MANAGEMENT’SDISCUSSION AND ANALYSIS

General

        The terms“Frontier” and “we” refer to Frontier Oil Corporation andits subsidiaries. Frontier operates refineries (the “Refineries”) inCheyenne, Wyoming and El Dorado, Kansas with a combined crude oil capacity of156,000 barrels per day (“bpd”). We focus our marketing efforts in theRocky Mountain and Plains States regions of the United States. We purchase thecrude oil to be refined and market the refined petroleum products produced,including various grades of gasoline, diesel fuel, jet fuel, asphalt and otherby-products. 

Results ofOperations

        To assist in understandingour operating results, please refer to the operating data at the end of thisanalysis, which provides key operating information for our combined Refineries.Data for each Refinery is included in our annual report on Form 10-K, ourquarterly reports on Form 10-Q and on our web site address:http://www.frontieroil.com. We make our web site content available forinformational purposes only. The web site should not be relied upon forinvestment purposes. We make available on this web site under “InvestorRelations”, free of charge, our annual reports on Form 10-K, quarterlyreports on Form 10-Q, current reports on Form 8-K and amendments to thosereports as soon as reasonably practicable after we electronically file thosematerials with, or furnish those materials to, the SEC. 

        The following are threesignificant indicators of our profitability reflected in the operating data ofthis analysis referred to above: 

**1)  gasoline and diesel crack spreads:**  the average  non-oxygenated  gasoline and diesel net sales prices we receivefor 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,  Oklahomaand 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 WestTexas sour crude oil priced at Midland, Texas.

        Other significant factorsthat influence our results are refinery utilization, crude oil price trends,asphalt and by-product margins and refinery operating expenses (includingnatural gas prices and turnaround, or planned maintenance, activity). 

**2003 Compared with 2002**

        **Overview of Results.**  We had net income for theyear 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. Our2003 net income was negatively impacted by the termination of the HollyCorporation (“Holly”) merger. On March 31, 2003, we announced that wehad entered into an agreement with Holly pursuant to which the two companieswould merge. On August 20, 2003, we announced that Holly had advised us thatthey 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 redeemedthe Senior Notes that had been issued to finance the cash portion of the Hollymerger. Merger termination and legal costs and merger termination financingcosts, 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 anddid not include bank facility charges related to the merger. 

        Despite the negative impactof 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 improvingoperating income were improved gasoline and diesel crack spreads, increases inthe light/heavy spread and WTI/WTS spread and improved yields and sales from ourCheyenne Refinery. Yields and sales were down in 2003 at our El Dorado Refinerydue to a major crude unit turnaround, or planned maintenance, in the spring of2003. Results were also negatively impacted by higher refinery operatingexpenses primarily due to higher natural gas costs at both Refineries. 

**        Specific Variances.**  Refined product revenuesincreased $356.9 million, or 20%, from $1.8 billion to $2.2 billion for the yearended December 31, 2003 compared to 2002 due to increased sales prices resultingfrom higher crude oil prices and higher gasoline and diesel crack spreads onnearly flat sales volumes. Our gasoline and diesel crack spreads averaged $7.00per barrel and $5.05 per barrel, respectively, in 2003, compared to $5.88 perbarrel and $3.97 per barrel, respectively, in 2002. Average gasoline pricesincreased from $33.08 per sales barrel in 2002 to $39.72 per sales barrel in2003. Sales volumes of gasoline decreased 2,147 barrels per day from 91,989barrels per day during 2002 to 89,842 barrels per day in 2003. Average dieseland jet fuel prices increased from $30.35 per sales barrel in 2002 to $36.91 persales barrel during 2003. Sales volumes of diesel and jet fuel increased 228barrels per day from 53,378 barrels per day during 2002 to 53,606 barrels perday in 2003. Total product sales volumes overall decreased less than 1% from166,532 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 obtainedthrough the distilling of crude oil and the operations of other refinery processunits. Yields of gasoline decreased 1,196 barrels per day, or 1%, from 84,645barrels per day in 2002 to 83,449 barrels per day in 2003 and yields of dieseland jet fuel decreased 280 barrels per day, or less than 1%, from 53,436 barrelsper day in 2002 compared to 53,156 barrels per day in 2003. Sales and yieldvolumes for 2003 for the El Dorado Refinery were lower than during 2002primarily because of the crude unit turnaround at the El Dorado Refinery whichcommenced on March 18, 2003 and was completed on March 30, 2003. Upon completionof the turnaround, the El Dorado Refinery operations were very strong theremainder of the year. The Cheyenne Refinery operations were very strong allyear resulting in both increased charge and yield volumes sufficient to offsetthe reduced charges and yields at the El Dorado Refinery to result in anaggregate 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 fromfutures trading in 2003 compared to net income of $108,000 in 2002 (see“Price Risk Management Activities”), offset by increased processingincome from our Cheyenne Refinery coker. 

        Raw material, freight andother costs include crude oil and other raw materials utilized in the refiningprocess, purchased products and blendstocks, freight costs for FOB destinationsales, as well as the impact of changes in inventory under first-in, first-out(“FIFO”) inventory accounting. The average price of crude oil wassubstantially higher in 2003 than in 2002. The average price of WTI crude oilpriced at Cushing, Oklahoma was $31.89 per barrel in 2003 compared to $26.17 perbarrel 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 anda smaller amount of inventory gains from rising prices during 2003 than during2002, 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 aresult of inventory gains of approximately $4.4 million after tax ($7.2 millionpretax, comprised of $3.0 million at the Cheyenne Refinery and $4.2 million atthe El Dorado Refinery) because of the increasing crude oil prices. The price ofcrude oil on the New York Mercantile Exchange was very volatile in 2003. Thecrude price began the year at $31.20 per barrel, reached a high of $37.83 perbarrel in March, dropped to a low of $25.24 per barrel in April and closed theyear at $32.52 per barrel. For the year ended December 31, 2002, we realized adecrease in raw material, freight and other costs as a result of inventory gainsof 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 DoradoRefinery) because of increasing crude oil prices. The price of crude oil on theNew York Mercantile Exchange increased during 2002 from $19.84 per barrel to$31.20 per barrel by year-end. 

        The Cheyenne Refinery rawmaterial, freight and other costs of $29.40 per sales barrel in 2003 increasedfrom $25.18 per sales barrel in 2002 due to higher crude oil prices and lessinventory gains, offset by an improved light/heavy spread. The heavy crude oilutilization rate at the Cheyenne Refinery expressed as a percentage of the totalcrude oil charge decreased to 88% in 2003 from 90% in 2002 as we utilizedslightly more light crude oil. The light/heavy spread for the Cheyenne Refineryaveraged $7.10 per barrel in 2003 compared to $4.77 per barrel in 2002. 

        The El Dorado Refinery rawmaterial, freight and other costs of $31.43 per sales barrel in 2003 increasedfrom $25.93 per sales barrel in 2002 due to higher average crude oil prices andless inventory gains, offset by an improved WTI/WTS spread. The WTI/WTS crudespread increased from an average of $1.36 per barrel in 2002 to $2.68 per barrelin 2003. 

        Refinery operatingexpenses, excluding depreciation, includes both the variable costs (includingenergy and utilities) and the fixed costs (salaries, taxes, maintenance costsand other) of operating the Refineries. Refinery operating expenses, excludingdepreciation, were $200.4 million, or $3.31 per sales barrel, in 2003 comparedto $178.3 million, or $2.93 per sales barrel, in 2002. 

        The Cheyenne Refineryoperating expense, excluding depreciation, was $61.4 million, or $3.12 per salesbarrel, in 2003 compared to $54.7 million, or $3.02 per sales barrel, in 2002primarily due to higher natural gas and other utility costs ($2.6 million),salaries ($2.5 million), consulting and legal ($800,000) and additives andchemicals ($700,000). 

        The El Dorado Refineryoperating expense, excluding depreciation, was $139.0 million, or $3.41 persales 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 ($3.8million), chemicals ($1.2 million) and excess turnaround costs ($2.3 million).The per barrel refinery operating expense variance was exacerbated by fewersales volumes in 2003 than in 2002. 

        Selling and generalexpenses, excluding depreciation, increased $2.3 million, or 13%, for the yearended December 31, 2003 because of $1.8 million in legal costs related to theBeverly Hills lawsuits, increases in other legal costs and salaries, and travel,engineering and other consulting services related to evaluating potentialacquisitions and possible refinery improvements. 

        Merger termination andlegal costs of $8.7 million for the year ended December 31, 2003 includetransaction and ongoing legal costs (on an accrual basis) associated with thetermination of the anticipated merger and resulting lawsuit with Holly. 

        Depreciation increased $1.5million, or 5%, for the year ended December 31, 2003 as compared to 2002 becauseof increases in capital investment at our Refineries. 

        The interest expense andother financing costs (excluding costs relating to the 8% Senior Notes issuedand redeemed in connection with the terminated Holly merger) of $28.7 millionfor 2003 increased $1.1 million from $27.6 million in 2002 primarily due to thepremium of $1.2 million paid upon redemption of our 9-1/8% Senior Notes in December2003. Average debt outstanding (excluding the 8% Senior Notes) decreased to $236million for the year ended December 31, 2003 from $246 million for the yearended December 31, 2002. 

        Interest income (excludinginterest income earned on the 8% Senior Notes escrow account) decreased $693,000from $1.8 million in 2002 to $1.1 million in 2003 due to less cash available toinvest and lower interest rates. 

        The 2003 merger financingtermination costs, net were $18.0 million and included interest expense, issuediscount, financing issue costs and the 1% redemption premium, net of $752,000interest income earned on the escrow account related to the $220.0 millionprincipal 8% Senior Notes. These costs did not include bank facility chargesrelated to the merger. 

        The income tax provisionfor the year ended December 31, 2003 was $3.0 million on pretax income of $6.2million (or 47.8%) due to one-time adjustments for permanent book versus taxdifferences related to 2003 and 2002 expenses and an increase of $280,000 in theincome tax provision for 2003 resulting from a true-up of the 2002 taxprovision. Our current estimated effective tax rate is 38.26%. Our effectiveincome tax rate for the book provision of income taxes for the year endedDecember 31, 2002, of 50.8% was also greater than our estimated statutory ratedue to one-time adjustments for permanent book versus tax differences and anincrease in the state deferred income tax provision due to a revised estimate ofstate apportionment factors based on actual 2002 allocation factor data. An$83,000 Canadian income tax payment for an audit settlement related to ourCanadian oil and gas operations (sold in June 1997) also increased our incometax provision in 2002. 

**2002 Compared with 2001**

        **Overview of Results.**  We had net income for theyear 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 yieldsand a reduction to our per sales barrel refinery operating expenses, excludingdepreciation, the decrease in operating income was primarily caused bysignificant declines in gasoline and diesel crack spreads and decreases in boththe light/heavy crude spread and the WTI/WTS crude spread. Supply and demandimbalances led to exceptional light product margins during two periods of 2001and as a result, our margins for both gasoline and diesel fuel greatly exceededthe historic five-year averages. In 2002, we struggled through some of thepoorest conditions our industry has ever faced. While gasoline underperformedcompared to historic five-year averages, the weakness was not as pronounced asthe weakness in the diesel and jet markets. Our crude spreads were depressed in2002 because of general tightness of heavy crude oil supplies in our markets andthe global shortage of heavy and sour crude oils due to OPEC cutbacks and thedisruptions from Venezuela. 

        In areas directlycontrollable by us, we continued to operate reliably while increasing refinerycharges and yields and reducing our operating costs per sales barrel. In late2001, we expanded the Cheyenne Refinery permitted annual crude capacity to46,000 bpd from 41,000 bpd. This expansion contributed significantly to theincreased charge and yield in 2002. Our refinery operating expenses, excludingdepreciation, declined from $3.27 per sales barrel in 2001 to $2.93 per salesbarrel in 2002. 

        **Specific Variances.**  Refined product revenuesdecreased $76.6 million, or 4%, for the year ended December 31, 2002 compared to2001 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 perbarrel, 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 salesbarrel in 2001 to $33.08 per sales barrel in 2002. Sales volumes of gasolineincreased 8,252 barrels per day from 83,737 barrels per day during 2001 to91,989 barrels per day in 2002. Average diesel and jet fuel prices decreasedfrom $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 51,539barrels per day during 2001 to 53,378 barrels per day in 2002. Total productsales volumes overall increased 5% from 159,100 barrels per day in 2001 to166,532 barrels per day in 2002. 

        Yields of gasolineincreased 6,519 barrels per day, or 8%, from 78,126 barrels per day in 2001 to84,645 barrels per day in 2002 while yields of diesel and jet fuel increased2,226 barrels per day, or 4%, from 51,210 barrels per day in 2001 compared to53,436 barrels per day in 2002. El Dorado gasoline yields improved in 2002 dueto 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 themajor turnaround, or planned maintenance, at the El Dorado Refinery whichcommenced in mid-March 2001 and was completed in mid-April 2001. Despite a majorturnaround at the Cheyenne Refinery during March and April 2002, refinery yieldsand sales for the year ended December 31, 2002 increased from the same period in2001 due to the benefit of the increased crude capacity from 41,000 barrels perday to 46,000 barrels per day which was completed toward the end of 2001 and inearly 2002. The Cheyenne Refinery throughput and resulting yields in the earlypart 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, 2002compared to a loss of $832,000 for the same period in 2001 due to $108,000 infutures trading net gains in 2002 compared to $2.0 million futures trading netlosses in 2001 (see “Price Risk Management Activities”). 

        Raw material, freight andother costs increased $70.8 million, or $.02 per sales barrel, from 2001 due tohigher average crude oil prices offset by inventory gains from rising pricesduring the year. For the year ended December 31, 2002, we realized a decrease inraw material, freight and other costs as a result of inventory gains ofapproximately $19.0 million after tax ($30.6 million pretax, comprised of $10.7million 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 NewYork Mercantile Exchange increased through 2002 from $19.84 per barrel to $31.20per barrel. For the year ended December 31, 2001, we realized an increase in rawmaterial, freight and other costs as a result of inventory losses ofapproximately $28.9 million after tax ($41.4 million pretax, comprised of $8.9million at the Cheyenne Refinery and $32.5 million at the El Dorado Refinery)because of decreasing crude oil prices. 

        The Cheyenne Refinery rawmaterial, freight and other costs of $25.18 per sales barrel in 2002 increasedfrom $24.85 per sales barrel in 2001 due to higher crude oil prices and areduced light/heavy spread offset by a positive inventory valuation impact as aresult of increasing crude oil and product prices. The heavy crude oilutilization rate at the Cheyenne Refinery expressed as a percentage of the totalcrude 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 depressedlight/heavy crude oil spread. The light/heavy spread for the Cheyenne Refineryaveraged $4.77 per barrel in 2002 compared to $7.62 per barrel in 2001. 

        The El Dorado Refinery rawmaterial, freight and other costs of $25.93 per sales barrel in 2002 decreasedfrom $26.01 per sales barrel in 2001 due to slightly higher average crude oilprices more than offset by the inventory gains from rising prices during theyear. The WTI/WTS crude spread decreased from an average of $3.10 per barrel in2001 to $1.36 per barrel in 2002. 

        Refinery operating expense,excluding depreciation, was $178.3 million, or $2.93 per sales barrel, in 2002compared to $189.9 million, or $3.27 per sales barrel, in 2001. The CheyenneRefinery operating expense, excluding depreciation, per sales barrel decreased$.37 to $3.02 per sales barrel in 2002 due to more sales volumes. The El DoradoRefinery operating expense, excluding depreciation, was $2.90 per sales barrelin 2002, decreasing from $3.22 per sales barrel in 2001 due to lower natural gascosts and more sales volumes. 

        Selling and generalexpenses, excluding depreciation, increased $40,000 for the year ended December31, 2002 because of an impairment loss on an asset held for sale and increasedengineering consulting services and travel costs offset by decreased salariesand benefits from the non-accrual of bonuses in 2002. 

        Depreciation increased $2.3million, or 9%, for the year ended December 31, 2002 as compared to 2001 becauseof increases in capital investment. 

        The interest expensedecrease of $3.5 million, or 11%, for the year ended December 31, 2002 wasattributable to repurchases of 9-1/8% Senior Notes and 113⁄4% Senior Notesduring 2001, less interest expense on the revolving credit facility due to lowerborrowing rates and the capitalization of interest in 2002. Average debtdecreased to $246.1 million for the year ended December 31, 2002 from $255.3million for the year ended December 31, 2001. 

        Interest income decreasedby $970,000, or 35%, for the year ended December 31, 2002 compared to 2001 dueto lower available interest rates on investments offset by more cash availableto invest. 

        Our effective income taxrate 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 differencesand an increase in the state deferred income tax provision due to a revisedestimate of state apportionment factors based on actual 2002 allocation factordata. An $83,000 Canadian income tax payment for an audit settlement related toour Canadian oil and gas operations (sold in June 1997) also increased ourincome tax provision in 2002. 

LIQUIDITY ANDCAPITAL RESOURCES

        Net cash used in operatingactivities was $6.0 million for the year ended December 31, 2003 while $50.8million cash was provided by operating activities for the year ended December31, 2002. The most significant impact on cash provided by operating activitieswas the change in trade and crude payables. In 2002, crude payables providedcash by increasing $55.6 million during the year due to dramatically increasingcrude prices throughout the year, while in 2003, crude prices were relativelyflat between the beginning and the end of the year. 

        The other most significantimpact on the decrease in cash provided by operating activities were the October2003 payments totaling approximately $26.6 million made to purchase an insurancepolicy related to the Beverly Hills Lawsuits. (See Note 8 in the “Notes toConsolidated 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 theinsurance company of a Commutation Account of approximately $19.6 million (fromwhich the insurance company will fund the first costs under the policyincluding, but not limited to, the costs of defense of the claims), and $772,500paid to the State of California for surplus lines tax on the premium. Thisinsurance premium and related expenses are in the prepaid insurance in thelong-term asset portion of our balance sheet. See Note 2 in the“Significant Accounting Policies” in the “Notes to ConsolidatedFinancial Statements” for a discussion of the accounting treatment on thispremium. Offsetting the negative cash impacts was a positive variance from 2002to 2003 resulting from trade and other receivables increasing (and utilizingcash) $4.6 million in 2003 compared to increasing (and utilizing cash) $22.2million in 2002. Working capital changes used a total of $25.9 million of cashflows in 2003 while providing $17.8 million of cash flows in 2002, the majorcomponent being the change in trade and crude payables discussed above. 

        At December 31, 2003, wehad $64.5 million of cash and cash equivalents, working capital of $38.6 millionand a $70.0 million borrowing base availability for additional borrowings underour revolving credit facility. 

        On April 17, 2003, wereceived the net proceeds from a private placement of $220 million of 8% seniornotes (“Senior Notes”) due April 15, 2013. The net proceeds of theSenior Notes were to be used, together with other available funds, to financethe cash portion of the Holly merger, to pay related fees and expenses and torefinance or pay off existing Holly indebtedness. The Senior Notes were issuedat 99.156% of principal amount and were issued by Frontier Escrow Corporation, anewly formed, wholly-owned, direct subsidiary of Frontier that was createdsolely to issue the Senior Notes and to merge with and into Frontier OilCorporation upon consummation of the Holly merger. Pending consummation of theHolly merger, the net proceeds of the offering, along with other amountscontributed by us, were placed in an escrow account. We were required, pursuantto terms of the indenture, to redeem the 8% Senior Notes if the merger withHolly was not consummated by October 31, 2003. Because of Holly’srepudiation 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 SeniorNotes plus accrued interest. Financing costs, net of interest income earned onthe escrow account, related to the Senior Notes were $18.0 million during theyear ended December 31, 2003 and included interest expense, issue discount,financing issue costs and redemption premium. These costs did not include bankfacility charges related to the merger. 

        In December 2003, we calledour 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. Ouronly remaining outstanding long-term debt at December 31, 2003 is $168.7 million($170.4 million principal, net of $1.7 million unamortized discount) of113⁄4% Senior Notes, issued in 1999 and due in 2009. 

        In November 2003, the Boardof Directors increased the number of shares under a previously approved stockrepurchase program from six million shares to eight million shares of commonstock. Through 2000, 2,491,096 shares of common stock were purchased, of which2,345,900 shares were purchased on the open market, for approximately $14.9million. In 2001, 1,850,970 shares were purchased for approximately $22.6million, of which 1,774,400 were purchased on the open market. In 2002, wecompleted the purchase, committed to at December 31, 2001, of another 25,300shares for $416,000. We did not initiate any additional purchases of commonstock under the stock repurchase program in 2003 nor in 2002. Through December2003, 4,367,366 shares of common stock had been purchased under the stockrepurchase programs. We also acquired 24,825 and 19,041 shares of treasury stockin 2003 and 2002, respectively, which was stock surrendered by employees tocover their withholding taxes on shares of restricted stock which vested duringthose years. During 2003, we also increased our treasury stock by another 88,638shares obtained directly from employees in cashless stock option exercises. 

        Capital expenditures for2003 were $33.7 million, which included $15 million for the low sulfur gasolineproject (now completed and in service) at our Cheyenne Refinery. Sustaining andother capital expenditures of approximately $39 million are planned for 2004.These 2004 capital expenditures include $17.5 million for the El DoradoRefinery, $20.5 million at the Cheyenne Refinery, and another $1.0 million ofcapital for expenditures in our Denver and Houston offices and asphalt terminalin Nebraska and for our share of crude pipeline projects. The $17.5 million ofcapital expenditures for our El Dorado Refinery includes operational, payout,safety, administrative, environmental and optimization projects. The $20.5million of capital expenditures for our Cheyenne Refinery includes operational,environmental, safety, administrative and payout projects as well asapproximately $5.3 million remaining cash costs on the completed low sulfurgasoline project. We are still evaluating how we will comply with the upcomingultra low sulfur diesel requirements at our Refineries, which will requireadditional capital expenditures in 2004 through 2006. The total minimum capitalrequired to comply with the regulations is estimated to be $13 million at theCheyenne Refinery and between $60 million and $90 million at the El DoradoRefinery. The estimated timing of the ultra low sulfur diesel projects is $2million at the Cheyenne Refinery and $25 million at the El Dorado Refinery in2004, the majority of which is in addition to the capital discussed above. Theremaining costs for the ultra low sulfur diesel projects at both refinerieswould be spent in 2005 and 2006. For the El Dorado Refinery we are consideringan alternate project to meet our ultra low sulfur diesel requirements, whichwould also generate improved gasoline yields and thus additional profits in thefuture. This alternative would increase the estimated total El Dorado Refinerycapital 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 in2005 and 2006. The decision on which project to pursue is expected to be madeduring fiscal 2004. It may be necessary for us to obtain external financing in2005 or 2006 to fund these required expenditures. 

        As of December 31, 2003, wehave $216.2 million principal ($170.4 million long-term debt and $45.8 millionunder our revolving credit facility) of total consolidated debt andshareholders’ equity of $169.3 million. Operating cash flows are affectedby crude oil and refined product prices and other risks as discussed in the“Market Risks” section. 

        Under the provisions of thepurchase agreement for our El Dorado Refinery, we have made, or may be requiredto make, contingent earn-out payments for each of the years 2000 through 2007equal to one-half of the excess over $60 million per year of the El DoradoRefinery’s revenues less its material costs and operating costs, other thandepreciation. The total amount of these contingent payments is capped at $40million, with an annual cap of $7.5 million. Any contingency payment will berecorded when determinable. Such contingency payments, if any, will be recordedas additional acquisition cost. No contingent earn-out payment was requiredbased on 2003, 2002 or 2000 results. A contingent earn-out payment of $7.5million was required based on 2001 results and was paid in early 2002. 

        On May 29, 2003, weannounced that we had entered into an amended and restated revolving creditfacility with a group of banks led by Union Bank of California and BNP Paribas.Commitments under the working capital facility are $175 million, subject toborrowing base amounts, with cash advances limited to a maximum of $125 million.Any unutilized capacity after cash borrowings is available for letters ofcredit. The facility includes reduced interest rate spreads and letter of creditfees. In addition, a new financial covenant package is based on consolidatedparent financials (as opposed to subsidiary level financials) and facilitatesintra-company funds flows. At December 31, 2003, we had borrowings of $45.8million and outstanding letters of credit of $26.2 million under our revolvingcredit facility, and approximately $70.0 million borrowing base availabilityremaining for additional borrowings under our revolving credit facility. We werein compliance with the financial covenants as of December 31, 2003. 

        Our Board of Directorsdeclared quarterly cash dividends in December 2002, March 2003, June 2003 andSeptember 2003 of $.05 per share, which were paid in January 2003, April 2003,July 2003 and October 2003, respectively. The total dividend payments in 2003were $5.2 million. In addition, our Board of Directors declared a quarterly cashdividend of $.05 per share in December 2003, which was paid on January 12, 2004to shareholders of record on December 26, 2003. The total cash required for thisdividend was approximately $1.3 million and was accrued at year-end. 

CONTRACTUALCASH OBLIGATIONS

        The table below lists thecontractual cash obligations we have by period. These items include ourlong-term debt based on their maturity dates, our operating lease commitments,purchase obligations and other long-term liabilities. Our operating leasesinclude building, equipment, aircraft and vehicle leases, which expire from 2004through 2008, as well as an operating sublease for the use of the cogenerationfacility at our El Dorado Refinery. The non-cancelable sublease, entered into inconnection with the acquisition of our El Dorado Refinery in 1999, expires in2016 with an option that allows us to renew the sublease for an additional eightyears. Purchase obligations include agreements to purchase goods or servicesthat are enforceable and legally binding and that specify terms, including fixedor minimum quantities to be purchased, fixed, minimum or variable priceprovisions, and the approximate timing of the transaction. Purchase obligationsexclude agreements that are cancelable without penalty. We have a five-yearcrude oil supply agreement, which began in 2003, with Baytex Marketing Ltd.(“Baytex”), a Canadian crude oil producer. This agreement provides forus to purchase 20,000 barrels per day of a Lloydminster crude oil blend, a heavyCanadian crude, at a price equal to 71% of the simple average of the near monthsettlement prices of the NYMEX light sweet crude oil contracts during the monthof delivery, plus the cost of transportation based on the Express Pipelinetariff, less $0.25 per barrel. Included in transportation, terminalling andstorage obligations below are our contractual obligations for crude oil pipelinecapacity on the Express Pipeline, net of our assignment to Baytex, as discussedbelow. We have two contracts that obligate us for crude oil pipeline capacityinto 2015 on the Express Pipeline from Hardisty, Alberta to Guernsey, Wyomingfrom 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 andfor an average 13,800 barrels per day over that 15-year period. We were allowedto assign a portion of our capacity in earlier years for additional capacity inlater years with this first contract. In December 2003, we entered into anexpansion capacity agreement on the Express Pipeline for an additional 10,000barrels per day of crude oil starting in April 2005 through 2015. Our remainingExpress 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 23,800barrels per day in 2006 through early 2012, and then reducing to 10,000 barrelsper day through 2015. Our crude oil supply agreement with Baytex includes anassignment of a portion of our pipeline capacity obligation to them. The amountsshown below for transportation, terminalling and storage contractual obligationsare net of $31.1 million, the approximate cost of the pipeline capacity assignedto Baytex for the initial term of that agreement. See Note 8 “Commitmentsand Contingencies” in the “Notes to Consolidated FinancialStatements.” 

**Contractual Cash Obligations**

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                                                                       Payments Due by Period
                                         --------------------------------------------------------------------------------------
(in thousands)                                Total       Within 1 Year  Within 2-3 Years   Within 4-5 Years  After 5 Years
                                         --------------------------------------------------------------------------------------
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
-------------------------------------------------------------------------------------------------------------------------------
```

OFF-BALANCESHEET ARRANGEMENTS

        We only have one interestin an unconsolidated entity (See Note 1 “Nature of Operations” in the“Notes to Consolidated Financial Statements”). This entity does notparticipate in any transactions, agreements, or other contractual arrangementswhich would result in any off-balance sheet liabilities or other arrangements tous. 

ENVIRONMENTAL

        Our refining and marketingoperations are subject to a variety of federal, state and local health andenvironmental laws and regulations governing product specifications, thedischarge 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 aresubject to revocation, modification and renewal. Governmental authorities havethe power to enforce compliance with these regulations and permits, andviolators are subject to injunctions, civil fines and even criminal penalties.We believe that each of our Refineries is in substantial overall compliance withexisting environmental laws, regulations and permits. 

        This discussion includesmajor environmental areas that impact our operations. Refer to Note 8“Commitments and Contingencies” in the “Notes to ConsolidatedFinancial Statements” for further environmental information. 

        Frontier’s operationsand many of the products manufactured are specifically subject to certainrequirements of the Clean Air Act (“CAA”) and related state and localregulations. The 1990 amendments to the CAA contain provisions that will requirecapital expenditures for the installation of certain air pollution controldevices at Frontier’s Refineries during the next several years. Subsequentrule making authorized by the CAA or similar laws or new agency interpretationsof existing rules may necessitate additional expenditures in future years. TheEnvironmental Protection Agency (“EPA”) recently embarked on aPetroleum Refining Initiative (“Initiative”) alleging industry-widenoncompliance with certain longstanding rules. The Initiative has resulted inmany refiners entering into consent decrees typically requiring substantialexpenditures for penalties and additional pollution control equipment. Frontierhas been contacted by the EPA and invited to meet with them to hear more aboutthe Initiative. At this time, Frontier does not know how or if the Initiativewill affect us. We have, however, in recognition of the EPA’sreinterpretation of certain regulatory requirements associated with theInitiative, determined that over the next three years, expenditures totalingapproximately $10 million may be necessary to further reduce emissions from theRefineries’ flare systems. This determination resulted from internalcompliance audits initiated by us and subsequently shared with the correspondingstate regulatory agencies under the provisions of state audit privilegestatutes. 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 decreeswith Frontier to settle these and certain other compliance matters. Becauseother refineries will be required to make similar expenditures, Frontier doesnot expect such expenditures to have a material adverse impact on ourcompetitive position. 

        The CAA authorizes the EPAto require modifications in the formulation of the refined transportation fuelproducts manufactured in order to limit the emissions associated with theirfinal use. On December 21, 1999, the EPA promulgated national regulationslimiting the amount of sulfur that is to be allowed in gasoline. The EPAbelieves such limits are necessary to protect new automobile emission controlsystems that may be inhibited by sulfur in the fuel. The new regulations requirethe phase-in of gasoline sulfur standards beginning in 2004 and continuingthrough 2008, with special provisions for refiners serving those Western statesexhibiting lesser air quality problems and for small business refiners, such asFrontier. Since Frontier qualifies as a small business refiner by having 1,500or fewer employees and a capacity of less than 155,000 barrels per day duringthe specified pre-2001 baseline years, the Cheyenne and El Dorado Refineries maycomply with an interim gasoline sulfur standard in 2004 that is based onhistoric gasoline sulfur levels rather than having to meet the much stricterstandard that will be applied to the general industry. Depending on the deadlinewe choose to comply with the new diesel sulfur limit (see discussion below), wewill then have between four and seven additional years to reduce our gasolinesulfur content of our Refineries to the national standard. The total capitalexpenditures estimated, as of December 31, 2003, to achieve the final gasolinesulfur standard are approximately $35 million at the Cheyenne Refinery andapproximately $44 million at the El Dorado Refinery. The $35 million at Cheyenneincludes over $28 million already incurred (on an accrual basis) throughDecember 31, 2003 to meet the interim standard in 2004. 

        The EPA recentlypromulgated regulations that will limit the sulfur content of highway dieselfuel beginning in 2006 to 15 parts per million (“ppm”). The currentstandard is 500 ppm. As a small business refiner, Frontier may choose to complywith 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 keepour original gasoline sulfur program timing. Although still under deliberation,it is now likely that Frontier will choose to comply with the 15 ppm highwaydiesel sulfur standard by June 2006 and extend our small refiner interimgasoline sulfur standards at each of our facilities until 2011. To satisfy aregulatory requirement necessary for the preservation of this compliance optionwe have submitted an application for a highway diesel volumetric baseline to theEPA. As of December 31, 2003, minimum capital costs for diesel desulfurizationare estimated to be approximately $13 million for the Cheyenne Refinery andbetween $60 million and $90 million for the El Dorado Refinery. The final costfor the El Dorado Refinery will be dependent on whether we choose to meet onlythe ultra low sulfur diesel requirement or decide on an alternative projectwhich would also result in increased future profitability. This alternativeproject would increase the total capital cost for the El Dorado Refinery fromthe $60 to $90 million range up to a total cost of $160 million. See“Liquidity and Capital Resources” on page 14 for further discussion onthe range of costs for the El Dorado Refinery. 

        On April 15, 2003, the EPAproposed regulations to reduce emissions from diesel engines used in off-roadactivities such as agriculture, mining and railroads and also to limit theallowable amount of sulfur in the diesel fuel used in those engines. Ifpromulgated, the EPA’s proposal would require a reduction of sulfur inoff-road diesel fuel by June 1, 2007 from the currently allowable 5,000 ppm to500 ppm and by June 1, 2010 further limit the concentration of sulfur in dieselfuel used in off-road applications other than railroads and marine engines to 15ppm. The EPA is also proposing to allow small business refiners, such asFrontier, to continue to produce off-road diesel at the current sulfur limit of5,000 ppm through May 31, 2010 and to meet a limit of 500 ppm sulfur from June1, 2010 until May 31, 2014. Frontier has historically provided a minor amount ofdiesel fuel to the off-road markets from both of our Refineries. Included inthis April 15, 2003 EPA proposal, are regulations that will, in part, cause asmall refiner, such as Frontier, to lose small refiner status upon merger withor acquisition of another refining entity if the post-merger or acquisitionrefining capacity exceeds 155,000 barrels per day. The small refiner losing suchstatus would be allowed two years from the date of acquisition or merger tocomply with the non-small refiner clean fuel standards. We are monitoring theseregulatory developments and are evaluating their compliance options. The coststhat we will eventually incur to comply with these regulations, when final, arecurrently unknown. 

        The front range of Colorado(including the Denver metro area) is a major market for the productsmanufactured by our Refineries. Until the summer of 2003, this area had been incompliance with all of the EPA’s National Ambient Air Quality Standards(“NAAQS”) for ozone for the summer seasons, and in recognition of thatcompliance had been granted annual waivers from federal gasoline vapor pressurestandards that pre-date that compliance. The combination of a new, lower NAAQSfor ozone and unusual summertime meteorological conditions in the area resultedin numerous and unforeseen instances where the new standard was exceeded. TheState of Colorado has recently undertaken an effort to develop and implementcontrols necessary to ensure the area will regain compliance with the NAAQS forozone during the three-year averaging period of 2005 through 2007. Thesecontrols will likely include a requirement to reduce the current allowablesummertime gasoline vapor pressure from 9.0 pounds to either 8.1 pounds or thecurrent federal standard of 7.8 pounds. These controls will most likely beinitiated for the gasoline to be sold in the area beginning in May of 2005. Weare currently evaluating what modifications may be required to the CheyenneRefinery 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 tomeet the anticipated new standard. 

CRITICALACCOUNTING POLICIES

               **Turnarounds.**   The costs for turnarounds  (scheduled and required  shutdowns of refinery  operating units forsignificant  overhaul and  refurbishment) are ratably accrued over the period from the prior turnaround to the nextscheduled  turnaround.  Since utilizing this policy relies on estimated costs for the next turnaround,  adjustmentsoccur as the estimate  changes or even when the  turnaround is in progress  should more or less  extensive  work benecessary  than was  anticipated.  These  accruals are included in our  consolidated  balance  sheet in the accruedturnaround cost and long-term accrued  turnaround cost. The turnaround  accrual,  any turnaround costs in excess ofaccrual  incurred at the time of  turnaround,  or  reductions  of expenses  when the actual costs are less than theestimate are included in Refinery  operating  expenses,  excluding  depreciation in our consolidated  statements ofincome. Turnaround costs include contract services, materials and rental equipment.

        In 2001, the AmericanInstitute of Certified Public Accountants (“AICPA”) issued an ExposureDraft for a Proposed Statement of Position (“SOP”), “Accountingfor Certain Costs and Activities Related to Property, Plant and Equipment”.At its September 2003 meeting, the Accounting Standards Executive Committee ofthe AICPA approved the SOP for issuance and it is scheduled to be addressed inApril 2004 by the Financial Accounting Standards Board (“FASB”). Ifcleared by the FASB, the SOP will become a generally accepted accountingprinciple (“GAAP”) and will become effective for fiscal yearsbeginning after December 15, 2004, with early adoption encouraged. The SOP willrequire us to account for our property, plant and equipment on a component levelwith each component being recorded at cost and depreciated over its expecteduseful life. The SOP will also require that any existing turnaround accruals bereversed to income immediately and the costs of future turnarounds expensed asincurred. We adopted the component level of accounting for property, plant andequipment beginning with December 2003 additions, and this aspect of the SOP didnot have any impact on our consolidated statements of income. If this proposedchange were in effect at December 31, 2003, we would have been required toreverse the turnaround accruals and recognize pretax income totaling $26.6million. The total accrued turnaround costs will change throughout the year asturnarounds are incurred and accruals are made for future turnarounds. When weadopt the SOP, income related to this proposed change as it relates toturnarounds would be reported as a cumulative effect of an accounting change,net of tax, in the consolidated statements of income. Since major turnaroundsoccur only every three to five years, this reporting change will result indramatic fluctuations in our operating results from year to year and quarter toquarter. Our operating results will be negatively impacted in the quarters andyears of the major turnarounds by reflecting all of the costs related to thoseturnarounds within that period as opposed to our current method of expensing thecosts over the period between the turnarounds. If this SOP becomes GAAP, weanticipate adopting the provisions of the SOP as they relate to turnarounds onJanuary 1, 2005. 

               **Inventories.**   Inventories of crude oil,  unfinished  products and all finished  products are recorded at thelower of cost on a FIFO basis or market.  Crude oil includes  both  domestic  and foreign  crude oil volumes at itscost and associated  freight and other cost.  Unfinished  products (work in process) include any crude oil that hasentered into the refining  process,  and other  feedstocks that are not finished as far as refining  operations areconcerned.  These include  unfinished  gasoline and diesel,  blendstocks  and other  feedstocks.  Finished  productinventory  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 materialfreight and other costs,  and direct refinery  operating  expense  allocated when refining begins relative to theirproportionate  market  values.  The FIFO  method of  accounting  for  inventories  sometimes  results  in  Frontierrecognizing  substantial  gains (in  periods of rising  prices) or losses (in periods of falling  prices)  from ourinventories of crude oil and products.  While Frontier feels this accounting  method more  accurately  reflects theresults 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 theimpact of the inventory accounting differences.

**        Stock-basedCompensation.**  Stock-based compensation is measured in accordance withAccounting Principles Board (“APB”) No. 25. Under this intrinsic valuemethod, compensation cost is the excess, if any, of the quoted market value ofFrontier’s common stock at the grant date over the amount the employee mustpay to acquire the stock. We have a stock option plan which authorizes thegranting of options to employees to purchase shares. Options under the plan aregranted at fair market value on the date of grant. No entries are made in theaccounts until the options are exercised, at which time the proceeds arecredited to common stock and paid-in capital. No compensation expense isrecorded. If we measured compensation in accordance with SFAS No. 123, Frontierwould record compensation expense based on the fair value of the awards at grantdate and would result in increased expenses. 

**        Price Risk ManagementActivities**.   See the “Market Risks” section and “Price RiskManagement Activities” under Notes 2 and 10 in the “Notes toConsolidated Financial Statements” for a discussion of our various pricerisk management activities. When we make the decision to manage our priceexposure, we neither incur losses from negative price changes nor do we obtainthe benefit of positive price changes. 

NEW ACCOUNTINGPRONOUNCEMENTS

        See “New AccountingPronouncements” under Note 2 in the “Notes to Consolidated FinancialStatements”. Other than the SOP discussed above under “CriticalAccounting Policies”, no other new pronouncements are expected to have amaterial impact on our financial statements. 

MARKET RISKS

**        Impact of ChangingPrices**.  Our revenues and cash flows, as well as estimates of future cashflows, are very sensitive to changes in energy prices. Major shifts in the costof crude oil, and the prices of refined products and natural gas can result inlarge changes in the operating margin from refining operations. These pricesalso determine the carrying value of the Refineries’ inventories. 

**        Price Risk ManagementActivities**.  Frontier, at times, enters into commodity derivative contractsto manage its price exposure to its inventory positions, purchases of foreigncrude oil and consumption of natural gas in the refining process or to fixmargins on certain future production. Gains or losses on commodity derivativecontracts accounted for as hedges are recognized in raw material, freight andother costs or refinery operating expenses, excluding depreciation when theassociated transactions are consummated while gains and losses on transactionsaccounted for using mark-to-market accounting are reflected in other revenues ateach period end. See “Price Risk Management Activities” under Notes 2and 10 in the “Notes to Consolidated Financial Statements”. 

SUBSEQUENTEVENT – CHEYENNE REFINERY FIRE

        On January 19, 2004, wereported that a fire had occurred in the furnaces of the coking unit at ourCheyenne Refinery. Fortunately, no serious injuries occurred as a result of thefire. The coker was out of service for approximately one month. We replaced oneof the furnaces and repaired the other furnace. We anticipate the total cost ofrepair, both capital and expense, above our $2.5 million deductible will becovered by insurance. We had previously scheduled a distillate hydrotreater andnaptha hydrotreater turnaround for late March 2004, but rescheduled theturnarounds to begin in mid-February in order to minimize lost production. Theseturnarounds are expected to last approximately 16 days. As a result of the fireand the turnarounds, we expect total crude charges for the first quarter at ourCheyenne Refinery will average 35,000 barrels per day, of which onlyapproximately 81% will be heavy crude. However, by the end of the year, weexpect to recover almost all of the production lost in the first quarter.