments as of December 31, 2005, not the total estimated costs of the projects. See Note 8 in the “Notes to Consolidated Financial Statements” for total estimated costs of the projects.
(4)  
In the fourth quarter of 2005, we entered into various contracts for future expansion and revamp construction at our Refineries. See “-Future capital expenditures” above for total estimated cost and completion dates for these projects. We signed a contract in December 2005 for $86.8 million of the $150 million total cost of the El Dorado Refinery crude unit and vacuum tower expansion. At December 31, 2005, we had no current obligations associated with this contract. At December 31, 2005, we had accrued approximately $1.5 million for costs incurred for the Cheyenne Refinery coker expansion and revamp project. The agreements are not included in the above table because they were cancellable at December 31, 2005 without penalty, except for the amounts accrued at year end.
(5)
Includes the estimated pension funding requirement in 2006 for our cash balance pension plan. Funding requirements for remaining years will be based on actuarial estimates and actual experience. Our retiree health care plan is unfunded. Future payments for retiree health care benefits are estimated for the next ten years in Note 7 “Employee Benefit Plans” in the “Notes to Consolidated Financial Statements.”
 
Off-Balance Sheet Arrangements
We have an interest in one unconsolidated entity (See Note 1 “Nature of Operations” in the “Notes to Consolidated Financial Statements”). Other than facility and equipment leasing agreements, we do not participate in any transactions, agreements or other contractual arrangements, which would result in any off-balance sheet liabilities or other arrangements to us.
 
Environmental
See “Environmental” in Note 8 in the “Notes to Consolidated Financial Statements.”
 
Application of Critical Accounting Policies
The preparation of financial statements in accordance with United States generally accepted accounting principles requires our management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates. The following summary provides information about our critical accounting policies, including identification of those involving critical accounting estimates, and should be read in conjunction with Note 2 in the “Notes to Consolidated Financial Statements”, which summarizes our significant accounting policies.
Turnarounds. The costs for turnarounds (scheduled and required shutdowns of refinery operating units for significant overhaul and refurbishment) are ratably accrued over the period from the prior turnaround to the next scheduled turnaround. Since this policy relies on our estimated costs for the next turnaround, adjustments occur as the estimate changes or even when the turnaround is in progress should more or less extensive work be necessary than was anticipated. These accruals are included in our Consolidated Balance Sheets in the accrued turnaround cost and long-term accrued turnaround cost. The turnaround accrual, any turnaround costs in excess of accrual incurred at the time of turnaround, or reductions of expenses when the actual costs are less than the estimate are included in “Refinery operating expenses, excluding depreciation” in our Consolidated Statements of Income. Turnaround costs include contract services, materials and rental equipment.
Inventories. Inventories of crude oil, unfinished products and all finished products are recorded at the lower of cost on a FIFO basis or market. Crude oil includes both domestic and foreign crude oil volumes at its cost and associated freight and other cost. Unfinished products (work in process) include any crude oil that has entered into the refining process, and other feedstocks that are not finished as far as refining operations are concerned. These include unfinished gasoline and diesel, blendstocks and other feedstocks. Finished product inventory includes saleable gasoline, diesel, jet fuel, chemicals, asphalt and other finished products. Unfinished and finished products inventory values have components of raw material, the associated raw material freight and other costs, and direct refinery operating expense allocated when refining begins relative to their proportionate market values. The FIFO method of accounting for inventories sometimes results in our recognizing substantial gains (in periods of rising prices) or losses (in periods of falling prices) from our inventories of crude oil and products. While we believe that this accounting method more accurately reflects the results of our operations, since many other refining companies instead utilize the last-in, first-out (“LIFO”) method of accounting for inventories, a comparison of our results to other refineries must take into account the impact of the inventory accounting differences.
Asset Retirement Obligations. We account for asset retirement obligations as required under the Financial Accounting Standards Board (“FASB”) Statement of Financial Accounting Standard (“FAS”) No. 143, “Accounting for Retirement Asset Obligations.” FAS No. 143 requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred, with the associated asset retirement costs being capitalized as a part of the carrying amount of the long-lived asset. FAS No. 143 also includes disclosure requirements that provide a description of asset retirement obligations and reconciliation of changes in the components of those obligations.
In March 2005, the FASB issued FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations” (“FIN 47”). FIN 47 clarified that the term “conditional asset retirement obligation” as used in FAS No. 143 refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. Since the obligation to perform the asset retirement activity is unconditional, FIN 47 provides that a liability for the fair value of a conditional asset obligation should be recognized if that fair value can be reasonably estimated, even though uncertainty exists about the timing and/or method of settlement. FIN 47 also clarifies when an entity would have sufficient information to reasonably estimate the fair value of a conditional asset retirement obligation under FAS No. 143. We adopted FIN 47 as of December 31, 2005 for which we recorded a net asset retirement obligation of $5.5 million, recognized $4.0 million in 2005 as the pretax cumulative effect of an accounting change ($2.5 million after tax) and recorded a $1.5 million increase in property, plant and equipment.
In order to determine fair value, management must make certain estimates and assumptions, including, among other things, projected cash flows, a credit-adjusted risk-free interest rate, and an assessment of market conditions that could significantly impact the estimated fair value of the asset retirement obligation. These estimates and assumptions are very subjective; however, we believe that we have adequately accrued for our asset retirement obligations at this time and that changes in estimates in future periods would not have a significant effect on our results of operations or financial condition.
Environmental Expenditures. Environmental expenditures are expensed or capitalized based upon their future economic benefit. Costs that improve a property’s pre-existing condition, and costs that prevent future environmental contamination, are capitalized. Remediation costs related to environmental damage resulting from operating activities subsequent to acquisition are expensed. Liabilities for these expenditures are recorded when it is probable that obligations have been incurred and the amounts can be reasonably estimated. Such estimates are subject to change due to many factors, including the identification of new sites requiring remediation, changes in environmental laws and regulations and their interpretation, additional information related to the extent and nature of remediation efforts, and potential improvements in remediation technologies.
Pension and Other Post-retirement Benefit Obligations. We have significant pension and post-retirement benefit liabilities and costs that are developed from actuarial valuations. Inherent in these valuations are key assumptions, including discount rates, expected returns on plan assets and health care cost trend rates. Changes in these assumptions are primarily influenced by factors outside of our control. These assumptions can have a significant effect on the amounts reported in our consolidated financial statements. See Note 7 in the “Notes to Consolidated Financial Statements” for more information on these plans and the current assumptions used.
 
New Accounting Pronouncements
See “New Accounting Pronouncements” in Note 2 in the “Notes to Consolidated Financial Statements.” No new pronouncements are expected to have a material impact on our financial statements.
 
Market Risks
See the Item 7A “Quantitative and Qualitative Disclosure about Market Risk” and Notes 2 and 10 in the “Notes to Consolidated Financial Statements” under “Price Risk Management Activities” for a discussion of our various price risk management activities. When we make the decision to manage our price exposure, our objective is generally to avoid losses from negative price changes, realizing we will not obtain the benefit of positive price changes.


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

Price Risk Management Activities. At times, we enter into commodity derivative contracts to manage our price exposure to our inventory positions, purchases of foreign crude oil and consumption of natural gas in the refining process or to fix margins on certain future production. Gains or losses on commodity derivative contracts accounted for as hedges are recognized in the Consolidated Statements of Income as “Raw material, freight and other costs” or “Refinery operating expenses, excluding depreciation” when the associated transactions are consummated, while gains and losses on transactions accounted for using mark-to-market accounting are reflected in “Other revenues” in the Consolidated Statements of Income at each period end. See “Price Risk Management Activities” under Notes 2 and 10 in the “Notes to Consolidated Financial Statements.”
 
Operating Data
The following tables set forth the refining operating statistical information on a consolidated basis and for each Refinery for 2005, 2004 and 2003. The statistical information includes the following terms:

·  
Charges - the quantity of crude oil and other feedstock processed through Refinery units on a bpd basis.
·  
Manufactured product yields - the volumes of specific materials that are obtained through the distilling of crude oil and the operations of other refinery process units on a bpd basis.
·  
Gasoline and diesel crack spreads - The average non-oxygenated gasoline and diesel net sales prices that we receive for each product less the average WTI crude oil price at Cushing, Oklahoma.
·  
Light/heavy crude oil differential - the average differential between the benchmark WTI crude oil priced at Cushing, Oklahoma and the heavy crude oil delivered to the Cheyenne Refinery.
·  
WTI/WTS crude oil differential - the average differential between benchmark WTI crude oil priced at Cushing, Oklahoma and the West Texas sour crude oil priced at Midland, Texas.

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



Cheyenne Refinery:
          
 
  
               
Years Ended December 31,
  
2005
  
2004
  
2003
  
Charges (bpd)
             
Light crude
    
8,575
    
6,645
    
5,405
  
Heavy crude
    
38,347
    
38,408
    
40,284
  
Other feed and blend stocks
    
4,399
    
4,392
    
5,966
  
Total
    
51,321
    
49,445
   
51,655
  
                     
Manufactured product yields (bpd)