EXHIBIT 13.1

## MANAGEMENTS
DISCUSSION AND ANALYSIS

## General

The terms
Frontier and we refer to Frontier Oil Corporation and
its subsidiaries. Frontier operates refineries (the Refineries) in
Cheyenne, Wyoming and El Dorado, Kansas with a combined crude oil capacity of
156,000 barrels per day (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.

## Results of
Operations

To assist in understanding
our operating results, please refer to the operating data at the end of this
analysis, which provides key operating information for our 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 113⁄4% 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.

## LIQUIDITY AND
CAPITAL RESOURCES

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
113⁄4% 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.

## CONTRACTUAL
CASH OBLIGATIONS

The table below lists the
contractual cash obligations we have by period. These items include our
long-term debt based on their maturity dates, our operating lease commitments,
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
                                         --------------------------------------------------------------------------------------
(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                  -                 -
-------------------------------------------------------------------------------------------------------------------------------
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                 -
-------------------------------------------------------------------------------------------------------------------------------
   Total contractual cash (3)              $ 1,283,810    $   360,920    $   430,209        $   223,022  $     $  269,659
-------------------------------------------------------------------------------------------------------------------------------`

|(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.

## OFF-BALANCE
SHEET ARRANGEMENTS

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.

## ENVIRONMENTAL

Our refining and marketing
operations are subject to a variety of federal, state and local health and
environmental laws and regulations governing product specifications, the
discharge of pollutants into the air and water, and the generation, treatment,
storage, transportation and disposal of solid and hazardous waste and materials.
Permits are required for the operation of our Refineries, and these permits are
subject to revocation, modification and renewal. Governmental authorities have
the power to enforce compliance with these regulations and permits, and
violators are subject to injunctions, civil fines and even criminal penalties.
We believe that each of our Refineries is in substantial 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.

## CRITICAL
ACCOUNTING POLICIES

Turnarounds.   The costs for turnarounds  (scheduled and required  shutdowns of refinery  operating units for
significant  overhaul and  refurbishment) are ratably accrued over the period from the prior turnaround to the next
scheduled  turnaround.  Since 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.

## NEW ACCOUNTING
PRONOUNCEMENTS

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.

## MARKET RISKS

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.

## SUBSEQUENT
EVENT  CHEYENNE REFINERY FIRE

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.`

---

# NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS

## 1.  NATURE OF
OPERATIONS

The financial statements include
the accounts of Frontier Oil Corporation, a Wyoming corporation, and its
wholly-owned subsidiaries, including Frontier Holdings Inc., collectively
referred to as Frontier or the Company. The Company is an energy company engaged
in crude oil refining and wholesale marketing of refined petroleum products (the
refining operations).

The Company operates
refineries (the Refineries) in Cheyenne, Wyoming and El Dorado,
Kansas. 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.

## 2.  SIGNIFICANT
ACCOUNTING POLICIES

## Refined
Product Revenues

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

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.

## Turnarounds

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

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
                                                           ===========   ===========`

## Prepaid
Insurance

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.

## Income Taxes

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

Environmental expenditures
are expensed or capitalized based upon their future economic benefit. Costs
which improve a propertys pre-existing condition and costs which prevent
future environmental contamination are capitalized. Remediation costs related to
environmental damage resulting from operating activities subsequent to
acquisition are expensed. Liabilities for these expenditures are recorded when
it is probable that obligations have been incurred and the amounts can be
reasonably estimated.

## Price Risk
Management Activities

The Company, at times, enters
into commodity derivative contracts to manage its price exposure to its
inventory positions, purchases of foreign crude oil and consumption of natural
gas in the refining process or to fix margins on certain future production. The
commodity derivative contracts used by the Company may take the form of futures
contracts, collars or price swaps and are entered into with credit worthy
counterparties. The Company believes there is minimal credit risk with respect
to its counterparties. The Company accounts for its commodity derivative
contracts under the hedge (or deferral) method of accounting when the derivative
contracts are designated as hedges for accounting purposes, or mark-to-market
accounting if the Company elects not to designate derivative contracts as
accounting hedges or if such derivative contracts do not qualify for hedge
accounting. As such, gains or losses on commodity derivative contracts accounted
for as hedges are recognized in 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

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.

## Principles of
Consolidation

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.

## Use of
Estimates

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.

## Cash
Equivalents

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.

## Supplemental
Cash Flow Information

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.

## Reclassifications

Certain prior year amounts have been reclassified to conform with the current year presentation.

## New Accounting
Pronouncements

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.

## 3.  HOLLY
MERGER AGREEMENT AND LITIGATION

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.

## 4.  DEBT

`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
                                                             =============   =============`

## Senior Notes

On November 5, 1999, the
Company issued $190 million principal amount of 113⁄4% Senior Notes due 2009.
The 113⁄4% Notes were issued at a price of 98.562%. The net proceeds were
utilized to acquire the El Dorado Refinery. The 113⁄4% 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 113⁄4% 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
113⁄4% 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.

## Revolving
Credit Facility

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.

## Five-year
Maturities

The 113⁄4% Notes are due 2009; until then there are no maturities of long-term debt.

## 5.  INCOME TAXES

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.

## 6.  COMMON STOCK

## Dividends

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.

## Earnings per
Share

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.

## Non-employee
Directors Stock Grant Plan

During 1995, the Company established
a stock grant plan for non-employee directors. The purpose of the plan is to
provide a part of non-employee directors compensation in Company stock.
The plan 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.

## Stock Option
Plan

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.

## Prior Stock
Option Plans

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.

## Restricted
Stock Plan

On March 13, 2001, the Company
established the Frontier Oil Corporation Restricted Stock Plan (the
Plan) covering 1,000,000 shares of common stock held as treasury
stock by the Company. The Plans purpose is to permit grants of shares,
subject to restrictions, to key employees of the Company and is intended to
promote the interests of the Company by encouraging those employees to acquire
or increase their equity interest in the Company. The Plan is also intended to
enhance the ability of the Company to attract and retain the services of key
employees who are important to the growth and profitability of the Company. The
Plan is designed to work in conjunction with the Companys annual bonus
program for employees whereby all or a portion of a bonus awarded shall be paid
in the form of restricted stock granted under the Plan. Shares awarded under the
Plan entitle the shareholder to all rights of common stock ownership except that
the shares may not be sold, transferred or pledged during the restriction period
except as provided for in the Plan and any dividends are held by the Company and
paid to the employee when the stock vests.

As of December 31, 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.

## 7.  EMPLOYEE
BENEFIT PLANS

## Contribution
Plans

The Company sponsors
defined contribution plans for its employees. All employees may participate by
contributing a portion of their annual earnings to the plans. The Company makes
basic and/or matching contributions on behalf of participating employees. The
cost of the plans for the three years ended December 31, 2003, 2002 and 2001 was
$5.1 million, $5.1 million and $4.6 million, respectively.

## Defined
Benefit Plans

The Company established a
defined cash balance pension plan, effective January 1, 2000, for eligible El
Dorado employees to supplement retirement benefits those employees lost upon the
sale of the El Dorado Refinery to Frontier. No other current or future employees
will be eligible to participate in the plan. This plan has assets of $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.

## 8.  COMMITMENTS
AND CONTINGENCIES

## Lease and
Other Commitments

On November 16, 1999, Frontier
acquired the 110,000 barrels per day crude oil refinery located in El Dorado,
Kansas from Equilon Enterprises LLC, now known as Shell Oil Products US
(Shell). Under the provisions of the purchase and sale agreement,
the Company is required to make contingent earn-out payments for each of the
years 2000 through 2007 equal to one-half of the excess over $60 million per
year of the El Dorado Refinerys revenues less its material costs and
operating costs, other than depreciation. The total amount of these contingent
payments is capped at $40 million, with an annual cap of $7.5 million. Any
contingency payment will be recorded when determinable. Such contingency
payments, if any, will be recorded as additional acquisition cost. No contingent
earn-out payment 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.

## Litigation

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.

## Concentration
of Credit Risk

The Company has
concentrations of credit risk with respect to sales within the same or related
industry and within limited geographic areas. The Company sells its Cheyenne
products exclusively at wholesale, principally to independent retailers and
major oil companies located primarily in the Denver, 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.

## Environmental

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.

## Collective
Bargaining Agreement Expiration

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.

## 9.  FAIR VALUE
OF FINANCIAL INSTRUMENTS

The fair value of the
Companys Senior Notes was estimated based on quotations obtained from
broker-dealers who make markets in these and similar securities. At December 31,
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.

## 10.  PRICE RISK
MANAGEMENT ACTIVITIES

The Company, at times,
enters into commodity derivative contracts for the purposes of managing price
risk on foreign crude purchases, crude and other inventories, and natural gas
purchases and to fix margins on certain future production.

## Trading
Activities

During 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.

## Hedging
Activities

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.

## 11.  SUBSEQUENT
EVENT  CHEYENNE REFINERY FIRE

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

## To the
Shareholders of Frontier Oil Corporation:

We have audited the
accompanying consolidated balance sheets of Frontier Oil Corporation (a Wyoming
corporation) and subsidiaries as of December 31, 2001 and 2000, and the related
consolidated statements of operations, changes in shareholders equity and
cash flows for each of the three years in the period ended December 31, 2001.
These financial statements are the responsibility of the Companys
management. Our responsibility is to express an opinion on these financial
statements based on our audits.

We conducted our audits in
accordance with auditing standards generally accepted in the United States.
Those standards require that we plan and perform the audit to obtain reasonable
assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the
financial statements referred to above present fairly, in all material respects,
the financial position of Frontier Oil Corporation and subsidiaries as of
December 31, 2001 and 2000, and the results of their operations and their cash
flows for each of the three years in the period ended December 31, 2001, in
conformity with accounting principles generally accepted in the United States.

ARTHUR ANDERSEN LLP     Houston, Texas     February 8, 2002

# REPORT OF
MANAGEMENT

The information contained
in this Annual Report, as well as all the financial and operational data we
present concerning Frontier Oil Corporation, is prepared by management. Our
financial statements are fairly presented in all material respects in conformity
with generally accepted accounting principles.

It has always been our
intent to apply proper and prudent accounting guidelines in the presentation of
our financial statements; and, we are committed to full and accurate
representation of our condition through complete and clear disclosures. We stand
behind this pledge as a matter of honor and integrity.



|James R. GibbsChairman of the Board,
President and Chief Executive Officer | Julie H. EdwardsExecutive Vice President - 
Finance and Administration,
Chief Financial Officer | Nancy J. ZupanVice President - Controller
|-------------------------------------------------------------------------- | ----------------------------------------------------------------------------------------------- | -----------------------------------------