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Article by DailyStocks_admin    (01-23-08 02:42 AM)

The Daily Magic Formula Stock for 01/22/2008 is Frontier Oil Corp. According to the Magic Formula Investing Web Site, the ebit yield is 24% and the EBIT ROIC is 75-100 %.

Dailystocks.com only deals with facts, not biased journalism. What is a better way than to go to the SEC Filings? It's not exciting reading, but it makes you money. We cut and paste the important information from SEC filings for you to get started on your research on a specific company.


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BUSINESS OVERVIEW

Overview
We are an independent energy company engaged in crude oil refining and the wholesale marketing of refined petroleum products. We operate refineries (the “Refineries”) in Cheyenne, Wyoming and El Dorado, Kansas with a total annual average crude oil capacity of approximately 162,000 barrels per day (“bpd”). Both of our Refineries are complex refineries, which means that they can process heavier, less expensive types of crude oil and still produce a high percentage of gasoline, diesel fuel and other high margin refined products. We focus our marketing efforts in the Rocky Mountain region and the Plains States, which we believe are among the most attractive refined products markets in the United States. The operations of refining and marketing of petroleum products are considered part of one reporting segment.
Cheyenne Refinery. Our Cheyenne Refinery has a permitted crude oil capacity of 52,000 bpd on a twelve-month average. We market its refined products primarily in the eastern slope of the Rocky Mountain region, which encompasses eastern Colorado (including the Denver metropolitan area), eastern Wyoming and western Nebraska (the “Eastern Slope”). The Cheyenne Refinery has a coking unit, which allows the refinery to process extensive amounts of heavy crude oil for use as a feedstock. The ability to process heavy crude oil lowers our raw material costs because heavy crude oil is generally less expensive than lighter types of crude oil. For the year ended December 31, 2006, heavy crude oil constituted approximately 73% of the Cheyenne Refinery’s total crude oil charge. For the year ended December 31, 2006, the Cheyenne Refinery’s product yield included gasoline (42%), diesel fuel (31%) and asphalt and other refined petroleum products (27%).
El Dorado Refinery. The El Dorado Refinery is one of the largest refineries in the Plains States and the Rocky Mountain region with an average crude oil capacity of 110,000 bpd. The El Dorado Refinery can select from many different types of crude oil because of its direct access to Cushing, Oklahoma, which is connected by pipeline to the Gulf Coast and, beginning in early 2006, to Canada. This access, combined with the El Dorado Refinery’s complexity (including a coking unit), gives it the flexibility to refine a wide variety of crude oils. In connection with our acquisition of the El Dorado Refinery in 1999, we entered into a 15-year refined product offtake agreement for gasoline and diesel production at this refinery with Shell Oil Products US (“Shell”). Shell has also agreed to purchase all jet fuel production until the end of the product offtake agreement. As our deliveries to Shell under the refined product offtake agreement have declined, we have marketed an increasing portion of the El Dorado Refinery’s gasoline and diesel in the same markets where Shell currently sells the El Dorado Refinery’s products, primarily in Denver and throughout the Plains States. For the year ended December 31, 2006, the El Dorado Refinery’s product yield included gasoline (52%), diesel and jet fuel (36%) and chemicals and other refined petroleum products (12%).
Other Assets. We also own a 34.72% interest in a crude oil pipeline in Wyoming and a 50% interest in two crude oil tanks in Guernsey, Wyoming.

Refining Operations
Varieties of Crude Oil and Products. Traditionally, crude oil has been classified within the following types:
• sweet (low sulfur content),
• sour (high sulfur content),
• light (high gravity),
• heavy (low gravity) and
• intermediate (if gravity or sulfur content is in between).
For the most part, heavy crude oil tends to be sour and light crude oil tends to be sweet. When refined, light crude oil produces a higher proportion of high margin refined products such as gasoline, diesel and jet fuel and, as a result, is more expensive than heavy crude oil. In contrast, heavy crude oil produces more low margin by-products and heavy residual oils. The discount at which heavy crude oil sells compared to light crude oil is known in the industry as the light/heavy spread or differential, while the discount at which sour crude oil sells compared to light crude oil is known as the sweet/sour, or WTI/WTS, spread or differential. Coking units, such as the ones at our Refineries, can process certain by-products and heavy residual oils to produce additional volumes of gasoline and diesel, thus increasing the aggregate yields of higher margin refined products from the same initial volume of crude oil.
Refineries are frequently classified according to their complexity, which refers to the number, type and capacity of processing units at the refinery. Each of our Refineries possesses a coking unit, which provides substantial upgrading capacity and generally increases a refinery’s complexity rating. Upgrading capacity refers to the ability of a refinery to produce high yields of high margin refined products such as gasoline and diesel from heavy and intermediate crude oil. In contrast, refiners with low upgrading capacity must process primarily light, sweet crude oil to produce a similar yield of gasoline and diesel. Some low complexity refineries may be capable of processing heavy and intermediate crude oil, but they will produce large volumes of by-products, including heavy residual oils and asphalt. Because gasoline, diesel and jet fuel sales generally achieve higher margins than are available on other refined products, we expect that these products will continue to make up the majority of our production.
Refinery Maintenance. Each of the processing units at our Refineries requires regular maintenance and repair shutdowns (referred to as “turnarounds”) during which the unit is not in operation. Turnaround cycles vary for different units but are generally required every one to five years. In general, turnarounds at our Refineries are managed so that some units continue to operate while others are down for scheduled maintenance. We also coordinate operations by staggering turnarounds between our two Refineries. Turnarounds are implemented using our regular personnel as well as additional contract labor. Once started, turnaround work typically proceeds 24 hours per day to minimize unit downtime. We defer the costs of turnarounds when incurred and amortize them on a straight-line basis over the period of time estimated to lapse until the next turnaround occurs. We normally schedule our turnaround work during the spring or fall of each year. When we perform a turnaround, we may increase product inventories prior to the turnaround to minimize the impact of the turnaround on our sales of refined products.
During 2006, we had no major turnaround work at the El Dorado Refinery. However, an existing distillate hydrotreater was revamped and loaded with new catalyst in preparation for the production of ultra-low sulfur diesel (“ULSD”). Construction of a new hydrogen manufacturing plant and a new distillate hydrotreater was also completed during the second quarter of 2006. Those units were brought on-line, and we completed plant modifications necessary to fully comply with the 2006 regulations pertaining to the production of ULSD. At the El Dorado Refinery, the only 2007 major turnaround work is expected to be on the alkylation unit.
The major turnaround work performed at the Cheyenne Refinery during 2006 was on the alkylation plant. However, the distillate hydrotreater unit at the Cheyenne Refinery was also revamped in 2006 in preparation for the production of ULSD, including the modification of an existing reactor and addition of a new reactor and furnace. For 2007, the major turnaround work planned at the Cheyenne Refinery is on the fluid catalytic cracking unit (“FCCU”), the crude unit and the coker. Timing of these turnarounds is expected to coincide with our shutdown of the delayed coking unit to implement the planned coker unit expansion.

Marketing and Distribution
Cheyenne Refinery. The primary market for the Cheyenne Refinery’s refined products is the Eastern Slope. For the year ended December 31, 2006, we sold approximately 85% of the Cheyenne Refinery’s gasoline sales volumes in Colorado and 12% in Wyoming. For the year ended December 31, 2006, we sold approximately 69% of the Cheyenne Refinery’s diesel in Wyoming and 25% in Colorado. Because of the location of the Cheyenne Refinery, we are able to sell a significant portion of its diesel product from the truck rack at the Refinery, thereby eliminating transportation costs. The gasoline and remaining diesel produced by this Refinery are primarily shipped via pipeline to terminals for distribution by truck or rail. Pipeline shipments from the Cheyenne Refinery are handled mainly by the Plains All American Pipeline (formerly Rocky Mountain Pipeline), serving Denver and Colorado Springs, Colorado, and the ConocoPhillips pipeline, serving Sidney, Nebraska.
We sell refined products from our Cheyenne Refinery to a broad base of independent retailers, jobbers and major oil companies. Refined product prices are determined by local market conditions at distribution centers known as “terminal racks,” and prices at the terminal racks are posted daily by sellers. The customer at a terminal rack typically supplies its own truck transportation. In the year ended December 31, 2006, approximately 88% of the Cheyenne Refinery’s sales were made to its 25 largest customers compared to the year ended December 31, 2005, when approximately 85% of the Cheyenne Refinery’s sales were made to its 25 largest customers. Occasionally, marketing volumes exceed the Refinery’s production, in which case we purchase product in the spot market as needed.
El Dorado Refinery. The primary markets for the El Dorado Refinery’s refined products are Colorado and the Plains States, which include the Kansas City metropolitan area. The gasoline, diesel and jet fuel produced by the El Dorado Refinery are primarily shipped via pipeline to terminals for distribution by truck or rail. The Valero pipeline, serving the northern Plains States, the Magellan Pipeline Company, L.P. (“Magellan”) mountain pipeline serving Denver, Colorado, and the Magellan mid-continent pipeline serving the Plains States handle shipments from our El Dorado Refinery.
For the year ended December 31, 2006, Shell was the El Dorado Refinery’s largest customer, representing approximately 64% of the El Dorado Refinery’s total sales and 44% of our total sales. Under the offtake agreement, Shell purchases gasoline, diesel and jet fuel produced by the El Dorado Refinery at market-based prices. Initially in 1999, Shell purchased all of the El Dorado Refinery’s production of these products. Beginning in 2000, we retained and marketed 5,000 bpd of the Refinery’s gasoline and diesel production. The retained portion increases by 5,000 bpd each year through 2009. In 2006, we retained 35,000 bpd of the Refinery’s gasoline and diesel production. As our sales to Shell under this agreement decrease, we intend to sell the gasoline and diesel produced by the El Dorado Refinery in the same general markets as Shell currently does, as described above.

Competition
Cheyenne Refinery. The most competitive market for the Cheyenne Refinery’s products is the Denver metropolitan area. Other than the Cheyenne Refinery, three principal refineries serve the Denver market: a 70,000 bpd refinery near Rawlins, Wyoming and a 25,000 bpd refinery in Casper, Wyoming, both owned by Sinclair Oil Company (“Sinclair”); and a 90,000 bpd refinery located in Denver and owned by Suncor Energy (U.S.A.) Inc. (“Suncor”). Five product pipelines also supply Denver, including three from outside the region that enable refined products from other regions to be sold in the Denver market. Refined products shipped from other regions typically bear the burden of higher transportation costs.
The Suncor refinery located in Denver has lower product transportation costs to serve the Denver market than we do. However, the Cheyenne Refinery has lower crude oil transportation costs because of its proximity to the Guernsey, Wyoming hub, the major crude oil pipeline hub in the Rocky Mountain region, and because of our ownership interest in the Centennial pipeline, which runs from Guernsey to the Cheyenne Refinery. Moreover, unlike Sinclair and Suncor, we only sell our products to the wholesale market. We believe that our commitment to the wholesale market gives us certain marketing advantages over our principal competitors in the Eastern Slope area, all of which also have retail outlets, because we do not compete directly with independent retailers of gasoline and diesel.
El Dorado Refinery. The El Dorado Refinery faces competition from other Plains States and mid-continent refiners, but the principal competitors for the El Dorado Refinery are Gulf Coast refiners. Although our Gulf Coast competitors typically have lower production costs because of their size (economies of scale) than the El Dorado Refinery, we believe that our competitors’ higher refined product transportation costs allow our El Dorado Refinery to compete effectively in the Plains States and Rocky Mountain region with the Gulf Coast refineries. The Plains States and mid-continent regions are supplied by three product pipelines that originate from the Gulf Coast.

Crude Oil Supply
Cheyenne Refinery. In the year ended December 31, 2006, we obtained approximately 58% of the Cheyenne Refinery’s crude oil charge from Canada, 22% from Wyoming, 17% from Colorado and 3% from other domestic sources. During the same period, heavy crude oil constituted approximately 73% of the Cheyenne Refinery’s total crude oil charge, compared to 82% in 2005 as we increased our charges of lighter crude oil in 2006 to take advantage of market opportunities. Cheyenne is 88 miles south of Guernsey, Wyoming, the main hub and crude oil trading center for the Rocky Mountain region. We transport up to 25,000 bpd of crude oil from Guernsey to the Cheyenne Refinery through the Centennial pipeline. Additional crude oil volumes are transported on an alternative common carrier pipeline. We anticipate that by mid-2007 Plains All American Pipeline will have completed construction of a new pipeline from Guernsey to Cheyenne, Wyoming. Ample quantities of heavy crude oil are available at Guernsey, including both locally produced Wyoming general sour and imported Canadian heavy crude oil, which is supplied by the Express pipeline system and the Poplar and Butte pipelines. The Cheyenne Refinery’s processing of 73% heavy crude oil in 2006, and our ability to process a higher percentage of heavy crude oil, gives us a distinct advantage over the three other Eastern Slope refineries, none of which has the necessary upgrading capacity to process such high volumes of heavy crude oil.
We purchase crude oil for the Cheyenne Refinery from several suppliers, including major oil companies, marketing companies and large and small independent producers, under arrangements which contain market-responsive pricing provisions. Many of these arrangements are subject to cancellation by either party or have terms that are not in excess of one year and are subject to periodic renegotiation. We have a five-year crude oil supply agreement with Baytex Marketing Ltd., which commenced January 1, 2003, and expires December 31, 2007. This agreement provides for the purchase of up to 20,000 bpd of a Lloydminster crude oil blend, a heavy Canadian crude oil. This type of crude oil typically sells at a discount from lighter crude oil prices. Our price for crude oil under the agreement is equal to 71% of the simple average of the near month settlement prices of the NYMEX light sweet crude oil contracts during the month of delivery, plus the cost of transportation based on the Express Pipeline tariff from Hardisty, Alberta to Guernsey, Wyoming, less $0.25 per barrel.
El Dorado Refinery. In the year ended December 31, 2006, we obtained approximately 67% of the El Dorado Refinery’s crude oil charge from Texas, 15% from Canada, 8% from Kansas, 6% from Louisiana, and the remaining 4% from other foreign and domestic locations. El Dorado is 125 miles north of Cushing, Oklahoma, a major crude oil hub. The Cushing hub is supplied by the Seaway pipeline, which runs from the Gulf Coast; the Basin pipeline, which runs through Wichita Falls, Texas from West Texas; the Sun pipeline, which originates at the Gulf Coast and connects to the Basin pipeline at Wichita Falls and the Spearhead Pipeline which connects at Griffith, Indiana with the Enbridge Pipeline to bring crude from Canada. The Osage pipeline runs from Cushing to El Dorado and transported approximately 92% of our crude oil charge during the year ended December 31, 2006. The remainder of our crude oil charge was transported to the El Dorado Refinery through Kansas gathering system pipelines. We have a Transportation Services Agreement to transport 38,000 bpd of crude oil on the Spearhead Pipeline from Griffith, Indiana to Cushing, Oklahoma, which enables us to transport heavy Canadian crude oil to our El Dorado Refinery. The initial term of this agreement is for a period of ten years from the actual commencement date of March 2006. We have the right to extend the agreement for an additional ten years and increase the volume transported under a preferential tariff to 50,000 bpd.

Saf e ty
We are subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) and comparable state occupational safety statutes.
The Cheyenne Refinery’s OSHA recordable incident rate in 2006 of 1.67 is higher than the latest reported industry average of 1.05 in 2005 as compiled by the National Petrochemical and Refiner’s Association (“NPRA”). While the frequency of injuries at the Cheyenne Refinery has risen above the NPRA average and our 2005 OSHA recordable incident rate of 1.07, we continue to emphasize safety and the various programs in place that support maintenance of a strong safety culture. This emphasis was evidenced by our 2006 achivement of completing more than four years without a lost-time accident. These efforts are supported by both management and our union employees. We are working to strengthen our behavioral-based safety observation programs as well as our process safety management programs. Because our contractor injury rate is higher than our employee injury rate at our Cheyenne Refinery, we increased our efforts in the area of contractor safety in 2006. By improving the training of the contractor workforce in general, we believe that we can improve the safety of the outside labor we hire at our Cheyenne Refinery as well as that of other industrial facilities in our geographic region.
The El Dorado Refinery’s OSHA recordable incident rate of 1.47 in 2006 compares to a rate of zero for 2005. The industry standard incident rate is 1.05 as last reported by NPRA for 2005. After completing 16 months in March 2006 without a recordable injury, El Dorado experienced a recordable event in April and four other OSHA recordable events for the rest of 2006. Management and employees at the El Dorado Refinery remain committed to those programs, processes and behaviors that had helped achieve a run of almost a year-and-a-half without a single OSHA recordable event. Improvement in contractor safety was a key initiative for the El Dorado refinery during 2006. Behavior-based safety programs were introduced in 2004 for our own employees. During 2006, we included the majority of our contractor base in these programs as well. These efforts resulted in a significant increase in contractor safety awareness and much improved contractor safety results.
Our employees and management continue to dedicate their efforts to a balanced safety program that combines individual behavioral elements in a safety-coaching environment with structured management-driven programs to improve the safety of the facility and operating procedures. Our objective is a safe working environment for employees who know how to work safely. Encouraging all employees to contribute toward improving safety performance through personal involvement in safety-related activities is an industry-proven way to reduce injuries.

Government Regulation

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

Centennial Pipeline Regulation. We own a 34.72% undivided interest in the Centennial pipeline, which runs approximately 88 miles from Guernsey to Cheyenne, Wyoming. Suncor Pipe Line Company is the sole operator of the Centennial pipeline and holds the remaining ownership interest. The Cheyenne Refinery receives up to 25,000 bpd of crude oil feedstock through the Centennial pipeline. Under the terms of the operating agreement for the Centennial pipeline, the costs and expenses incurred to operate and maintain the Centennial pipeline are allocated to us on a combined basis, based on our throughput and ownership interest. The Centennial pipeline is subject to numerous federal, state and local laws and regulations relating to the protection of health, safety and the environment. We believe that the Centennial pipeline is operated in accordance with all applicable laws and regulations. We are not aware of any material pending legal proceedings to which the Centennial pipeline is a party.

Employees
At December 31, 2006, we employed approximately 747 full-time employees: 82 in the Houston and Denver offices, 285 at the Cheyenne Refinery, and 380 at the El Dorado Refinery. The Cheyenne Refinery employees include 99 administrative and technical personnel and 186 union members. The El Dorado Refinery employees include 138 administrative and technical personnel and 242 union members. The union members at our El Dorado Refinery are represented by the United Steel, Paper and Forestry, Rubber, Manufacturing, Energy, Allied Industrial and Service Workers International Union (“USW”). The union members at our Cheyenne Refinery are represented by seven bargaining units, the largest being the USW.
For our Cheyenne Refinery, the current contract between the Company, the USW, and its Local 8-0574 (which represents approximately 150 workers) expires in July 2009.
At our El Dorado Refinery, the current contract between the Company, the USW, and its Local 5-241 (which represents approximately 250 workers) expires in January 2009.

CEO BACKGROUND

Mr. James R. Gibbs (62) joined the Company in February 1982 and has been President and Chief Operating Officer since January 1987. He assumed the additional position of Chief Executive Officer on April 1, 1992 and additionally became Chairman of the Board on April 29, 1999. Mr. Gibbs is a member of the Board of Directors of Smith International, Inc., an oil field service company; an advisory director of Frost National Bank, Houston; and serves on the Board of Trustees of Southern Methodist University. Mr. Gibbs was elected a director of the Company in 1985.

Mr. Douglas Y. Bech (61) has been Chairman and Chief Executive Officer of Raintree Resorts International (“Raintree”) since August 1997. In November 2003, Teton Club LLC, a private resident club in Jackson, Wyoming owned by Raintree and a non-affiliated third party, Jackson Hole Ski Corp., filed for protection under Chapter 11 and the Teton Club LLC was successfully reorganized in August 2004. From 1994 to 1997, Mr. Bech was a partner in the law firm of Akin, Gump, Strauss, Hauer & Feld, L.L.P. of Houston, Texas. Since 1994, he has also been a managing director of Raintree Capital Company, LLC, a merchant banking firm. From 1993 to 1994, Mr. Bech was a partner of Gardere & Wynne, L.L.P. of Houston, Texas. From 1970 until 1993, Mr. Bech was associated with and a senior partner of Andrews Kurth LLP of Houston, Texas. Mr. Bech is a member of the Board of Directors of j2 Global Communications, Inc., an internet document communications company. He was appointed a director of the Company in 1993.

Mr. G. Clyde Buck (69) has been a Senior Vice President and Managing Director of the investment banking firm Sanders Morris Harris, Inc. (including predecessor firms) since 1998. From 1983 to 1998, he was a Managing Director of Dain Rauscher Corporation, also an investment banking firm. Mr. Buck is also a member of the Board of Directors of Smith International, Inc., an oilfield service company. He was appointed a director of the Company in 1999.

Mr. T. Michael Dossey (64) has been a management consultant located in Houston, Texas since April 2000. From April 2000 through September 2002, Mr. Dossey was a management consultant affiliated with the Adizes Institute of Santa Barbara, California. Prior to April 2000, Mr. Dossey spent 35 years with the Shell Oil Company and its affiliates. Prior to his retirement from Shell, his last assignment with Shell was General Manager-Mergers and Acquisitions for Equilon Enterprises LLC, an alliance between the domestic downstream operations of Shell and Texaco. He also had been Vice President and Business Manager for Shell Deer Park Refining Company, which was a joint venture operation with Pemex. Previously, he spent several years in Saudi Arabia where he was General Operations Manager for Saudi Petrochemical Company, a joint venture between Shell and the Saudi Arabian government. Earlier in his career, Mr. Dossey’s positions included various business and operational positions in Shell’s refining and petrochemical operations domestically and in Europe. He was appointed a director of the Company in 2000.

Mr. James H. Lee (58) is Managing General Partner and principal owner of Lee, Hite & Wisda Ltd., an oil and gas consulting and exploration firm, which he founded in 1984. From 1981 to 1984, Mr. Lee was a Principal with the oil and gas advisory firm of Schroder Energy Associates. He had prior experience in investment management, corporate finance and mergers and acquisitions at Cooper Industries Inc., a manufacturer of consumer and industrial products, and at White, Weld & Co. Incorporated, an investment bank and brokerage firm. Mr. Lee is a member of the Board of Directors of Forest Oil Corporation, an oil and gas exploration and production company. He was appointed a director of the Company in 2000.

Mr. Paul B. Loyd, Jr. (60) has been since 2002 an Executive-In-Residence for J.P. Morgan Capital Partners, Chairman of Penloyd Holdings LLC, a private company engaged in investment activities, and an independent private investor. He served as Chairman of the Board and Chief Executive Officer of R&B Falcon Corporation, the world’s largest offshore drilling company, from December 1997 until its merger in January 2001 with Transocean Sedco Forex. From April 1991 until December 1997, Mr. Loyd was Chairman of the Board and Chief Executive Officer of Reading & Bates Corporation, and prior to that time he had served as Assistant to the president of Atwood Oceanics International, President of Griffin-Alexander Company, and Chief Executive Officer of Chiles-Alexander International, Inc., all of which are companies in the offshore drilling industry. He has served as consultant to the Government of Saudi Arabia, and was a founder and principal of Loyd & Associates, Inc., an investment company focusing on the energy industry. Mr. Loyd is a member of the Board of Directors of Carrizo Oil & Gas, Inc., a public company engaged in oil and gas exploration and production, and Vetco International, a private company that manufactures and sells oil production and pressure control equipment; and he serves on the Board of Trustees of Southern Methodist University and the Executive Board of the Cox School of Business. He was appointed a director of the Company in 1994.

Mr. Michael E. Rose (60) has been involved in private investments since retiring from Anadarko Petroleum Corporation, one of the nation’s largest independent oil and gas companies (“Anadarko”), in January 2004. Mr. Rose had been with Anadarko for 24 years prior to his retirement, and from August 2000 until January 2004 he served as Executive Vice President Finance & Chief Financial Officer of Anadarko. He also served as Senior Vice President Finance & Chief Financial Officer from January 1993 until August 2000 and prior to that time was Vice President Finance & Chief Financial Officer from January 1987 until January 1993. From May 1981 until January 1987 he was Vice President & Controller of Anadarko. From 1971 until joining Anadarko as their Chief Accountant in 1978, he held a variety of positions with Atlantic Richfield Company, an integrated oil company now owned by BP. He was appointed a director of the Company in 2005.

SHARE OWNERSHIP


Includes 36,994 shares which Mr. Gibbs has the right to acquire under the Company’s Omnibus Incentive Compensation Plan within 60 days of the date for which beneficial ownership is provided in the table. Also includes 1,521,116 shares subject to a variable forward contract agreed to between Mr. Gibbs and a financial institution on February 28, 2005. In connection therewith, Mr. Gibbs has delivered all such shares to a custodial account for the duration of the contract, which concludes in October 2007. Mr. Gibbs has no dispositive power with respect to such shares while they remain in the custodial account, although he does retain voting power with respect to such shares. At the end of the contract period, Mr. Gibbs will be required to either (i) deliver a number of such shares, determined pursuant to a predetermined formula, to the financial institution in exchange for an aggregate of $11,566,109 in cash, or (ii) deliver a cash payment to the financial institution in exchange for the return of such shares from the custodial account. In addition to the 1,521,116 shares in which Mr. Gibbs has sole voting power and no dispositive power, he has sole voting power and sole dispositive power with respect to 36,912 shares and sole voting power for an additional 266,984 shares of restricted stock.

Includes 25,000 shares which Mr. Bech has the right to acquire under the Company’s Omnibus Incentive Compensation Plan within 60 days of the date for which beneficial ownership is provided in the table. Mr. Bech has sole voting and sole dispositive power with respect to 87,879 shares.

Includes 25,000 shares which Mr. Buck has the right to acquire under the Company’s Omnibus Incentive Compensation Plan within 60 days of the date for which beneficial ownership is provided in the table. Mr. Buck has sole voting and sole dispositive power with respect to 125,792 shares.

Includes 70,000 shares which Mr. Dossey has the right to acquire under the Company’s Omnibus Incentive Compensation Plan within 60 days of the date for which beneficial ownership is provided in the table. Mr. Dossey has sole voting and sole dispositive power with respect to 13,502 shares.

Includes 70,000 shares which Mr. Lee has the right to acquire under the Company’s Omnibus Incentive Compensation Plan within 60 days of the date for which beneficial ownership is provided in the table. Mr. Lee has sole voting and sole dispositive power with respect to 17,190 shares.

Includes 25,000 shares which Mr. Loyd has the right to acquire under the Company’s Omnibus Incentive Compensation Plan within 60 days of the date for which beneficial ownership is provided in the table. Mr. Loyd has sole voting and sole dispositive power with respect to 91,688 shares.


Mr. Rose has sole voting power and sole dispositive power with respect to 3,568 shares.


Includes 11,098 shares which Mr. Jennings has the right to acquire under the Company’s Omnibus Incentive Compensation Plan within 60 days of the date for which beneficial ownership is provided in the table. Mr. Jennings has sole voting and sole dispositive power with respect to 4,544 shares and sole voting power for an additional 104,648 shares of restricted stock.

Includes 12,332 shares which Mr. Eisman has the right to acquire under the Company’s Omnibus Incentive Compensation Plan within 60 days of the date for which beneficial ownership is provided in the table. Mr. Eisman has sole voting power for an additional 66,035 shares of restricted stock.

Includes 24,932 shares which Mr. Bechtol has the right to acquire under the Company’s Omnibus Incentive Compensation Plan within 60 days of the date for which beneficial ownership is provided in the table. Mr. Bechtol has sole voting and sole dispositive power with respect to 30,290 shares and sole voting power for an additional 42,094 shares of restricted stock.

Includes 43,700 shares which Mr. Galvin has the right to acquire under the Company’s Omnibus Incentive Compensation Plan within 60 days of the date for which beneficial ownership is provided in the table. Mr. Galvin has sole voting and sole dispositive power with respect to 134,986 shares and sole voting power for an additional 52,072 shares of restricted stock.

Includes 69,700 shares which Ms. Zupan has the right to acquire under the Company’s Omnibus Incentive Compensation Plan within 60 days of the date for which beneficial ownership is provided in the table. Ms. Zupan has sole voting and sole dispositive power with respect to 100,810 shares and sole voting power for an additional 51,196 shares of restricted stock.

COMPENSATION

During 2006, the directors each received an annual cash retainer of $35,000 plus cash payments of $1,500 per meeting attended. The Chairmen of the Nominating & Corporate Governance Committee (Mr. Lee) and the Safety and Environmental Committee (Mr. Buck) each received an annual committee chair stipend of $5,000. The Chairmen of the Compensation Committee (Mr. Bech) and Audit Committee (Mr. Rose) each received an annual committee chair stipend of $15,000. These stipends were paid due to the additional time required to serve effectively as a committee chairman.

The dollar amounts shown for Stock Awards reflect amounts (pursuant to FAS 123(R)) expensed by the Company in 2006 for restricted stock units held by the directors. Dollar amounts for Option Awards reflect amounts expensed (pursuant to FAS 123(R)) by the Company in 2006 for unvested stock options held by the directors. During 2006, each director received as part of his normal compensation an award of restricted stock units equivalent to 4,840 shares of common stock and having a grant date present value of $141,425. In addition, those directors having unexercised stock options outstanding on the ex-dividend date related to the Company’s $0.50 per share special dividend paid in January 2006 received restricted stock unit grants to compensate them for reduction in the value of such stock options resulting from the special dividend.

The Company does not provide a defined benefit pension plan for its directors. Mr. Bech participates in the Company’s Deferred Compensation Plan. However, his earnings on Deferred Compensation Plan balances did not exceed 120% of the long-term federal rate during 2006. As for all other participants in the Deferred Compensation Plan, the Company provides no subsidy or guarantee of the participant’s earnings on Deferred Compensation Plan balances.

MANAGEMENT DISCUSSION FROM LATEST 10K

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

Results of Operations
To assist in understanding our operating results, please refer to the operating data at the end of this analysis which provides key operating information for our Refineries. Refinery operating data is also included in our quarterly reports on Form 10-Q and on our web site address: http://www.frontieroil.com . We make our web site content available for informational purposes only. It should not be relied upon for investment purposes, nor is it incorporated by reference in this Form 10-K.

Overview
Our Refineries have a total annual average crude oil capacity of 162,000 bpd. The four significant indicators of our profitability which are reflected and defined in the operating data at the end of this analysis, are the gasoline crack spread, the diesel crack spread, the light/heavy crude oil differential and the WTI/WTS crude oil differential. Other significant factors that influence our financial results are refinery utilization, crude oil price trends, asphalt and by-product margins and refinery operating expenses (including natural gas and maintenance). Under our first-in, first-out (“FIFO”) inventory accounting method, crude oil price trends can cause significant fluctuations in the inventory valuation of our crude oil, unfinished products and finished products, thereby resulting in FIFO inventory gains when crude oil prices increase and FIFO inventory losses when crude oil prices decrease during the reporting period. We typically do not use derivative instruments to offset price risk on our base level of operating inventories. See “Price Risk Management Activities” under Item 7A for a discussion of our utilization of futures trading.
The NYMEX crude oil price was volatile during 2006, beginning the year at $61.04 per barrel, reaching a 2006 high of $77.03 per barrel in mid-July, reducing to the annual low of $55.81 per barrel in mid-November and ending 2006 at $61.05 per barrel. Crude oil market fundamentals and geopolitical considerations have caused crude oil prices to be volatile and generally higher than historic averages. The increase in crude oil prices, along with additional production of heavy and/or sour crude oil, increased our crude oil differentials during the year ended December 31, 2006, when compared to the same period in 2005. Our 2006 gasoline and diesel crack spreads were the highest in our history, while 2005 gasoline and diesel crack spreads were the second highest in our history.
As discussed in Note 3 in the “Notes to Consolidated Financial Statements,” during the fourth quarter of 2006 we changed our accounting method for the costs for planned major maintenance (“turnarounds”) from the accrual method to the deferral method. Turnarounds are the scheduled and required shutdowns of refinery processing units for significant overhaul and refurbishment. Under the deferral method, the costs of turnarounds are deferred when incurred and amortized on a straight-line basis over the period of time estimated to lapse until the next turnaround occurs. We adopted this new method of accounting for turnarounds in order to adhere to FSP No. AUG AIR-1 “Accounting for Planned Maintenance Activities,” which prohibits the accrual method of accounting for planned major maintenance activities. The Company elected to early adopt the FSP during the fourth quarter of 2006. The comparative consolidated financial statements for 2005 and 2004 have been adjusted to reflect the period specific effects of applying the new accounting principle. Deferred charges related to these turnaround costs are included in our Consolidated Balance Sheets in “Deferred charges and other assets.” The associated amortization expenses are included in “Refinery operating expenses, excluding depreciation” in our Consolidated Statements of Income.
As discussed in Note 7 in the “Notes to Consolidated Financial Statements,” we effected stock splits on June 17, 2005 and June 26, 2006. All prior period share-related numbers have been revised to reflect the effect of the stock splits.

2006 Compared with 2005
(2005 as Adjusted)

Overview of Results

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

Refined product revenues. Refined product revenues increased $759.7 million, or 39%, from $4.0 billion to $4.8 billion for the year ended December 31, 2006 compared to the same period in 2005. This increase was due to both an increase in average product sales prices ($8.81 higher per sales barrel) and an increase in product sales volumes in 2006 (1,657 more bpd). Sales prices increased primarily as a result of increased crude oil prices and improvements in the gasoline and diesel crack spreads.

Manufactured product yields. Manufactured product yields (“yields”) are the volumes of specific materials that are obtained through the distilling of crude oil and the operations of other refinery process units. Yields increased 6,776 bpd at the El Dorado Refinery while decreasing 3,669 bpd at the Cheyenne Refinery for the year ended December 31, 2006 compared to 2005. A Cheyenne Refinery turnaround in April 2006 caused yields to be lower during 2006 than during 2005, and an El Dorado Refinery turnaround from March 1 through April 5, 2005 caused yields to be lower in 2005 than 2006.

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

Raw material, freight and other costs. Raw material, freight and other costs include crude oil and other raw materials used in the refining process, purchased products and blendstocks, freight costs for FOB destination sales, as well as the impact of changes in inventory under the FIFO inventory accounting method. Raw material, freight and other costs increased by $603.6 million, or 19%, during the year ended December 31, 2006, from $3.2 billion in 2005 to $3.9 billion in 2006. The increase in raw material, freight and other costs when compared to 2005 was due to higher average crude prices, higher crude oil charges on an overall combined basis, and FIFO inventory losses in the year ended December 31, 2006. We benefited from slightly improved crude oil differentials during the year ended December 31, 2006 compared to the same period in 2005. The average WTI crude oil priced at Cushing, Oklahoma (ConocoPhillips WTI crude oil posting plus) was $64.94 for the year ended December 31, 2006 compared to $55.77 for the year ended December 31, 2005. Crude oil charges were 154,473 bpd for the year ended December 31, 2006, compared to 152,649 bpd for the comparable period in 2005. For the year ended December 31, 2006, we realized an increase in raw material, freight and other costs as a result of net FIFO inventory losses of approximately $16.1 million after tax ($25.7 million pretax, comprised of a $31.7 million loss at the El Dorado Refinery and a $6.0 million gain at the Cheyenne Refinery) due to decreasing crude oil and refined product prices during the latter part of 2006. For the year ended December 31, 2005, we realized a reduction in raw material, freight and other costs as a result of FIFO inventory gains of approximately $29.4 million after tax ($47.6 million pretax, comprised of $39.0 million for the El Dorado Refinery and $8.6 million for the Cheyenne Refinery) because of increasing crude oil and refined product prices.
The Cheyenne Refinery raw material, freight and other costs of $57.07 per sales barrel for the year ended December 31, 2006 increased from $48.49 per sales barrel in the same period in 2005 due to higher crude oil prices and a lower FIFO inventory gain, offset by fewer crude oil charges and the benefit of a slightly improved light/heavy crude oil differential. Crude oil charges of 45,999 bpd for the year ended December 31, 2006 were lower than the 46,922 bpd in the comparable period in 2005 because of the previously mentioned turnaround in 2006. The heavy crude oil utilization rate at the Cheyenne Refinery expressed as a percentage of the total crude oil charge decreased to 73% in the year ended December 31, 2006, from 82% in 2005 as we increased our charges of lighter crude oil to take advantage of favorable pricing opportunities for light crude purchases. The light/heavy crude oil differential for the Cheyenne Refinery averaged $16.21 per barrel in the year ended December 31, 2006 compared to $15.32 per barrel in the same period in 2005.
The El Dorado Refinery raw material, freight and other costs of $63.15 per sales barrel for the year ended December 31, 2006 increased from $54.01 per sales barrel in the same period in 2005 due to higher average crude oil prices and a FIFO inventory loss in 2006 compared to FIFO inventory gains in 2005. Crude oil charges were 108,475 bpd for the year ended December 31, 2006, compared to 105,727 bpd for the comparable period in 2005 because of the previously mentioned turnaround in 2005. In 2006, our El Dorado Refinery began charging Canadian heavy crude oil and achieved a light/heavy crude oil differential of $18.13 per barrel. For the year ended December 31, 2006, the heavy crude oil utilization rate at our El Dorado Refinery expressed as a percentage of the total crude oil charge was approximately 11%. The WTI/WTS crude oil differential increased from an average of $4.51 per barrel in the year ended December 31, 2005 to $5.22 per barrel in the same period in 2006.

Refinery operating expenses. Refinery operating expenses, excluding depreciation, include both the variable costs (energy and utilities) and the fixed costs (salaries, taxes, maintenance costs and other) of operating the Refineries. Refinery operating expenses, excluding depreciation, increased $35.7 million, or 15%, from $241.5 million in the year ended December 31, 2005 to $277.1 million in the comparable period of 2005.
The Cheyenne Refinery operating expenses, excluding depreciation, were $101.9 million in the year ended December 31, 2006, compared to $78.9 million in the comparable period of 2005. The increased expenses included higher maintenance costs ($8.1 million, with $3.0 million of the costs related to a plant-wide steam outage in February 2006, $1.2 million for slop oil centrifuging, $557,000 related to a September 2006 coker outage and $577,000 related to a butamer unit outage), increased environmental expenses ($5.8 million, including a $5.0 million accrual related to a potential waste-water pond clean up), higher salaries and benefits ($4.3 million, including $1.4 million in increased stock-based compensation costs and $787,000 additional bonus accruals), higher additive and chemical costs ($2.1 million, including increased wastewater treatment chemical use, cost of testing chemicals from a new vendor and increased usage of fresh fluid catalyst) and higher turnaround amortization ($1.0 million).
The El Dorado Refinery operating expenses, excluding depreciation, were $175.3 million in the year ended December 31, 2006, increasing from $162.5 million for the year ended December 31, 2005. The primary areas of increased costs were in electricity ($3.8 million), chemicals and additives ($4.1 million), maintenance ($6.2 million, including $1.8 million due to a fire on a distillate hydrotreater unit, $1.1 million for tank repairs and $1.0 million for a gofiner unit catalyst change-out), salaries and benefits ($1.1 million, including $767,000 in increased stock-based compensation costs), lease and rental equipment ($1.3 million, including higher cogeneration facility lease costs and rentals for a reverse osmosis trailer and filter), environmental ($827,000), insurance ($668,000) and non-maintenance contractors ($928,000). Electricity costs were higher during the year ended December 31, 2006, compared to the same period in 2005, as we produced electricity from our cogeneration facility in 2005 and did not do so in 2006. Chemicals and additive costs were higher during the year ended December 31, 2006, compared to the same period in 2005, as the fluid catalytic cracking unit consumed more additives and chemicals running for the full year in 2006, while it was down for turnaround work for approximately one month in 2005. We also purchased more nitrogen and oxygen during 2006 than in 2005 because the cogeneration facility provided us with some nitrogen and oxygen in 2005. We realized a $7.9 million reduction in natural gas costs due to lower natural gas prices and lower consumption in 2006 because we did not purchase natural gas for the cogeneration facility.

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

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

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

Interest and investment income. Interest and investment income increased $10.5 million, or 138%, from $7.6 million in the year ended December 31, 2005 to $18.1 million in the year ended December 31, 2006, due to larger cash balances and higher interest rates on invested cash.

Provision for income taxes. The provision for income taxes for the year ended December 31, 2006 was $200.8 million on pretax income of $580.1 million (or 34.6%) compared to $170.0 million on pretax income of $447.3 million (or 37.9%) for the same period in 2005. The American Jobs Creation Act of 2004 (“the Act”) benefited both our 2006 and 2005 current income taxes payable by allowing us an accelerated depreciation deduction of 75% of qualified capital costs incurred to achieve low sulfur diesel fuel requirements (See “Environmental” under Note 9 in the “Notes to Consolidated Financial Statements”). The Act also provides for a $0.05 per gallon credit on compliant diesel fuel up to an amount equal to the remaining 25% of these qualified capital costs for federal income tax purposes and for the year ended December 31, 2006 we realized a $22.4 million federal income tax credit ($14.5 million excess tax benefit). This credit greatly reduced our 2006 income taxes payable and reduced our overall effective income tax rate. Another provision of the Act which benefited our 2006 and 2005 income taxes payable by an estimated $5.7 million and $3.2 million, respectively, and reduced our overall effective tax rate in both of those years was the Section 199 production activities deduction for manufacturers. See Note 6 in the “Notes to Consolidated Financial Statements” for detailed information on our deferred tax assets. Our effective income tax rate for the year ended December 31, 2007 will be higher than that realized in the year ended December 31, 2006, as we only have approximately $8.4 million of ultra-low sulfur diesel production credits available for utilization in 2007.

MANAGEMENT DISCUSSION FOR LATEST QUARTER

RESULTS OF OPERATIONS

We are an independent energy company engaged in crude oil refining and the wholesale marketing of refined petroleum products. We operate refineries (the “Refineries”) in Cheyenne, Wyoming and El Dorado, Kansas with a total annual average crude oil capacity of approximately 162,000 barrels per day (“bpd”). 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 annual report on Form 10-K, our quarterly reports on Form 10-Q and on our web site at http://www.frontieroil.com . We make our web site content available for informational purposes only. The web site should not be relied upon for investment purposes. 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, proxy statements, 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.

Overview

The terms “Frontier,” “we” and “our” refer to Frontier Oil Corporation and its subsidiaries. The four significant indicators of our profitability, which are reflected and defined in the operating data at the end of this analysis, are the gasoline crack spread, the diesel crack spread, the light/heavy crude oil differential and the WTI/WTS crude oil differential. Other significant factors that influence our results are refinery utilization, crude oil price trends, asphalt and by-product margins and refinery operating expenses (including natural gas prices and maintenance). Under our first-in, first-out (“FIFO”) inventory accounting method, crude oil price trends can cause significant fluctuations in the inventory valuation of our crude oil, unfinished products and finished products, thereby resulting in FIFO inventory gains when crude oil prices increase and FIFO inventory losses when crude oil prices decrease during the reporting period. We typically do not use derivative instruments to offset price risk on our base level of operating inventories. See “Price Risk Management Activities” under Item 3 for a discussion of our utilization of futures trading.
As discussed in Note 2 in the “Notes to Condensed Consolidated Financial Statements,” during the fourth quarter of 2006 we changed our accounting method for the costs for planned major maintenance (“turnarounds”) from the accrual method to the deferral method. Turnarounds are the scheduled and required shutdowns of refinery processing units for significant overhaul and refurbishment. Under the deferral method, the costs of turnarounds are deferred when incurred and amortized on a straight-line basis over the period of time estimated to lapse until the next turnaround occurs. We adopted this new method of accounting for turnarounds in order to adhere to the FSP No. AUG AIR-1 “Accounting for Planned Maintenance Activities,” which prohibits the accrual method of accounting for planned major maintenance activities. We elected to early adopt the FSP during the fourth quarter of 2006. The comparative condensed consolidated financial statements for the nine and three months ended September 30, 2006 have been adjusted to reflect the period specific effects of applying the new accounting principle. Deferred costs related to these turnaround costs are included in our Condensed Consolidated Balance Sheets in “Deferred turnaround costs.” The associated amortization expenses are included in “Refinery operating expenses, excluding depreciation” in our Condensed Consolidated Statements of Income. The amortization expenses are included in our Condensed Consolidated Statements of Cash Flows in “Depreciation, accretion and amortization.”

Nine months ended September 30, 2007 compared with the same period in 2006

Overview of Results

We had net income for the nine months ended September 30, 2007 of $455.7 million, or $4.19 per diluted share, compared to net income of $326.8 million, or $2.89 per diluted share, earned in the same period in 2006. Our operating income of $694.0 million for the nine months ended September 30, 2007 increased $195.3 million from the $498.7 million for the comparable period in 2006. The average diesel and gasoline crack spreads were higher during the first nine months of 2007 ($24.76 and $23.41 per barrel, respectively) than in the first nine months of 2006 ($21.73 and $16.15 per barrel, respectively).

Specific Variances

Refined product revenues. Refined product revenues increased $215.9 million, or 6%, from $3.7 billion to $3.9 billion for the nine months ended September 30, 2007 compared to the same period in 2006. This increase was due to increased sales volumes (1,635 more bpd) and continued tight product availability supporting higher product sales prices ($3.83 higher average per sales barrel), despite lower average crude oil prices.
Manufactured product yields. Manufactured product yields (“yields”) are the volumes of specific materials that are obtained through the distillation of crude oil and the operations of other refinery process units. Yields decreased 3,140 bpd at the Cheyenne Refinery while increasing 357 bpd at the El Dorado Refinery for the nine months ended September 30, 2007 compared to same period in 2006. The decrease in yields at the Cheyenne Refinery was due to the spring turnaround that occurred in May 2007 and the fluid catalytic cracking unit being temporarily shutdown for repairs during the third quarter of this year.
Other revenues. Other revenues decreased $55.5 million to a loss of $30.4 million for the nine months ended September 30, 2007, compared to income of $25.1 million for the same period in 2006. The primary source of this difference was $35.7 million in net losses from derivative contracts partially offset by $4.8 million in gasoline sulfur credit sales in the nine months ended September 30, 2007, compared to $23.5 million in net gains from derivative contracts in the nine months ended September 30, 2006 and $1.6 million in gasoline sulfur credit sales in 2006. See “Price Risk Management Activities” under Item 3 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 blend stocks, 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 decreased by $39.1 million, from $2.94 billion in the nine months ended September 30, 2006, to $2.90 billion in the same period for 2007. The decrease in raw material, freight and other costs was due to the lower average crude oil price and decreased overall crude oil charges partially offset by lower crude oil differentials during the nine months ended September 30, 2007 when compared to the same period in 2006. For the nine months ended September 30, 2007, we realized a reduction in raw material, freight and other costs as a result of inventory gains of approximately $37.6 million after tax ($60.5 million pretax, consisting of a $25.8 million gain at the Cheyenne Refinery and a $34.8 million gain at the El Dorado Refinery). For the nine months ended September 30, 2006, we realized a reduction in raw material, freight and other costs as a result of inventory gains of approximately $7.9 million after tax ($13.0 million pretax, comprised of a $12.0 million gain at the Cheyenne Refinery and a $1.0 million gain at the El Dorado Refinery).
The Cheyenne Refinery raw material, freight and other costs of $59.02 per sales barrel for the nine months ended September 30, 2007 increased from $58.52 per sales barrel in the same period in 2006 due to a lower volume of sales barrels because of the spring 2007 turnaround, reduced light/heavy crude oil differentials and increased purchased products. The increase was partially offset by lower average crude oil prices and decreased overall crude oil charges. The light/heavy crude oil differential for the Cheyenne Refinery averaged $15.27 per barrel in the nine months ended September 30, 2007 compared to $16.82 per barrel in the same period in 2006.
The El Dorado Refinery raw material, freight and other costs of $62.40 per sales barrel for the nine months ended September 30, 2007 decreased from $64.71 per sales barrel in the same period in 2006 due to an increased volume of sales barrels and lower average crude oil prices partially offset by reduced crude oil differentials and increased purchased products. The WTI/WTS crude oil differential decreased from an average of $5.34 per barrel in the nine month period ended September 30, 2006, to $4.38 per barrel in the same period in 2007. The light/heavy crude oil differential decreased from an average of $19.91 per barrel in the nine month period ended September 30, 2006, to $17.26 per barrel in the same period in 2007.
Refinery operating expenses. Refinery operating expenses, excluding depreciation, includes both the variable costs (including energy and utilities) and the fixed costs (salaries, property taxes, maintenance and other costs) of operating the Refineries. Refinery operating expenses, excluding depreciation, were $210.4 million in the nine months ended September 30, 2007 compared to $203.8 million in the comparable period of 2006.
The Cheyenne Refinery operating expenses, excluding depreciation, were $71.5 million in the nine months ended September 30, 2007 compared to $75.8 million in the comparable period of 2006. The primary areas of decreased costs were in lower environmental costs ($5.0 million) related to an estimated waste water pond clean up accrual recorded in 2006, maintenance costs ($1.7 million) due to the 2006 costs related to a plant-wide steam outage and a butamer unit outage, and natural gas costs ($1.5 million) due to lower natural gas prices in 2007. Primary areas of increased costs were in higher salaries and benefits ($2.8 million) due to an increased number of employees and higher bonus accruals; and greater consulting and legal expenses ($929,000).
The El Dorado Refinery operating expenses, excluding depreciation, were $138.9 million in the nine months ended September 30, 2007, increasing from $128.0 million in the same nine month period of 2006. We experienced lower maintenance costs ($1.0 million) at the El Dorado Refinery during the nine months ended September 30, 2007, compared to the same period in 2006 offset by increased property tax accruals ($3.3 million), natural gas costs ($2.5 million, due to higher usage of natural gas volumes), additives and chemicals ($2.2 million), consulting and legal ($1.2 million), electricity ($1.0 million), environmental costs ($522,000), and salaries and wages ($518,000).
Selling and general expenses. Selling and general expenses, excluding depreciation, increased $5.0 million, or 14%, from $36.8 million for the nine months ended September 30, 2006 to $41.9 million for the nine months ended September 30, 2007, primarily due to costs related to the Beverly Hills litigation ($2.4 million) and an increase in salaries and benefits expense ($1.6 million) primarily resulting from the issuance of additional stock-based compensation awards in 2007 partially offset by a decrease in bonus accruals. Stock-based compensation expense was nearly $14.9 million for the nine months ended September 30, 2007 compared to $11.3 million for the comparable period in 2006.
Depreciation, accretion and amortization. Depreciation, accretion and amortization increased $7.9 million, or 26%, for the nine months ended September 30, 2007 compared to the same period in 2006 because of increased capital investment in our Refineries, including the ultra low sulfur diesel projects placed into service in the middle of the second quarter of 2006 and our Cheyenne Refinery coker expansion project placed into service in the second quarter of 2007. We also had higher depreciation expense during the nine months ended September 30, 2007 due to changes in the estimated useful lives of certain assets that are expected to be retired in connection with certain of our capital projects in 2008 and 2009.
Gain on sale of assets. The $15.2 million gain on sale of assets during the nine months ended September 30, 2007 resulted from a gain of $17.3 million from the sale of our 34.72% interest in a crude oil pipeline in Wyoming and a 50% interest in two crude oil tanks in Guernsey, Wyoming on September 28, 2007 partially offset by the buyout and sale of a leased aircraft.
Interest expense and other financing costs. Interest expense and other financing costs of $7.0 million for the nine months ended September 30, 2007 decreased $1.9 million, or 21%, from $8.9 million in the comparable period in 2006. The primary components of the decrease were higher capitalized interest in 2007 of $5.6 million in the first nine months of 2007 compared to $2.9 million for the same period in 2006 and a decrease in credit facility interest and fees of $202,000, partially offset by a $356,000 increase in facility costs and financing expenses related to the Utexam Master Crude Oil Purchase and Sale Contract entered into in March 2006 (“Utexam Arrangement”) and by a $678,000 increase in accrued interest expense for income tax contingencies. Average debt outstanding decreased to $150.0 million during the nine months ended September 30, 2007 from $152.2 million for the same period in 2006 (excluding amounts payable to Utexam under the Utexam Arrangement).
Interest and investment income. Interest and investment income increased $5.3 million from $12.4 million in the nine months ended September 30, 2006, to $17.7 million in the nine months ended September 30, 2007, because we had more cash available to invest and because of higher interest rates on invested cash.
Provision for income taxes . The provision for income taxes for the nine months ended September 30, 2007 was $248.9 million on pretax income of $704.7 million (or 35.3%) reflecting benefits from the “American Jobs Creation Act of 2004” (the “Act”) production activities deduction for manufacturers and an income tax credit for production of ultra low sulfur diesel fuel. Our current estimated effective tax rate excluding both of these benefits is 37.9%. Our provision for income taxes for the nine months ended September 30, 2006, was $175.4 million on pretax income of $502.2 million (or 34.9%).

Three months ended September 30, 2007 compared with the same period in 2006

Overview of Results

We had net income for the three months ended September 30, 2007 of $137.2 million, or $1.28 per diluted share, compared to net income of $123.6 million, or $1.10 per diluted share, earned in the same period in 2006. Our operating income of $207.0 million for the three months ended September 30, 2007 increased $26.3 million from the $180.8 million for the comparable period in 2006. The average gasoline crack spreads were higher during the third quarter of 2007 ($20.51) than in the third quarter of 2006 ($18.41), but the average diesel crack spread decreased to $23.43 during the third quarter of 2007 from $26.21 in the comparable period in 2006.

Specific Variances

Refined product revenues. Refined product revenues increased $57.4 million, or 4%, from $1.36 billion to $1.42 billion for the three months ended September 30, 2007 compared to the same period in 2006. This increase was due to continued tight product availability supporting higher product sales prices ($4.23 higher average per sales barrel) and higher crude oil prices, despite a decline in sales volumes.
Manufactured product yields. Yields decreased 2,146 bpd at the Cheyenne Refinery while increasing 186 bpd at the El Dorado Refinery for the three months ended September 30, 2007 compared to same period in 2006. The decrease in yields at the Cheyenne Refinery was primarily due to the fluid catalytic cracking unit being temporarily shutdown for repairs during the third quarter of this year.
Other revenues. Other revenues decreased $52.0 million to a loss of $31.7 million for the three months ended September 30, 2007, compared to income of $20.3 million for the same period in 2006, the primary source of which was $31.9 million in net losses from derivative contracts in the three months ended September 30, 2007 compared to $20.2 million in net gains from derivative contracts in the three months ended September 30, 2006. See “Price Risk Management Activities” under Item 3 for a discussion of our utilization of commodity derivative contracts.
Raw material, freight and other costs. Raw material, freight and other costs decreased by $14.9 million, from $1.110 billion in the three months ended September 30, 2006, to $1.095 billion in the same period for 2007. The decrease in raw material, freight and other costs was due to decreased overall crude oil charges and higher light/heavy crude oil differentials partially offset by higher average crude oil prices and increased purchased products during the three months ended September 30, 2007 when compared to the same period in 2006. For the three months ended September 30, 2007, we realized a reduction in raw material, freight and other costs as a result of inventory gains of approximately $15.5 million after tax ($25.0 million pretax, consisting of a $2.2 million gain at the Cheyenne Refinery and a $22.8 million gain at the El Dorado Refinery). For the three months ended September 30, 2006, we realized a reduction in raw material, freight and other costs as a result of inventory gains of approximately $15.7 million after tax ($25.3 million pretax, comprised of $6.0 million at the Cheyenne Refinery and $19.3 million at the El Dorado Refinery).
The Cheyenne Refinery raw material, freight and other costs of $63.83 per sales barrel for the three months ended September 30, 2007 decreased from $64.74 per sales barrel in the same period in 2006 due to a higher volume of sales barrels, increased light/heavy crude oil differentials and lower overall crude oil charges partially offset by higher average crude oil prices and increased purchased products. The light/heavy crude oil differential for the Cheyenne Refinery averaged $18.40 per barrel in the three months ended September 30, 2007 compared to $16.30 per barrel in the same period in 2006.
The El Dorado Refinery raw material, freight and other costs of $70.45 per sales barrel for the three months ended September 30, 2007 decreased from $70.54 per sales barrel in the same period in 2006 due to decreased overall crude charges and higher light/heavy crude oil differentials partially offset by a lower volume of sales barrels and higher average crude oil prices. The WTI/WTS crude oil differential decreased from an average of $4.69 per barrel in the three month period ended September 30, 2006, to $4.20 per barrel in the same period in 2007. The light/heavy crude oil differential increased from an average of $12.83 per barrel in the three month period ended September 30, 2006, to $20.60 per barrel in the same period in 2007.
Refinery operating expenses. Refinery operating expenses, excluding depreciation, were $69.4 million in the three months ended September 30, 2007 compared to $63.9 million in the comparable period of 2006.
The Cheyenne Refinery operating expenses, excluding depreciation, were $23.7 million in the three months ended September 30, 2007 compared to $23.8 million in the comparable period of 2006.
The El Dorado Refinery operating expenses, excluding depreciation, were $45.7 million in the three months ended September 30, 2007, increasing from $40.2 million in the same three month period of 2006. Primary areas of increased costs were: natural gas costs ($2.2 million, due to increased usage of natural gas volumes), property tax accruals ($1.1 million), chemicals and catalyst ($1.3 million), and consulting and legal ($671,000).
Selling and general expenses. Selling and general expenses, excluding depreciation, increased $2.1 million, or 14%, from $15.1 million for the three months ended September 30, 2006 to $17.2 million for the three months ended September 30, 2007, due to costs related to the Beverly Hills litigation ($4.3 million) partially offset by a decrease in salaries and benefits expense ($2.3 million). Stock-based compensation expense was $4.0 million for the three months ended September 30, 2007 compared to $4.6 million for the comparable period in 2006.
Depreciation, accretion and amortization. Depreciation, accretion and amortization increased $3.6 million, or 33%, for the three months ended September 30, 2007 compared to the same period in 2006 because of increased capital investment in our Refineries, including the ultra low sulfur diesel projects placed into service in the middle of the second quarter of 2006 and our Cheyenne Refinery coker expansion project placed into service in the second quarter of 2007. We also had higher depreciation expense during the three months ended September 30, 2007 due to changes in the estimated useful lives of certain assets that are expected to be retired in connection with certain of our capital projects in 2008 and 2009.
Gain on sale of assets. The $17.3 million gain on sale of assets during the three months ended September 30, 2007 resulted from the sale of our 34.72% interest in a crude oil pipeline in Wyoming and a 50% interest in two crude oil tanks in Guernsey, Wyoming on September 28, 2007.
Interest expense and other financing costs. Interest expense and other financing costs of $2.1 million for the three months ended September 30, 2007 decreased $1.5 million, or 42%, from $3.6 million in the comparable period in 2006. The primary component of the decrease was higher capitalized interest in the third quarter of 2007 of $2.1 million compared to $452,000 in 2006. Average debt outstanding was $150.0 million during both of the three months ended September 30, 2007 and 2006 (excluding amounts payable to Utexam under the Utexam Arrangement).
Interest and investment income. Interest and investment income increased $113,000 from $5.9 million in the three months ended September 30, 2006, to $6.0 million in the three months ended September 30, 2007, because we had more cash available to invest and because of higher interest rates on invested cash.
Provision for income taxes. The provision for income taxes for the three months ended September 30, 2007 was $73.8 million on pretax income of $211.0 million (or 35.0%) reflecting benefits from the Act production activities deduction for manufacturers and an income tax credit for production of ultra low sulfur diesel fuel. Our current estimated effective tax rate excluding both of these benefits is 37.9%. Our provision for income taxes for the three months ended September 30, 2006, was $59.5 million on pretax income of $183.1 million (or 32.5%).

LIQUIDITY AND CAPITAL RESOURCES

Cash flows from operating activities. Net cash provided by operating activities was $452.9 million for the nine months ended September 30, 2007 compared to net cash provided by operating activities of $283.4 million during the nine months ended September 30, 2006. Cash flows from working capital changes consumed less cash during the 2007 period compared to the same period in 2006; improved results of operations also increased cash flow. Operating cash flows are affected by crude oil and refined product prices and other risks as discussed in “Item 3. Quantitative and Qualitative Disclosures About Market Risks.”
Working capital changes used a total of $55.8 million of cash in the nine months ended September 30, 2007 while using $87.5 million of cash in the comparable period in 2006. The most significant component of the working capital change was an increase in inventories of $70.4 million in the first nine months of 2007 compared to an increase in inventories of $126.8 million in the 2006 comparable period, partially offset by an increase in receivables of $37.7 million in 2007 compared to a decrease in 2006 of $7.5 million. The increase in inventories during the nine months ended September 30, 2006, was due to higher crude oil inventories, primarily Canadian crude in-transit for the El Dorado Refinery, as well as other increased inventory levels and higher prices. The increase in receivables during the nine months ended September 30, 2007 was due to an overall increase in average sale prices. At September 30, 2007, we had $432.7 million of cash and cash equivalents, $577.4 million of working capital and $199.8 million of borrowing base availability for cash borrowings under our $225 million revolving credit facility.
Cash flows used in investing activities. Capital expenditures during the first nine months of 2007 were $229.2 million, which included approximately $113.1 million for the El Dorado Refinery and $111.6 million for the Cheyenne Refinery. The $113.1 million of capital expenditures for our El Dorado Refinery included $69.2 million for the crude unit and vacuum tower expansion, $20.2 million on the coke drum replacement, $4.6 million on the gasoil hydrotreater revamp, $3.7 million on the catalytic cracker regenerator emission control project and $2.9 million on the catalytic cracker expansion as well as operational, payout, safety, administrative, environmental and optimization projects. The $111.6 million of capital expenditures for our Cheyenne Refinery included approximately $75.3 million for the coker expansion and $7.5 million for the amine plant as well as environmental, operational, safety, administrative and payout projects.
We also purchased in February 2007 for approximately $3.0 million (net of current assets received), Ethanol Management Company (“EMC”), a 25,000 bpd products terminal and blending facility located in Henderson, Colorado.
In the nine months ending September 30, 2007, we had asset sales which generated total proceeds of $22.2 million.
Under the provisions of the purchase agreement with Shell for our El Dorado Refinery, we have been required to make contingent earn-out payments for each of the years 2000 through 2007 equal to one-half of the excess over $60.0 million per year of the El Dorado Refinery’s annual revenues less material costs and operating costs, other than depreciation. The total amount of these contingent payments is capped at $40.0 million, with an annual cap of $7.5 million. Such contingency payments are recorded as an additional acquisition cost when the payment is considered probable and estimable. Payments of $7.5 million each were paid in early 2005, 2006 and 2007, based on 2004, 2005 and 2006 results, and were accrued as of December 31, 2004, 2005 and 2006, respectively. Including the payment made in early 2007, we have paid a total of $30.0 million to date for contingent earn-out payments. Based on the results of operations for the nine months ended September 30, 2007, it is probable that a payment will be required in early 2008, and $7.5 million was accrued as of September 30, 2007.
Cash flows used in financing activities. During the nine months ended September 30, 2007, we spent $199.4 million to repurchase stock under the authorization of the stock repurchase program discussed below. Treasury stock increased by 122,176 shares ($4.8 million) from stock surrendered by employees and members of the Board of Directors to pay their withholding taxes on stock-based compensation which vested during the first nine months of 2007. We also paid $12.0 million in dividends during the nine months ended September 30, 2007.
In November 2006, our Board of Directors approved a $100 million share repurchase program, which replaced all existing repurchase authorizations and was utilized for share repurchases in the nine months ended September 30, 2007 (no shares had been repurchased under this program as of December 31, 2006). At its April 2007 meeting, our Board of Directors increased the size of our repurchase authorization by $100 million and increased the repurchase authorization by an additional $100 million at its August 2007 meeting, bringing the total authorizations since November 2006 to $300 million. As indicated above, we used $199.4 million to repurchase stock under this program during the nine months ended September 30, 2007, leaving a remaining authorization of $100.6 million.
During the nine months ended September 30, 2007, we issued 340,171 shares of common stock from our treasury stock in connection with stock option exercises by employees and members of our Board of Directors, for which we received $2.0 million in cash.
As of September 30, 2007, we had $150.0 million of long-term debt outstanding and no borrowings under our revolving credit facility. We also had $25.2 million of letters of credit outstanding under our revolving credit facility. We were in compliance with the financial covenants of our revolving credit facility as of September 30, 2007. On October 1, 2007, we entered into a third amended and restated revolving credit agreement that provides us the ability to increase our maximum commitment amount available from $250 million to $350 million, extended the termination date of the credit facility to October 3, 2011 as well as updated the financial covenants and other terms of the facility. Shareholders’ equity as of September 30, 2007 stood at an all-time high of $1.0 billion.
Our Board of Directors declared regular quarterly cash dividends of $0.03 per share in December 2006 and in March 2007, which were paid in January 2007 and April 2007, respectively. In April 2007 and August 2007, our Board of Directors declared regular quarterly cash dividends of $0.05 per share for shareholders of record on June 29, 2007 and September 29, 2007, which were paid in July 2007 and October 2007, respectively. The total cash required for the dividend declared in August 2007 was approximately $5.3 million and was included in “Accrued dividends” on the September 30, 2007 Condensed Consolidated Balance Sheet.
Future capital expenditures. Four major capital projects were started in 2006, and we expect to complete these projects in 2007 and 2008. These projects include a $156 million crude unit and vacuum expansion with an associated metallurgy upgrade at our El Dorado Refinery expected to be completed in 2008 and, at our Cheyenne Refinery, a $117 million coker expansion and revamp and a $6 million crude fractionation project. Also included is an amine unit project which is currently appropriated at $12 million, but we are evaluating additional costs necessary to complete this project. The coker expansion and revamp and crude fractionation projects were substantially completed during the second quarter of 2007. The above amounts include estimated capitalized interest. At September 30, 2007, outstanding purchase commitments for the crude unit and vacuum tower expansion project at our El Dorado Refinery were $9.6 million. At our Cheyenne Refinery, the coker expansion project’s outstanding commitments at September 30, 2007 were $4.0 million.
Our Board of Directors approved four additional major capital improvement projects for our El Dorado Refinery which we expect to complete in 2008 and 2009. These projects include an $82 million gasoil hydrotreater revamp, an $80 million catalytic cracker expansion, a $60 million coke drum replacement, and a $36 million catalytic cracker regenerator emission control project. The above amounts include estimated capitalized interest. At September 30, 2007, outstanding purchase commitments for the coke drum replacement were $8.5 million and for the gasoil hydrotreater revamp were $3.4 million. We have experienced cost overruns and delays on certain of our capital projects and may do so in the future because of strong industry demand for material, labor and engineering resources.
Capital expenditures aggregating approximately $312 million are currently planned for 2007, and include $169 million at our El Dorado Refinery, $134 million at our Cheyenne Refinery and $5 million for capital expenditures at our Denver and Houston offices. These capital expenditures for 2007 also include $3 million for the acquisition of EMC, mentioned above, and $1 million for capital expenditure projects for that facility. The $169 million of planned capital expenditures for our El Dorado Refinery includes approximately $85 million on the crude unit and vacuum tower expansion, $37 million for coke drum replacement, $4 million for the catalytic cracker expansion and $8 million for a gasoil hydrotreater revamp, as mentioned above, as well as environmental, operational, safety, administrative and payout projects. The $134 million of planned capital expenditures for our Cheyenne Refinery includes approximately $84 million on the coker expansion, $7 million on the new amine plant and $5 million on the crude fractionation project, as mentioned above, as well as environmental, operational, safety, administrative and payout projects. Our 2007 capital expenditures will be funded with cash generated by our operations and with a portion of our existing cash balance, if necessary.
The crude unit and vacuum tower expansion at the El Dorado Refinery will allow for higher crude charge rates (including a significantly greater percentage of heavy crude oil) and higher gasoline and distillate yields. This project also includes a metallurgical upgrade to the unit which facilitates running high napthenic acid crude oils, a characteristic typical of crude types found in Western Canada, West Africa and the North Sea. This project will likely be brought online in the spring of 2008 during the next planned turnaround for the crude/vacuum unit complex. The coker expansion at the Cheyenne Refinery, which was substantially completed in the second quarter of 2007, will significantly decrease the amount of asphalt produced and increase the amount of higher margin products. The new amine unit at the Cheyenne Refinery is intended to result in improved alkylation unit reliability and provide a partial backup unit if the main amine unit is not operating. The project is expected to be completed and in operation in early 2008. The crude fractionation project at the Cheyenne Refinery allows us to improve the recovery of diesel from the crude charged to the Refinery and was completed in the second quarter of 2007.
The gasoil hydrotreater revamp at the El Dorado Refinery is the key project to achieving gasoline sulfur compliance at our El Dorado Refinery (see Note 8 in the “Notes to Condensed Consolidated Financial Statements”). The project will also result in significant yield improvement for the catalytic cracking unit and is anticipated to be completed in the fall of 2009. The El Dorado Refinery’s catalytic cracker expansion project includes both a revamp component and new technology which will facilitate higher charge rates and improved product yields; it is expected to be completed in the fall of 2009. The coke drum replacement project for our El Dorado Refinery includes safety and reliability components as well as overall throughput support for the Refinery and is expected to be completed by mid-2008. The El Dorado Refinery catalytic cracker regenerator emission control project, with a fall 2009 estimated completion date, will add a scrubber to improve the environmental performance of the unit, specifically as it relates to flue-gas emissions. This project is necessary to support the catalytic cracking expansion project and to meet a portion of the expected requirements of the EPA Petroleum Refining Initiative (see Note 8 in the “Notes to Condensed Consolidated Financial Statements”).

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