EXHIBIT 13.1
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 (“bpd”). We focus our marketing efforts in the Rocky Mountain and Plains States regions of the United States. We purchase the crude oil to be refined and market the refined petroleum products produced, including various grades of gasoline, diesel fuel, jet fuel, asphalt and other by-products.
To assist in understanding our operating results, please refer to the operating data at the end of this analysis, which provides key operating information for our combined Refineries. Data for each Refinery is included in our annual report on Form 10-K, our quarterly reports on Form 10-Q and on our web site address: http://www.frontieroil.com. We make our web site content available for informational purposes only. The web site should not be relied upon for investment purposes. We make available on this web site under “Investor Relations”, free of charge, our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports as soon as reasonably practicable after we electronically file those materials with, or furnish those materials to, the SEC.
The following are three significant indicators of our profitability reflected in the operating data of this analysis referred to above:
1) gasoline and diesel crack spreads: the average non-oxygenated gasoline and diesel net sales prices we receive for each product less the average West Texas Intermediate ("WTI") crude price at Cushing, Oklahoma,
2) light/heavy spread: the average differential between the benchmark WTI crude oil priced at Cushing, Oklahoma and the heavy crude oil priced delivered to the Cheyenne Refinery, and
3) WTI/WTS spread: the average differential between benchmark WTI crude oil priced at Cushing, Oklahoma and West Texas sour crude oil priced at Midland, Texas.
Other significant factors that influence our results are refinery utilization, crude oil price trends, asphalt and by-product margins and refinery operating expenses (including natural gas prices and turnaround, or planned maintenance, activity).
2003 Compared with 2002
Overview of Results. We had net income for the year ended December 31, 2003 of $3.2 million, or $.12 per diluted share, compared to net income of $1.0 million, or $.04 per diluted share, for 2002. Our 2003 net income was negatively impacted by the termination of the Holly Corporation (“Holly”) merger. On March 31, 2003, we announced that we had entered into an agreement with Holly pursuant to which the two companies would merge. On August 20, 2003, we announced that Holly had advised us that they were not willing to proceed with our merger agreement on the agreed terms. As a result, we filed suit against Holly for damages in Delaware and we redeemed the Senior Notes that had been issued to finance the cash portion of the Holly merger. Merger termination and legal costs and merger termination financing costs, net of interest income, reduced 2003 earnings by $26.8 million pretax ($16.5 million after tax). The merger-related costs were on an accrual basis and did not include bank facility charges related to the merger.
Despite the negative impact of the terminated Holly merger, our operating income of $51.9 million increased $24.0 million from the $27.9 million for 2002. The major factors improving operating income were improved gasoline and diesel crack spreads, increases in the light/heavy spread and WTI/WTS spread and improved yields and sales from our Cheyenne Refinery. Yields and sales were down in 2003 at our El Dorado Refinery due to a major crude unit turnaround, or planned maintenance, in the spring of 2003. Results were also negatively impacted by higher refinery operating expenses primarily due to higher natural gas costs at both Refineries.
Specific Variances. Refined product revenues increased $356.9 million, or 20%, from $1.8 billion to $2.2 billion for the year ended December 31, 2003 compared to 2002 due to increased sales prices resulting from higher crude oil prices and higher gasoline and diesel crack spreads on nearly flat sales volumes. Our gasoline and diesel crack spreads averaged $7.00 per barrel and $5.05 per barrel, respectively, in 2003, compared to $5.88 per barrel and $3.97 per barrel, respectively, in 2002. Average gasoline prices increased from $33.08 per sales barrel in 2002 to $39.72 per sales barrel in 2003. Sales volumes of gasoline decreased 2,147 barrels per day from 91,989 barrels per day during 2002 to 89,842 barrels per day in 2003. Average diesel and jet fuel prices increased from $30.35 per sales barrel in 2002 to $36.91 per sales barrel during 2003. Sales volumes of diesel and jet fuel increased 228 barrels per day from 53,378 barrels per day during 2002 to 53,606 barrels per day in 2003. Total product sales volumes overall decreased less than 1% from 166,532 barrels per day in 2002 to 165,667 barrels per day in 2003.
Manufactured product yields (“yields”) are the volumes of specific materials that are obtained through the distilling of crude oil and the operations of other refinery process units. Yields of gasoline decreased 1,196 barrels per day, or 1%, from 84,645 barrels per day in 2002 to 83,449 barrels per day in 2003 and yields of diesel and jet fuel decreased 280 barrels per day, or less than 1%, from 53,436 barrels per day in 2002 compared to 53,156 barrels per day in 2003. Sales and yield volumes for 2003 for the El Dorado Refinery were lower than during 2002 primarily because of the crude unit turnaround at the El Dorado Refinery which commenced on March 18, 2003 and was completed on March 30, 2003. Upon completion of the turnaround, the El Dorado Refinery operations were very strong the remainder of the year. The Cheyenne Refinery operations were very strong all year resulting in both increased charge and yield volumes sufficient to offset the reduced charges and yields at the El Dorado Refinery to result in an aggregate small increase in charge and yield volumes.
Other revenues decreased $185,000 to $952,000 for the year ended December 31, 2003 compared to income of $1.1 million for the same period in 2002 due to $268,000 in net losses from futures trading in 2003 compared to net income of $108,000 in 2002 (see “Price Risk Management Activities”), offset by increased processing income from our Cheyenne Refinery coker.
Raw material, freight and other costs include crude oil and other raw materials utilized in the refining process, purchased products and blendstocks, freight costs for FOB destination sales, as well as the impact of changes in inventory under first-in, first-out (“FIFO”) inventory accounting. The average price of crude oil was substantially higher in 2003 than in 2002. The average price of WTI crude oil priced at Cushing, Oklahoma was $31.89 per barrel in 2003 compared to $26.17 per barrel in 2002. Raw material, freight and other costs increased $298.2 million, or $5.06 per sales barrel, from 2002 due to higher average crude oil prices and a smaller amount of inventory gains from rising prices during 2003 than during 2002, offset by improved crude oil spreads. For the year ended December 31, 2003, we realized a decrease in raw material, freight and other costs as a result of inventory gains of approximately $4.4 million after tax ($7.2 million pretax, comprised of $3.0 million at the Cheyenne Refinery and $4.2 million at the El Dorado Refinery) because of the increasing crude oil prices. The price of crude oil on the New York Mercantile Exchange was very volatile in 2003. The crude price began the year at $31.20 per barrel, reached a high of $37.83 per barrel in March, dropped to a low of $25.24 per barrel in April and closed the year at $32.52 per barrel. For the year ended December 31, 2002, we realized a decrease in raw material, freight and other costs as a result of inventory gains of approximately $19.0 million after tax ($30.6 million pretax, comprised of $10.7 million at the Cheyenne Refinery and $19.9 million at the El Dorado Refinery) because of increasing crude oil prices. The price of crude oil on the New York Mercantile Exchange increased during 2002 from $19.84 per barrel to $31.20 per barrel by year-end.
The Cheyenne Refinery raw material, freight and other costs of $29.40 per sales barrel in 2003 increased from $25.18 per sales barrel in 2002 due to higher crude oil prices and less inventory gains, offset by an improved 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 88% in 2003 from 90% in 2002 as we utilized slightly more light crude oil. The light/heavy spread for the Cheyenne Refinery averaged $7.10 per barrel in 2003 compared to $4.77 per barrel in 2002.
The El Dorado Refinery raw material, freight and other costs of $31.43 per sales barrel in 2003 increased from $25.93 per sales barrel in 2002 due to higher average crude oil prices and less inventory gains, offset by an improved WTI/WTS spread. The WTI/WTS crude spread increased from an average of $1.36 per barrel in 2002 to $2.68 per barrel in 2003.
Refinery operating expenses, excluding depreciation, includes both the variable costs (including energy and utilities) and the fixed costs (salaries, taxes, maintenance costs and other) of operating the Refineries. Refinery operating expenses, excluding depreciation, were $200.4 million, or $3.31 per sales barrel, in 2003 compared to $178.3 million, or $2.93 per sales barrel, in 2002.
The Cheyenne Refinery operating expense, excluding depreciation, was $61.4 million, or $3.12 per sales barrel, in 2003 compared to $54.7 million, or $3.02 per sales barrel, in 2002 primarily due to higher natural gas and other utility costs ($2.6 million), salaries ($2.5 million), consulting and legal ($800,000) and additives and chemicals ($700,000).
The El Dorado Refinery operating expense, excluding depreciation, was $139.0 million, or $3.41 per sales barrel, in 2003 increasing from $123.6 million, or $2.90 per sales barrel, in 2002 primarily due to higher natural gas costs ($8.2 million), salaries ($3.8 million), chemicals ($1.2 million) and excess turnaround costs ($2.3 million). The per barrel refinery operating expense variance was exacerbated by fewer sales volumes in 2003 than in 2002.
Selling and general expenses, excluding depreciation, increased $2.3 million, or 13%, for the year ended December 31, 2003 because of $1.8 million in legal costs related to the Beverly Hills lawsuits, increases in other legal costs and salaries, and travel, engineering and other consulting services related to evaluating potential acquisitions and possible refinery improvements.
Merger termination and legal costs of $8.7 million for the year ended December 31, 2003 include transaction and ongoing legal costs (on an accrual basis) associated with the termination of the anticipated merger and resulting lawsuit with Holly.
Depreciation increased $1.5 million, or 5%, for the year ended December 31, 2003 as compared to 2002 because of increases in capital investment at our Refineries.
The interest expense and other financing costs (excluding costs relating to the 8% Senior Notes issued and redeemed in connection with the terminated Holly merger) of $28.7 million for 2003 increased $1.1 million from $27.6 million in 2002 primarily due to the premium of $1.2 million paid upon redemption of our 9-1/8% Senior Notes in December 2003. Average debt outstanding (excluding the 8% Senior Notes) decreased to $236 million for the year ended December 31, 2003 from $246 million for the year ended December 31, 2002.
Interest income (excluding interest income earned on the 8% Senior Notes escrow account) decreased $693,000 from $1.8 million in 2002 to $1.1 million in 2003 due to less cash available to invest and lower interest rates.
The 2003 merger financing termination costs, net were $18.0 million and included interest expense, issue discount, financing issue costs and the 1% redemption premium, net of $752,000 interest income earned on the escrow account related to the $220.0 million principal 8% Senior Notes. These costs did not include bank facility charges related to the merger.
The income tax provision for the year ended December 31, 2003 was $3.0 million on pretax income of $6.2 million (or 47.8%) due to one-time adjustments for permanent book versus tax differences related to 2003 and 2002 expenses and an increase of $280,000 in the income tax provision for 2003 resulting from a true-up of the 2002 tax provision. Our current estimated effective tax rate is 38.26%. Our effective income tax rate for the book provision of income taxes for the year ended December 31, 2002, of 50.8% was also greater than our estimated statutory rate 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.
2002 Compared with 2001
Overview of Results. 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. Our operating income of $27.9 million in 2002 was $136.2 million lower than the $164.1 million in 2001. Although we achieved record refinery charges and yields and a reduction to our per sales barrel refinery operating expenses, excluding depreciation, the decrease in operating income was primarily caused by significant declines in gasoline and diesel crack spreads and decreases in both the light/heavy crude spread and the WTI/WTS crude spread. Supply and demand imbalances led to exceptional light product margins during two periods of 2001 and as a result, our margins for both gasoline and diesel fuel greatly exceeded the historic five-year averages. In 2002, we struggled through some of the poorest conditions our industry has ever faced. While gasoline underperformed compared to historic five-year averages, the weakness was not as pronounced as the weakness in the diesel and jet markets. Our crude spreads were depressed in 2002 because of general tightness of heavy crude oil supplies in our markets and the global shortage of heavy and sour crude oils due to OPEC cutbacks and the disruptions from Venezuela.
In areas directly controllable by us, we continued to operate reliably while increasing refinery charges and yields and reducing our operating costs per sales barrel. In late 2001, we expanded the Cheyenne Refinery permitted annual crude capacity to 46,000 bpd from 41,000 bpd. This expansion contributed significantly to the increased charge and yield in 2002. Our refinery operating expenses, excluding depreciation, declined from $3.27 per sales barrel in 2001 to $2.93 per sales barrel in 2002.
Specific Variances. Refined product revenues decreased $76.6 million, or 4%, for the year ended December 31, 2002 compared to 2001 due to decreased sales prices and lower gasoline and diesel crack spreads. Our gasoline and diesel crack spreads averaged $5.88 per barrel and $3.97 per barrel, respectively, in 2002 compared to $8.91 per barrel and $7.91 per barrel, respectively, in 2001. Average gasoline prices decreased from $35.85 per sales barrel in 2001 to $33.08 per sales barrel in 2002. Sales volumes of gasoline increased 8,252 barrels per day from 83,737 barrels per day during 2001 to 91,989 barrels per day in 2002. Average diesel and jet fuel prices decreased from $34.12 per sales barrel in 2001 to $30.35 per sales barrel during 2002. Sales volumes of diesel and jet fuel increased 1,839 barrels per day from 51,539 barrels per day during 2001 to 53,378 barrels per day in 2002. Total product sales volumes overall increased 5% from 159,100 barrels per day in 2001 to 166,532 barrels per day in 2002.
Yields of gasoline increased 6,519 barrels per day, or 8%, from 78,126 barrels per day in 2001 to 84,645 barrels per day in 2002 while yields of diesel and jet fuel increased 2,226 barrels per day, or 4%, from 51,210 barrels per day in 2001 compared to 53,436 barrels per day in 2002. El Dorado gasoline yields improved in 2002 due to the diversion of 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 toward the end of 2001 and in 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 an 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”).
Raw material, freight and other costs increased $70.8 million, or $.02 per sales barrel, from 2001 due to higher average crude oil prices offset by inventory gains from rising prices during the year. For the year ended December 31, 2002, we realized a decrease in raw material, freight and other costs as a result of inventory gains of approximately $19.0 million after tax ($30.6 million pretax, comprised of $10.7 million at the Cheyenne Refinery and $19.9 million at the El Dorado Refinery) because of the increasing crude oil prices. 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, 2001, we realized an increase in raw material, freight and other costs as a result of inventory losses of approximately $28.9 million after tax ($41.4 million pretax, comprised of $8.9 million at the Cheyenne Refinery and $32.5 million at the El Dorado Refinery) because of decreasing crude oil prices.
The Cheyenne Refinery raw material, freight and other costs of $25.18 per sales barrel in 2002 increased from $24.85 per sales barrel in 2001 due to higher crude oil prices and a reduced light/heavy spread offset by a positive inventory valuation impact as a result of increasing crude oil and product prices. 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 $4.77 per barrel in 2002 compared to $7.62 per barrel in 2001.
The El Dorado Refinery raw material, freight and other costs of $25.93 per sales barrel in 2002 decreased from $26.01 per sales barrel in 2001 due to slightly higher average crude oil prices more than offset by the inventory gains from rising prices during the year. The WTI/WTS crude spread decreased from an average of $3.10 per barrel in 2001 to $1.36 per barrel in 2002.
Refinery operating expense, excluding depreciation, was $178.3 million, or $2.93 per sales barrel, in 2002 compared to $189.9 million, or $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, excluding depreciation, increased $40,000 for the year ended December 31, 2002 because of an impairment loss on an asset held for sale and increased engineering consulting services and travel costs offset by decreased salaries and benefits from the non-accrual of bonuses in 2002.
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 the capitalization of interest in 2002. 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.
Interest income decreased by $970,000, or 35%, for the year ended December 31, 2002 compared to 2001 due to lower available interest rates on investments offset by more cash available to invest.
Our effective income tax rate for the book provision of income taxes for the year ended December 31, 2002, of 50.8% was 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.
Net cash used in operating activities was $6.0 million for the year ended December 31, 2003 while $50.8 million cash was provided by operating activities for the year ended December 31, 2002. The most significant impact on cash provided by operating activities was the change in trade and crude payables. In 2002, crude payables provided cash by increasing $55.6 million during the year due to dramatically increasing crude prices throughout the year, while in 2003, crude prices were relatively flat between the beginning and the end of the year.
The other most significant impact on the decrease in cash provided by operating activities were the October 2003 payments totaling approximately $26.6 million made to purchase an insurance policy related to the Beverly Hills Lawsuits. (See Note 8 in the “Notes to Consolidated Financial Statements”) The $26.6 million was comprised of $6.25 million to the insurance company (which included an indemnity premium of $5.75 million and a $500,000 administration fee) and the funding with the insurance company of a Commutation Account of approximately $19.6 million (from which the insurance company will fund the first costs under the policy including, but not limited to, the costs of defense of the claims), and $772,500 paid to the State of California for surplus lines tax on the premium. This insurance premium and related expenses are in the prepaid insurance in the long-term asset portion of our balance sheet. See Note 2 in the “Significant Accounting Policies” in the “Notes to Consolidated Financial Statements” for a discussion of the accounting treatment on this premium. Offsetting the negative cash impacts was a positive variance from 2002 to 2003 resulting from trade and other receivables increasing (and utilizing cash) $4.6 million in 2003 compared to increasing (and utilizing cash) $22.2 million in 2002. Working capital changes used a total of $25.9 million of cash flows in 2003 while providing $17.8 million of cash flows in 2002, the major component being the change in trade and crude payables discussed above.
At December 31, 2003, we had $64.5 million of cash and cash equivalents, working capital of $38.6 million and a $70.0 million borrowing base availability for additional borrowings under our revolving credit facility.
On April 17, 2003, we received the net proceeds from a private placement of $220 million of 8% senior notes (“Senior Notes”) due April 15, 2013. The net proceeds of the Senior Notes were to be used, together with other available funds, to finance the cash portion of the Holly merger, to pay related fees and expenses and to refinance or pay off existing Holly indebtedness. The Senior Notes were issued at 99.156% of principal amount and were issued by Frontier Escrow Corporation, a newly formed, wholly-owned, direct subsidiary of Frontier that was created solely to issue the Senior Notes and to merge with and into Frontier Oil Corporation upon consummation of the Holly merger. Pending consummation of the Holly merger, the net proceeds of the offering, along with other amounts contributed by us, were placed in an escrow account. We were required, pursuant to terms of the indenture, to redeem the 8% Senior Notes if the merger with Holly was not consummated by October 31, 2003. Because of Holly’s repudiation of the merger agreement, we redeemed the Senior Notes on October 10, 2003 at a price equal to 101% of the aggregate principal amount of the Senior Notes plus accrued interest. Financing costs, net of interest income earned on the escrow account, related to the Senior Notes were $18.0 million during the year ended December 31, 2003 and included interest expense, issue discount, financing issue costs and redemption premium. These costs did not include bank facility charges related to the merger.
In December 2003, we called our outstanding $39.5 million of 9-1/8% Senior Notes, originally issued in 1998, along with the required redemption premium, which approximated $1.2 million. Our only remaining outstanding long-term debt at December 31, 2003 is $168.7 million ($170.4 million principal, net of $1.7 million unamortized discount) of 11¾% Senior Notes, issued in 1999 and due in 2009.
In November 2003, the Board of Directors increased the number of shares under a previously approved stock repurchase program from six million shares to eight million shares of common stock. Through 2000, 2,491,096 shares of common stock were purchased, of which 2,345,900 shares were purchased on the open market, for approximately $14.9 million. 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. We did not initiate any additional purchases of common stock under the stock repurchase program in 2003 nor in 2002. Through December 2003, 4,367,366 shares of common stock had been purchased under the stock repurchase programs. We also acquired 24,825 and 19,041 shares of treasury stock in 2003 and 2002, respectively, which was stock surrendered by employees to cover their withholding taxes on shares of restricted stock which vested during those years. During 2003, we also increased our treasury stock by another 88,638 shares obtained directly from employees in cashless stock option exercises.
Capital expenditures for 2003 were $33.7 million, which included $15 million for the low sulfur gasoline project (now completed and in service) at our Cheyenne Refinery. Sustaining and other capital expenditures of approximately $39 million are planned for 2004. These 2004 capital expenditures include $17.5 million for the El Dorado Refinery, $20.5 million at the Cheyenne Refinery, and another $1.0 million of capital for expenditures in our Denver and Houston offices and asphalt terminal in Nebraska and for our share of crude pipeline projects. The $17.5 million of capital expenditures for our El Dorado Refinery includes operational, payout, safety, administrative, environmental and optimization projects. The $20.5 million of capital expenditures for our Cheyenne Refinery includes operational, environmental, safety, administrative and payout projects as well as approximately $5.3 million remaining cash costs on the completed low sulfur gasoline project. We are still evaluating how we will comply with the upcoming ultra low sulfur diesel requirements at our Refineries, which will require additional capital expenditures in 2004 through 2006. The total minimum capital required to comply with the regulations is estimated to be $13 million at the Cheyenne Refinery and between $60 million and $90 million at the El Dorado Refinery. The estimated timing of the ultra low sulfur diesel projects is $2 million at the Cheyenne Refinery and $25 million at the El Dorado Refinery in 2004, the majority of which is in addition to the capital discussed above. The remaining costs for the ultra low sulfur diesel projects at both refineries would be spent in 2005 and 2006. For the El Dorado Refinery we are considering an alternate project to meet our ultra low sulfur diesel requirements, which would also generate improved gasoline yields and thus additional profits in the future. This alternative would increase the estimated total El Dorado Refinery capital requirement from between $60 million and $90 million up to $160 million, with $25 million still estimated to be spent in 2004 and the remaining costs in 2005 and 2006. The decision on which project to pursue is expected to be made during fiscal 2004. It may be necessary for us to obtain external financing in 2005 or 2006 to fund these required expenditures.
As of December 31, 2003, we have $216.2 million principal ($170.4 million long-term debt and $45.8 million under our revolving credit facility) of total consolidated debt and shareholders’ equity of $169.3 million. Operating cash flows are affected by crude oil and refined product prices and other risks as discussed in the “Market Risks” section.
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 was required based on 2003, 2002 or 2000 results. A contingent earn-out payment of $7.5 million was required based on 2001 results and was paid in early 2002.
On May 29, 2003, we announced that we had entered into an amended and restated revolving credit facility with a group of banks led by Union Bank of California and BNP Paribas. Commitments under the working capital facility are $175 million, subject to borrowing base amounts, with cash advances limited to a maximum of $125 million. Any unutilized capacity after cash borrowings is available for letters of credit. The facility includes reduced interest rate spreads and letter of credit fees. In addition, a new financial covenant package is based on consolidated parent financials (as opposed to subsidiary level financials) and facilitates intra-company funds flows. At December 31, 2003, we had borrowings of $45.8 million and outstanding letters of credit of $26.2 million under our revolving credit facility, and approximately $70.0 million borrowing base availability remaining for additional borrowings under our revolving credit facility. We were in compliance with the financial covenants as of December 31, 2003.
Our Board of Directors declared quarterly cash dividends in December 2002, March 2003, June 2003 and September 2003 of $.05 per share, which were paid in January 2003, April 2003, July 2003 and October 2003, respectively. The total dividend payments in 2003 were $5.2 million. In addition, our Board of Directors declared a quarterly cash dividend of $.05 per share in December 2003, which was paid on January 12, 2004 to shareholders of record on December 26, 2003. The total cash required for this dividend was approximately $1.3 million and was accrued at year-end.
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, purchase obligations and other long-term liabilities. Our operating leases include building, equipment, aircraft and vehicle leases, which expire from 2004 through 2008, as well as an operating sublease for the use of the cogeneration facility at our El Dorado Refinery. The non-cancelable sublease, entered into in connection with the acquisition of our El Dorado Refinery in 1999, expires in 2016 with an option that allows us to renew the sublease for an additional eight years. Purchase obligations include agreements to purchase goods or services that are enforceable and legally binding and that specify terms, including fixed or minimum quantities to be purchased, fixed, minimum or variable price provisions, and the approximate timing of the transaction. Purchase obligations exclude agreements that are cancelable without penalty. We have a five-year crude oil supply agreement, which began in 2003, with Baytex Marketing Ltd. (“Baytex”), a Canadian crude oil producer. This agreement provides for us to purchase 20,000 barrels per day of a Lloydminster crude oil blend, a heavy Canadian crude, at a price equal to 71% of the simple average of the near month settlement prices of the NYMEX light sweet crude oil contracts during the month of delivery, plus the cost of transportation based on the Express Pipeline tariff, less $0.25 per barrel. Included in transportation, terminalling and storage obligations below are our contractual obligations for crude oil pipeline capacity on the Express Pipeline, net of our assignment to Baytex, as discussed below. We have two contracts that obligate us for crude oil pipeline capacity into 2015 on the Express Pipeline from Hardisty, Alberta to Guernsey, Wyoming from which we then have pipeline access to take the crude oil to our Cheyenne, Wyoming Refinery. The first contract, which began in 1997, is for 15 years and for an average 13,800 barrels per day over that 15-year period. We were allowed to assign a portion of our capacity in earlier years for additional capacity in later years with this first contract. In December 2003, we entered into an expansion capacity agreement on the Express Pipeline for an additional 10,000 barrels per day of crude oil starting in April 2005 through 2015. Our remaining Express Pipeline commitments range from 18,600 barrels per day in 2004, increasing to a high of 32,600 barrels per day in 2005, then reducing to 23,800 barrels per day in 2006 through early 2012, and then reducing to 10,000 barrels per day through 2015. Our crude oil supply agreement with Baytex includes an assignment of a portion of our pipeline capacity obligation to them. The amounts shown below for transportation, terminalling and storage contractual obligations are net of $31.1 million, the approximate cost of the pipeline capacity assigned to Baytex for the initial term of that agreement. See Note 8 “Commitments and Contingencies” in the “Notes to Consolidated Financial Statements.”
Contractual Cash Obligations
Payments Due by Period
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(in thousands) Total Within 1 Year Within 2-3 Years Within 4-5 Years After 5 Years
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Long-term debt (1) $ 170,449 $ - $ - $ - $ 170,449
Operating leases 83,016 9,284 16,902 12,755 44,075
Purchase obligations:
Baytex crude supply (2) 749,077 187,999 374,052 187,026 -
Other crude supply, feedstocks and
natural gas (2) 146,814 146,814 - - -
Transportation, terminalling and
storage 113,744 12,636 25,349 20,624 55,135
Other goods and services 4,481 4,187 294 - -
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Total purchase obligations 1,014,116 351,636 399,695 207,650 55,135
Long-term accrued turnaround cost 16,229 - 13,612 2,617 -
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Total contractual cash (3) $ 1,283,810 $ 360,920 $ 430,209 $ 223,022 $ $ 269,659
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| (1) | Cash requirements for interest on the long-term debt are approximately $20 million per year. |
| (2) | Baytex crude supply and other crude supply, feedstocks and natural gas future obligations were calculated using current market prices and/or prices established in applicable contracts. Of these obligations, $176.5 million relate to January and February 2004 feedstock and natural gas requirements of the Refineries. |
| (3) | Minimum pension funding requirements are not included as such amounts have not been determined; however estimate that we will contribute approximately $1.4 million in 2004 to our cash balance pension plan. See Note 7 “Employee Benefit Plans” in the “Notes to Consolidated Financial Statements.” |
We only have one interest in an unconsolidated entity (See Note 1 “Nature of Operations” in the “Notes to Consolidated Financial Statements”). This entity does not participate in any transactions, agreements, or other contractual arrangements which would result in any off-balance sheet liabilities or other arrangements to us.
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 overall compliance with existing environmental laws, regulations and permits.
This discussion includes major environmental areas that impact our operations. Refer to Note 8 “Commitments and Contingencies” in the “Notes to Consolidated Financial Statements” for further environmental information.
Frontier’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 Frontier’s Refineries during the next several years. Subsequent rule making authorized by the CAA or similar laws or new agency interpretations of existing rules may necessitate additional expenditures in future years. The Environmental Protection Agency (“EPA”) recently embarked on a Petroleum Refining Initiative (“Initiative”) alleging industry-wide noncompliance with certain longstanding 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, Frontier does not know how or if the Initiative will affect us. We have, however, in recognition of the EPA’s reinterpretation of certain regulatory requirements associated with the Initiative, determined that over the next three years, expenditures totaling approximately $10 million may be necessary to further reduce emissions from the Refineries’ flare systems. This determination resulted from internal compliance audits initiated by us and subsequently shared with the corresponding state regulatory agencies under the provisions of state audit privilege statutes. Both the Kansas Department of Health and Environment (“KDHE”) and the Wyoming Department of Environmental Quality (“WDEQ”) have expressed their preference to enter into consent decrees with Frontier to settle these and certain other compliance matters. Because other refineries will be required to make similar expenditures, Frontier does not expect such expenditures to have a material adverse impact on our competitive position.
The CAA authorizes the EPA to require modifications in the formulation of the refined transportation fuel products manufactured in order to limit the emissions associated with their final use. On December 21, 1999, the EPA promulgated national regulations limiting the amount of sulfur that is to be allowed in gasoline. The EPA believes such limits are necessary to protect new automobile emission control systems that may be inhibited by sulfur in the fuel. The new regulations require the phase-in of gasoline sulfur standards beginning in 2004 and continuing through 2008, with special provisions for refiners serving those Western states exhibiting lesser air quality problems and for small business refiners, such as Frontier. Since Frontier qualifies as a small business refiner by having 1,500 or fewer employees and a capacity of less than 155,000 barrels per day during the specified pre-2001 baseline years, the Cheyenne and El Dorado Refineries may comply with an interim gasoline sulfur standard in 2004 that is based on historic gasoline sulfur levels rather than having to meet the much stricter standard that will be applied to the general industry. Depending on the deadline we choose to comply with the new diesel sulfur limit (see discussion below), we will then have between four and seven additional years to reduce our gasoline sulfur content of our Refineries to the national standard. The total capital expenditures estimated, as of December 31, 2003, to achieve the final gasoline sulfur standard are approximately $35 million at the Cheyenne Refinery and approximately $44 million at the El Dorado Refinery. The $35 million at Cheyenne includes over $28 million already incurred (on an accrual basis) through December 31, 2003 to meet the interim standard in 2004.
The EPA recently promulgated regulations that will limit the sulfur content of highway diesel fuel beginning in 2006 to 15 parts per million (“ppm”). The current standard is 500 ppm. As a small business refiner, Frontier may choose to comply with the 2006 program and extend our interim gasoline standard by three years (until 2011) or delay the diesel standard by four years (until 2010) and keep our original gasoline sulfur program timing. Although still under deliberation, it is now likely that Frontier will choose to comply with the 15 ppm highway diesel sulfur standard by June 2006 and extend our small refiner interim gasoline sulfur standards at each of our facilities until 2011. To satisfy a regulatory requirement necessary for the preservation of this compliance option we have submitted an application for a highway diesel volumetric baseline to the EPA. As of December 31, 2003, minimum capital costs for diesel desulfurization are estimated to be approximately $13 million for the Cheyenne Refinery and between $60 million and $90 million for the El Dorado Refinery. The final cost for the El Dorado Refinery will be dependent on whether we choose to meet only the ultra low sulfur diesel requirement or decide on an alternative project which would also result in increased future profitability. This alternative project would increase the total capital cost for the El Dorado Refinery from the $60 to $90 million range up to a total cost of $160 million. See “Liquidity and Capital Resources” on page 14 for further discussion on the range of costs for the El Dorado Refinery.
On April 15, 2003, the EPA proposed regulations to reduce emissions from diesel engines used in off-road activities such as agriculture, mining and railroads and also to limit the allowable amount of sulfur in the diesel fuel used in those engines. If promulgated, the EPA’s proposal would require a reduction of sulfur in off-road diesel fuel by June 1, 2007 from the currently allowable 5,000 ppm to 500 ppm and by June 1, 2010 further limit the concentration of sulfur in diesel fuel used in off-road applications other than railroads and marine engines to 15 ppm. The EPA is also proposing to allow small business refiners, such as Frontier, to continue to produce off-road diesel at the current sulfur limit of 5,000 ppm through May 31, 2010 and to meet a limit of 500 ppm sulfur from June 1, 2010 until May 31, 2014. Frontier has historically provided a minor amount of diesel fuel to the off-road markets from both of our Refineries. Included in this April 15, 2003 EPA proposal, are regulations that will, in part, cause a small refiner, such as Frontier, to lose small refiner status upon merger with or acquisition of another refining entity if the post-merger or acquisition refining capacity exceeds 155,000 barrels per day. The small refiner losing such status would be allowed two years from the date of acquisition or merger to comply with the non-small refiner clean fuel standards. We are monitoring these regulatory developments and are evaluating their compliance options. The costs that we will eventually incur to comply with these regulations, when final, are currently unknown.
The front range of Colorado (including the Denver metro area) is a major market for the products manufactured by our Refineries. Until the summer of 2003, this area had been in compliance with all of the EPA’s National Ambient Air Quality Standards (“NAAQS”) for ozone for the summer seasons, and in recognition of that compliance had been granted annual waivers from federal gasoline vapor pressure standards that pre-date that compliance. The combination of a new, lower NAAQS for ozone and unusual summertime meteorological conditions in the area resulted in numerous and unforeseen instances where the new standard was exceeded. The State of Colorado has recently undertaken an effort to develop and implement controls necessary to ensure the area will regain compliance with the NAAQS for ozone during the three-year averaging period of 2005 through 2007. These controls will likely include a requirement to reduce the current allowable summertime gasoline vapor pressure from 9.0 pounds to either 8.1 pounds or the current federal standard of 7.8 pounds. These controls will most likely be initiated for the gasoline to be sold in the area beginning in May of 2005. We are currently evaluating what modifications may be required to the Cheyenne Refinery to allow manufacture of the lower vapor pressure product. At this time, we do not believe that any capital investment will be required at El Dorado to meet the anticipated new standard.
Turnarounds. The costs for turnarounds (scheduled and required shutdowns of refinery operating units for significant overhaul and refurbishment) are ratably accrued over the period from the prior turnaround to the next scheduled turnaround. Since utilizing this policy relies on estimated costs for the next turnaround, adjustments occur as the estimate changes or even when the turnaround is in progress should more or less extensive work be necessary than was anticipated. These accruals are included in our consolidated balance sheet in the accrued turnaround cost and long-term accrued turnaround cost. The turnaround accrual, any turnaround costs in excess of accrual incurred at the time of turnaround, or reductions of expenses when the actual costs are less than the estimate are included in Refinery operating expenses, excluding depreciation in our consolidated statements of income. Turnaround costs include contract services, materials and rental equipment.
In 2001, the American Institute of Certified Public Accountants (“AICPA”) issued an Exposure Draft for a Proposed Statement of Position (“SOP”), “Accounting for Certain Costs and Activities Related to Property, Plant and Equipment”. At its September 2003 meeting, the Accounting Standards Executive Committee of the AICPA approved the SOP for issuance and it is scheduled to be addressed in April 2004 by the Financial Accounting Standards Board (“FASB”). If cleared by the FASB, the SOP will become a generally accepted accounting principle (“GAAP”) and will become effective for fiscal years beginning after December 15, 2004, with early adoption encouraged. The SOP will require us to account for our property, plant and equipment on a component level with each component being recorded at cost and depreciated over its expected useful life. The SOP will also require that any existing turnaround accruals be reversed to income immediately and the costs of future turnarounds expensed as incurred. We adopted the component level of accounting for property, plant and equipment beginning with December 2003 additions, and this aspect of the SOP did not have any impact on our consolidated statements of income. If this proposed change were in effect at December 31, 2003, we would have been required to reverse the turnaround accruals and recognize pretax income totaling $26.6 million. The total accrued turnaround costs will change throughout the year as turnarounds are incurred and accruals are made for future turnarounds. When we adopt the SOP, income related to this proposed change as it relates to turnarounds would be reported as a cumulative effect of an accounting change, net of tax, in the consolidated statements of income. Since major turnarounds occur only every three to five years, this reporting change will result in dramatic fluctuations in our operating results from year to year and quarter to quarter. Our operating results will be negatively impacted in the quarters and years of the major turnarounds by reflecting all of the costs related to those turnarounds within that period as opposed to our current method of expensing the costs over the period between the turnarounds. If this SOP becomes GAAP, we anticipate adopting the provisions of the SOP as they relate to turnarounds on January 1, 2005.
Inventories. Inventories of crude oil, unfinished products and all finished products are recorded at the lower of cost on a FIFO basis or market. Crude oil includes both domestic and foreign crude oil volumes at its cost and associated freight and other cost. Unfinished products (work in process) include any crude oil that has entered into the refining process, and other feedstocks that are not finished as far as refining operations are concerned. These include unfinished gasoline and diesel, blendstocks and other feedstocks. Finished product inventory includes saleable gasoline, diesel, jet fuel, chemicals, asphalt and other finished products. Unfinished and finished products inventory values have components of raw material, the associated raw material freight and other costs, and direct refinery operating expense allocated when refining begins relative to their proportionate market values. The FIFO method of accounting for inventories sometimes results in Frontier recognizing substantial gains (in periods of rising prices) or losses (in periods of falling prices) from our inventories of crude oil and products. While Frontier feels this accounting method more accurately reflects the results of our operations, since many other refining companies instead utilize the last-in, first-out ("LIFO") method of accounting for inventories, comparison of our results to other refineries must take into account the impact of the inventory accounting differences.
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 Frontier’s common stock at the grant date over the amount the employee must pay to acquire the stock. We have a stock option plan which authorizes the granting of options to employees to purchase shares. 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. No compensation expense is recorded. If we measured compensation in accordance with SFAS No. 123, Frontier would record compensation expense based on the fair value of the awards at grant date and would result in increased expenses.
Price Risk Management Activities. See the “Market Risks” section and “Price Risk Management Activities” under Notes 2 and 10 in the “Notes to Consolidated Financial Statements” for a discussion of our various price risk management activities. When we make the decision to manage our price exposure, we neither incur losses from negative price changes nor do we obtain the benefit of positive price changes.
See “New Accounting Pronouncements” under Note 2 in the “Notes to Consolidated Financial Statements”. Other than the SOP discussed above under “Critical Accounting Policies”, no other new pronouncements are expected to have a material impact on our financial statements.
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. Frontier, 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. Gains or losses on commodity derivative contracts accounted for as hedges are recognized in raw material, freight and other costs or refinery operating expenses, excluding depreciation when the associated transactions are consummated while gains and losses on transactions accounted for using mark-to-market accounting are reflected in other revenues at each period end. See “Price Risk Management Activities” under Notes 2 and 10 in the “Notes to Consolidated Financial Statements”.
On January 19, 2004, we reported that a fire had occurred in the furnaces of the coking unit at our Cheyenne Refinery. Fortunately, no serious injuries occurred as a result of the fire. The coker was out of service for approximately one month. We replaced one of the furnaces and repaired the other furnace. We anticipate the total cost of repair, both capital and expense, above our $2.5 million deductible will be covered by insurance. We had previously scheduled a distillate hydrotreater and naptha hydrotreater turnaround for late March 2004, but rescheduled the turnarounds to begin in mid-February in order to minimize lost production. These turnarounds are expected to last approximately 16 days. As a result of the fire and the turnarounds, we expect total crude charges for the first quarter at our Cheyenne Refinery will average 35,000 barrels per day, of which only approximately 81% will be heavy crude. However, by the end of the year, we expect to recover almost all of the production lost in the first quarter.
SELECTED QUARTERLY FINANCIAL AND OPERATING DATA
(Dollars in thousands except per share)
2003 2002
--------------------------------------- --------------------------------------
Unaudited Fourth Third Second First Fourth Third Second First
- ------------------------------------------------------------------------------------------------------------------------------------
Revenues $542,943 $594,763 $533,413 $499,384 $531,558 $486,680 $459,162 $336,350
Operating income $ 14,830 $ 27,304 $ 8,599 $ 1,131 $ 11,110 $ 8,487 $ 1,631 $ 6,671
Net income (loss) $ 4,102 $ 3,822 $ (992) $ (3,700) $ 2,965 $ 809 $ (3,007) $ 261
Basic earnings (loss) per share: $ .16 $ .15 $ (.04) $ (.14) $ .11 $ .03 $ (.12) $ .01
Diluted earnings (loss) per share: $ .15 $ .14 $ (.04) $ (.14) $ .11 $ .03 $ (.12) $ .01
Net cash provided by (used in) operating activities $(35,322) $ 29,341 $ 19,315 $(19,339) $ 43,749 $ 20,237 $ (3,120) $(10,044)
Net cash used in investing activities $ (7,544) $ (7,193)$(12,956) $ (6,607) $ (6,729)$ (4,193)$(10,560) $(15,635)
Net cash provided by (used in) financing activities $ 770 $ 6,646 $(42,468) $ 27,513 $(31,339)$(19,082)$ 15,494 $ 29,591
EBITDA (1) $ 22,475 $ 34,460 $ 15,670 $ 8,091 $ 18,089 $ 15,466 $ 8,407 $ 13,269
Refining operations
Total charges (bpd) (2) 166,347 177,364 173,610 144,824 162,361 170,391 165,074 157,310
Gasoline yields (bpd) (3) 87,937 86,014 85,056 74,614 94,564 79,779 82,050 82,104
Diesel and jet fuel yields (bpd) (3) 53,059 57,321 59,324 42,760 55,140 53,101 54,190 51,273
Total product sales (bpd) 169,233 176,914 171,215 144,921 175,888 166,750 169,366 153,880
Average gasoline crack spreads (per bbl) $ 5.22 $ 9.70 $ 7.24 $ 5.85 $ 5.47 $ 6.40 $ 6.83 $ 5.07
Average diesel crack spreads (per bbl) $ 5.57 $ 4.75 $ 3.91 $ 5.95 $ 6.01 $ 4.02 $ 2.82 $ 3.21
Average light/heavy spread (per bbl) (4) $ 7.66 $ 6.81 $ 6.56 $ 7.37 $ 6.31 $ 4.18 $ 4.07 $ 4.50
Average WTI/WTS crude oil spread (per bbl) $ 2.71 $ 2.44 $ 3.19 $ 2.38 $ 1.73 $ 0.97 $ 1.22 $ 1.53
- ------------------------------------------------------------------------------------------------------------------------------------
| (1) | EBITDA represents income before interest expense, interest income, 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 our consolidated financial statements. EBITDA should not be considered as an alternative to net income or operating income, as an indication of our operating performance or as an alternative to operating cash flow as a measure of liquidity. EBITDA is not necessarily comparable to similarly titled measures of other companies. EBITDA is presented here because it enhances an investor's understanding of Frontier's ability to satisfy principal and interest obligations with respect to Frontier's indebtedness and to use cash for other purposes, including capital expenditures. EBITDA is also used for internal analysis and as a basis for financial covenants. Frontier's EBITDA is reconciled to net income as follows (in thousands): |
2003 2002
-------------------------------------------------------------------------------
Fourth Third Second First Fourth Third Second First
-------------------------------------------------------------------------------
Net income (loss) $ 4,102 $ 3,822 $ (992) $ (3,700) $ 2,965 $ 809 $ (3,007) $ 261
Add provision (benefit) for income taxes 2,526 2,940 (288) (2,222) 1,686 1,140 (1,864) 98
Add interest expense and other financing costs 7,997 6,590 6,733 7,426 6,874 7,009 6,953 6,777
Subtract interest income (202) (260) (274) (373) (415) (471) (451) (465)
Add merger financing termination costs, net 407 14,212 3,420 - - - - -
Add depreciation and amortization 7,645 7,156 7,071 6,960 6,979 6,979 6,776 6,598
-------------------------------------------------------------------------------
EBITDA $ 22,475 $ 34,460 $ 15,670 $ 8,091 $ 18,089 $ 15,466 $ 8,407 $ 13,269
===============================================================================
| (2) | Charges are the quantity of crude oil and other feedstock processed through refinery units. |
| (3) | Manufactured product yields are the volumes of specific materials that are obtained through the distilling of crude oil and the operations of other refinery process units. |
| (4) | The average light/heavy spread for prior periods has been restated to conform to the current presentation using WTI as the light crude oil in order to be comparable with the WTI/WTS spread reported for the El Dorado Refinery. |
FIVE YEAR FINANCIAL DATA
(in thousands except per share)
2003 2002 2001 2000 1999 (1)
- ------------------------------------------------------------------------------------------------------------------------
Revenues $2,170,503 $1,813,750 $1,888,401 $2,045,157 $503,600
Operating income (loss) 51,864 27,899 164,100 70,655 (5,249)
Net income (loss) 3,232 1,028 107,653 37,206 (17,061)
Basic earnings (loss) per share 0.12 0.04 4.12 1.36 (0.62)
Diluted earnings (loss) per share 0.12 0.04 4.00 1.34 (0.62)
Net cash (used in) provided by operating activities (6,005) 50,822 138,575 66,346 (11,332)
Net cash used in investing activities (34,300) (37,117) (22,824) (12,688) (181,703)
Net cash provided by (used in) financing activities (7,539) (5,336) (76,202) (27,557) 197,791
Working capital 38,621 108,253 109,064 43,610 24,832
Total assets 642,297 628,877 581,746 588,213 521,493
Long-term debt 168,689 207,966 208,880 239,583 257,286
Shareholders' equity 169,277 168,258 169,204 81,424 50,681
Capital expenditures 34,300 37,117 22,824 12,688 181,703
Dividends declared per common share .20 .20 .15 - -
EBITDA (2) 80,696 55,231 189,110 93,662 7,799
- ------------------------------------------------------------------------------------------------------------------------
| (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, interest income, 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 our consolidated financial statements. EBITDA should not be considered as an alternative to net income or operating income, as an indication of our operating performance or as an alternative to operating cash flow as a measure of liquidity. EBITDA is not necessarily comparable to similarly titled measures of other companies. EBITDA is presented here because it enhances an investor's understanding of Frontier's ability to satisfy principal and interest obligations with respect to Frontier's indebtedness and to use cash for other purposes, including capital expenditures. EBITDA is also used for internal analysis and as a basis for financial covenants. Frontier's EBITDA is reconciled to net income as follows (in thousands): |
2003 2002 2001 2000 1999
--------- --------- --------- --------- ---------
Net income (loss) $ 3,232 $ 1,028 $ 107,653 $ 37,206 $ (17,061)
Add provision for income taxes 2,956 1,060 28,073 2,075 1,865
Add interest expense and other financing costs 28,746 27,613 31,146 34,738 11,447
Subtract interest income (1,109) (1,802) (2,772) (3,364) (1,500)
Add merger financing termination costs, net 18,039 - - - -
--------- --------- --------- --------- ---------
Add depreciation and amortization 28,832 27,332 25,010 23,007 13,048
--------- --------- --------- --------- ---------
EBITDA $ 80,696 $ 55,231 $ 189,110 $ 93,662 $ 7,799
========= ========= ========= ========= =========
FIVE YEAR OPERATING DATA
2003 2002 2001 2000 1999 (1)
- -------------------------------------------------------------------------------------------------------------------
Charges (bpd) (2)
Light crude 31,314 35,684 31,456 35,605 10,250
Heavy crude (3) 115,907 110,372 111,061 105,529 39,315
Other feed and blend stocks 18,407 17,760 15,538 14,884 7,589
------- ------- ------- ------- ------
Total charges 165,628 163,816 158,055 156,018 57,154
Manufactured product yields (bpd) (4)
Gasoline 83,449 84,645 78,126 76,795 24,923
Diesel and jet fuel 53,156 53,436 51,210 50,924 17,340
Chemicals (5) 842 369 1,370 1,804 232
Asphalt and other 24,066 22,352 24,483 23,363 12,982
------- ------- ------- ------- ------
Total manufactured product yields 161,513 160,802 155,189 152,886 55,477
Product sales (bpd)
Gasoline 89,842 91,989 83,737 83,070 29,728
Diesel and jet fuel 53,606 53,378 51,539 51,568 17,156
Chemicals (5) 842 439 1,413 1,964 44
Asphalt and other 21,377 20,726 22,411 21,556 10,965
------- ------- ------- ------- ------
Total product sales 165,667 166,532 159,100 158,158 57,893
Average sales price (per bbl)
Gasoline $39.72 $33.08 $35.85 $38.09 $26.61
Diesel and jet fuel 36.91 30.35 34.12 37.19 25.92
Chemicals (5) 53.90 41.68 70.81 70.52 57.50
Asphalt and other 16.46 13.72 14.07 16.14 12.36
Refinery operating margin information (per sales bbl)
Refined products revenue $35.88 $29.82 $32.53 $35.20 $23.73
Raw material, freight and other costs 30.77 25.71 25.69 30.41 20.31
Refinery operating expenses excluding depreciation 3.31 2.93 3.27 3.07 2.71
Refinery depreciation 0.47 0.44 0.42 0.39 0.61
Average gasoline crack spreads (per bbl) $7.00 $5.88 $8.91 $5.76 N/A
Average diesel crack spreads (per bbl) $5.05 $3.97 $7.91 $5.64 N/A
Average light/heavy spread (per bbl) (6) $7.10 $4.77 $7.62 $5.88 N/A
Average WTI/WTS crude oil spread (per bbl) $2.68 $1.36 $3.10 $2.06 N/A
- -------------------------------------------------------------------------------------------------------------------
| (1) | Includes El Dorado Refinery operating data from the date of acquisition, November 17, 1999. |
| (2) | Charges are the quantity of crude oil and other feedstock processed through refinery units. |
| (3) | Includes intermediate varieties of crude oil used by the El Dorado Refinery. |
| (4) | Manufactured product yields are the volumes of specific materials that are obtained through the distilling of crude oil and the operations of other refinery process units. |
| (5) | During 2002, the process of shutting down the phenol and cumene units at El Dorado began and by year-end Frontier had discontinued the production of phenol and acetone, and began producing and selling benzene. |
| (6) | The average light/heavy spread for prior periods has been restated to conform to the current presentation using WTI as the light crude oil in order to be comparable with the WTI/WTS spread reported for the El Dorado Refinery. |
CONSOLIDATED STATEMENTS OF INCOME
(in thousands except per share amounts)
Years Ended December 31,
----------------------------------------------
2003 2002 2001
------------- ------------- -----------
Revenues:
Refined products $ 2,169,551 $ 1,812,613 $ 1,889,233
Other 952 1,137 (832)
------------- ------------- -----------
2,170,503 1,813,750 1,888,401
------------- ------------- -----------
Costs and Expenses:
Raw material, freight and other costs 1,860,795 1,562,613 1,491,772
Refinery operating expenses, excluding depreciation 200,383 178,295 189,948
Selling and general expenses, excluding depreciation 19,890 17,611 17,571
Merger termination and legal costs (Note 3) 8,739 - -
Depreciation 28,832 27,332 25,010
------------- ------------- -----------
2,118,639 1,785,851 1,724,301
------------- ------------- -----------
Operating income 51,864 27,899 164,100
Interest expense and other financing costs 28,746 27,613 31,146
Interest income (1,109) (1,802) (2,772)
Merger financing termination costs, net (Note 3) 18,039 - -
------------- ------------- -----------
45,676 25,811 28,374
------------- ------------- -----------
Income before income taxes 6,188 2,088 135,726
Provision for income taxes 2,956 1,060 28,073
------------- ------------- -----------
Net income $ 3,232 $ 1,028 $ 107,653
============= ============= ===========
Basic earnings per share of common stock $ .12 $ .04 $ 4.12
============= ============= ===========
Diluted earnings per share of common stock $ .12 $ .04 $ 4.00
============= ============= ===========
The accompanying notes are an integral part of these consolidated financial statements.
CONSOLIDATED BALANCE SHEETS
(in thousands except share data)
December 31, 2003 2002
------------ ------------
ASSETS
Current assets:
Cash and cash equivalents (Note 2) $ 64,520 $ 112,364
Trade receivables, net of allowance of $500 in both years 86,519 81,154
Note receivable, net of allowance of $800 in 2002 - 1,449
Other receivables 1,834 987
Inventory of crude oil, products and other 123,999 105,160
Deferred tax assets 5,967 5,346
Other current assets 1,974 2,510
------------ ------------
Total current assets 284,813 308,970
------------ ------------
Property, plant and equipment, at cost:
Refineries, terminal equipment and pipelines 489,502 447,948
Furniture, fixtures and other equipment 6,142 5,119
------------ ------------
495,644 453,067
Less - accumulated depreciation 173,196 144,127
------------ ------------
322,448 308,940
Deferred financing costs, net 4,009 5,460
Commutation account (Note 8) 19,550 -
Prepaid insurance (Notes 2 and 8) 6,593 -
Other assets 4,884 5,507
------------ ------------
Total assets $ 642,297 $ 628,877
============ ============
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable $ 177,235 $ 174,917
Revolving credit facility 45,750 -
Accrued turnaround cost 10,412 12,849
Accrued liabilities and other 10,282 9,095
Accrued interest 2,513 3,856
------------ ------------
Total current liabilities 246,192 200,717
------------ ------------
Long-term debt 168,689 207,966
Long-term accrued turnaround cost 16,229 14,013
Post-retirement employee liabilities 20,725 18,784
Deferred credits and other 4,255 3,963
Deferred income taxes 16,930 15,176
Commitments and contingencies (Note 8)
Shareholders' equity:
Preferred stock, $100 par value, 500,000 shares authorized,
no shares issued - -
Common stock, no par, 50,000,000 shares authorized,
30,643,549 and 30,290,324 shares
issued in 2003 and 2002, respectively 57,504 57,469
Paid-in capital 106,443 102,557
Retained earnings 47,614 49,621
Accumulated other comprehensive loss (924) (598)
Treasury stock, at cost, 4,264,673 and 4,151,210
shares at December 31, 2003 and 2002, respectively (39,914) (37,959)
Deferred employee compensation (1,446) (2,832)
------------ ------------
Total shareholders' equity 169,277 168,258
------------ ------------
Total liabilities and shareholders' equity $ 642,297 $ 628,877
============ ============
The accompanying notes are an integral part of these consolidated financial statements.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
Years Ended December 31,
---------------------------------------------
2003 2002 2001
----------- ----------- -----------
Cash flows from operating activities:
Net income $ 3,232 $ 1,028 $ 107,653
Depreciation 28,832 27,332 25,010
Deferred finance cost and bond discount amortization 10,642 2,033 2,168
Deferred employee compensation amortization 1,386 907 380
(Decrease) increase allowance for doubtful trade and note receivables (186) 800 -
Impairment loss on asset to be sold 189 363 -
Deferred income taxes 2,655 1,149 9,463
Long-term commutation account and prepaid insurance (26,566) - -
Amortization of long-term prepaid insurance 423 - -
Other (690) (562) 381
Changes in components of working capital from operations:
Decrease (increase) in trade, note and other receivables (4,577) (22,178) 15,912
Decrease (increase) in inventory (18,839) (17,190) 37,511
Decrease (increase) in other current assets 536 (267) 1,569
(Decrease) increase in accounts payable (4,282) 64,004 (60,013)
(Decrease) increase in accrued liabilities and other 1,240 (6,597) (1,459)
----------- ----------- -----------
Net cash (used in) provided by operating activities (6,005) 50,822 138,575
Cash flows from investing activities:
Additions to property, plant and equipment (33,677) (29,517) (22,745)
Proceeds from sale of assets 304 - -
Other investments (927) (100) (79)
El Dorado Refinery acquisition - contingent earn-out payment - (7,500) -
----------- ------------ -----------
Net cash used in investing activities (34,300) (37,117) (22,824)
Cash flows from financing activities:
Proceeds from issuance of 8% Senior Notes, net of discount 218,143 - -
Repurchase of debt:
9-1/8% Senior Notes (39,475) (1,090) (24,410)
8% Senior Notes (220,000) - -
11-3/4% Senior Notes - - (6,541)
Proceeds (repayments) of revolving credit facility, net 45,750 - (23,000)
Proceeds from issuance of common stock (Note 6) 1,441 1,702 3,271
Purchase of treasury stock (1,075) (787) (22,600)
Dividends paid (5,187) (5,161) (2,629)
Deferred finance costs and other (7,136) - (293)
------------ ----------- -----------
Net cash used in financing activities (7,539) (5,336) (76,202)
----------- ----------- -----------
(Decrease) increase in cash and cash equivalents (47,844) 8,369 39,549
Cash and cash equivalents, beginning of period 112,364 103,995 64,446
----------- ----------- -----------
Cash and cash equivalents, end of period $ 64,520 $ 112,364 $ 103,995
=========== =========== ===========
The accompanying notes are an integral part of these consolidated financial statements.
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY AND STATEMENTS OF COMPREHENSIVE INCOME
(in thousands except shares)
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, 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
Restricted stock issuances, net - - 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 of $206 3,910
Change in fair value of
derivatives, net of tax of $160 (1,626)
Derivative value reclassed to
income, net of tax of $46 (2,284)
Minimum pension liability,
net of tax of $158 (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
Restricted stock issuances, net - - 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 of $21 (33)
Derivative value reclassed to
income, net of tax of $21 33
Minimum pension liability,
net of tax of $214 (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
------------- ----------- --------- ---------- ----------- ---------- ------------ ------------ ------------ -----------
Shares issued under:
Stock option plan 353,225 35 2,286 - - - - - 353,225 2,321
Shares repurchased under:
Stock repurchase plans - - - - (88,638) (1,527) - - (88,638) (1,527)
Restricted stock plan - - - - (24,825) (428) - - (24,825) (428)
Comprehensive income:
Net income - - - $ 3,232 3,232 - - - - - 3,232
Other comprehensive income:
Minimum pension liability,
net of tax of $201 (326)
--------
Other comprehensive income (326) (326) (326)
--------
Comprehensive income $ 2,906
========
Income tax benefits of stock compensation - - 1,600 - - - - - - 1,600
Deferred employee compensation:
Amortization/vested shares - - - - - - 1,386 - - 1,386
Dividends declared - - - (5,239) - - - - - (5,239)
------------- ----------- --------- ---------- ----------- ---------- ------------ ------------ ------------ -----------
December 31, 2003 30,643,549 $ 57,504 $ 106,443 $ 47,614 (4,264,673) $ (39,914) $ (1,446) $ (924) 26,378,876 $ 169,277
============= =========== ========= ========== =========== ========== ============ ============ ============ ===========
The accompanying notes are an integral part of these consolidated financial statements.
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. The Company also owns FGI, LLC, an asphalt terminal and storage facility in Grand Island, Nebraska, whose activities are included in the consolidated financial statements since December 1, 2003 when the Company increased its ownership from 50% to 100%. This additional investment is reflected on the 2003 Consolidated Statements of Cash Flows under “Other investments” in the cash flows from investing activities section. Previously, the Company’s 50% interest in FGI, LLC was accounted for using the equity method of accounting. The Company also owns a 34.72% interest in a crude oil pipeline in Wyoming and a 50% interest in two crude oil tanks in Guernsey, Wyoming, both of which are accounted for as undivided interests. Each asset, liability, revenue and expense is reported on a proportionate gross basis. In addition, the equity method of accounting is utilized for the Company’s 25% interest in 8901 Hangar, Inc., a company which leases and operates a private airplane hangar. All of the operations of the Company are in the United States with its marketing efforts focused in the Rocky Mountain and Plains States regions of the United States. The Company purchases crude oil to be refined and markets the refined petroleum products produced, including various grades of gasoline, diesel fuel, jet fuel, asphalt, chemicals and petroleum coke. The operations of refining and marketing of petroleum products are considered part of one reporting segment.
Revenues from sales of refined products are earned and realized upon transfer of title to the customer based on the contractual terms of delivery. Title primarily transfers at the refinery or terminal when the refined product is loaded into the common carrier pipelines, trucks or railcars (free on board origin). In some situations, title transfers at the customer’s destination (free on board destination).
Property, plant and equipment additions are recorded at cost and depreciated using the straight-line method over the estimated useful lives. Beginning with December 2003 asset additions, the Company began accounting for property, plant and equipment additions on a component level basis. See the information on the Proposed Statement of Position, “Accounting for Certain Costs and Activities Related to Property, Plant and Equipment”, under the “New Accounting Pronouncements” section below, which may require the component method beginning for fiscal years ending after December 31, 2004. The components are depreciated over their estimated useful lives, which range as follows:
Refinery buildings and equipment............................ 5 to 50 years Pipelines and pipeline improvements......................... 5 to 20 years Furniture, fixtures and other............................... 3 to 10 years
The Company reviews long-lived assets for impairments under the Financial Accounting Standards Board (“FASB”) Statement of Financial Accounting Standard (“SFAS”) No. 144, “Accounting for the Impairment or Disposal of Long-lived Assets” whenever events or changes in circumstances indicate that the carrying value of an asset may not be recoverable. If the undiscounted future cash flow of an asset to be held and used in operations is less than the carrying value, the Company would recognize a loss for the difference between the carrying value and fair value. When fair values are not available, the Company estimates fair value based on a discounted cash flow analysis. The Company capitalizes interest on debt incurred to fund the construction of significant assets. Interest capitalized for the years ended December 31, 2003 and 2002 was $586,000 and $342,000, respectively. There was no interest capitalized in 2001.
Normal maintenance and repairs are expensed as incurred. The costs for turnarounds (scheduled and required shutdowns of refinery operating units for significant overhaul and refurbishment) are ratably accrued over the period from the prior turnaround to the next scheduled turnaround. 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 “Refinery operating expenses, excluding depreciation” in the Company’s consolidated statements of income. Turnaround costs include contract services, materials and rental equipment. Major improvements are capitalized, and the material assets replaced are retired. See the information on the Proposed Statement of Position, “Accounting for Certain Costs and Activities Related to Property, Plant and Equipment”, under the “New Accounting Pronouncements” section, which may require the Company to change its method of accounting for turnarounds in the future.
Inventories of crude oil, unfinished products and all finished products are recorded at the lower of cost on a first-in, first-out (“FIFO”) basis or market. Crude oil includes both domestic and foreign crude oil volumes at its cost and associated freight and other cost. Unfinished products (work in process) include any crude oil that has entered into the refining process, and other feedstocks that are not finished as far as refining operations are concerned. These include unfinished gasoline and diesel, blendstocks and other feedstocks. Finished product inventory includes saleable gasoline, diesel, jet fuel, chemicals, asphalt and other finished products. Unfinished and finished products inventory values have components of raw material, the associated raw material freight and other costs, and direct refinery operating expense allocated when refining begins relative to their proportionate market values. Refined product exchange transactions are considered asset exchanges with deliveries offset against receipts. The net exchange balance is included in inventory. Inventories of materials and supplies and process chemicals are recorded at the lower of average cost or market. Crude oil inventories, unfinished product inventories and finished product inventories are used to secure financing for operations under the Company’s revolving credit facility (See Note 4).
Components of Inventory
(in thousands)
December 31,
-------------------------
2003 2002
----------- -----------
Crude oil $ 39,374 $ 33,765
Unfinished products 31,240 24,806
Finished products 34,712 29,836
Process chemicals 5,175 3,308
Repairs and maintenance supplies and other 13,498 13,445
----------- -----------
$ 123,999 $ 105,160
=========== ===========
The Company expenses the amounts paid for insurance policies over the term of the policy. Prepaid insurance related to policies with terms in the range of one year are included in “Other current assets” on the balance sheet. The loss mitigation insurance premium and related expenses (see “Loss mitigation insurance-Beverly Hills Lawsuits” under Note 8) are in “Prepaid insurance” in the long-term asset portion of the balance sheet. Of the total indemnity premium, $1.4 million relates to year one of the policy, and is being amortized to expense over the one-year period which began October 1, 2003. The remaining $4.3 million of the indemnity premium will be amortized over four years beginning October 1, 2004. The administrative fee and surplus lines tax totaling $1.3 million is being amortized to expense over the five-year policy term which began October 1, 2003.
The Company accounts for income taxes under the provisions of 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 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.
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 “Raw material, freight and other costs” or “Refinery operating expenses, excluding depreciation” when the associated transactions are consummated, while gains and losses on transactions accounted for using mark-to-market accounting are reflected in “Other revenues” at each period end.
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. No compensation cost for stock options was recognized in the consolidated statements of income for the years ended December 31, 2003, 2002 and 2001. See Note 6 for pro forma compensation costs for each of those years had the Company determined compensation costs based on the fair value at the grant date for awards. Compensation costs of $1.4 million, $907,000 and $380,000 related to restricted stock awards was recognized for the years ended December 31, 2003, 2002 and 2001, respectively.
The Consolidated Financial Statements include the accounts of Frontier Oil Corporation and all majority-owned subsidiaries, as well as the Company’s undivided interests in a crude oil pipeline and crude oil tanks. All intercompany transactions and balances are eliminated in consolidation.
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America 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.
Highly liquid investments with a maturity, when purchased, of three months or less are considered to be cash equivalents. Cash equivalents were $56.8 million and $109.8 million at December 31, 2003 and 2002, respectively.
Cash payments for interest, excluding capitalized interest, during 2003, 2002 and 2001 were $33.5 million, $24.5 million and $27.8 million, respectively. Cash payments for income taxes during 2003, 2002 and 2001 were $626,000, $83,000 and $21.2 million, respectively.
Certain prior year amounts have been reclassified to conform with the current year presentation.
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 became 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 would have asset retirement obligation (“ARO”) liabilities related to its Refineries and certain other assets as a result of environmental and other legal requirements; however, any ARO liability is not currently estimatable as to amount and timing. The Company will continue to monitor and evaluate its potential ARO liabilties. 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 adoption of SFAS No. 143 on January 1, 2003 did not have any impact on the Company’s current financial condition or results of operations.
In 2001, the American Institute of Certified Public Accountants (“AICPA”) issued an Exposure Draft for a Proposed Statement of Position, “Accounting for Certain Costs and Activities Related to Property, Plant and Equipment”. The Statement of Position (“SOP”) requires a company to account for its property, plant and equipment at a component level with each component being recorded at cost and depreciated over its expected useful life. The SOP also requires major maintenance activities, such as refinery turnarounds, to be expensed as costs are incurred. At its September 2003 meeting, the Accounting Standards Executive Committee of the AICPA approved the SOP for issuance and it is scheduled to be addressed by the FASB in April 2004. If cleared by the FASB, the SOP would become a generally accepted accounting principle (“GAAP”) and will become effective for fiscal years beginning after December 15, 2004, with early adoption encouraged. The Company adopted the component level of accounting for property, plant and equipment beginning with December 2003 additions and this aspect of the SOP did not have any impact on the Company’s consolidated statements of income. The SOP will also require that any existing turnaround accruals be reversed to income immediately and the costs of future turnarounds expensed as incurred. If this proposed change were in effect at December 31, 2003, the Company would have been required to reverse the turnaround accruals and recognize pretax income totaling $26.6 million. The total accrued turnaround costs will change throughout the year as turnarounds are incurred and accruals are made for future turnarounds. When the Company adopts the SOP, 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 income. The Company will evaluate the date to adopt, but it is anticipated Frontier will not adopt the provisions of the SOP as they relate to turnarounds until January 1, 2005.
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.” 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 Accounting Principles Board Opinion No. 30. The Company adopted SFAS No. 145 effective January 1, 2003.
In December 2002, the FASB issued SFAS No. 148, “Accounting for Stock-Based Compensation-Transition and Disclosure”. This statement amends FASB Statement 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. The Company is currently evaluating the various provisions of SFAS No. 148. When Frontier decides to change to the fair value based method of accounting as allowed under SFAS No. 148, the impact on the Company’s financial condition or results of operations will depend on the number and terms of stock options outstanding on the date of change, as well as future options granted. See Note 6 for the pro forma impact the fair value method would have had on the Company’s net income for each of the years ended December 31, 2003, 2002 and 2001.
In January 2003, the FASB issued FASB Interpretation No. 46, “Consolidation of Variable Interest Entities” (FIN 46). FIN 46 clarifies the application of Accounting Research Bulletin No. 51, “Consolidated Financial Statements” to certain entities in which equity investors do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated support from other parties. FIN 46 requires existing unconsolidated variable interest entities to be consolidated by their primary beneficiaries if the entities do not effectively disperse risks among parties involved. All companies with interests in variable interest entities created after January 31, 2003 shall apply the provisions of FIN 46 to those entities immediately. FIN 46 is effective for the first fiscal year or interim period beginning after December 15, 2003, for variable interest entities created before February 1, 2003. The Company does not believe the adoption of FIN 46 will have a material effect on its financial statements.
In April 2003, the FASB issued SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities”. This statement amends and clarifies financial accounting and reporting for derivative instruments, including certain derivative instruments embedded in other activities. SFAS No. 149 is to be applied prospectively for contracts entered into or modified after June 30, 2003 and did not have any impact on the Company’s financial condition or results of operations.
In May 2003, the FASB issued SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity”. This statement established standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. It requires that an issuer classify a financial instrument within its scope as a liability (or asset in some circumstances). This statement was effective for financial instruments entered into or modified after May 31, 2003 and otherwise is effective at the beginning of the first interim period beginning after June 15, 2003. The Company adopted SFAS No. 150 on July 1, 2003, and it did not have any impact on the Company’s financial condition or results of operations.
In December 2003, the FASB issued a revised SFAS No. 132, “Employers’ Disclosures about Pensions and Other Post-retirement Benefits”. This statement adds additional disclosure requirements for pension and other post-retirement benefit plans and is effective for fiscal years ending after December 15, 2003, with certain provisions not effective until fiscal years ending after June 15, 2004. The Company adopted revised SFAS No. 132 when issued and the required additional disclosures effective for fiscal years ending after December 15, 2003 are reflected in Note 7.
On March 31, 2003, the Company announced that it had entered into an agreement with Holly Corporation (“Holly”) pursuant to which the two companies would merge. On August 20, 2003, Frontier announced that Holly had advised the Company that Holly was not willing to proceed with the merger agreement on the agreed terms. As a result, the Company filed suit for damages in the Delaware Court of Chancery. On September 2, 2003, Holly filed an answer and counterclaims, denying the Company’s claims, asserting that Frontier repudiated the merger agreement by filing the Delaware lawsuit, and claiming among other things that the Beverly Hills, California litigation caused the Company to be in breach of its representations and warranties in the merger agreement. Frontier has denied all of Holly’s counterclaims. Trial on the suit and Holly’s counterclaims is anticipated to begin the week of February 23, 2004.
The operating results for the year ended December 31, 2003 were negatively impacted by costs related to the Holly merger transaction aggregating $26.8 million pretax ($16.5 million after tax) and are reflected in the consolidated statements of income as “Merger termination and legal costs” ($8.7 million) and “Merger financing termination costs, net” ($18.0 million). The $8.7 million of “Merger termination and legal costs” for the year ended December 31, 2003 included $3.0 million in transaction related costs and over $5.7 million in legal expenses incurred to date (on an accrual basis) on the Holly lawsuit. The $18.0 million of “Merger financing termination costs, net”, for the year ended December 31, 2003, includes interest expense, issue discount, debt issue costs and redemption premium on the 8% Senior Notes, net of $752,000 interest income earned on the senior notes escrow account (see Note 4 ). These costs did not include bank facility charges related to the merger.
Schedule of Long-term Debt
(in thousands)
December 31,
-----------------------------
2003 2002
------------- -------------
11-3/4% Senior Notes, net of unamortized discount $ 168,689 $ 168,491
9-1/8% Senior Notes - 39,475
------------- -------------
$ 168,689 $ 207,966
============= =============
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 December 22, 2003, the Company called and redeemed, at the premium of 3.042%, or $1.2 million, provided for in the indenture, the remaining outstanding $39.5 million of the 9-1/8% Senior Notes. The original $70 million of 9-1/8% Senior Notes had semi-annual interest payments and were issued on February 9, 1998, and were due 2006. During 2002, 2001 and 2000, the Company purchased and held 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.
On April 17, 2003, the Company received the net proceeds (net of issue discount and underwriting fees) from a private placement of $220 million of 8% senior notes (“Senior Notes”) due April 15, 2013. The net proceeds of the Senior Notes were to be used, together with other available funds, to finance the cash portion of the merger with Holly, to pay related fees and expenses and to refinance or pay off existing Holly indebtedness. Pending consummation of the merger with Holly, the net proceeds of the notes offering, along with other amounts contributed by the Company, were placed in an escrow account. As provided for in the escrow agreement, since the merger with Holly did not occur, on October 10, 2003 Frontier closed the escrow account and redeemed the notes at a price equal to 101% of the aggregate principal amount of the notes plus accrued interest. The redemption premium, financing costs and issue discount of the notes were all reflected as expenses as of December 31, 2003 and included under the heading “Merger financing termination costs, net” on the consolidated statements of income.
The refining operations have a working capital credit facility with a group of banks led by Union Bank of California and BNP Paribas (“Facility”). The Facility has a current expiration date of June 15, 2006. 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. Debt outstanding under the Facility was $45.8 million at December 31, 2003. No borrowings were outstanding at December 31, 2002 under the Facility. Standby letters of credit outstanding were $26.2 million and $48.0 million at December 31, 2003 and 2002, respectively. As of December 31, 2003, the Company had borrowing base availability of $70.0 million under the Facility.
The Facility, secured by trade accounts receivable and inventories, provides working capital financing for operations, generally the financing of crude and product supply. The Facility provides for a quarterly commitment fee of 0.3% to 0.375% per annum. Borrowing rates are based, at the Company’s option, on agent bank’s prime rate plus 0.25% to 1%, prevailing Federal Funds Rate plus 1.25% to 2% or LIBOR plus 1.5% to 2.5%. Outstanding standby letters of credit charges are 1.125% to 1.75% per annum, plus standard issuance and renewal fees. The rates/fees discussed above increase from the lower to higher levels based on the ratio of funded debt to earnings, as defined in the Facility agreement. The average interest rate on funds borrowed under the Facility during 2003 was 2.99%. The Facility is subject to compliance with financial covenants relating to working capital, tangible net worth, fixed charges and cash coverage, and debt leverage ratios. The Company was in compliance with these covenants at December 31, 2003.
The 11¾% Notes are due 2009; until then there are no maturities of long-term debt.
The following is the provision for income taxes for the three years ended December 31, 2003, 2002 and 2001.
Provision for Income Taxes
(in thousands)
2003 2002 2001
----------- ----------- -----------
Current:
State $ 25 $ 32 $ 6,231
Federal 276 (204) 12,379
Canadian - 83 -
----------- ----------- -----------
Total current (benefit) provision $ 301 $ (89) $ 18,610
----------- ----------- -----------
Deferred:
State 411 303 457
Federal 2,244 846 9,006
----------- ----------- -----------
Total deferred provision $ 2,655 $ 1,149 $ 9,463
----------- ----------- -----------
Tax provision $ 2,956 $ 1,060 $ 28,073
=========== =========== ===========
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, 2003, 2002 and 2001.
Reconciliation of Tax Provision
(in thousands)
2003 2002 2001
----------- ----------- -----------
Provision based on statutory rates $ 2,166 $ 731 $ 47,504
Increase (decrease) resulting from:
Release of valuation allowance - - (24,603)
Federal tax effect of state and other income taxes (153) (146) (2,341)
State and other income taxes 436 418 6,688
Other 507 57 825
----------- ----------- -----------
Provision as reported $ 2,956 $ 1,060 $ 28,073
=========== =========== ===========
Significant components of deferred tax assets and liabilities are shown below:
COMPONENTS OF DEFERRED TAXES
(in thousands)
December 31, 2003 December 31, 2002
-------------------------------- --------------------------------
State Federal Total State Federal Total
-------------------------------- --------------------------------
Current deferred tax assets:
Gross current assets:
Turnaround accruals $ 522 $ 3,644 $ 4,166 $ 643 $ 4,498 $ 5,141
Pension retirement benefits 71 498 569 84 585 669
Restricted stock amortization 57 396 453 - - -
Bad debt reserve 25 175 200 65 455 520
Unrealized hedge loss 20 140 160 - - -
Charitable contributions carryforward 12 82 94 - - -
Capitalized SG&A - - - 16 113 129
State net operating losses 880 - 880 287 - 287
-------------------------------- --------------------------------
Total gross deferred tax assets 1,587 4,935 6,522 1,095 5,651 6,746
-------------------------------- --------------------------------
Gross current liabilities:
Installment sale gain - - - (129) (906) (1,035)
Unrecognized hedge gain - - - (3) (25) (28)
State deferred taxes - (555) (555) - (337) (337)
-------------------------------- --------------------------------
Total current net deferred tax assets $ 1,587 $ 4,380 $ 5,967 $ 963 $ 4,383 $ 5,346
================================ ================================
Long-term deferred tax liabilities:
Gross long-term assets:
Turnaround accruals $ 813 $ 5,679 $ 6,492 $ 700 $ 4,904 $ 5,604
Pension retirement benefits 199 1,391 1,590 217 1,521 1,738
Other post-retirement benefits 840 5,862 6,702 724 5,054 5,778
Deferred compensation 99 692 791 126 878 1,004
State deferred taxes - 1,850 1,850 - 1,566 1,566
Federal net operating loss - 6,757 6,757 - 2,357 2,357
Federal alternative minimum tax credits - 13,434 13,434 - 13,434 13,434
-------------------------------- --------------------------------
Gross long-term assets 1,951 35,665 37,616 1,767 29,714 31,481
Less valuation allowance (600) (955) (1,555) (600) (955) (1,555)
-------------------------------- --------------------------------
Total long-term net deferred tax assets 1,351 34,710 36,061 1,167 28,759 29,926
Gross long-term liabilities:
Depreciation (6,636) (46,355) (52,991) (5,642) (39,460) (45,102)
-------------------------------- --------------------------------
Total long-term net deferred tax liabilities $ (5,285) $(11,645) $(16,930) $ (4,475) $(10,701) $(15,176)
================================ ================================
At December 31, 2003, 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 $19.3 million as of December 31, 2003, the majority of which will not expire until 2023.
The Company has estimated state net operating losses generated during 2002 and 2003 to reduce future state taxable income of $10.5 million for Kansas, $2.2 million for Colorado and $104,000 for Nebraska. Carryforward periods for the state net operating losses are ten years for Kansas, twenty years for Colorado and five years for Nebraska.
The Company declared quarterly dividends of $.05 per share of common stock for each quarter during both 2003 and 2002. Quarterly dividends of $.05 per share were declared for the second, third and fourth quarters of 2001.
The following sets forth the computation of diluted earnings per share (“EPS”) for the years ended December 31, 2003, 2002 and 2001.
(in thousands except per share amounts)
2003 2002 2001
--------------------------------------- --------------------------------------- ---------------------------------------
Per Per Per
Income Shares Share Income Shares Share Income Shares Share
(Numerator) (Denominator) Amount (Numerator) (Denominator) Amount (Numerator) (Denominator) Amount
-------------- ------------- -------- -------------- ------------- -------- -------------- ------------- --------
Basic EPS:
Net income $ 3,232 25,939 $ .12 $ 1,028 25,780 $ .04 $ 107,653 26,113 $ 4.12
Dilutive securities:
Stock options and
restricted stock - 1,052 - 1,154 - 772
-------------- ------------- -------- -------------- ------------- -------- -------------- ------------- --------
Dilutive EPS:
Net income $ 3,232 26,991 $ .12 $ 1,028 26,934 $ .04 $ 107,653 26,885 $ 4.00
============== ============= ======== ============== ============= ======== ============== ============= ========
The number of outstanding stock options that could potentially dilute EPS in future years but were not included in the computation of diluted EPS (because the exercise prices exceeded the average market prices for the periods) for the years ended 2003, 2002 and 2001 were 1,546,700, 702,700 and 10,000 shares, respectively.
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 is 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. Under the plan, the Company may grant an aggregate of 60,000 shares of the Company’s common stock held in treasury. No grants were made under this plan during the year ended December 31, 2003. The Company made aggregate grants to non-employee directors under this plan of 3,000 shares during each of the years ending December 31, 2002 and 2001, and expensed compensation in the amount of $13,500 for each of these years. There were 42,000 shares available for grant as of December 31, 2003.
The Company has a stock option plan which authorizes the granting of options to employees to purchase shares. The plan through December 31, 2003 has reserved for issuance a total of 3,600,000 shares of common stock of which 3,458,350 shares have been granted (2,764,350 are still outstanding) and 141,650 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. Of the $2.3 million (353,225 shares) of common stock issued in 2003 under stock option plans, $880,000 was funded by the Company receiving shares of treasury stock directly from employees in cashless stock option exercises.
There are also options granted and outstanding to purchase a total of 307,175 shares of common stock under two prior stock option plans of the Company. No additional options are available for grant under these plans.
Changes during 2003, 2002 and 2001 in outstanding options are presented below:
2003 2002 2001
---------------------------- ---------------------------- ----------------------------
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 2,581,250 $11.18 2,159,700 $ 7.22 2,451,220 $ 5.88
Granted 844,000 16.65 702,400 21.85 623,500 8.88
Exercised (353,225) 6.57 (230,750) 6.79 (869,570) 4.68
Expired (500) 8.60 (50,100) 10.21 (45,450) 6.41
----------- ----------- -----------
Outstanding at end of year 3,071,525 13.21 2,581,250 11.18 2,159,700
=========== =========== ===========
Exercisable at end of year 1,945,801 10.88 1,512,325 8.63 1,022,826
=========== =========== ===========
Available for grant at end of year 141,650 985,650 765,230
=========== =========== ===========
Weighted-average fair value of
options granted during the year 7.01 9.34 4.39
The following table summarizes information about stock options outstanding at December 31, 2003:
Options Outstanding Options Exercisable
----------------------------------------- -------------------------
Weighted-
Average Weighted- Weighted-
Number Remaining Average Average
Outstanding Contractual Exercise Exercisable Exercise
Range of Exercise Prices At 12/31/03 Life (Years) Price at 12/31/03 Price
- ------------------------- ----------- ------------ --------- ----------- ---------
$5.63 to $7.00 1,013,575 0.97 $ 6.65 1,013,575 $ 6.65
$8.50 to $8.75 491,250 2.12 8.60 352,376 8.59
$12.10 to $16.65 864,000 4.10 16.55 226,000 16.35
$19.07 to 21.85 702,700 3.29 21.81 353,850 21.79
Had compensation costs been determined based on the fair value at the grant dates for awards made in 2003, 2002, and prior years for the vested portions of the awards in each of the years 2003, 2002 and 2001, 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, 2003, 2002 and 2001:
(in thousands except per share amounts) 2003 2002 2001
----------- ----------- -----------
Net income as reported $ 3,232 $ 1,028 $ 107,653
Pro forma compensation expense, net of tax (3,070) (2,540) (1,436)
----------- ----------- -----------
Pro forma net income (loss) 162 (1,512) 106,217
Basic EPS:
As reported $ .12 $ .04 $ 4.12
Pro forma .01 (.06) 4.07
Diluted EPS:
As reported $ .12 $ .04 $ 4.00
Pro forma .01 (.06) 3.95
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 2003, 2002 and 2001, respectively: risk-free interest rates of 2.75%, 2.76% and 4.80%, expected volatilities of 50.50%, 51.40% and 50.20%, expected lives of 5.0 years, 5.0 years, and 5.0 years and 1.27% dividend yield in 2003 and 2002, 0.5% dividend yield in 2001.
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, 2003, there were 205,629 shares of unvested restricted stock, which represents the total of grants made in 2001 and 2002 less the vested portion of the grants and shares forfeited from employee departures prior to vesting. The remaining 123,054 shares from the 2001 grants vest in March 2004. Of the remaining 82,575 shares from the 2002 grants, approximately 27,527 shares will vest in March 2004 with the remaining vesting in March 2005. No grants were made in the year ended December 31, 2003. Restricted shares, when granted, are recorded at the market value on the date of issuance as deferred employee compensation (equity account) and amortized to compensation expense over the respective vesting periods of the stock. Compensation expense under the Plan for the years ended December 31, 2003, 2002 and 2001 was $1.4 million, $907,000 and $380,000, respectively.
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, 2003, 2002 and 2001 was $5.1 million, $5.1 million and $4.6 million, respectively.
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 $5.3 million at December 31, 2003 and its funding status is in compliance with ERISA.
The Company provides post-retirement healthcare and other benefits to certain employees of the El Dorado Refinery. Eligible employees are employees hired by the Refinery before certain defined dates and who satisfy certain age and service requirements. Employees hired on or before November 16, 1999 qualify for retirement healthcare insurance until eligible for Medicare. Employees hired on or before January 1, 1995 are also eligible for Medicare supplemental insurance. These plans have no assets as of December 31, 2003 and 2002.
The following tables set forth the change in benefit obligation, the change in plan assets, the funded status of the pension plan and post-retirement 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
-------------------------------------------
(in thousands) 2003 2002 2003 2002
-------- -------- -------- --------
Change in benefit obligation
Benefit obligation at January 1 $ 9,794 $ 8,816 $ 19,380 $ 15,075
Service cost - - 803 691
Interest cost 611 582 1,262 1,071
Plan participant contributions - - - 3
Actuarial (gains) losses 355 449 1,894 2,547
Benefits paid (65) (53) (89) (7)
-------- -------- --------- --------
Benefit obligation at December 31 $ 10,695 $ 9,794 $ 23,250 $ 19,380
======== ======== ========= ========
Change in plan assets
Fair value of plan assets at January 1 $ 3,777 $ 925 $ - $ -
Actual return on plan assets 200 54 - -
Employer contribution 1,386 2,851 89 4
Plan participant contributions - - - 3
Benefits paid (65) (53) (89) (7)
-------- -------- --------- --------
Fair value of plan assets at December 31 $ 5,298 $ 3,777 $ - $ -
======== ======== ========= ========
Funded status $ (5,397) $ (6,017) $ (23,250) $(19,380)
Unrecognized net actuarial loss 1,498 970 6,498 4,941
-------- -------- ---------- --------
Net amount recognized $ (3,899) $ (5,047) $ (16,752) $(14,439)
======== ======== ========= ========
Amounts recognized in the balance sheets:
Accrued benefit liability $ (5,397) $ (6,017) $ (16,752) $(14,439)
Accumulated other comprehensive loss 1,498 970 - -
-------- -------- --------- --------
Net amount recognized $ (3,899) $ (5,047) $ (16,752) $(14,439)
======== ======== ========= ========
Weighted-average assumptions as of December 31
Discount rate 6.00% 6.25% 6.00% 6.25%
Expected return on plan assets 8.00% 8.00% - -
| (1) | The actuary for the cash balance pension plan has used an 8% expected long-term rate of return on assets based on a blend of historic returns of equity and debt securities. Historic returns on the Company's plan have not yet been considered as the plan is relatively new and its plan assets have not been substantial until recently. |
| (2) | On December 8, 2003, the President of the United States of America signed into law the Medicare Prescription Drug Act (“Act”) which may impact the accounting for post-retirement medical plans. As the FASB has not yet provided detailed guidance on the implications of the Act under SFAS No. 106, “Employers’ Accounting for Post-retirement Benefits Other Than Pensions”, the Company is deferring the recognition of this Act as allowed under SFAS No. 106. The disclosed post-retirement healthcare obligations and net periodic costs do not reflect the effects of the Act. As specific guidance on reflecting the effects of the Act is pending, such guidance, when issued, could require the Company to change previously disclosed information. |
Components of net periodic benefit cost are as follows:
Post-retirement
Healthcare and
Pension Benefits Other Benefits
------------------------ -------------------------------
(in thousands) 2003 2002 2001 2003 2002 2001
------ ------- ------- --------- --------- ---------
Components of net periodic benefit cost:
Service cost $ - $ - $ - $ 803 $ 691 $ 599
Interest cost 611 582 563 1,262 1,071 901
Expected return on plan assets (373) (162) (25) - - -
Amortization of prior service cost - - - - - -
Recognized net actuarial loss - - - 337 136 11
------ ------- ------- --------- --------- ---------
Net periodic benefit cost $ 238 $ 420 $ 538 $ 2,402 $ 1,898 $ 1,511
====== ======= ======= ========= ========= =========
Healthcare cost-trend rate:
13.00% 15.00% 15.00%
ratable to ratable to ratable to
5.0% 5.0% 5.0%
from 2007 from 2007 from 2007
- -------------------------------------------------------------------------------------------------------------------
Sensitivity analysis:
Effect of 1% (-1%) change in healthcare cost-trend rate:
Year-end benefit obligation $ 5,036 $ 4,258 $ 3,322
(3,926) (3,313) (2,585)
Total of service and interest cost 467 394 338
(363) (307) (263)
- -------------------------------------------------------------------------------------------------------------------
Plan Assets
The pension plan assets are held in a Trust Fund (the “Fund”) whose trustee is Frost National Bank (“trustee”). Frontier’s pension plan weighted-average asset allocations in the Fund at December 31, 2003 and 2002, by asset category are as follows:
Percentage of
Plan Assets at December 31,
---------------------------
2003 2002
---- ----
Asset Category:
Cash equivalents 47% 51%
Equity common trust funds 16% 5%
Fixed income common trust funds 37% 30%
Bond fund common trust funds -% 10%
Stock fund common trust funds -% 4%
Total 100% 100%
The trustee has the following investment powers:
• except for limitations on investing Fund assets in Company securities or real property, the trustee may invest and reinvest in any property, real, personal or mixed, wherever situated, including without limitation, common and preferred stocks, bonds, notes, debentures, mutual funds, leaseholds, mortgages, certificates of deposit, and oil, mineral or gas properties, royalties, interests or rights;
• to make commingled, collective or common investments and to invest or reinvest all or any portion of the pension plan assets with funds of other pension and profit sharing trusts exempt from tax under section 501(a) of the Internal Revenue Code; and
• to deposit or invest all or a part of the Fund in savings accounts, certificates of deposit or other deposits which bear a reasonable rate of interest in a bank or similar financial institution, including the commercial department of the trustee.
Contributions expected to be paid by the Company into the Fund during the year ending December 31, 2004 are approximately $1.4 million.
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 was required based on 2003, 2002 or 2000 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.
In connection with the acquisition of the El Dorado Refinery, the Company entered into an operating sublease agreement with Shell for the use of the cogeneration facility at the El Dorado Refinery. The non-cancelable operating sublease 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 2004 through 2008. Operating lease rental expense was approximately $9.0 million, $11.3 million and $11.9 million for the three years ended December 31, 2003, 2002 and 2001, respectively. The approximate future minimum lease payments as of December 31, 2003 are $9.3 million for 2004, $8.8 million for 2005, $8.1 million for 2006, $6.6 million for 2007, $6.2 million for 2008 and $44.1 million thereafter.
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 commenced January 1, 2003, provides 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 received 9,000 barrels per day, which increased to 20,000 barrels per day by October 2003. The Company processes 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 is equal to 71% of the simple average of the near month settlement prices of the NYMEX light sweet crude oil contracts during the month of delivery, plus the cost of transportation based on the Express Pipeline tariff from Hardisty, Alberta to Guernsey, Wyoming, less $0.25 per barrel. The initial term of the agreement is through December 31, 2007. This agreement provides a firm source of heavy Canadian crude and also assigns some of the Company’s dedicated capacity through the Express Pipeline.
The Company has two contracts for crude oil pipeline capacity into 2015 on the Express Pipeline. The first contract, which began in 1997, is for 15 years and for an average of 13,800 barrels per day over that 15-year period. The agreement has allowed the Company to assign a portion of its capacity in early years for additional capacity in later years. As discussed above, the Company has assigned a portion of its contracted pipeline capacity to Baytex in connection with the crude supply agreement. In December 2003, the Company entered into an expansion capacity agreement on the Express Pipeline for an additional 10,000 barrels per day starting in April 2005 through 2015. The Company’s remaining 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 $205,000 for 2004, $4.6 million for 2005, $5.3 million for 2006, $5.1 million for 2007, approximately $11.5 million for each of the years 2008 through 2011, $7.2 million for 2012, $5.8 million for each of the years 2013 through 2014 and $1.5 million for 2015. Should the Baytex agreement be extended, as provided for in the agreement, beyond the initial term, which is through December 31, 2007, a 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 Phillips which expires after the earlier of a certain number of barrels processed, but no later than December 2006. During 2003, this agreement was assigned from Conoco Phillips to Suncor Energy (U.S.A.) (“Suncor”), when Suncor purchased the refinery in Denver from Conoco Phillips. Suncor is entitled to process in the Cheyenne Refinery coker unit up to 3,300 barrels per day of resid, a heavy end by-product of the refining process. 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. It is anticipated the agreement will end during the first half of 2004 due to the required number of processing barrels being reached.
The Company owns a 34.72% interest in a crude oil pipeline from Guernsey, Wyoming to the Cheyenne Refinery and a 50% interest in two crude oil tanks in Guernsey. The Company’s share of operating costs for the crude oil pipeline and the tanks are recorded as raw material, freight and other costs.
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. The Company had a one-year foreign crude oil supply agreement with Shell, which expired in April 2003.
Beverly Hills Lawsuits. A Frontier subsidiary, Wainoco Oil & Gas Company, owned and operated an interest in an oil field in the Los Angeles, California metropolitan area from 1985 to 1995. The production facilities for that interest in the oil field are located at the campus of the Beverly Hills High School. In April 2003, a law firm began filing claims with the Beverly Hills Unified School District and the City of Beverly Hills on behalf of former students, school employees, area residents and others alleging that emissions from the oil field or the production facilities caused cancers or various other health problems in those individuals. Wainoco Oil & Gas Company and Frontier are defendants in five pending lawsuits relating to some of those claims; other defendants include the Beverly Hills Unified School District, the City of Beverly Hills, ten other oil and gas companies, two additional companies involved in owning or operating a power plant adjacent to the Beverly Hills High School and three of their related parent companies. The lawsuits include claims for personal injury, wrongful death, loss of consortium and/or fear of contracting diseases, and also ask for punitive damages. No dollar amounts of damages have been specified in any of the lawsuits. The five pending lawsuits have been or will be formally related to one another and have been or will be transferred to a judge on the complex civil litigation panel in the Superior Court of the State of California for the County of Los Angeles. The Company believes that neither the claims that have been made, the five pending lawsuits, nor other potential future litigation by which similar or related claims may be asserted against Frontier or its subsidiary will result in any material liability or have any material adverse effect upon Frontier.
Loss Mitigation Insurance-Beverly Hills Lawsuits. The oil production site operated by Frontier’s subsidiary was a modern facility and was operated with a high level of safety and responsibility. Frontier believes that its subsidiary’s activities did not cause any health problems for anyone, including former Beverly Hills high school students, school employees or area residents. Nevertheless, as a matter of prudent risk management, Frontier purchased insurance in 2003 from an insurance company with an A.M. Best rating of A++ (Superior) covering the existing claims described above and any similar claims for bodily injury or property damage asserted during the five-year period following the policy’s September 30, 2003 commencement date. The claims are covered, whether asserted directly against the insured parties or as a result of contractual indemnity. The policy covers defense costs, and any payments made to claimants, up to an aggregate limit of $120 million, including coinsurance by Frontier of up to $3.9 million of the coverage between $40 million and $120 million. In October 2003, the Company paid $6.25 million to the insurance company (which includes an indemnity premium of $5.75 million and a $500,000 administration fee) and have funded with the insurance company a Commutation Account of approximately $19.6 million, from which the insurance company will fund the first costs under the policy including, but not limited to, the costs of defense of the claims. The Company also paid $772,500 to the state of California for surplus lines tax on the premium. Frontier has the right to terminate the policy at any time after the first year and prior to September 30, 2008, receive a refund of up to $4.3 million of the premium (which the dollar amount declines over time) plus any unspent balance in the Commutation Account plus accumulated interest. While the policy is in effect, the insurance company will manage the defense of the claims. The Company is also seeking coverage with respect to the Beverly Hills, California claims from the insurance companies that provided policies to Frontier during the 1985 to 1995 period.
Holly Lawsuit. See Note 3 “Holly Merger Agreement and Litigation”.
MTBE Contamination Lawsuit. Although the Company has never provided MTBE blended product to the Kansas marketplace, the Company has recently become aware that Frontier El Dorado Refining Company (“FEDRC”), the company’s subsidiary which owns and operates the El Dorado Refinery, is named as one of 52 defendants in four lawsuits brought on behalf the City of Dodge City, Kansas, the Chisholm Creek Utility Authority, the City of Bel Aire, Kansas, the County of Sedgwick Water Authority and the City of Park City, Kansas alleging unspecified damages for contamination of groundwater/public water wells by MTBE and tertiary butyl alcohol (TBA) a degradation product of MTBE. One element of the claims entails the alleged need for a well field vulnerability study in excess of $75,000. Plaintiffs contend that the defendants manufactured or otherwise put MTBE into the stream of interstate commerce. The causes of action stated include strict liability for a defective product or design, strict liability for failure to warn, negligence, public nuisance, private nuisance, trespass, and civil conspiracy. The company has requested that Shell Oil Company (as successor in interest to Equilon Enterprises, LLC) assume the defense and indemnify FEDRC in connection with these cases pursuant to the 1999 purchase and sale agreement for the El Dorado Refinery.
Other. The Company is also 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.
The Company has concentrations of credit risk with respect to sales within the same or related industry and within limited geographic areas. The Company sells its Cheyenne products exclusively at wholesale, principally to independent retailers and major oil companies located primarily in the Denver, Colorado, western Nebraska and eastern Wyoming regions. The Company sells a majority of its El Dorado gasoline, diesel and jet fuel to Shell at market-based prices, under a 15-year offtake agreement in conjunction with the purchase of the El Dorado Refinery in 1999. 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 also purchase all jet fuel production from the El Dorado Refinery through the offtake agreement term. The Company retains and markets all by-products 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 represented the estimated unsecured portion of the note. During 2003, the Company foreclosed on the collateral of the note, realized a $614,000 bad debt loss and reversed $186,000 of the previously provided allowance related to the note. During 2003, the Company also wrote off a doubtful account for one customer totaling $103,000. The Company made sales to Shell of approximately $1.1 billion in each of the years 2003, 2002 and 2001, which accounted for 53% of consolidated refined products revenues in 2003, 58% of consolidated refined products revenues in 2002 and 59% of consolidated refined products revenues in 2001.
The Company accounts for environmental costs as indicated in Note 2. 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 the Company’s Refineries during the next several years. The Environmental Protection Agency (“EPA”) recently embarked on a Petroleum Refining Initiative (“Initiative”) alleging industry-wide noncompliance with certain longstanding 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, Frontier does not know how or if the Initiative will affect the Company. The Company has, however, in recognition of the EPA’s reinterpretation of certain regulatory requirements associated with the Initiative, determined that over the next three years, expenditures totaling approximately $10 million may be necessary to further reduce emissions from the Refineries’ flare systems. Both the Kansas Department of Health and Environment (“KDHE”) and the Wyoming Department of Environmental Quality (“WDEQ”) have expressed their preference to enter into consent decrees with the Company to settle these and certain other compliance matters. The provisions of a KDHE Order have not yet been proposed. The WDEQ has informally suggested that it will be seeking injunctive relief and a penalty in the $600,000 range, an amount that is subject to potential negotiation and may largely be offset by supplemental environmental projects. The Company has accrued $317,000 as of December 31, 2003 to cover the estimated cash portion of the possible penalty.
On December 21, 1999, the EPA promulgated national regulations limiting the amount of sulfur that is to be allowed in gasoline. The new regulations require the phase-in of gasoline sulfur standards beginning in 2004 and continuing through 2008, with special provisions for small business refiners. Since the Company qualifies as a small business refiner, the Company’s Refineries may comply with an interim gasoline sulfur standard in 2004 that is based on historic gasoline sulfur levels rather than having to meet the much stricter standard that will be applied to the general industry. Depending on the deadline the Company chooses to comply with the new diesel sulfur limit (see discussion below), Frontier will then have between four and seven additional years to reduce its gasoline sulfur content to the national standard. The total capital expenditures estimated, as of December 31, 2003, to achieve the final gasoline sulfur standard, are approximately $35 million at the Cheyenne Refinery and approximately $44 million at the El Dorado Refinery. Over $28 million of the Cheyenne Refinery expenditures had been incurred (on and accrual basis) as of December 31, 2003 with the remaining $7 million to be incurred 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. As a small business refiner, Frontier may choose to comply with the 2006 program and extend the interim gasoline standard by three years (until 2011) or delay the diesel standard by four years (until 2010) and keep the original gasoline sulfur program timing. Although still under deliberation, it is now likely that Frontier will choose to comply with the highway diesel sulfur standard by June 2006 and extend Frontier’s small refiner interim gasoline sulfur standards at each of the Refineries until 2011. As of December 31, 2003, minimum capital costs for diesel desulfurization are estimated to be approximately $13 million for the Cheyenne Refinery and between $60 million and $90 million for the El Dorado Refinery. The final cost for the El Dorado Refinery will be dependent on whether the Company chooses to meet only the ultra low sulfur diesel requirement or decides on an alternative project which would also result in increased future profitability. This alternative project would increase the total cost for the El Dorado Refinery from the $60 to $90 million range up to a total cost of $160 million. The decision on which project to pursue is expected to be made during fiscal 2004. The Cheyenne Refinery expenditures are currently expected to be committed beginning in 2004, with the majority to be committed in 2005 and 2006. Approximately $25 million of the El Dorado Refinery expenditures are currently expected to be committed in 2004 with the remaining expenditures in 2005 and 2006. It may be necessary for the Company to pursue external financing to fund a portion of these capital expenditures beginning in 2005 or 2006.
On April 15, 2003, the EPA proposed regulations to reduce emissions from diesel engines used in off-road activities such as agriculture, mining and railroads and also to limit the allowable amount of sulfur in the diesel fuel used in those engines. Included in this April 15, 2003 EPA proposal, are regulations that will, in part, cause a small refiner, such as Frontier, to lose small refiner status upon merger with or acquisition of another refining entity if the post-merger or acquisition refining capacity exceeds 155,000 barrels per day. The small refiner losing such status would be allowed two years from the date of acquisition or merger to comply with the non-small refiner clean fuel standards. The Company is monitoring these regulatory developments and is evaluating its compliance options. The costs that the Company will eventually incur to comply with these regulations, when final, are currently unknown.
The front range of Colorado (including the Denver metro area) is a major market for the products manufactured by the Company’s Refineries. The State of Colorado has recently undertaken an effort to develop and implement controls necessary to ensure the area will regain compliance with the EPA’s National Ambient Air Quality Standards for ozone during the three-year averaging period of 2005 through 2007. These controls will likely include a requirement to reduce the current allowable summertime gasoline vapor pressure beginning in May of 2005. The Company is currently evaluating what modifications may be required to the Cheyenne Refinery to allow manufacture of the lower vapor pressure product. At this time, the Company does not believe that any capital investment will be required at El Dorado to meet the anticipated new standard.
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, that the Company may have 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, that may have been impacted by past operational activities. Prior to this agreement, we addressed tasks required under a consent decree entered by the Wyoming State District Court on November 28, 1984 and involving the State of Wyoming, the WDEQ and the predecessor owners of the Cheyenne Refinery. This action primarily addressed the threat of groundwater and surface water contamination at the Cheyenne Refinery. As a result of these investigative efforts, capital expenditures and remediation of conditions found to exist have already taken place or are in progress, including the completion of surface impoundment closures, waste stabilization activities and other site remediation projects totaling approximately $4 million and an ongoing groundwater remediation program averaging $150,000 in annual operation and maintenance costs. Additionally, the EPA issued an administrative consent order with respect to the Cheyenne Refinery on September 24, 1990 pursuant to the Resource Conservation and Recovery Act. 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.
El Dorado Refinery. The El Dorado Refinery is subject to a 1988 consent order with the 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. More specifically, the refinery must continue to operate the hydrocarbon recovery well systems and containment barriers at the site and conduct sampling from monitoring wells and surface water stations. Quarterly and annual reports must also be submitted to the KDHE. The order requires that remediation activities continue until KDHE-established groundwater criteria or other criteria agreed to by the KDHE and the refinery are met. 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 (“NPDES”) 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, 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. The Company further agreed to undertake a program designed to identify and remedy any wastewater toxicity non-compliance issues remaining after the first phase of wastewater treatment system upgrades was completed. Wastewater toxicity testing subsequent to the commissioning of the upgrades did not confirm satisfactory, routine compliance with permit limits. As a result, Frontier submitted, and the KDHE approved, a Toxicity Identification and Elimination plan that we believe will facilitate resolution of the remaining wastewater quality concerns. Good progress has since been made toward satisfying the provisions of the Agreement, with the Refinery wastewater in full compliance for the last three quarters of 2003. The KDHE has recently agreed to consider the Agreement satisfied upon a demonstration of compliance with the wastewater toxicity requirements for four of five consecutive calendar quarters, a goal we expect to reach in the first half of 2004.
The Company’s refining 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 59% of the Company’s work force at December 31, 2003.
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, 2003 and 2002, the carrying amounts of long-term debt instruments were $168.7 million and $208.0 million, respectively, and the estimated fair values were $185.8 million and $212.6 million. For cash and cash equivalents, trade receivables, inventory, and accounts payable, the carrying amount is a reasonable estimate of fair value.
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.
During 2003, 2002 and 2001, the Company had the following derivative activities which, while economic hedges, were not accounted for as hedges and whose gains or losses are reflected in “Other revenues” on the consolidated statements of income:
• Derivative contracts on barrels of crude oil to hedge butane inventory builds at the El Dorado Refinery. During the year ended December 31, 2003, the Company recorded $1.6 million in realized losses on these positions. During the year ended December 31, 2002, the Company recorded $903,000 in realized losses on these positions.
• Derivative contracts on barrels of crude oil to hedge excess gas oil inventory at the Cheyenne Refinery. During the year ended December 31, 2003, the Company recorded $27,000 in realized losses on these positions. During the year ended December 31, 2002, the Company recorded $202,000 in realized losses on these positions.
• Derivative contracts on barrels of crude oil to hedge excess gas oil inventory at the El Dorado Refinery. During the year ended December 31, 2003, the Company recorded $1.3 million in realized gains on these positions. During the year ended December 31, 2002, the Company recorded $896,000 in realized gains on these positions.
• Derivative contracts to hedge crude oil. During the year ended December 31, 2003, the Company recorded $451,000 in realized gains on these positions. During the year ended December 31, 2002, the Company recorded $48,000 in realized gains on these positions. 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).
• Derivative contracts to hedge intermediates, distillate and gas oil builds at the El Dorado Refinery. During the year ended December 31, 2003, the Company recorded a net $66,000 in realized gains on these positions.
• Derivative contracts on barrels of crude oil to hedge excess naptha inventory at the El Dorado Refinery. During the year ended December 31, 2002 the Company recorded losses of $579,000 on these positions.
• 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).
• Derivative contracts on unleaded gasoline to hedge butylene inventory builds at the El Dorado Refinery. 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).
• 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).
• 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, 2003, the Company had the following open derivative contracts which were not being accounted for as hedges.
• Derivative contracts on 440,000 barrels of crude oil to fix the heavy crude differential to the Nymexlight crude oil contract price for a portion of the purchases committed to under the Company’s crude oil supply agreement with Baytex. These positions fix the heavy crude oil differential on 50% of January 2004 deliveries, 75% of February 2004 deliveries, 65% of March 2004 deliveries, 33% of April 2004 deliveries and 25% of May 2004 deliveries. As of December 31, 2003, the Company had realized losses of $16,000 and unrealized losses of $401,000 related to these contracts which are reflected in “Other revenues” on the consolidated statements of income.
During 2003, 2002 and 2001, the Company had the following derivatives which were appropriately designated and accounted for as hedges:
• Crude Purchases. At December 31, 2003, the Company had no open derivative contracts to hedge against price declines on foreign crude oil purchases. In January 2003, the Company had derivative contracts on 200,000 barrels of crude oil to hedge Canadian crude costs for the Cheyenne Refinery which were accounted as fair value hedges. A $13,000 loss was realized on these positions, of which $31,000 increased crude costs and $18,000 increased income which was reflected in “Other revenues” in the consolidated statements of income for the ineffective portion of this hedge. In May 2003, the Company closed out derivative contracts it had purchased in April 2003 on 675,000 barrels of crude oil to hedge two foreign crude cargos purchased for the El Dorado Refinery. A $13,000 gain was realized on these positions, of which $11,000 reduced crude costs and $2,000 was reflected in “Other revenues” for the ineffective portion of these hedges.
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.
• Natural Gas Collars. Price swaps on natural gas for the purpose of hedging against natural gas price increases for February and March 2003 for approximately 100% of the El Dorado Refinery’s anticipated usage and which are accounted for as cash flow hedges. The February group of contracts to hedge natural gas costs were for 700,000 MMBTU and expired with no gain or loss. The March group of contracts to hedge natural gas totaled 720,000 MMBTU and the Company realized a $1.7 million gain which reduced refining operating expenses in March.
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. As of December 31, 2002, the realized gains or losses ($434,000, net) were included in “Refinery operating expenses, excluding depreciation”.
At December 31, 2003, the Company had no open derivative contracts which are being accounted for as hedges.
On January 19, 2004, the Company reported a fire in the furnaces of the coking unit at its Cheyenne Refinery. Fortunately, no serious injuries occurred as a result of the fire. The coker was out of service for approximately one month.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of Frontier Oil Corporation:
We have audited the accompanying consolidated balance sheets of Frontier Oil Corporation and subsidiaries as of December 31, 2003 and 2002, and the related consolidated statements of income, changes in shareholders’ equity and comprehensive income, and cash flows for the years 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 audits. The consolidated financial statements of Frontier Oil Corporation for the year ended December 31, 2001 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 audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Frontier Oil Corporation and subsidiaries as of December 31, 2003 and 2002 and the results of their operations and their cash flows for the years then ended, in conformity with accounting principles generally accepted in the United States of America.
DELOITTE & TOUCHE LLP Houston, Texas February 19, 2004
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
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
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 |