EXHIBIT 13.1
General
The terms “Frontier” and “we” refer to Frontier Oil Corporation and its subsidiaries. Frontier operates refineries (the “Refineries”) in Cheyenne, Wyoming and El Dorado, Kansas with a combined crude oil capacity of 156,000 barrels per day. The Company focuses its marketing efforts in the Rocky Mountain and Plains States regions of the United States. The Company purchases the crude oil to be refined and markets the refined petroleum products produced, including various grades of gasoline, diesel fuel, jet fuel, asphalt and chemicals.
Result of Operations
2002 Compared with 2001.We had net income for the year ended December 31, 2002 of $1.0 million, or $.04 per diluted share, compared to net income of $107.7 million, or $4.00 per diluted share, for 2001.
Operating income decreased $136.2 million in 2002 versus 2001 due to decreases in the refined product spread (revenues less material, freight and other costs) of $147.5 million, an increase in depreciation of $2.3 million and a $.3 million impairment loss on asset held for sale in 2002 offset by an increase in other income of $2.0 million and decreases in refinery operating expenses (excluding depreciation) of $11.7 million and selling and general costs of $.3 million.
The refined product spread was $4.11 per barrel for the year ended December 31, 2002 compared to $6.84 per barrel in 2001 due to lower light product margins and a decrease in both the light/heavy and WTI/WTS crude spreads offset by a positive inventory valuation impact during the year ended December 31, 2002 from rising crude oil and product prices during the period. The price of crude oil on the New York Mercantile Exchange increased through 2002 from $19.84 per barrel to $31.20 per barrel. For the year ended December 31, 2002, we realized an increase to the refined product spread from inventory gains of approximately $30.7 million pretax ($19.0 million after tax) because of the increasing crude oil prices. For the year ended December 31, 2001, we realized a reduction to the refined product spread from inventory losses of approximately $41.4 million pretax ($28.9 million after tax) because of decreasing crude oil prices.
The Cheyenne Refinery refined product spread was $4.73 per barrel in 2002 compared to $8.03 per barrel in 2001. The reduced product spread was due to lower light product margins and a decrease in the light/heavy spread offset by a positive inventory valuation impact from increasing crude and product prices during the year ended December 31, 2002. The light/heavy spread decreased from an average $7.07 per barrel in 2001 to $4.24 per barrel in 2002. For the year ended December 31, 2002 at the Cheyenne Refinery, we realized an increase to the refined product spread from inventory profits of approximately $10.7 million pretax compared to a reduction to the refined product spread from inventory losses of approximately $8.9 million pretax for the year ended December 31, 2001.
The El Dorado Refinery refined product spread was $3.85 per barrel in 2002 compared to $6.39 per barrel in 2001 due to lower light product margins and a decrease in the WTI/WTS crude oil spread offset by a positive inventory valuation impact from rising crude and product prices during the year ended December 31, 2002. For the year ended December 31, 2002 at the El Dorado Refinery, we realized an increase to the refined product spread from inventory gains of approximately $19.9 million pretax compared to a reduction to the refined product spread from inventory losses of approximately $32.5 million pretax for the year ended December 31, 2001.
Refined product revenues decreased $76.6 million or 4% for the year ended December 31, 2002 compared to 2001 due to decreased sales prices. Average gasoline prices decreased $2.77 per barrel and average diesel prices decreased $3.77 per barrel, but we experienced a 5% overall increase in sales volumes. Yields of gasoline increased approximately 8% while yields of diesel and jet fuel increased 4% in 2002 compared to the year ended December 31, 2001. El Dorado gasoline yields improved in 2002 due to diverting feedstocks previously used in the phenol and cumene units. The primary reason for the lower volumes in sales and yields in 2001 was the major turnaround, or planned maintenance, at the El Dorado Refinery which commenced in mid-March 2001 and was completed in mid-April 2001. Despite a major turnaround at the Cheyenne Refinery during March and April 2002, refinery yields and sales for the year ended December 31, 2002 increased from the same period in 2001 due to the benefit of the increased crude capacity from 41,000 barrels per day to 46,000 barrels per day which was completed during latter 2001 and early 2002. The Cheyenne Refinery throughput and resulting yields in the early part of 2001 was constrained by asphalt inventory storage availability.
Other revenues increased $2.0 million to income of $1.1 million for the year ended December 31, 2002 compared to a loss of $832,000 for the same period in 2001 due to $108,000 in futures trading net gains in 2002 compared to $2.0 million futures trading net losses in 2001 (see “Price Risk Management Activities”).
Refining operating costs increased $59.2 million or 4% for the year ended December 31, 2002 compared to 2001 due to increases in raw material, freight and other costs offset by lower refinery operating expenses.
Material, freight and other costs per barrel increased $.02 per barrel from 2001 due to higher average crude oil prices offset by inventory gains from rising prices during the year. The Cheyenne refinery material, freight and other costs of $25.18 per barrel increased from $24.85 per barrel in 2001 due to higher crude oil prices and a reduced light/heavy spread. The heavy crude oil utilization rate at the Cheyenne Refinery expressed as a percentage of the total crude oil charge decreased to 90% in the year ended December 31, 2002 from 91% in 2001 as we utilized slightly more light crude oil due to the depressed light/heavy crude oil spread. The light/heavy spread for the Cheyenne Refinery averaged $4.24 per barrel compared to $7.07 per barrel in 2001. The El Dorado Refinery material, freight and other costs of $25.93 per barrel decreased from $26.01 per barrel in 2001 due to slightly higher average crude oil prices more than offset by the inventory gains from rising prices during the year.
Refinery operating expense (excluding depreciation) was $2.93 per sales barrel in 2002 compared to $3.27 per sales barrel in 2001. The Cheyenne Refinery operating expense (excluding depreciation) per sales barrel decreased $.37 to $3.02 per sales barrel in 2002 due to more sales volumes. The El Dorado Refinery operating expense (excluding depreciation) was $2.90 per sales barrel in 2002 decreasing from $3.22 per sales barrel in 2001 due to lower natural gas costs and more sales volumes.
Selling and general expenses decreased $.3 million or 2% for the year ended December 31, 2002 because of decreased salaries and benefits due to bonuses not being accrued this year partially offset by increased engineering consulting services and travel costs.
Depreciation increased $2.3 million or 9% for the year ended December 31, 2002 as compared to 2001 because of increases in capital investment.
The interest expense decrease of $3.5 million or 11% for the year ended December 31, 2002 was attributable to repurchases of 9-1/8% Senior Notes and 11¾% Senior Notes during 2001, less interest expense on the revolving credit facility due to lower borrowing rates and capitalized interest in 2002. Interest income decreased by $.9 million or 35% for the year ended December 31, 2002 compared to 2001 due to lower available investing interest rates offset by more cash available to invest. Average debt decreased to $246.1 million for the year ended December 31, 2002 from $255.3 million for the year ended December 31, 2001.
Our effective income tax rate for the book provision of income taxes for the year ended December 31, 2002, of 50.8% is greater than our current estimated statutory rate of 38.25% primarily due to one-time adjustments for permanent book versus tax differences and an increase in the state deferred income tax provision due to a revised estimate of state apportionment factors based on actual 2002 allocation factor data. An $83,000 Canadian income tax payment for an audit settlement related to our Canadian oil and gas operations (sold in June 1997) also increased our income tax provision in 2002.
2001 Compared with 2000.We had net income for the year ended December 31, 2001 of $107.7 million, or $4.00 per diluted share, compared to net income of $37.2 million, or $1.34 per diluted share, for 2000.
Operating income increased $93.4 million in 2001 versus 2000 due to increases in the refined product spread (revenues less raw material, freight and other costs) of $119.9 million offset by a decrease in other income of $8.2 million and increases in refinery operating expenses (excluding depreciation) of $12.1 million, selling and general costs of $4.2 million and depreciation of $2.0 million.
The refined product spread was $6.84 per barrel for the year ended December 31, 2001 compared to $4.79 per barrel in 2000 due to improved light product margins offset by a negative inventory valuation impact from declining crude oil prices. The price of crude oil on the New York Mercantile Exchange declined through 2001 from $26.80 per barrel to $19.84 per barrel. For the year ended December 31, 2001, we realized a reduction to the refined product spread from inventory losses of approximately $41.4 million pretax ($28.9 million after tax) because of the decreasing crude oil prices. For the year ended December 31, 2000, we realized an increase to the refined product spread from inventory profits of approximately $19.2 million pretax ($18.7 million after tax) from rising crude oil prices. Frontier records inventories at the lower of cost on a first in, first out (FIFO) basis or market.
The Cheyenne Refinery refined product spread was $8.03 per barrel in 2001 compared to $5.68 per barrel in 2000. The improved product spread was due to improved light product margins and an increase in the light/heavy spread offset by a negative inventory valuation impact. The light/heavy spread increased from an average $5.09 per barrel in 2000 to $7.07 per barrel in 2001. For the year ended December 31, 2001 at the Cheyenne Refinery, we realized a reduction to the refined product spread from inventory losses of approximately $8.9 million pretax compared to an increase to the refined product spread from inventory profits of approximately $2.3 million pretax from rising crude oil prices for the year ended December 31, 2000.
The El Dorado Refinery refined product spread was $6.39 per barrel in 2001 compared to $4.42 per barrel in 2000 due to improved light product margins and an increase in the WTI/WTS crude oil spread offset by a negative inventory valuation impact. For the year ended December 31, 2001 at the El Dorado Refinery, we realized a reduction to the refined product spread from inventory losses of approximately $32.5 million pretax compared to an increase to the refined product spread from inventory profits of approximately $16.9 million pretax from rising crude oil prices for the year ended December 31, 2000.
Refined product revenues decreased $148.6 million or 7% for the year ended December 31, 2001 compared to 2000 due to decreased sales prices. Average gasoline prices decreased $2.24 per barrel and average diesel prices decreased $3.07 per barrel. Yields of gasoline increased approximately 2% while yields of diesel and jet fuel remained nearly flat in 2001 compared to 2000.
Other revenues decreased $8.2 million to a loss of $832,000 for the year ended December 31, 2001 compared to the same period in 2000 due to a $1.9 million realized futures trading net losses in 2001 compared to a $4.6 million futures trading net gain in 2000. Other revenues in 2000 also included $1.1 million proceeds from the sale of excess catalyst platinum from the El Dorado Refinery, insurance proceeds of $300,000, which was related to a business interruption at the El Dorado Refinery in 2000, and sulfur credit sales of $230,000.
Refining operating costs decreased $256.4 million or 13% for the year ended December 31, 2001 compared to 2000 due to decreases in raw material, freight and other costs offset by higher refinery operating expenses.
Raw material, freight and other costs per barrel decreased 16% or $4.72 per barrel in 2001 primarily due to lower crude oil prices. The Cheyenne Refinery raw material, freight and other costs of $24.85 per barrel decreased from $28.51 per barrel in 2000 due to lower crude oil prices and an increased light/heavy spread. The heavy crude oil utilization rate at the Cheyenne Refinery expressed as a percentage of the total crude oil charge decreased to 91% in the year ended December 31, 2001 from 94% in 2000 due to fulfilling light crude oil purchase contracts while reducing spot purchases of heavy crude oil during the fall 2001 crude unit turnaround. The light/heavy spread for the Cheyenne Refinery averaged $7.07 per barrel compared to $5.09 per barrel in 2000. The El Dorado Refinery raw material, freight and other costs of $26.01 per barrel decreased from $31.20 per barrel in 2000 due to lower crude oil prices.
Refinery operating expense (excluding depreciation) was $3.27 per sales barrel in 2001 compared to $3.07 per sales barrel in 2000. The Cheyenne Refinery operating expense (excluding depreciation) per sales barrel increased $.56 to $3.39 per sales barrel in 2001 due to higher maintenance and turnaround costs and reduced yields and sales volumes due to the fall crude unit turnaround and higher natural gas costs early in the year. The El Dorado Refinery operating expense (excluding depreciation) was $3.22 per sales barrel in 2001 increasing from $3.17 per sales barrel in 2000 due to higher natural gas costs early in the year, electrical costs, and chemical and additive costs offset by more yields and sales volumes.
Selling and general expenses increased $4.2 million or 32% for the year ended December 31, 2001 because of increased compensation, mainly bonuses, personnel, and other costs, particularly travel, relating to the operation of multiple locations.
Depreciation increased $2.0 million or 9% for the year ended December 31, 2001 as compared to 2000 because of increases in capital investment.
The interest expense decrease of $3.6 million or 10% for the year ended December 31, 2001 was attributable to the reduction of debt including repurchases of 9-1/8% Senior Notes and 11¾% Senior Notes during 2001 and 2000 and lower borrowing rates, balances and fees on the revolving credit facility. Interest income decreased by $.6 million or 18% for the year ended December 31, 2001 compared to 2000 due to lower available investing interest rates offset by more available cash to invest. Average debt decreased to $255.3 million for the year ended December 31, 2001 from $295.7 million for the year ended December 31, 2000.
Income tax expense of $28.1 million for the year ended December 31, 2001 increased as a result of the full utilization in 2001 of our deferred tax assets (primarily net operating loss carryforwards) for which we had previously provided a valuation allowance.
Liquidity and Capital Resources
Net cash provided by operating activities was $50.8 million for the year ended December 31, 2002 while $138.6 million cash was provided by operating activities for the year ended December 31, 2001. The most significant decrease from cash provided by operating activities was the decrease in operating income due to the lower product margins and decreases in the crude spreads discussed above. Working capital changes provided $17.8 million of cash flows in 2002 while using $6.5 million of cash flows in 2001.
At December 31, 2002, we had $112.4 million of cash and cash equivalents, and $88.2 million available under the revolving credit facility line of credit. We had working capital of $108.3 million at December 31, 2002.
On November 5, 1999, we issued $190 million principal amount of 11¾% Senior Notes due 2009. The Notes were issued at a price of 98.562%. Net proceeds of the offering were approximately $181.0 million. We used the net proceeds to fund the $170 million purchase price of the El Dorado Refinery and for general corporate purposes. During 2001 and 2000, we purchased $6.5 million and $13.0 million principal amount, respectively, of the 11¾% Senior Notes and are holding them as treasury notes, the accounting for which reduced debt.
During 2002, 2001 and 2000, we purchased $1.1 million, $24.4 million and $5.0 million principal amount, respectively, of the 9-1/8% Senior Notes and are holding them as treasury notes. The accounting for which reduced debt. The 9-1/8% Senior Notes were issued in 1998.
On September 1, 1998, we announced that the Board of Directors had approved a stock repurchase program of up to three million shares of common stock. In late 2000, the Board of Directors increased this amount to a total of four million shares and in June 2001 authorized an additional two million shares to bring the total authorization to six million shares, which may be purchased and held as treasury shares. In 1998, 469,700 shares of common stock were purchased for $2.3 million and in 1999, 627,700 shares of common stock were purchased for $3.4 million. In 2000, 1,393,696 shares of common stock were purchased for approximately $9.2 million, of which 1,248,500 shares were purchased on the open market. In 2001, 1,850,970 shares were purchased for approximately $22.6 million, of which 1,774,400 were purchased on the open market. In 2002, we completed the purchase, committed to at December 31, 2001, of another 25,300 shares for $416,000. During the year ended 2002, we did not initiate any additional purchases of common stock under the stock repurchase programs, however we did acquire 19,041 shares of stock from employees to cover their withholding taxes on shares of restricted stock which vested during the year.
Capital expenditures for 2002 were $37.1 million which included the $7.5 million El Dorado earn-out payment accrued as of December 31, 2001. We reduced our originally planned total capital expenditures in 2002 due to reevaluating the economics of the previously announced heavy crude oil expansion at the El Dorado Refinery. Due to anticipated cost and market conditions, we reached a decision in the fourth quarter of 2002 to cancel this project and $2.4 million previously recorded as capital expenditures was expensed.
Capital expenditures for 2001 were $22.8 million. Capital expenditures of approximately $41.0 million are planned for 2003, which includes nearly $14.0 million for the low sulfur gasoline project at the Cheyenne Refinery and does not include any amount for an El Dorado earn-out payment as none was earned in 2002. The planned capital expenditures in excess of $35.0 million will be subject to bank approval under our revolving credit facility or we have the option to lease a portion of the equipment required for the low sulfur gasoline project.
Under the provisions of the purchase agreement 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 million per year of the El Dorado Refinery’s revenues less its material costs and operating costs, other than depreciation. The total amount of these contingent payments is capped at $40 million, with an annual cap of $7.5 million. Any contingency payment will be recorded when determinable. Such contingency payments, if any, will be recorded as additional acquisition cost. No contingent earn-out payment will be required based on 2002 results. A contingent earn-out payment of $7.5 million was required based on 2001 results and was accrued as of December 31, 2001 and paid in early 2002. No contingent earn-out payment was required based on 2000 results.
As of December 31, 2002, we have $208.0 million of total consolidated debt and shareholders’ equity of $168.3 million. For 2003, we anticipate that cash generated from operating activities may have to be supplemented with a portion of our current cash balance to meet our 2003 capital investment plans and debt obligations. Operating cash flows are affected by crude oil and refined product prices and other risks as discussed in Market Risks below.
Under certain conditions, the revolving credit facility, which is at the subsidiary level, restricts the transfer of cash in the form of dividends, loans or advances from the operating subsidiary to the parent holding company. We do not believe these restrictions limit our current operating plans. Our refining revolving credit facility was amended, effective September 23, 2002 to allow for capital expenditures of up to $35.0 million cash in any calendar year, in addition to any El Dorado earn-out payments required. We are in compliance with the financial covenants as of December 31, 2002.
Our Board of Directors declared quarterly cash dividends in December 2001, March 2002, June 2002 and September 2002 of $.05 per share which were paid in January 2002, April 2002, July 2002 and October 2002, respectively. The total paid out for dividends in 2002 was $5.2 million. In addition, our Board of Directors declared a quarterly cash dividend of $.05 per share in December 2002, to be paid on January 13, 2003 to shareholders of record on December 27, 2002. The total cash required for this dividend is approximately $1.3 million and was accrued at year end.
Contractual Cash Obligations
The table below 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 and our commitment for crude oil pipeline capacity. We have contracted for pipeline capacity into 2012 on the Express Pipeline from Hardisty, Alberta to Guernsey, Wyoming at which we then have pipeline access to take the crude oil to our Cheyenne, Wyoming Refinery. Our 15-year contract, which began in 1997, is for an average 13,800 barrels per day, however we were allowed to assign a portion of our capacity in earlier years for additional capacity in later years, thus our remaining commitments range from 16,600 barrels per day in 2003, increasing to a high of 22,600 barrels per day in 2006 and then are reduced back down to 13,800 barrels per day through the remainder of the contract. Our crude oil supply agreement with Baytex Marketing Ltd. (“Baytex”) includes an assignment of a portion of our pipeline capacity obligation to them. The amounts shown below for pipeline capacity contractual obligations are net of $37.0 million, the approximate cost of the pipeline capacity assigned to Baytex for the initial term of that agreement. Our operating leases include building, equipment, aircraft and vehicle leases which expire from 2002 through 2008, as well as an operating sublease for the use of the cogeneration facility at our El Dorado Refinery. The noncancellable sublease, entered into in connection with the acquisition of our El Dorado Refinery in 1999, expires in 2016 with an option to allow us to renew the sublease for an additional eight years. At the end of the renewal sublease term we have the option to purchase the cogeneration facility for the greater of fair value or $22.3 million.
- ---------------------------- ----------------------------------------------------------------------------------------
Contractual Obligation Payments due by Period (in thousands)
- ---------------------------- ----------------------------------------------------------------------------------------
Total Within 1 year Within 2 - 3 years Within 4 - 5 years After 5 years
- ---------------------------- ------------ --------------- -------------------- ------------------- ------------------
Long-term Debt $ 209,924 $ - $ - $ 39,475 $ 170,449
- ---------------------------- ------------ --------------- -------------------- ------------------- ------------------
Operating Leases 103,262 10,430 19,482 16,444 56,906
- ---------------------------- ------------ --------------- -------------------- ------------------- ------------------
Pipeline Capacity 28,923 1,560 1,111 284 25,968
- ---------------------------- ------------ --------------- -------------------- ------------------- ------------------
Total Contractual Cash $ 342,109 $ 11,990 $ 20,593 $ 56,203 $ 253,323
- ---------------------------- ------------ --------------- -------------------- ------------------- ------------------
Impact of Changing Prices.Our revenues and cash flows, as well as estimates of future cash flows, are very sensitive to changes in energy prices. Major shifts in the cost of crude oil, and the prices of refined products and natural gas can result in large changes in the operating margin from refining operations. These prices also determine the carrying value of the Refineries’ inventories.
Price Risk Management Activities. At times, we enter into commodity derivative contracts to manage our price exposure to our inventory positions, our purchases of foreign crude oil and consumption of natural gas in the refining process as well as fix margins on certain future production. The commodity derivative contracts we use may take the form of futures contracts or price swaps and are entered into with reputable counterparties. We use futures transactions to price foreign crude oil cargos at the time when the crude oil is processed by the El Dorado Refinery instead of the price when purchased. Foreign crude oil delivery times can exceed one month from when the purchase is made. In addition, we may engage in futures transactions for the purchase of natural gas at fixed prices. The Refineries consume natural gas for energy purposes. We account for our commodity derivative contracts under 1) the hedge (or deferral) method of accounting when the derivative contracts qualify and are designated as hedges for accounting purposes, or 2) mark-to-market accounting if we elect not to designate derivative contracts as accounting hedges or if such derivative contracts do not qualify for hedge accounting. As such, gains or losses on commodity derivative contracts accounted for as hedges are recognized in refining operating costs when the associated transactions are consummated while gains and losses on transactions accounted for using mark-to-market accounting are reflected in other revenues at each period end.
Other revenues for the year ended December 31, 2002 includes $878,000 realized net gains on the ineffective portion of fair value hedges on crude oil cargos and $740,000 realized net losses on derivative contracts accounted for using mark-to-market accounting. The ineffective portion of foreign crude oil hedges arises primarily from changes in the shape of the forward futures price curve.
During the year ended December 31, 2002, we had the following derivative activities which were appropriately designated and accounted for as hedges:
• At December 31, 2002 we had no open derivative contracts to hedge against price changes on foreign crude oil purchase commitments. During the year ended December 31, 2002, we closed out contracts to hedge foreign crude purchases and realized net losses of $9.8 million, of which $10.7 million increased crude costs and $878,000 income was reflected in other revenues for the ineffective portion of those hedges. These contracts were accounted for as fair value hedges.
• In March 2002, we entered into price swaps on natural gas for the purpose of hedging approximately 50% of the Refineries’ anticipated usage against natural gas price increases for April 2002 through December 2002. These contracts were accounted for as cash flow hedges. One group of contracts to hedge natural gas costs at our El Dorado Refinery averaged 300,000 MMBTU per month at an average price of $3.34 per MMBTU (Panhandle). A second group of contracts to hedge natural gas costs at our Cheyenne Refinery averaged 112,222 MMBTU per month at an average price of $2.84 per MMBTU (CIG). The April and May contracts resulted in net realized gains totaling $41,000 and were recorded into refining operating costs. Due to natural gas market conditions, we made a decision in May to close out the remaining June through December contracts resulting in a net gain of $393,000. The realized gains or losses were recorded in other comprehensive income (equity account), net of tax. The pretax realized gains or losses were reclassified into refining operating costs and out of other comprehensive income based on the month when the corresponding natural gas was purchased. As of December 31, 2002, all these gains and losses had been reclassified into earnings.
During the year ended December 31, 2002, we had the following derivative activities which, while economic hedges, did not qualify for hedge accounting treatment and whose gains or losses are reflected in other revenues:
• We had derivative contracts on barrels of crude oil to hedge butane inventory builds at the El Dorado Refinery and recorded $903,000 in realized losses on these positions.
• We had derivative contracts on barrels of crude oil to hedge excess gas oil inventory at our Cheyenne Refinery and had realized losses of $202,000 on these positions.
• Derivative contracts on barrels of crude oil to hedge excess gas oil inventory at our El Dorado Refinery resulted in gains of $896,000.
• We also hedged excess naptha inventory at our El Dorado Refinery by having derivative contracts on barrels of crude oil which resulted in losses of $579,000.
• Contracts to hedge crude oil resulted in a gain of $48,000.
Interest Rate Risk. Borrowings under our revolving credit facility bear a current market rate of interest. Our approximately $39.5 million of outstanding 9-1/8% Senior Notes, due 2006, have a fixed interest rate. Our approximately $170.5 million principal of 11¾% Senior Notes outstanding, due 2009, also have a fixed interest rate. Accordingly, our long-term debt is not exposed to cash flow risk from interest rate changes, however, our long-term debt is exposed to fair value risk. The estimated fair value of the 9-1/8% Senior Notes at December 31, 2002 was $37.9 million and the estimated fair value of the 11¾% Senior Notes was $174.7 million.
Environmental
Our refining and marketing operations are subject to a variety of federal, state and local health and environmental laws and regulations governing product specifications, the discharge of pollutants into the air and water, and the generation, treatment, storage, transportation and disposal of solid and hazardous waste and materials. Permits are required for the operation of our Refineries, and these permits are subject to revocation, modification and renewal. Governmental authorities have the power to enforce compliance with these regulations and permits, and violators are subject to injunctions, civil fines and even criminal penalties. We believe that each of our Refineries is in substantial compliance with existing environmental laws, regulations and permits.
Our operations and many of the products we manufacture are specifically subject to certain requirements of the Clean Air Act (“CAA”) and related state and local regulations. The 1990 amendments to the CAA contain provisions that will require capital expenditures for the installation of certain air pollution control devices at our refineries during the next several years. The EPA recently embarked on a Petroleum Refining Initiative (“Initiative”) alleging industry-wide noncompliance with certain CAA rules. The Initiative has resulted in many refiners entering into consent decrees typically requiring substantial expenditures for penalties and additional pollution control equipment. We have been contacted by the EPA and invited to meet with them to hear more about the Initiative. At this time, we do not know how or if the Initiative will affect the Company. We have, however, recently determined that over the next three years, expenditures totaling approximately $10 million may be necessary to further reduce emissions from our Refineries’ flare systems. Because other refineries will be required to make similar expenditures, we do not expect such expenditures to materially adversely impact our competitive position.
On December 21, 1999, the EPA promulgated national regulations limiting the amount of sulfur that is to be allowed in gasoline. The total capital expenditures estimated, as of December 31, 2002, to achieve the final gasoline sulfur standard, are approximately $35 million at the Cheyenne Refinery and approximately $44 million at the El Dorado Refinery. Approximately $7.2 million of the Cheyenne Refinery expenditures had been incurred as of December 31, 2002, an additional $20.8 million is expected to be incurred by early 2004 with the remaining $7 million in 2009 and 2010. The expenditures for the El Dorado Refinery are expected to be incurred beginning in 2008 and completed in 2010.
The EPA recently promulgated regulations that will limit the sulfur content of highway diesel fuel beginning in 2006 to 15 parts-per-million from the current standard of 500 parts-per-million. As of December 31, 2002, capital costs for diesel desulfurization are estimated to be approximately $5 million for Cheyenne and $56 million for El Dorado. The Cheyenne Refinery expenditures are currently expected to be committed beginning in 2005, with the majority to be committed in 2006. Approximately $6 million of the El Dorado Refinery expenditures are currently expected to be committed in 2004 with the remaining $50 million in 2005 and 2006.
The EPA has recently stated their intent to propose new regulations that will limit emissions from diesel fuel powered engines used in off-road activities such as mining, construction and agriculture. The EPA has also stated their intent to simultaneously limit the sulfur content of diesel fuel used in these engines to facilitate compliance with the new emission standards. The EPA expects to propose the new off-road diesel engine emissions and related fuel sulfur standards early in 2003. It is likely that the new rules will require the off-road diesel fuel sulfur content to be reduced to 500 parts-per-million or less from the current limit of 5,000 parts-per-million by 2007. Since a minor portion of the diesel fuel we manufacture at our El Dorado Refinery is sold to the off-road market, these regulations, when promulgated, will likely require certain modifications to the Refinery. The cost associated with such modifications cannot be estimated until the final regulatory limits are known.
As is the case with all companies engaged in similar industries, we face potential exposure from future claims and lawsuits involving environmental matters. The matters include soil and water contamination, air pollution, personal injury and property damage allegedly caused by substances which we manufactured, handled, used, released or disposed of.
Cheyenne Refinery. We are party to an agreement with the State of Wyoming requiring the investigation and possible eventual remediation of certain areas of the Cheyenne Refinery’s property which may have been impacted by past operational activities. Among other things, this order required a technical investigation of the Cheyenne Refinery to determine if certain areas have been adversely impacted by past operational activities. Based upon the results of the investigation, additional remedial action could be required by a subsequent administrative order or permit. The ultimate cost of any environmental remediation projects that may be identified by the site investigation required by the agreement cannot be reasonably estimated at this time.
El Dorado Refinery. The El Dorado Refinery is subject to a 1988 consent order with the Kansas Department of Health and the Environment (“KDHE”). This order, including various subsequent modifications, requires us to continue the implementation of a groundwater management program with oversight provided by the KDHE Bureau of Environmental Remediation. The order requires that remediation activities continue until KDHE-established groundwater criteria or other criteria agreed to by the KDHE and Frontier are met. Frontier acquired the El Dorado refinery in 1999 from Equilon Enterprises LLC, now known as Shell Oil Products US (“Shell”). Subject to the terms of the purchase and sale agreement, Shell will be responsible for the costs of continued compliance with this order.
The most recent National Pollutant Discharge Elimination System permit issued to the El Dorado Refinery requires, in part, the preparation and submittal of an engineering report identifying certain refinery wastewater treatment plant upgrades necessary to allow routine compliance with applicable discharge permit limits. In accordance with the provisions of the purchase and sale agreement, Shell will be responsible for the first $2 million of any required wastewater treatment system upgrades. If required system upgrade costs exceed this amount, Shell and Frontier will share, based on a sliding scale percentage, up to another $3 million in upgrade costs. Subject to the terms of the purchase and sale agreement, Shell will be responsible for up to $5 million in costs, in addition to Shell’s obligation for the wastewater treatment system upgrade, relating to safety, health and environmental conditions after closing arising from Shell’s operation of the El Dorado Refinery that are not covered under a ten-year insurance policy. This insurance policy has $25 million coverage through November 17, 2009 for environmental liabilities, with a $500,000 deductible, and will reimburse us for losses related to all known and some unknown conditions existing prior to our acquisition of the El Dorado Refinery. The first phase of wastewater treatment system upgrades was completed in 2001 at a cost of $2.6 million with payment apportioned as described above.
On August 18, 2000, we entered into a Consent Agreement and Final Order of the Secretary (“Agreement”) with the KDHE that required the initiation of a wastewater toxicity testing program to commence upon the completion of the wastewater treatment upgrades described above. Good progress has since been made toward satisfying the provisions of the Agreement and we expect to meet all applicable requirements.
Significant Accounting Policies
Refined Product Revenues. We recognize revenues from sales of refined products on transfer of title.
Property, Plant and Equipment. We record property, plant and equipment at cost and depreciate the asset or groups of assets using the straight-line method over the estimated useful lives. The estimated useful lives are:
Refinery plant and equipment................................ 5 to 20 years
Pipeline and pumps.......................................... 10 to 20 years
Furniture, fixtures and other............................... 3 to 10 years
We review long-lived assets for impairments whenever events or changes in circumstances indicate that the carrying value of an asset may not be recoverable. If the undiscounted future cash flows of an asset to be held and used in operations is less than the carrying value, we would recognize a loss for the difference between the carrying value and fair market value. We capitalize interest on debt incurred to fund the construction of significant assets.
Turnarounds. Normal maintenance and repairs are expensed as incurred. The costs for turnarounds (scheduled and required shutdown of refinery operating units for significant overhaul and refurbishment) are ratably accrued over the period from the prior turnaround to the next scheduled turnaround. These accruals are included in our consolidated balance sheet in the “Accrued turnaround cost” and “Long-term accrued turnaround cost.” The turnaround accrual expenses are included in “Refining operating costs” in our consolidated statements of operations. Turnaround costs include contract services, materials and rental equipment. Major improvements are capitalized and the assets replaced are retired.
Inventories. Inventories of crude oil, unfinished products and all finished products are recorded at the lower of cost on a first in, first out (FIFO) basis or market. Refined product exchange transactions are considered asset exchanges with deliveries offset against receipts. The net exchange balance is included in inventory. Inventories of materials and supplies and process chemicals are recorded at the lower of average cost or market.
Income Taxes.We account for income taxes under the provisions of Statement of Financial Accounting Standards (“SFAS”) No. 109, Accounting for Income Taxes. SFAS No. 109 requires the asset and liability approach for accounting for income taxes. Under this approach, deferred tax assets and liabilities are recognized based on anticipated future tax consequences attributable to differences between financial statement carrying amounts of assets and liabilities and their respective tax bases.
Environmental Expenditures. Environmental expenditures are expensed or capitalized based upon their future economic benefit. Costs which improve a property’s pre-existing condition and costs which 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.
New Accounting Pronouncements
In June 2001, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 142, “Goodwill and Other Intangible Assets”. SFAS No. 142 addresses financial accounting and reporting for acquired goodwill and other intangible assets and supersedes Accounting Principles Board (“APB") Opinion No. 17, “Intangible Assets”. SFAS No. 142 addresses how intangible assets that are acquired should be accounted for in financial statements upon their acquisition and also addresses how goodwill and other intangible assets should be accounted for after they have been initially recognized in the financial statements. We adopted SFAS No. 142 effective January 1, 2002. The adoption did not have any impact on our financial condition or results of operations.
In June 2001, the FASB issued SFAS No. 143, “Accounting for Asset Retirement Obligations”. This statement provides accounting and disclosure requirements for retirement obligations associated with long-lived assets and is effective January 1, 2003. SFAS 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. SFAS No. 143 also includes disclosure requirements that provide a description of asset retirement obligations and reconciliation of changes in the components of those obligations. We have potential asset retirement obligation (“ARO”) liabilities related to our Refineries as a result of environmental and other legal requirements. Any ARO liability is not currently estimatable as to amount and timing, but we will continue to monitor and evaluate our potential AROs. In the event that we decide to cease the use of a particular refinery, an ARO liability would be recorded at that time. We do not expect the adoption of SFAS No. 143 to have a material impact on our current financial condition or results of operations.
In August 2001, the FASB issued SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets”. SFAS No. 144 addresses the accounting and reporting for the impairment or disposal of long-lived assets and supersedes SFAS No. 121, “Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of ” and APB Opinion No. 30, “Reporting the Results of Operations - Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions.” SFAS No. 144 establishes one accounting model for long-lived assets to be disposed of by sale as well as resolve implementation issues related to SFAS No. 121. We adopted SFAS No. 144 effective January 1, 2002. The adoption did not have any impact on our financial condition or results of operations.
The Accounting Standards Executive Committee of the American Institute of Certified Public Accountants has issued an exposure draft of a proposed Statement of Position (“SOP”) entitled “Accounting for Certain Costs and Activities Related to Property, Plant and Equipment.” If adopted as proposed, this SOP would require companies to expense as incurred turnaround costs, defined as “the non-capital portion of major maintenance costs.” Adoption of the proposed SOP would also require that any existing turnaround accruals be reversed to income immediately. If this proposed change were in effect at December 31, 2002, we would have been required to reverse the turnaround accruals and recognize pretax income totaling $26.9 million. The total accrued turnaround costs will change throughout the year as turnarounds are incurred and accruals are made for future turnarounds. If adopted in its present form, income related to this proposed change would be reported as a cumulative effect of an accounting change, net of tax, in the consolidated statements of operations.
In April 2002, the FASB issued SFAS No. 145, “Rescission of FASB Statements No. 4, 44 and 64, Amendment of FASB Statement No. 13, and Technical Corrections.” It is probable that the rescission of SFAS No. 4 is the only portion of SFAS No. 145 that may have an impact on us in the future. Under SFAS No. 4, all gains and losses from extinguishment of debt were required to be aggregated and, if material, classified as an extraordinary item, net of related income tax effect. SFAS No. 145 eliminates SFAS No. 4. As a result, gains and losses from extinguishment of debt should be classified as extraordinary items only if they meet the criteria in Opinion 30. We adopted SFAS No. 145 effective January 1, 2003 and it did not have any impact on our financial condition or results of operations.
In June 2002, the FASB issued SFAS No. 146, “Accounting for Costs Associated with Exit or Disposal Activities.” SFAS No. 146 addresses financial accounting and reporting for costs associated with exit or disposal activities. SFAS No. 146 is effective for exit or disposal activities that are initiated after December 31, 2002.
In December 2002, the FASB issued SFAS No. 148, “Accounting for Stock-Based Compensation – Transition and Disclosure, an amendment of FASB Statement No. 123.” SFAS No. 148 amends SFAS No. 123, “Accounting for Stock-Based Compensation”, to provide alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation. In addition, SFAS No. 148 amends the disclosure requirements of SFAS No. 123 to require prominent disclosures in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on reported results. SFAS No. 148 is effective for the December 31, 2002 financial statements and all required disclosures have been made in the notes to the 2002 financial statements.
SELECTED QUARTERLY FINANCIAL AND OPERATING DATA
(Dollars in thousands except per share )
2002 2001
------------------------------------------ -------------------------------------------
(unaudited) Fourth Third Second First Fourth Third Second First
- -----------------------------------------------------------------------------------------------------------------------------------------------
Revenues $531,558 $486,680 $459,162 $336,350 $365,560 $538,049 $553,649 $431,143
Operating income (loss) 11,110 8,487 1,631 6,671 (11,447) 62,473 100,916 12,158
Net income (loss) 2,965 809 (3,007) 261 (10,422) 34,662 78,901 4,512
Basic earnings (loss) per share: $0.11 $0.03 ($0.12) $0.01 ($0.41) $1.33 $2.99 $0.17
Diluted earnings (loss) per share: $0.11 $0.03 ($0.12) $0.01 ($0.41) $1.27 $2.86 $0.17
EBITDA (1) 18,089 15,466 8,407 13,269 (5,056) 68,808 107,120 18,238
Net cash provided by (used in) operating activities 43,749 20,237 (3,120) (10,044) (10,827) 73,812 109,164 (33,574)
Refining operations
Total charges (bpd) 162,361 170,391 165,074 157,310 153,649 169,878 161,854 146,632
Gasoline yields (bpd) 94,564 79,779 82,050 82,104 82,310 83,506 77,283 69,201
Diesel and jet fuel yields (bpd) 55,140 53,101 54,190 51,273 49,313 54,578 52,653 48,247
Total product sales (bpd) 175,888 166,750 169,366 153,880 163,375 174,281 159,531 138,770
Average light/heavy spread based on delivered
crude costs for the Cheyenne Refinery(per bbl) $5.73 $3.95 $3.52 $3.75 $6.13 $6.42 $7.55 $8.20
Average WTI/WTS crude oil spread (per bbl) $1.73 $0.97 $1.22 $1.53 $2.22 $2.68 $3.77 $3.73
- -----------------------------------------------------------------------------------------------------------------------------------------------
| (1) | EBITDA represents income before interest expense, income tax and depreciation and amortization. EBITDA is not a calculation based upon generally accepted accounting principles; however, the amounts included in the EBITDA calculation are derived from amounts included in the consolidated financial statements. In addition, EBITDA should not be considered as an alternative to net income or operating income, as an indication of operating performance or as an alternative to operating cash flow as a measure of liquidity. |
FIVE-YEAR FINANCIAL DATA
(Dollars in thousands except per share)
2002 2001 2000 1999 (1) 1998
- -----------------------------------------------------------------------------------------------------------------------------
Revenues $1,813,750 $1,888,401 $2,045,157 $503,600 $299,368
Operating income (loss) 27,899 164,100 70,655 (5,249) 25,700
Income (loss) before extraordinary item 1,028 107,653 37,206 (17,061) 18,818
Extraordinary loss, net of taxes - - - - 3,013
Net income (loss) 1,028 107,653 37,206 (17,061) 15,805
Basic earnings (loss) per share:
Before extraordinary item 0.04 4.12 1.36 (0.62) 0.67
Net income (loss) 0.04 4.12 1.36 (0.62) 0.56
Diluted earnings (loss) per share:
Before extraordinary item 0.04 4.00 1.34 (0.62) 0.65
Net income (loss) 0.04 4.00 1.34 (0.62) 0.55
EBITDA (2) 55,231 189,110 93,662 7,799 36,410
Net cash (used in) provided by operating activities 50,822 138,575 66,346 (11,332) 31,263
Working capital 108,253 109,064 43,610 24,832 30,125
Total assets 628,877 581,746 588,213 521,493 182,026
Long-term debt 207,966 208,880 239,583 257,286 70,000
Shareholders' equity 168,258 169,204 81,424 50,681 70,353
Capital expenditures 37,117 22,824 12,688 181,703 16,763
Dividends declared per common share 0.20 0.15 - - -
- -----------------------------------------------------------------------------------------------------------------------------
| (1) | Includes El Dorado Refinery financial data from November 17, 1999. Capital expenditures in 1999 included the purchase of the El Dorado Refinery. |
| (2) | EBITDA represents income before interest expense, income tax and depreciation and amortization. EBITDA is not a calculaton based upon generally accepted accounting principles; however, the amounts included in the EBITDA calculation are derived from amounts included in the consolidated financial statements of the Company. In addition, EBITDA should not be considered as an alternative to net income or operating income, as an indication of operating performance of the Company or as an alternative to operating cash flow as a measure of liquidity. |
FIVE-YEAR OPERATING DATA
2002 2001 2000 1999 (1) 1998
- ----------------------------------------------------------------------------------------------------------------------
Charges (bpd)
Light crude 35,684 31,456 35,605 10,250 2,174
Heavy crude (2) 110,372 111,061 105,529 39,315 32,303
Other feed and blend stocks 17,760 15,538 14,884 7,589 5,909
Total charges 163,816 158,055 156,018 57,154 40,386
Manufactured product yields (bpd)
Gasoline 84,645 78,126 76,795 24,923 15,738
Diesel and jet fuel 53,436 51,210 50,924 17,340 13,097
Chemicals (3) 369 1,370 1,804 232 -
Asphalt and other 22,352 24,483 23,363 12,982 10,236
Total manufactured product yields 160,802 155,189 152,886 55,477 39,071
Product sales (bpd)
Gasoline 91,989 83,737 83,070 29,728 21,421
Diesel and jet fuel 53,378 51,539 51,568 17,156 12,484
Chemicals (3) 439 1,413 1,964 44 -
Asphalt and other 20,726 22,411 21,556 10,965 8,797
Total product sales 166,532 159,100 158,158 57,893 42,702
Average sales price (per bbl)
Gasoline $33.08 $35.85 $38.09 $26.61 $21.52
Diesel and jet fuel 30.35 34.12 37.19 25.92 19.90
Chemicals (3) 41.68 70.81 70.52 57.50 -
Asphalt and other 13.72 14.07 16.14 12.36 12.07
Operating margin information (per sales bbl)
Average sales price $29.82 $32.53 $35.20 $23.73 $19.10
Raw material, freight and other costs 25.71 25.69 30.41 20.31 13.33
------ ------ ------ ------ ------
Product spread 4.11 6.84 4.79 3.42 5.77
Operating expenses excluding depreciation 2.93 3.27 3.07 2.71 3.02
Depreciation 0.44 0.42 0.39 0.61 0.68
------ ------ ------ ------ ------
Operating margin $ 0.74 $ 3.15 $ 1.33 $ 0.10 $ 2.07
====== ====== ====== ====== ======
Average light/heavy spread based on delivered crude
costs for the Cheyenne Refinery (per bbl) $ 4.24 $ 7.07 $ 5.09 $ 2.17 $ 4.15
Average WTI/WTS crude oil spread (per bbl) $ 1.36 $ 3.10 $ 2.06 n/a n/a
- ----------------------------------------------------------------------------------------------------------------------
| (1) | Includes El Dorado Refinery operating data from November 17, 1999. |
| (2) | Includes intermediate varieties of crude oil used by the El Dorado Refinery. |
| (3) | During 2002, the process of shutting down the phenol and cumene units at El Dorado began and by year-end we had discontinued the production of phenol and acetone, and began producing and selling benzene. |
FRONTIER OIL CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands except per share amounts)
For the years ended December 31, 2002 2001 2000
----------- ----------- -----------
Revenues:
Refined products $ 1,812,613 $ 1,889,233 $ 2,037,840
Other 1,137 (832) 7,317
----------- ----------- -----------
1,813,750 1,888,401 2,045,157
----------- ----------- -----------
Costs and Expenses:
Refining operating costs 1,740,908 1,681,720 1,938,162
Selling and general expenses 17,248 17,571 13,333
Impairment loss on asset held for sale 363 - -
Depreciation 27,332 25,010 23,007
----------- ----------- -----------
1,785,851 1,724,301 1,974,502
----------- ----------- -----------
Operating income 27,899 164,100 70,655
Interest expense and other financing costs 27,613 31,146 34,738
Interest income (1,802) (2,772) (3,364)
----------- ----------- -----------
25,811 28,374 31,374
----------- ----------- -----------
Income before income taxes 2,088 135,726 39,281
Provision for income taxes 1,060 28,073 2,075
----------- ----------- -----------
Net income $ 1,028 $ 107,653 $ 37,206
=========== =========== ===========
Basic earnings per share of common stock $ .04 $ 4.12 $ 1.36
=========== =========== ===========
Diluted earnings per share of common stock $ .04 $ 4.00 $ 1.34
=========== =========== ===========
The accompanying notes are an integral part of these financial statements.
FRONTIER OIL CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(In thousands except share data)
December 31, 2002 2001
------------- -------------
ASSETS
Current assets:
Cash and cash equivalents (Note 2) $ 112,364 $ 103,995
Trade receivables, net of allowance of $500 in both years 81,154 55,848
Note receivable, net of allowance of $800 1,449 -
Other receivables 987 6,469
Inventory of crude oil, products and other 105,160 87,970
Deferred tax assets 5,346 4,845
Other current assets 2,510 2,243
------------- -------------
Total current assets 308,970 261,370
------------- -------------
Property, plant and equipment, at cost:
Refineries and pipelines 447,948 419,962
Furniture, fixtures and other equipment 5,119 5,853
------------- -------------
453,067 425,815
Less - accumulated depreciation 144,127 117,252
------------- -------------
308,940 308,563
Asset held for sale 472 -
Other assets 10,495 11,813
------------- -------------
Total assets $ 628,877 $ 581,746
============= =============
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable $ 174,917 $ 112,303
Accrued turnaround cost 12,849 10,394
Accrued liabilities and other 9,095 25,714
Accrued interest 3,856 3,895
------------- -------------
Total current liabilities 200,717 152,306
------------- -------------
Long-term debt 207,966 208,880
Long-term accrued turnaround cost 14,013 15,443
Postretirement employee liabilities 18,784 16,734
Deferred credits and other 3,963 4,099
Deferred income taxes 15,176 15,080
Commitments and contingencies (Note 7)
Shareholders' equity:
Preferred stock, $100 par value, 500,000 shares authorized,
no shares issued - -
Common stock, no par, 50,000,000 shares authorized,
30,290,324 and 30,059,574 shares
issued in 2002 and 2001, respectively 57,469 57,446
Paid-in capital 102,557 98,046
Retained earnings 49,621 53,764
Accumulated other comprehensive loss (598) (255)
Treasury stock , at cost, 4,151,210 and 4,240,937
shares at December 31, 2002 and 2001, respectively (37,959) (38,163)
Deferred employee compensation (2,832) (1,634)
------------- -------------
Total shareholders' equity 168,258 169,204
------------- -------------
Total liabilities and shareholders' equity $ 628,877 $ 581,746
============= =============
The accompanying notes are an integral part of these financial statements.
FRONTIER OIL CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
For the years ended December 31, 2002 2001 2000
----------- ----------- -----------
Cash flows from operating activities:
Net income $ 1,028 $ 107,653 $ 37,206
Depreciation 27,332 25,010 23,007
Deferred finance cost and bond discount amortization 2,033 2,168 2,190
Deferred employee compensation amortization 907 380 -
Allowance for doubtful trade and note receivables 800 - 533
Impairment loss on asset to be sold 363 - -
Deferred income taxes 1,149 9,463 130
Other (562) 381 (285)
Changes in components of working capital from operations:
Decrease (increase) in trade, note and other receivables (22,178) 15,912 (25,583)
Decrease (increase) in inventory (17,190) 37,511 (25,122)
Decrease (increase) in other current assets (267) 1,569 (2,927)
(Decrease) increase in accounts payable 64,004 (60,013) 49,551
(Decrease) increase in accrued liabilities and other (6,597) (1,459) 7,646
----------- ----------- -----------
Net cash provided by operating activities 50,822 138,575 66,346
----------- ----------- -----------
Cash flows from investing activities:
Additions to property, plant and equipment & other (29,617) (22,824) (12,688)
El Dorado Refinery acquisition-contingent earn-out payment (7,500) - -
------------ ----------- -----------
Net cash used in investing activities (37,117) (22,824) (12,688)
----------- ----------- -----------
Cash flows from financing activities:
Repurchase of debt:
9-1/8% Senior Notes (1,090) (24,410) (5,025)
11-3/4% Senior Notes - (6,541) (13,010)
Repayments of revolving credit facility, net - (23,000) (3,000)
Proceeds from issuance of common stock 1,702 3,271 2,743
Purchase of treasury stock (787) (22,600) (9,215)
Dividends paid (5,161) (2,629) -
Other - (293) (50)
----------- ----------- -----------
Net cash used in financing activities (5,336) (76,202) (27,557)
----------- ----------- -----------
Increase in cash and cash equivalents 8,369 39,549 26,101
Cash and cash equivalents, beginning of period 103,995 64,446 38,345
----------- ----------- -----------
Cash and cash equivalents, end of period $ 112,364 $ 103,995 $ 64,446
=========== =========== ===========
The accompanying notes are an integral part of these financial statements.
FRONTIER OIL CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY
(In thousands except share data)
Common Stock Treasury Stock Total
------------------------ ---------------------- Accumulated --------------------
Compre- Retained Deferred Other
Number of Paid-In hensive Earnings Number of Employee Comprehensive Number of
Shares Issued Amount Capital Income (Deficit) Shares Amount Compensation Income (Loss) Shares Amount
-------------- --------- --------- --------- --------- ----------- --------- --------------- ------------- ----------- ---------
December 31, 1999 28,542,330 $ 57,294 $ 87,028 $ (87,122) (1,230,900) $ (6,519) $ - $ - 27,311,430 $ 50,681
Net income - - - $ 37,206 37,206 - - - - - 37,206
=========
Shares issued under:
Stock option plan 647,674 65 2,678 - (145,196) (1,013) - - 502,478 1,730
Directors stock plan - - - - 2,000 9 - - 2,000 9
Shares repurchased under:
Stock repurchase plans - - - - (1,248,500) (8,202) - - (1,248,500) (8,202)
December 31, 2000 29,190,004 57,359 89,706 (49,916) (2,622,596) (15,725) - - 26,567,408 81,424
Shares issued under:
Stock option plan 869,570 87 3,987 - (101,870) (785) - - 767,700 3,289
Directors stock plan - - - - 3,000 13 - - 3,000 13
Other stock issuances - - 663 - 254,929 1,351 (2,014) - 254,929 -
Shares repurchased under:
Stock repurchase plans - - - - (1,774,400) (23,017) - - (1,774,400) (23,017)
Comprehensive income:
Net income - - - $ 107,653 107,653 - - - - - 107,653
Other comprehensive income:
Cumulative effect of accounting
change on fair value of derivative
instruments, net of tax 3,910
Change in fair value of derivatives (1,626)
Derivative value reclassed to income (2,284)
Minimum pension liability (255)
---------
Other comprehensive income (255) - - - - (255) - (255)
---------
Comprehensive income $ 107,398
=========
Income tax benefits of stock options - - 3,690 - - - - - - 3,690
Deferred employee compensation
Amortization/vested shares - - - - - - 380 - - 380
Dividends declared - - - (3,973) - - - - - (3,973)
December 31, 2001 30,059,574 57,446 98,046 53,764 (4,240,937) (38,163) (1,634) (255) 25,818,637 169,204
Shares issued under:
Stock option plan 230,750 23 1,543 - - - - - 230,750 1,566
Directors stock plan - - - - 3,000 13 - - 3,000 13
Other stock issuances - - 1,544 - 105,768 561 (2,105) - 105,768 -
Shares repurchased under:
Restricted stock plan - - - - (19,041) (370) - - (19,041) (370)
Comprehensive income:
Net income - - - $ 1,028 1,028 - - - - - 1,028
Other comprehensive income:
Deferred net loss on derivative
contracts, net of tax (33)
Derivative value reclassed to income 33
Minimum pension liability (343)
---------
Other comprehensive income (343) (343) (343)
---------
Comprehensive income $ 685
=========
Income tax benefits of
stock compensation - - 1,424 - - - - - - 1,424
Deferred employee compensation
Amortization/vested shares - - - - - - 907 - - 907
Dividends declared - - - (5,171) - - - - - (5,171)
---------- --------- --------- --------- ---------- ---------- ---------- --------- ----------- ---------
December 31, 2002 30,290,324 $ 57,469 $ 102,557 $ 49,621 (4,151,210) $ (37,959) $ (2,832) $ (598) 26,139,114 $ 168,258
========== ========= ========= ========= ========== =========== ========== ========= =========== =========
The accompanying notes are an integral part of these financial statements.
FRONTIER OIL CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
For the Years Ended December 31, 2002, 2001 and 2000
1. Nature of Operations
The financial statements include the accounts of Frontier Oil Corporation, a Wyoming corporation, and its wholly owned subsidiaries, including Frontier Holdings Inc., collectively referred to as Frontier or the Company. The Company is an energy company engaged in crude oil refining and wholesale marketing of refined petroleum products (the “refining operations”).
The Company operates refineries (“the Refineries”) in Cheyenne, Wyoming and El Dorado, Kansas with a combined crude oil capacity of 156,000 barrels per day. The Company also owns a 34.72% undivided interest in a crude oil pipeline in Wyoming and a 50% interest in one crude oil tank and another under construction in Guernsey, Wyoming, both of which are accounted for on a pro rata consolidated basis. The company also has a 50% interest in FGI, LLC, an asphalt terminal and storage facility in Grand Island, Nebraska and a 25% interest in 8901 Hangar, Inc., a company which leases and operates a private airplane hangar, both of which are accounted for using the equity method of accounting. The Company focuses its marketing efforts in the Rocky Mountain and Plains States regions of the United States. The Company purchases crude oil to be refined and markets the refined petroleum products produced, including various grades of gasoline, diesel fuel, jet fuel, asphalt, chemicals and petroleum coke.
2. Significant Accounting Policies
Refined Product Revenues
Revenues from sales of refined products are recognized on transfer of title.
Property, Plant and Equipment
Property, plant and equipment additions are recorded at cost and depreciated using the straight-line method over the estimated useful lives. The estimated useful lives are:
Refinery plant and equipment................................ 5 to 20 years
Pipeline and pumps.......................................... 10 to 20 years
Furniture, fixtures and other............................... 3 to 10 years
The Company reviews long-lived assets for impairments whenever events or changes in circumstances indicate that the carrying value of an asset may not be recoverable. If the undiscounted future cash flows of an asset to be held and used in operations is less than the carrying value, the Company would recognize a loss for the difference between the carrying value and fair market value. The Company capitalizes interest on debt incurred to fund the constructions of significant assets. Interest capitalized for the year ended December 31, 2002 was $342,000. There was no interest capitalized for the years 2001 and 2000.
Turnarounds
Normal maintenance and repairs are expensed as incurred. The costs for turnarounds (scheduled and required shutdown of refinery operating units for significant overhaul and refurbishment) are ratably accrued over the period from the prior turnaround to the next scheduled turnaround. These accruals are included in the Company’s consolidated balance sheet in the “Accrued turnaround cost” and “Long-term accrued turnaround cost.” The turnaround accrual expenses are included in “Refining operating costs” in the Company’s consolidated statements of operations. Turnaround costs include contract services, materials and rental equipment. Major improvements are capitalized, and the assets replaced are retired.
Inventories
Inventories of crude oil, unfinished products and all finished products are recorded at the lower of cost on a first in, first out (FIFO) basis or market. Refined product exchange transactions are considered asset exchanges with deliveries offset against receipts. The net exchange balance is included in inventory. Inventories of materials and supplies and process chemicals are recorded at the lower of average cost or market.
Components of Inventory
(In thousands)
December 31,
------------------------
2002 2001
----------- -----------
Crude Oil $ 33,765 $ 24,787
Unfinished products 24,806 24,406
Finished products 29,836 21,607
Process chemicals 3,308 4,103
Repairs and maintenance supplies and other 13,445 13,067
----------- -----------
$ 105,160 $ 87,970
=========== ===========
Income Taxes
The Company accounts for income taxes under the provisions of Statement of Financial Accounting Standards (“SFAS”) No. 109, Accounting for Income Taxes. SFAS No. 109 requires the asset and liability approach for accounting for income taxes. Under this approach, deferred tax assets and liabilities are recognized based on anticipated future tax consequences attributable to differences between financial statement carrying amounts of assets and liabilities and their respective tax bases.
Environmental Expenditures
Environmental expenditures are expensed or capitalized based upon their future economic benefit. Costs which improve a property’s pre-existing condition and costs which prevent future environmental contamination are capitalized. Remediation costs related to environmental damage resulting from operating activities subsequent to acquisition are expensed. Liabilities for these expenditures are recorded when it is probable that obligations have been incurred and the amounts can be reasonably estimated.
Price Risk Management Activities
The Company, at times, enters into commodity derivative contracts to manage its price exposure to its inventory positions, purchases of foreign crude oil and consumption of natural gas in the refining process or to fix margins on certain future production. The commodity derivative contracts used by the Company may take the form of futures contracts, collars or price swaps and are entered into with credit-worthy counterparties. The Company believes there is minimal credit risk with respect to its counterparties. The Company accounts for its commodity derivative contracts under the hedge (or deferral) method of accounting when the derivative contracts are designated as hedges for accounting purposes, or mark-to-market accounting if the Company elects not to designate derivative contracts as accounting hedges or if such derivative contracts do not qualify for hedge accounting. As such, gains or losses on commodity derivative contracts accounted for as hedges are recognized in refining operating costs when the associated transactions are consummated while gains and losses on transactions accounted for using mark-to-market accounting are reflected in other revenues at each period end.
Stock-Based Compensation
Stock-based compensation is measured in accordance with Accounting Principles Board (“APB”) No. 25. Under this intrinsic value method, compensation cost is the excess, if any, of the quoted market value of the Company’s common stock at the grant date over the amount the employee must pay to acquire the stock. Compensation costs of $907,000 and $380,000 related to restricted stock awards was recognized for the years ended December 31, 2002 and 2001, respectively. No compensation cost was recognized for the year ended December 31, 2000.
Intercompany Transactions
Intercompany transactions are eliminated in consolidation.
Use of Estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
New Accounting Pronouncements
In June 2001, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 142, “Goodwill and Other Intangible Assets”. SFAS No. 142 addresses financial accounting and reporting for acquired goodwill and other intangible assets and supersedes APB Opinion No. 17, “Intangible Assets”. SFAS No. 142 addresses how intangible assets that are acquired should be accounted for in financial statements upon their acquisition and also addresses how goodwill and other intangible assets should be accounted for after they have been initially recognized in the financial statements. The Company adopted SFAS No. 142 effective January 1, 2002. The adoption did not have any impact on the Company’s financial condition or results of operations.
In June 2001, the FASB issued SFAS No. 143, “Accounting for Asset Retirement Obligations”. This statement provides accounting and disclosure requirements for retirement obligations associated with long-lived assets and is effective January 1, 2003. SFAS 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. SFAS No. 143 also includes disclosure requirements that provide a description of asset retirement obligations and reconciliation of changes in the components of those obligations. The Company has potential asset retirement obligation (“ARO”) liabilities related to its Refineries as a result of environmental and other legal requirements. Any ARO liability is not currently estimatable as to amount and timing, but the Company will continue to monitor and evaluate its potential AROs. In the event that the Company decides to cease the use of a particular refinery, an ARO liability would be recorded at that time. The Company does not expect the adoption of SFAS No. 143 to have a material impact on the Company’s current financial condition or results of operations.
In August 2001, the FASB issued SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets”. SFAS No. 144 addresses the accounting and reporting for the impairment or disposal of long-lived assets and supersedes SFAS No. 121, “Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of ” and APB Opinion No. 30, “Reporting the Results of Operations - Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions.” SFAS No. 144 establishes one accounting model for long-lived assets to be disposed of by sale as well as resolves implementation issues related to SFAS No. 121. The Company adopted SFAS No. 144 effective January 1, 2002. The adoption did not have any impact on the Company’s financial condition or results of operations.
The Accounting Standards Executive Committee of the American Institute of Certified Public Accountants has issued an exposure draft of a proposed Statement of Position (“SOP”) entitled “Accounting for Certain Costs and Activities Related to Property, Plant and Equipment.” If adopted as proposed, this SOP would require companies to expense as incurred turnaround costs, defined as “the non-capital portion of major maintenance costs.” Adoption of the proposed SOP would also require that any existing turnaround accruals be reversed to income immediately. If this proposed change were in effect at December 31, 2002, the Company would have been required to reverse the turnaround accruals and recognize pretax income totaling $26.9 million. The total accrued turnaround costs will change throughout the year as turnarounds are incurred and accruals are made for future turnarounds. If adopted in its present form, income related to this proposed change would be reported as a cumulative effect of an accounting change, net of tax, in the consolidated statements of operations.
In April 2002, the FASB issued SFAS No. 145, “Rescission of FASB Statements No. 4, 44 and 64, Amendment of FASB Statement No. 13, and Technical Corrections.” It is probable that the rescission of SFAS No. 4 is the only portion of SFAS No. 145 that may have an impact on the Company in the future. Under SFAS No. 4, all gains and losses from extinguishment of debt were required to be aggregated and, if material, classified as an extraordinary item, net of related income tax effect. SFAS No. 145 eliminates SFAS No. 4. As a result, gains and losses from extinguishment of debt should be classified as extraordinary items only if they meet the criteria in Opinion 30. The Company adopted SFAS No. 145 effective January 1, 2003 and it did not expected have any impact on the Company’s financial condition or results of operations for the periods presented herein.
In June 2002, the FASB issued SFAS No. 146, “Accounting for Costs Associated with Exit or Disposal Activities.” SFAS No. 146 addresses financial accounting and reporting for costs associated with exit or disposal activities. SFAS No. 146 is effective for exit or disposal activities that are initiated after December 31, 2002.
In December 2002, the FASB issued SFAS No. 148, “Accounting for Stock-Based Compensation – Transition and Disclosure, an amendment of FASB Statement No. 123.” SFAS No. 148 amends SFAS No. 123, “Accounting for Stock-Based Compensation”, to provide alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation. In addition, SFAS No. 148 amends the disclosure requirements of SFAS No. 123 to require prominent disclosures in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on reported results. SFAS No. 148 is effective for the December 31, 2002 financial statements and all required disclosures have been made in the notes to the 2002 financial statements.
Cash Equivalents
Highly liquid investments with a maturity, when purchased, of three months or less are considered to be cash equivalents. Cash equivalents were $109.8 million and $102.3 million at December 31, 2002 and 2001, respectively.
Supplemental Cash Flow Information
Cash payments for interest, excluding capitalized interest, during 2002, 2001 and 2000 were $24.5 million, $27.8 million and $31.7 million, respectively. Cash payments for income taxes during 2002, 2001 and 2000 were $83,000, $21.2 million and $2.4 million, respectively.
Reclassifications
Certain prior year amounts have been reclassified to conform with the current year presentation.
3. Debt
Schedule of Long-term Debt
(in thousands)
December 31,
---------------------------
2002 2001
------------ ------------
11-3/4% Senior Notes, net of unamortized discount $ 168,491 $ 168,315
9-1/8% Senior Notes 39,475 40,565
------------ ------------
$ 207,966 $ 208,880
============ ============
Senior Notes
On November 5, 1999, the Company issued $190 million principal amount of 11¾% Senior Notes due 2009. The 11¾% Notes were issued at a price of 98.562%. The net proceeds were utilized to acquire the El Dorado Refinery. The 11¾% Notes are redeemable, at the option of the Company, at 105.875% after November 15, 2004, declining to 100% in 2007. Prior to November 15, 2004, the Company may at its option redeem the 11¾% Notes at a defined make-whole amount, plus accrued and unpaid interest. During 2001 and 2000, the Company purchased and is holding as treasury notes $6.5 million and $13.0 million, respectively, principal amount of the 11¾% Senior Notes, the accounting for which was a reduction of debt. Interest is paid semiannually.
On February 9, 1998, the Company issued $70 million of 9-1/8% Senior Notes due 2006. The 9-1/8% Notes are redeemable, at the option of the Company, at 104.563% after February 15, 2002, declining to 100% in 2005. Interest is paid semiannually. During 2002, 2001 and 2000, the Company purchased and is holding as treasury notes $1.1 million, $24.4 million and $5.0 million, respectively, principal amount of the 9-1/8% Senior Notes, the accounting for which was a reduction of debt.
Revolving Credit Facility
The refining operations have a working capital credit facility with a group of nine banks. The revolving credit facility has a current expiration date of June 15, 2004. The facility is a collateral-based facility with total capacity of up to $175 million, of which maximum cash borrowings are $125 million, subject to borrowing base amounts. Any unutilized capacity after cash borrowings is available for letters of credit. No debt was outstanding at December 31, 2002 or 2001. Standby letters of credit outstanding were $48.0 million and $175,000 at December 31, 2002 and 2001, respectively.
The facility provides working capital financing for operations, generally the financing of crude and product supply. It is generally secured by the Refineries’ current assets. The agreement provides for a quarterly commitment fee of 0.375 of 1% to 0.500 of 1% per annum. Interest rates are based, at the Company’s option, on the agent bank’s prime rate plus 0.25% to 1%, the prevailing Federal Funds Rate plus 2% to 2.75%, or the reserve-adjusted LIBOR plus 1.5% to 2.25%. Standby letters of credit issued bear a fee of 1.125% to 1.875% annually, plus standard issuance and renewal fees. In all cases, the rate and fees discussed above increase from the lower to higher levels as the ratio of funded debt to earnings, as defined, increases. The average interest rate on funds borrowed under the revolving credit facility during 2002 was 3.7%. The agreement includes certain financial covenant requirements relating to the Refineries’ working capital, cash earnings, tangible net worth and capital expenditure limits. The Company was in compliance with these covenants at December 31, 2002.
Restrictions on Loans, Transfer of Funds and Payment of Dividends
The revolving credit facility restricts the Refineries as to the distribution of capital assets and the transfer of cash in the form of dividends, loans or advances when there are any outstanding borrowings under the facility or when a default exists or would occur. The Company is currently in compliance with the provisions of its credit agreement.
Five-year Maturities
The 9-1/8% Senior Notes are due 2006 and the 11¾% Notes are due 2009; until then there are no maturities of long-term debt.
4. Income Taxes
The following is the provision for income taxes for the three years ended December 31, 2002, 2001 and 2000.
Provision (Befefit) for Income Taxes
(In thousands)
2002 2001 2000
------------- ------------- -------------
Current:
State $ 32 $ 6,231 $ 615
Canadian 83 - 751
Federal (204) 12,379 579
------------- ------------- -------------
Total current (benefit) provision (89) 18,610 1,945
------------- ------------- -------------
Deferred:
State 303 457 1,277
Federal 846 9,006 (1,147)
------------- ------------- -------------
Total deferred provision 1,149 9,463 130
------------- ------------- -------------
$ 1,060 $ 28,073 $ 2,075
============= ============= =============
The following is a reconciliation of the provision for income taxes computed at the statutory United States income tax rates on pretax income and the provision for income taxes as reported for the three years ended December 31, 2002, 2001 and 2000.
Reconciliation of Tax Provision
(In thousands)
2002 2001 2000
------------- ------------- -------------
Provision based on statutory rates $ 731 $ 47,504 $ 13,748
Increase (decrease) resulting from:
Release of valuation allowance - (24,603) (13,574)
Federal tax effect of state and other income taxes (146) (2,341) (925)
State and other income taxes 418 6,688 2,643
Other 57 825 183
------------- ------------- -------------
Provision as reported $ 1,060 $ 28,073 $ 2,075
============= ============= =============
Significant components of deferred tax assets and liabilities are shown below:
Components of Deferred Taxes
(In thousands)
December 31,
------------------------------
2002 2001
------------- -------------
Current deferred tax assets:
State gross current assets $ 808 $ 765
State net operating losses 287 -
State gross current liabilities (132) (149)
------------- -------------
Total state current net deferred tax assets 963 616
------------- -------------
Federal gross current assets 5,651 5,304
Federal gross current liabilities (1,268) (1,075)
------------- -------------
Total federal current net deferred tax assets 4,383 4,229
------------- -------------
Total current deferred tax assets $ 5,346 $ 4,845
============= =============
Long-term deferred tax liabilities:
State gross long-term liabilities $ 6,242 $ 5,700
State gross long-term assets (1,767) (1,660)
------------- -------------
Total state long-term net deferred tax liabilities 4,475 4,040
------------- -------------
Federal gross long-term liabilities 39,460 41,071
Federal gross long-term assets:
Accrued liabilities and other (13,923) (13,372)
Federal alternative minimum tax credits (13,434) (13,614)
Federal net operating loss carryforwards and other (1,402) (3,045)
------------- -------------
Total federal gross long-term assets (28,759) (30,031)
------------- -------------
Total federal long-term net deferred tax liabilities 10,701 11,040
------------- -------------
Total long-term deferred tax liabilities $ 15,176 $ 15,080
============= =============
The accrued liabilities and other deferred tax assets primarily include turnaround and postretirement employee benefit expenses. The major component of the deferred tax liabilities is depreciation.
At December 31, 2002, the Company had alternative minimum tax carryforwards of approximately $13.4 million which are indefinitely available to reduce future United States income taxes payable, of which $644,000 represents alternative minimum tax carryforwards generated by the Cheyenne refining operations prior to its 1991 acquisition by the Company which may be subject to certain limitations. The Company had an estimated federal net operating loss carryforward of $6.7 million as of December 31, 2002, the majority of which will not expire until 2022.
The Company has estimated state net operating losses generated during 2002 to reduce future state taxable income of $3.3 million for Kansas, $690,000 for Colorado and $174,000 for Nebraska. Carryforward periods for the state net operating losses are ten years for Kansas, twenty years for Colorado and five years for Nebraska. State deferred tax liabilities were $3.5 million and $3.4 million at December 31, 2002 and 2001, respectively, reflecting the estimated state tax effect of temporary differences, primarily for differences in depreciation for property, plant and equipment.
5. Common Stock
Dividends
The Company declared quarterly dividends of $.05 per share of common stock for each quarter during 2002 and quarterly dividends of $.05 per share for the second, third and fourth quarters of 2001. No dividends were declared for the year ended December 31, 2000.
Earnings per Share
The following sets forth the computation of diluted earnings per share (“EPS”) for the years ended December 31, 2002, 2001 and 2000.
2002 2001 2000
---------------------------------- ---------------------------------- ----------------------------------
Per Per Per
Income Shares Share Income Shares Share Income Shares Share
(Numerator) (Denominator) Amount (Numerator) (Denominator) Amount (Numerator) (Denominator) Amount
----------- ------------- -------- ----------- ------------- -------- ----------- ------------- --------
(In thousands except per share amounts)
Basic EPS:
Net income $ 1,028 25,780 $ .04 $ 107,653 26,113 $ 4.12 $ 37,206 27,374 $ 1.36
Dilutive securities:
Stock options and
restricted stock - 1,154 - 772 - 415
----------- ------------- -------- ----------- ------------- -------- ----------- ------------- --------
Dilutive EPS:
Net income $ 1,028 26,934 $ .04 $ 107,653 26,885 $ 4.00 $ 37,206 27,789 $ 1.34
========= ============= ======== =========== ============= ======== =========== ============= ========
Certain of the Company’s restricted stock that could potentially dilute basic EPS in the future were not included in the computation of diluted EPS because to do so would have been antidilutive for the periods presented.
Non-employee Directors Stock Grant Plan
During 1995, the Company established a stock grant plan for non-employee directors. The purpose of the plan is to provide a part of non-employee directors’ compensation in Company stock. The plan will be beneficial to the Company and its stockholders by allowing non-employee directors to have a personal financial stake in the Company through an ownership interest in the Company’s common stock. The plan may grant an aggregate of 60,000 shares of the Company’s common stock held in treasury. The Company made aggregate grants to directors under this plan of 3,000 shares in 2002, 3,000 shares in 2001 and 2,000 shares in 2000 and expensed compensation in the amount of $13,500, $13,500 and $9,000, respectively for each of these years. There were 42,000 shares available for grant as of December 31, 2002.
Stock Option Plan
The Company has a stock option plan which authorizes the granting of options to employees to purchase shares. The plans through December 31, 2002 have reserved for issuance a total of 8,002,075 shares of common stock of which 4,435,175 shares were granted and exercised, 2,581,250 shares were granted and were outstanding and 985,650 shares were available to be granted. Options under the plan are granted at fair market value on the date of grant. No entries are made in the accounts until the options are exercised, at which time the proceeds are credited to common stock and paid-in capital. Generally, the options vest ratably throughout their one- to five-year terms.
Changes during 2002, 2001 and 2000 in outstanding options are presented below:
2002 2001 2000
--------------------------- --------------------------- ---------------------------
Weighted- Weighted- Weighted-
Number of Average Number of Average Number of Average
Options Exercise Price Options Exercise Price Options Exercise Price
---------- -------------- ---------- -------------- ---------- --------------
Outstanding at beginning of year 2,159,700 $ 7.22 2,451,220 $ 5.88 2,115,884 $ 4.68
Granted 702,400 21.85 623,500 8.88 1,218,000 7.13
Exercised (230,750) 6.79 (869,570) 4.68 (647,674) 4.24
Expired (50,100) 10.21 (45,450) 6.41 (234,990) 6.10
---------- ---------- ----------
Outstanding at end of year 2,581,250 11.18 2,159,700 7.22 2,451,220 5.88
========== ========== ==========
Exercisable at end of year 1,512,325 8.63 1,022,826 6.72 1,326,570 5.17
========== ========== ==========
Available for grant at end of year 985,650 765,230 1,343,280
========== ========== ==========
Weighted-average fair value of
options granted during the year 9.34 4.39 3.58
The following table summarizes information about stock options outstanding at December 31, 2002:
Options Outstanding Options Exercisable
------------------------------------------- ---------------------------
Weighted-
Average Weighted- Weighted-
Number Remaining Average Average
Outstanding Contractual Exercise Exercisable Exercise
Range of Exercise Prices At 12/31/02 Life (Years) Price at 12/31/02 Price
- -------------------------- -------------- ------------ ---------- ------------- -----------
$5.63 to $7.00 1,263,550 1.86 $ 6.48 1,039,650 $ 6.37
$8.50 to $8.75 595,000 3.04 8.58 284,500 8.57
$12.10 20,000 3.33 10.10 10,000 12.10
$19.07 to 21.85 702,700 4.29 21.81 178,175 21.77
Had compensation costs been determined based on the fair value at the grant dates for awards made in 2002, 2001, and prior years for the vested portions of the awards in each of the years 2002, 2001 and 2000, the Company’s net income (loss) and EPS would have been the pro forma amounts indicated in the following table for the years ended December 31, 2002, 2001 and 2000:
2002 2001 2000
------------- ------------- -------------
(In thousands except per share amounts)
Net income as reported $ 1,028 $ 107,653 $ 37,206
Pro forma compensation expense, net of tax (4,002) (1,670) (2,156)
------------- ------------- -------------
Pro forma net income (loss) (2,974) 105,983 35,050
Basic EPS:
As reported $ .04 $ 4.12 $ 1.36
Pro forma (.12) 4.06 1.28
Diluted EPS:
As reported $ .04 $ 4.00 $ 1.34
Pro forma (.12) 3.94 1.26
The fair value of grants was estimated on the date of grant using the Black-Scholes option pricing model with the following weighted-average assumptions used for 2002, 2001 and 2000, respectively: risk-free interest rates of 2.76%, 4.80% and 6.58%, expected volatilities of 55.6%, 50.20% and 47.40%, expected lives of 5.0 years, 5.0 years, and 3.50 years and 1.27% dividend yield in 2002, 0.5% dividend yield in 2001 and no dividend yield in 2000.
Restricted Stock Plan
On March 13, 2001, the Company established the Frontier Oil Corporation Restricted Stock Plan (the “Plan”) covering 1,000,000 shares of common stock held as treasury stock by the Company. The Plan’s purpose is to permit grants of shares, subject to restrictions, to key employees of the Company and is intended to promote the interests of the Company by encouraging those employees to acquire or increase their equity interest in the Company. The Plan is also intended to enhance the ability of the Company to attract and retain the services of key employees who are important to the growth and profitability of the Company. The Plan is designed to work in conjunction with the Company’s annual bonus program for employees whereby all or a portion of a bonus awarded shall be paid in the form of restricted stock granted under the Plan. Shares awarded under the Plan entitle the shareholder to all rights of common stock ownership except that the shares may not be sold, transferred or pledged during the restriction period except as provided for in the Plan and any dividends are held by the Company and paid to the employee when the stock vests.
As of December 31, 2002, there are 294,697 shares of unvested restricted stock which represents the total of both the 2001 and 2002 grants less the portion of the 2001 grant which has now vested and reduced by shares forfeited from employee departures prior to vesting. Of the remaining 181,638 shares from the 2001 grants, 60,540 shares vest in March 2003 and the remaining 121,098 shares will vest in March 2004. The Company granted an additional 113,059 restricted shares on March 13, 2002 and recorded an additional $2.2 million to deferred employee compensation. These restricted shares of common stock granted in 2002 vest 25% in March 2003, 25% in March 2004 and 50% in March 2005. The shares for both the 2002 and 2001 grants were recorded at the market value on the date of issuance (March 13, 2002 and 2001 respectively) as deferred employee compensation (equity account) and is being amortized to compensation expense over the respective vesting periods of the stock. Compensation expense for the years ended December 31, 2002 and 2001 was $907,000 and $380,000, respectively.
6. Employee Benefit Plans
Contribution Plans
The Company sponsors defined contribution plans for its employees. All employees may participate by contributing a portion of their annual earnings to the plans. The Company makes basic and/or matching contributions on behalf of participating employees. The cost of the plans for the three years ended December 31, 2002, 2001 and 2000 was $5.1 million, $4.6 million and $4.8 million, respectively.
Defined Benefit Plans
The Company established a defined cash balance pension plan, effective January 1, 2000, for eligible El Dorado employees to supplement retirement benefits those employees lost upon the sale of the El Dorado Refinery to Frontier. No other current or future employees will be eligible to participate in the plan. This plan has assets of $3.8 million at December 31, 2002 and its funding status is in compliance with ERISA.
The Company provides postretirement healthcare and other benefits to certain employees of the El Dorado Refinery. Eligible employees are employees hired by the Refinery before certain defined dates and who satisfy certain age and service requirements. Employees hired on or before November 16, 1999 qualify for retirement healthcare insurance until eligible for Medicare. Employees hired on or before January 1, 1995 are also eligible for Medicare supplemental insurance. These plans have no assets as of December 31, 2002 and 2001.
The following tables set forth the change in benefit obligation, the change in plan assets, the funded status of the pension plan and postretirement healthcare and other benefit plans, amounts recognized in the Company’s financial statements, and the principal weighted-average assumptions used:
Post-retirement
Healthcare and
Pension Benefits Other Benefits
------------------- -------------------
2002 2001 2002 2001
-------- -------- -------- --------
(In thousands)
Change in benefit obligation
Benefit obligation at January 1 $ 8,816 $ 8,409 $ 15,075 $ 12,015
Service cost - - 691 599
Interest cost 582 563 1,071 901
Plan participant contributions - - 3 1
Actuarial (gains) losses 449 (95) 2,547 1,566
Benefits paid (53) (61) (7) (7)
-------- -------- -------- --------
Benefit obligation at December 31 $ 9,794 $ 8,816 $ 19,380 $ 15,075
======== ======== ======== ========
Change in plan assets
Fair value of plan assets at January 1 $ 925 $ - $ - $ -
Actual return on plan assets 54 13 - -
Employer contribution 2,851 973 4 6
Plan participant contributions - - 3 1
Benefits paid (53) (61) (7) (7)
-------- -------- -------- --------
Fair value of plan assets at December 31 $ 3,777 $ 925 $ - $ -
======== ======== ======== ========
Funded status $ (6,017) $ (7,891) $(19,380) $(15,075)
Unrecognized net actuarial loss 970 413 4,941 2,530
-------- -------- -------- --------
Net amount recognized $ (5,047) $ (7,478) $(14,439) $(12,545)
======== ======== ======== ========
Amounts recognized in the balance sheets:
Accrued benefit liability $ (6,017) $ (7,891) $(14,439) $(12,545)
Accumulated other comprehensive loss 970 413 - -
-------- -------- -------- --------
Net amount recognized $ (5,047) $ (7,478) $(14,439) $(12,545)
======== ======== ======== ========
Weighted-average assumptions as of December 31
Discount rate 6.25% 6.82% 6.25% 6.82%
Expected return on plan assets 8.00% 8.00% 8.00% 8.00%
Components of net periodic benefit cost are as follows:
Post-retirement
Healthcare and
Pension Benefits Other Benefits
------------------- -------------------
2002 2001 2002 2001
-------- -------- -------- --------
(in thousands)
Components of net periodic benefit cost:
Service cost $ - $ - $ 691 $ 599
Interest cost 582 563 1071 901
Expected return on plan assets (162) (25) - -
Amortization of prior service cost - - - -
Recognized net actuarial loss - - 136 11
-------- -------- -------- --------
Net periodic benefit cost $ 420 $ 538 $ 1,898 $ 1,511
======== ======== ======== ========
Healthcare cost trend rate:
15.00% 15.00%
ratable to ratable to
5.0% from 5.0% from
2007 2007
Sensitivity Analysis:
Effect of 1% (-1%) change in healthcare cost-trend rate:
Year-end benefit obligation $ 4,258 $ 3,322
(3,313) (2,585)
Total of service and interest cost 394 338
(307) (263)
7. Commitments and Contingencies
Lease and Other Commitments
On November 16, 1999, Frontier acquired the 110,000 barrels per day crude oil refinery located in El Dorado, Kansas from Equilon Enterprises LLC, now known as Shell Oil Products US (“Shell”). Under the provisions of the purchase and sale agreement, the Company is required to make contingent earn-out payments for each of the years 2000 through 2007 equal to one-half of the excess over $60 million per year of the El Dorado Refinery’s revenues less its material costs and operating costs, other than depreciation. The total amount of these contingent payments is capped at $40 million, with an annual cap of $7.5 million. Any contingency payment will be recorded when determinable. Such contingency payments, if any, will be recorded as additional acquisition cost. No contingent earn-out payment will be required based on 2002 results. A contingent earn-out payment of $7.5 million was required based on 2001 results and was accrued as of December 31, 2001 and paid in early 2002. No contingent earn-out payment was required based on 2000 results.
In connection with the acquisition of the El Dorado Refinery, the Company entered into an operating sublease agreement with Shell for the use of the cogeneration facility at the El Dorado Refinery. The noncancellable operating sublease expires in 2016 with the Company having the option to renew the sublease for an additional eight years. At the end of the renewal sublease term, the Company has the option to purchase the cogeneration facility for the greater of fair value or $22.3 million. The Company also has building, equipment, aircraft and vehicle operating leases that expire from 2003 through 2008. Operating lease rental expense was approximately $11.3 million, $11.9 million and $11.1 million for the three years ended December 31, 2002, 2001 and 2000, respectively. The approximate future minimum lease payments as of December 31, 2002 are $10.4 million for 2003, $10.0 million for 2004, $9.5 million for 2005, $9.0 million for 2006, $7.5 million for 2007 and $56.9 million thereafter.
The Company has a one-year foreign crude oil supply agreement with Shell which expires April 2003. Under this agreement, the Company may purchase crude oil for the El Dorado Refinery from Shell, although the Company is not obligated to do so. The Company is obligated to pay monthly installments towards an annualized commitment fee to Shell for making foreign crude volumes available to the Company under this agreement based on a per barrel fee for crude purchased under this agreement. This agreement allows the Company to use Shell’s worldwide network to acquire foreign crude oil.
In October 2002, the Company 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. (“Baytex”). This agreement, which commences January 1, 2003, will provide for the Company to purchase up to 20,000 barrels per day of a Lloydminster crude oil blend, a heavy Canadian crude. Initially, the Company will receive 9,000 barrels per day, increasing up to 20,000 barrels per day by October 2003. The Company intends to process this crude oil at the Cheyenne Refinery, which is near Guernsey, Wyoming, the delivery point of the crude oil under this agreement. This type of crude oil typically sells at a discount to lighter crude oils. The Company’s price for the crude oil under the agreement will be 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 pipeline tariff from Hardisty, Alberta to Guernsey, Wyoming, less $0.25 per barrel. The initial term of the agreement is through December 31, 2007. This agreement provides a firm source of heavy Canadian crude and also assigns most of the Company’s dedicated capacity through the Express Pipeline, a crude oil pipeline from Canada to Guernsey, Wyoming.
The Company contracted for pipeline capacity of approximately 13,800 bpd on the Express Pipeline from Hardisty, Alberta to Guernsey, Wyoming in 1997 for a period of 15 years. The agreement has allowed the Company to assign a portion of its capacity in early years for additional capacity in later years. As discussed above, the Company has assigned a portion of its contracted pipeline capacity to Baytex in connection with the crude supply agreement. The Company’s commitment for pipeline capacity, based on the current tariff, and after reducing for the commitment assigned to Baytex under the initial term of the agreement, is approximately $1.6 million for 2003, $178,000 for 2004, $934,000 for 2005, $284,000 for 2006, $0 for 2007, $6.1 million for each of the years 2008 though 2011, and $1.5 million for 2012. Should the Baytex agreement be extended, as provided for in the agreement, beyond the initial term which is through December 31, 2007, a significant portion of the Company’s commitment for pipeline capacity will continue to be assigned to Baytex in the years 2008 through 2012.
The Company has a Resid Processing Agreement, as amended, with Conoco Inc. (“Conoco”) which expires no later than December 2006. Conoco is entitled to process in the Cheyenne Refinery coker unit up to 3,300 barrels per day of resid. The Company earns a processing fee ranging from $.80 to $2.05 per barrel depending on the number of barrels of resid processed plus a pro rata share of the actual coker operating costs.
The Company owns a 25,000 bpd interest in a crude oil pipeline from Guernsey, Wyoming to the Cheyenne Refinery and a 50% interest in some crude oil tankage in Guernsey. The Company’s share of operating costs for the crude oil pipeline and the tanks are recorded as refining operating costs.
The Company has commitments to purchase crude oil from various suppliers on a one-month to one-year basis at daily market posted prices to meet its refineries’ throughput requirements.
Concentration of Credit Risk
The Company has concentrations of credit risk with respect to sales within the same or related industry and within limited geographic areas. The Company sells its Cheyenne products exclusively at wholesale, principally to independent retailers and major oil companies located primarily in the Denver, western Nebraska and eastern Wyoming regions. The Company sells a majority of its El Dorado gasoline, diesel and jet fuel to Shell at market-based prices, under a 15-year offtake agreement in conjunction with the purchase of the El Dorado Refinery previously discussed. Beginning in 2000, the Company retained and marketed a portion of the El Dorado Refinery’s gasoline and diesel production. This portion will increase 5,000 barrels per day each year for ten years. The amount of gasoline and diesel production retained by the Company began at 5,000 barrels per day in 2000, and will rise to 50,000 barrels in 2009 and remain at that level through the term of the agreement. Shell will purchase all jet fuel production from the El Dorado Refinery through 2004. The Company retains and markets all of the chemicals and heavy oils production from the El Dorado Refinery.
The Company extends credit to its customers based on ongoing credit evaluations. An allowance for doubtful accounts is provided based on the current evaluation of each customers’ credit risk, past experience and other factors. During 2002, the Company provided an allowance of $800,000 against a $2.2 million note receivable from a customer which represents the estimated unsecured portion of the note. During 2000, doubtful accounts for two customers totaling $533,000 were written off. The Company made sales to Shell during 2002, 2001 and 2000 of approximately $1.1 billion, $1.1 billion and $1.2 billion, respectively, which accounted for 58% of consolidated sales revenues in 2002 and 59% of consolidated sales revenues in 2001 and 2000.
Environmental
The Company accounts for environmental costs as indicated in Note 2. The Company’s refining and marketing operations are subject to a variety of federal, state and local health and environmental laws and regulations governing product specifications, the discharge of pollutants into the air and water, and the generation, treatment, storage, transportation and disposal of solid and hazardous waste and materials. Permits are required for the operation of the Refineries, and these permits are subject to revocation, modification and renewal. Governmental authorities have the power to enforce compliance with these regulations and permits, and violators are subject to injunctions, civil fines and even criminal penalties. The Company believes that each of our Refineries is in substantial compliance with existing environmental laws, regulations and permits.
The Company’s operations and many of the products manufactured are specifically subject to certain requirements of the Clean Air Act (“CAA”) and related state and local regulations. The 1990 amendments to the CAA contain provisions that will require capital expenditures for the installation of certain air pollution control devices at our refineries during the next several years. The EPA recently embarked on a Petroleum Refining Initiative (“Initiative”) alleging industry-wide noncompliance with certain CAA rules. The Initiative has resulted in many refiners entering into consent decrees typically requiring substantial expenditures for penalties and additional pollution control equipment. Frontier has been contacted by the EPA and invited to meet with them to hear more about the Initiative. At this time, the Company does not know how or if the Initiative will affect Frontier. The Company has, however, recently determined that over the next three years, expenditures totaling approximately $10 million may be necessary to further reduce emissions from the Refineries’ flare systems. Because other refineries will be required to make similar expenditures, Frontier does not expect such expenditures to materially adversely impact the Company’s competitive position.
On December 21, 1999, the EPA promulgated national regulations limiting the amount of sulfur that is to be allowed in gasoline. The total capital expenditures estimated, as of December 31, 2002, to achieve the final gasoline sulfur standard, are approximately $35 million at the Cheyenne Refinery and approximately $44 million at the El Dorado Refinery. Approximately $7.2 million of the Cheyenne Refinery expenditures had been incurred as of December 31, 2002, an additional $20.8 million is expected to be incurred by early 2004 with the remaining $7 million in 2009 and 2010. The expenditures for the El Dorado Refinery are expected to be incurred beginning in 2008 and completed in 2010.
The EPA recently promulgated regulations that will limit the sulfur content of highway diesel fuel beginning in 2006 to 15 parts-per-million from the current standard of 500 parts-per-million. As of December 31, 2002, capital costs for diesel desulfurization are estimated to be approximately $5 million for Cheyenne and $56 million for El Dorado. The Cheyenne Refinery expenditures are currently expected to be committed beginning in 2005, with the majority to be committed in 2006. Approximately $6 million of the El Dorado Refinery expenditures are currently expected to be committed in 2004 with the remaining $50 million in 2005 and 2006.
The EPA has recently stated their intent to propose new regulations that will limit emissions from diesel fuel powered engines used in off-road activities such as mining, construction and agriculture. The EPA has also stated their intent to simultaneously limit the sulfur content of diesel fuel used in these engines to facilitate compliance with the new emission standards. The EPA expects to propose the new off-road diesel engine emissions and related fuel sulfur standards early in 2003. It is likely that the new rules will require the off-road diesel fuel sulfur content to be reduced to 500 parts-per-million or less from the current limit of 5,000 parts-per-million by 2007. Since a minor portion of the diesel fuel the Company manufactures at the El Dorado Refinery is sold to the off-road market, these regulations, when promulgated, will likely require certain modifications to the Refinery. The cost associated with such modifications cannot be estimated until the final regulatory limits are known.
As is the case with all companies engaged in similar industries, the Company faces potential exposure from future claims and lawsuits involving environmental matters. The matters include soil and water contamination, air pollution, personal injury and property damage allegedly caused by substances which the Company manufactured, handled, used, released or disposed of.
Cheyenne Refinery. The Company is party to an agreement with the State of Wyoming requiring the investigation and possible eventual remediation of certain areas of the Cheyenne Refinery’s property which may have been impacted by past operational activities. Among other things, this order required a technical investigation of the Cheyenne Refinery to determine if certain areas have been adversely impacted by past operational activities. Based upon the results of the investigation, additional remedial action could be required by a subsequent administrative order or permit. The ultimate cost of any environmental remediation projects that may be identified by the site investigation required by the agreement cannot be reasonably estimated at this time.
El Dorado Refinery. The El Dorado Refinery is subject to a 1988 consent order with the Kansas Department of Health and the Environment (“KDHE”). This order, including various subsequent modifications, requires the Refinery to continue the implementation of a groundwater management program with oversight provided by the KDHE Bureau of Environmental Remediation. The order requires that remediation activities continue until KDHE-established groundwater criteria or other criteria agreed to by the KDHE and the Refinery are met. Subject to the terms of the purchase and sale agreement, Shell will be responsible for the costs of continued compliance with this order.
The most recent National Pollutant Discharge Elimination System permit issued to the El Dorado Refinery requires, in part, the preparation and submittal of an engineering report identifying certain refinery wastewater treatment plant upgrades necessary to allow routine compliance with applicable discharge permit limits. In accordance with the provisions of the purchase and sale agreement, Shell will be responsible for the first $2 million of any required wastewater treatment system upgrades. If required system upgrade costs exceed this amount, Shell and Frontier will share, based on a sliding scale percentage, up to another $3 million in upgrade costs. Subject to the terms of the purchase and sale agreement, Shell will be responsible for up to $5 million in costs, in addition to Shell’s obligation for the wastewater treatment system upgrade, relating to safety, health and environmental conditions after closing arising from Shell’s operation of the El Dorado Refinery that are not covered under a ten-year insurance policy. This insurance policy has $25 million coverage through November 17, 2009 for environmental liabilities, with a $500,000 deductible, and will reimburse the Company for losses related to all known and some unknown conditions existing prior to our acquisition of the El Dorado Refinery. The first phase of wastewater treatment system upgrades was completed in 2001 at a cost of $2.6 million with payment apportioned as described above.
On August 18, 2000, the Company entered into a Consent Agreement and Final Order of the Secretary (“Agreement”) with the KDHE that required the initiation of a wastewater toxicity testing program to commence upon the completion of the wastewater treatment upgrades described above. Good progress has since been made toward satisfying the provisions of the Agreement and Frontier expects to meet all applicable requirements.
Litigation
The Company is involved in various lawsuits which are incidental to its business. In management’s opinion, the adverse determination of such lawsuits would not have a material adverse effect on the Company’s liquidity, financial position or results of operations.
Collective Bargaining Agreement Expiration
The Company’s refining units hourly employees are represented by seven bargaining units, the largest being the Paper, Allied-Industrial, Chemical and Energy Workers International Union (“PACE”). Six AFL-CIO affiliated unions represent the Cheyenne Refinery craft workers. At the Cheyenne Refinery, the current contract with PACE expires in July 2006, while the current contract with the AFL-CIO affiliated unions expires in June 2009. The El Dorado Refinery’s hourly workers are all represented by PACE and the current contract with PACE expires January 2006. The union employees represent approximately 61% of the Company’s work force at December 31, 2002.
8. Fair Value of Financial Instruments
The fair value of the Company’s Senior Notes was estimated based on quotations obtained from broker-dealers who make markets in these and similar securities. At December 31, 2002 and 2001, the carrying amounts of long-term debt instruments were $208.0 million and $208.9 million, respectively, and the estimated fair values were $212.6 million and $222.3 million.
9. Price Risk Management Activities
The Company, at times, enters into commodity derivative contracts for the purposes of managing price risk on foreign crude purchases, crude and other inventories, and natural gas purchases and to fix margins on certain future production.
Trading Activities
During 2002, 2001 and 2000, the Company had the following derivative activities which, while economic hedges were not accounted for as hedges and whose gains or losses are reflected in other revenues:
• Derivative contracts on barrels of crude oil to hedge butane inventory builds at the El Dorado Refinery. During the year ended December 31, 2002, the Company recorded $903,000 in realized losses on these positions.
• Derivative contracts during 2002 on barrels of crude oil to hedge excess gas oil inventory at the Cheyenne Refinery had $202,000 in realized losses.
• Derivative contracts during 2002 on barrels of crude oil to hedge excess gas oil inventory at the El Dorado Refinery resulted in gains of $896,000.
• Derivative contracts during 2002 on barrels of crude oil to hedge excess naptha inventory at the El Dorado Refinery resulted in losses of $579,000.
• Derivative contracts during 2002 to hedge crude oil resulted in a gain of $48,000.
• Derivative contracts to fix margins on sales of gasoline and diesel. During 2001, the Company recorded net gains on these positions totaling $2.5 million ($394,000 realized gain plus the reversal of the $2.1 million unrealized loss recorded in 2000). During 2000, the impact of these positions was $0 ($2.1 million realized gain and an unrealized loss of $2.1 million recorded at December 31, 2000 on open positions).
• Derivative contracts on unleaded gasoline to hedge butylene inventory builds at the El Dorado Refinery which were drawn down in April and May 2001. During 2001, the Company recorded a net loss of $1.3 million on these positions ($769,000 realized loss plus the reversal of the unrealized gain recorded in 2000.) During 2000, the Company recorded net gains of $564,000, consisting of an unrealized gain recorded at December 31, 2000 on open positions.
• Derivative contracts on barrels of crude oil to hedge excess inventory against price declines. During 2001, the Company recorded net losses of $1.5 million on these positions ($763,000 net realized losses plus the reversal of the unrealized gain recorded in 2000). During 2000, the Company recorded net gains of $115,000 on these positions ($622,000 realized losses plus an unrealized gain of $737,000 recorded on open positions at December 31, 2000).
• Derivative contracts on barrels of crude oil to protect against price declines on foreign crude oil purchases. During 2001, the Company recorded a net loss of $2.2 million on these positions ($1.8 million realized gain less the unrealized gain recorded in 2000.) During 2000, the Company recorded net gains of $4.0 million, consisting of an unrealized gain recorded at December 31, 2000 on open positions.
• Derivative contracts on natural gas to hedge natural gas costs. During 2001, the Company realized a $472,000 gain on positions to hedge natural gas.
• Derivative contracts on barrels of unleaded gasoline and barrels of heating oil to hedge gas oil inventory builds at the Cheyenne Refinery. During 2001, the Company realized a $144,000 loss on these positions.
As of December 31, 2002, the Company had no open derivative contracts.
Hedging Activities
During 2002, 2001 and 2000, the Company had the following derivatives which were appropriately designated and accounted for as hedges:
• Crude Purchases. At December 31, 2002, the Company had no open derivative contracts to hedge against price declines on foreign crude oil purchases. During the year ended December 31, 2002, the Company closed out contracts to hedge foreign crude purchases and realized net losses of $9.8 million, of which $10.7 million increased crude costs and $878,000 income was reflected in other revenues for the ineffective portion of those hedges. These contracts were accounted for as fair value hedges. At December 31, 2001, the Company had open derivative contracts on 422,000 barrels of crude oil to hedge against price declines on foreign crude oil purchases which were accounted for as fair value hedges under SFAS No. 133. The unrealized ineffective portion of this hedge recorded in other revenues during 2001 was a $30,000 gain. During 2001, the Company realized gains of $7.1 million on crude fair value hedges of which $229,000 was the ineffective portions recorded in other revenues and $6.8 million was recorded as a reduction of crude oil costs. During 2000, the Company recognized losses of $6.0 million on crude oil hedging derivative contracts.
• Natural Gas Collars. In March 2002, the Company entered into price swaps on natural gas for the purpose of hedging approximately 50% of the Refineries’ anticipated usage against natural gas price increases for April 2002 through December 2002. These contracts were accounted for as cash flow hedges. One group of contracts to hedge natural gas costs at the El Dorado Refinery averaged 300,000 MMBTU per month at an average price of $3.34 per MMBTU (Panhandle). A second group of contracts to hedge natural gas costs at the Cheyenne Refinery averaged 112,222 MMBTU per month at an average price of $2.84 per MMBTU (CIG). The April and May contracts resulted in net realized gains totaling $41,000 and were recorded into refining operating costs. Due to natural gas market conditions, a decision was made in May to close out the remaining June through December contracts resulting in a net gain of $393,000. The realized gains or losses were recorded in other comprehensive income (equity account), net of tax. The pretax realized gains or losses were reclassified into refining operating costs and out of other comprehensive income based on the month when the corresponding natural gas was purchased. As of December 31, 2002, all these gains and losses and been reclassified into earnings.
During September 2000, the Company purchased two costless collars for the purpose of hedging against natural gas price increases for the November 2000 through March 2001 period. The first collar covered an aggregate of 38,000 MMBTU with ceiling and floor prices of $6.50 and $4.29, respectively. The second collar covered an aggregate of 9,000 MMBTU with ceiling and floor prices of $6.50 and $4.00, respectively. Through December 31, 2000, no gains or losses had been recorded related to the collars. At December 31, 2000, these collars had a fair value of $4.1 million. In the first quarter of 2001, these positions were closed and the Company realized a $2.4 million gain. Beginning January 1, 2001, the Company began accounting for these contracts as cash flow hedges under the provisions of SFAS No. 133.
• Natural Gas Purchases. During 2000, the Company recognized natural gas hedging gains of $195,000.
INDEPENDENT AUDITORS’ REPORT
To the Board of Directors and Shareholders of Frontier Oil Corporation:
We have audited the accompanying consolidated balance sheet of Frontier Oil Corporation and subsidiaries as of December 31, 2002, and the related consolidated statements of operations, changes in shareholders’ equity and cash flows for the year then ended. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audit. The consolidated financial statements of Frontier Oil Corporation as of December 31, 2001, and for the years ended December 31, 2001 and 2000 were audited by other auditors who have ceased operations. Those auditors expressed an unqualified opinion on those consolidated financial statements in their report dated February 8, 2002.
We conducted our audit in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Frontier Oil Corporation and subsidiaries as of December 31, 2002 and the results of their operations and their cash flows for the year ended December 31, 2002, in conformity with accounting principles generally accepted in the United States of America.
DELOITTE & TOUCHE LLP
Houston, Texas
February 7, 2003
Frontier Oil Corporation dismissed Arthur Andersen LLP on March 28, 2002 and subsequently engaged Deloitte & Touche LLP as its independent auditors. The predecessor auditors’ report appearing below is a copy of Arthur Andersen LLP’s previously issued opinion dated February 8, 2002. Since Frontier Oil Corporation is unable to obtain a manually signed audit report, a copy of Arthur Andersen LLP’s most recent signed and dated report has been included to satisfy filing requirements, as permitted under Rule 2-02(e) of Regulation S-X.
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Shareholders of Frontier Oil Corporation:
We have audited the accompanying consolidated balance sheets of Frontier Oil Corporation (a Wyoming corporation) and subsidiaries as of December 31, 2001 and 2000, and the related consolidated statements of operations, changes in shareholders’ equity and cash flows for each of the three years in the period ended December 31, 2001. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Frontier Oil Corporation and subsidiaries as of December 31, 2001 and 2000, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2001, in conformity with accounting principles generally accepted in the United States.
ARTHUR ANDERSEN LLP
Houston, Texas
February 8, 2002
REPORT OF MANAGEMENT
The information contained in this Annual Report, as well as all the financial and operational data we present concerning Frontier Oil Corporation, is prepared by management. Our financial statements are fairly presented in all material respects in conformity with generally accepted accounting principles.
It has always been our intent to apply proper and prudent accounting guidelines in the presentation of our financial statements; and, we are committed to full and accurate representation of our condition through complete and clear disclosures. We stand behind this pledge as a matter of honor and integrity.
James R. Gibbs
Chairman of the Board, President and
Chief Executive Officer
Julie H. Edwards
Executive Vice President - Finance and Administration,
Chief Financial Officer
Nancy J. Zupan
Vice President - Controller
