**UNITED
      STATES****SECURITIES
      AND EXCHANGE COMMISSION****Washington,
      D.C. 20549****FORM
      10-K**ANNUAL
      REPORT PURSUANT TO SECTION 13 OR 15(d)þ
    OF
      THE SECURITIES EXCHANGE ACT OF 1934**For
      the Fiscal Year Ended: December 31, 2004**ORTRANSITION
      REPORT PURSUANT TO SECTION 13 OR 15(d)o
    OF
      THE SECURITIES EXCHANGE ACT OF 1934For
      the transition period from . . . . to . . . .Commission
      File Number: 1-7627**FRONTIER
      OIL CORPORATION**(Exact
      name of registrant as specified in its charter)**Wyoming**
    
    **74-1895085**(State
      or other jurisdiction of
    
    (I.R.S.
      Employerincorporation
      or organization)
    
    Identification
      No.)**10000
      Memorial Drive, Suite 600**
    
    **77024-3411****Houston,
      Texas**
    
    (Zip
      Code)(Address
      of principal executive offices)Registrant’s
      telephone number, including area code:**(713)
      688-9600**Securities
      registered pursuant to Section 12(b) of the Act:Name
      of Each ExchangeTitle
      of Each Class
    
    on
      Which RegisteredCommon
      Stock
    New
      York Stock Exchange65⁄8%
      Senior Notes due 2011Securities
      registered pursuant to Section 12(g) of the Act:NoneIndicate
      by check mark whether the registrant (1) has filed all reports required to
      be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934
      during the preceding 12 months (or for such shorter period that the
      registrant was required to file such reports), and (2) has been subject to
      such filing requirements for the past 90 days.YesüNo
      . . .Indicate
      by check mark if disclosure of delinquent filers pursuant to rule 405 of
      Regulation S-K is not contained herein, and will not be contained, to the
      best of registrant’s knowledge, in definitive proxy or information
      statements incorporated by reference in Part III of this Form 10-K or any
      amendment to this Form 10-K.üIndicate
      by check mark whether the registrant is an accelerated filer (as defined
      in Rule 12b-2 of the Act).YesüNo
      . . .The
      aggregate market value of the voting and non-voting common equity held by
      non-affiliates computed by reference to the price at which the common
      equity was last sold as of June 30, 2004 was $556.0
    million.The
      number of shares of common stock outstanding as of February 18, 2005 was
      27,150,710.**DOCUMENTS
      INCORPORATED BY REFERENCE**Portions
      of the Annual Proxy Statement for the registrant’s 2005 annual meeting of
      shareholders are incorporated by reference into Items 10 through 14 of
      Part III.
  
 
   **TABLE
OF CONTENTS**
 
 Part
      IItem
      1.
    BusinessSummary and OverviewRefining OperationsMarketing and DistributionCompetitionCrude Oil SupplySafetyGovernment RegulationEmployeesRisk Factors Relating to Our
      BusinessAvailable InformationItem
      2.
    PropertiesItem
      3.
    Legal ProceedingsItem
      4.
    Submission of Matters to a Vote of Security
      HoldersPart
      IIItem
      5.
    Market for Registrant’s Common Equity and Related
      Stockholder MattersItem
      6.
    Selected Financial DataItem
      7.
    Management’s Discussion and Analysis of Financial
      Condition and Results of OperationsItem
      7A.
    Quantitative and Qualitative Disclosures About Market
      RiskItem
      8.
    Financial Statements and Supplementary
    DataItem
      9.
    Changes in and Disagreements with Accountants on
      Accounting and Financial DisclosureItem
      9A.
    Controls and ProceduresPart IIIPart
      IVItem
      15.
    Exhibits and Financial Statement Schedules
    
 **Forward-Looking
Statements**
 This Form
10-K contains “forward-looking statements” as defined by the Securities and
Exchange Commission. Such statements are those concerning contemplated
transactions and strategic plans, expectations and objectives for future
operations. These include, without limitation:
 ·
    statements,
      other than statements of historical facts, that address activities, events
      or developments that we expect, believe or anticipate will or may occur in
      the future;·
    statements
      relating to future financial performance, future capital sources and other
      matters; and·
    any
      other statements preceded by, followed by or that include the words
      “anticipates,” “believes,” “expects,” “plans,” “intends,” “estimates,”
      “projects,” “could,” “should,” “may,” or similar
    expressions.
 Although
we believe that our plans, intentions and expectations reflected in or suggested
by the forward-looking statements we make in this Form 10-K are reasonable, we
can give no assurance that such plans, intentions or expectations will be
achieved. These statements are based on assumptions made by us based on our
experience and perception of historical trends, current conditions, expected
future developments and other factors that we believe are appropriate in the
circumstances. Such statements are subject to a number of risks and
uncertainties, many of which are beyond our control. You are cautioned that any
such statements are not guarantees of future performance and that actual results
or developments may differ materially from those projected in the
forward-looking statements.
 We
undertake no obligation to update or revise publicly any revisions to any such
forward-looking statements that may be made to reflect events or circumstances
after the date of this Form 10-K, or to reflect the occurrence of unanticipated
events.
 
 
  
 **PART I**
 
 **Item
1.** **Business**
 
 **Summary**
 The terms
“Frontier,” “we,” “us” and “our” as used in this Form 10-K refer to Frontier Oil
Corporation and its subsidiaries, except where it is clear that those terms mean
only the parent company. When we use the term “Rocky Mountain region,” we refer
to the states of Colorado, Wyoming, Montana and Utah, and when we use the term
“Plains States,” we refer to the states of Kansas, Oklahoma, Nebraska, Iowa,
Missouri, North Dakota and South Dakota.
 
 **Overview**
 We are an
independent energy company engaged in crude oil refining and the wholesale
marketing of refined petroleum products. We operate refineries (the
“Refineries”) in Cheyenne, Wyoming and El Dorado, Kansas with a total annual
average crude oil capacity of 156,000 barrels per day (“bpd”). Both of our
Refineries are complex refineries, which means that they can process heavier,
less expensive types of crude oil and still produce a high percentage of
gasoline, diesel fuel and other high margin refined products. We focus our
marketing efforts in the Rocky Mountain region and the Plains States, which we
believe are among the most attractive refined products markets in the United
States. The operations of refining and marketing of petroleum products are
considered part of one reporting segment.
 **Cheyenne
Refinery.**  Our
Cheyenne Refinery has a permitted crude capacity of 46,000 bpd on a twelve-month
average. We market its refined products primarily in the eastern slope of the
Rocky Mountain region, which encompasses eastern Colorado (including the Denver
metropolitan area), eastern Wyoming and western Nebraska (the “Eastern Slope”).
The Cheyenne Refinery has a coking unit, which allows the refinery to process up
to 100% heavy crude oil for use as a feedstock. The ability to process heavy
crude oil lowers our crude oil supply costs because heavy crude oil is generally
less expensive than lighter types of crude oil. For the year ended December 31,
2004, heavy crude oil constituted approximately 85% of the Cheyenne Refinery’s
total crude oil charge. For the year ended December 31, 2004, the Cheyenne
Refinery’s yielded product mix included gasoline (42%), diesel fuel (30%) and
asphalt and other refined petroleum products (28%).
 **El
Dorado Refinery.** The El
Dorado Refinery, acquired on November 16, 1999 from Equilon Enterprises LLC, now
known as Shell Oil Products US (“Shell”), is one of the largest refineries in
the Plains States and the Rocky Mountain region with a crude capacity of 110,000
bpd. The El Dorado Refinery can select from many different types of crude oil
because of its direct access to Cushing, Oklahoma, which is connected by
pipeline to the Gulf Coast. This access, combined with the El Dorado Refinery’s
complexity (including a coking unit), gives it the flexibility to refine a wide
variety of crude oils. In connection with our acquisition of the El Dorado
Refinery in late 1999, we entered into a 15-year refined product offtake
agreement for gasoline and diesel production at this refinery with Equiva
Trading Company (“Equiva”), an affiliate of Shell Oil Company. In 2002, Equiva
assigned this offtake agreement to Shell. Shell will also continue to purchase
all jet fuel production until the end of the product offtake agreement. The
offtake agreement allowed us to maximize the operating efficiency of the El
Dorado Refinery during the initial years. As our commitments to Shell under the
refined product offtake agreement decline over the first ten years, we intend to
market an increasing portion of the El Dorado Refinery’s gasoline and diesel in
the same markets in which Shell currently sells the El Dorado Refinery’s
production, primarily in Denver and throughout the Plains States. For the year
ended December 31, 2004, the El Dorado Refinery’s yielded product mix included
gasoline (56%), diesel and jet fuel (34%) and chemicals and other refined
petroleum products (10%).
 **Other
Assets.** We also
own FGI, LLC, a 120,000 barrel asphalt terminal and storage facility in Grand
Island Nebraska, a 34.72% interest in a crude oil pipeline in Wyoming and a 50%
interest in two crude oil tanks in Guernsey, Wyoming.
 
 **Refining Operations**
 **Varieties
of Crude Oil.** Traditionally, crude oil has been classified within the following
types:
 ·
    sweet
      (low sulfur content),
 ·
    sour
      (high sulfur content),
 ·
    light
      (high gravity),
 ·
    heavy
      (low gravity) and
 ·
    intermediate
      (if gravity or sulfur content is in between).
 For the
most part, heavy crude oil tends to be sour and light crude oil tends to be
sweet. When refined, light crude oil produces a higher yield of higher margin
refined products such as gasoline, diesel and jet fuel and as a result, is more
expensive than heavy crude oil. In contrast, heavy crude oil produces more low
margin by-products and heavy residual oils. The discount at which heavy crude
oil sells compared to the sales price of light crude oil is known in the
industry as the light/heavy spread or differential. Coking units, such as the
ones used by our refineries, can process certain by-products and heavy residual
oils to produce additional volumes of gasoline and diesel, thus increasing the
aggregate yields of higher margin refined products from the same initial volume
of crude oil.
 **Products.** The
Cheyenne and El Dorado Refineries are both complex refineries. Refineries are
frequently classified according to their complexity, which refers to the number,
type and capacity of processing units at the refinery. Each of our refineries
possesses a coking unit, which provides substantial upgrading capacity.
Upgrading capacity refers to the ability of a refinery to produce high yields of
high margin refined products such as gasoline and diesel despite processing
significant volumes of heavy and intermediate crude oil. In contrast, in order
to produce high yields of gasoline and diesel, refineries with low upgrading
capacity must process primarily sweet crude oil. Some low complexity refineries
may be capable of processing heavy and intermediate crude oil, but they will
produce large volumes of by-products and heavy residual oils. The Cheyenne and
El Dorado Refineries have high upgrading capacity relative to other refineries
in the Plains States and Rocky Mountain region. Because gasoline, diesel and jet
fuel sales generally achieve higher margins than are available on other refined
products, we expect that these products will continue to make up the bulk of our
production.
 **Refinery
Maintenance.**  Each of
the operating units at our refineries requires regular maintenance and repair
shutdowns (referred to as “turnarounds”) during which the unit is not in
operation. Turnaround cycles vary for different units but are generally required
every one to five years. In general, turnarounds at our refineries are managed
so that some units continue to operate while others are down for scheduled
maintenance. We also coordinate operations by staggering turnarounds at the two
refineries. Maintenance turnarounds are implemented using our regular personnel
as well as additional contract labor. Turnaround work typically proceeds on a
continuous 24-hour basis to minimize unit downtime. We accrue for our turnaround
costs over the period from the prior turnaround to the next scheduled
turnaround. We normally schedule our maintenance turnaround work during the
spring or fall of each year. When we perform a turnaround we may increase
product inventories prior to the turnaround to minimize the impact of the
turnaround on our sales of refined products. We have major turnaround work
scheduled on the fluid catalytic cracking unit (“FCCU”) and related units at our
El Dorado Refinery during March 2005. Major turnaround work was performed on our
alkylation unit at our El Dorado Refinery in March 2004. Turnaround work was
performed on our sulfur and hydrotreating units at our Cheyenne Refinery in
February 2004.
 
 **Marketing And Distribution**
 **Cheyenne
Refinery.** The
primary market for the Cheyenne Refinery’s refined products is the Eastern
Slope. For the year ended December 31, 2004, we sold approximately 87% of the
Cheyenne Refinery’s gasoline sales volumes in Colorado and 8% in Wyoming. For
the year ended December 31, 2004, we sold approximately 33% of the Cheyenne
Refinery’s diesel sales volumes in Colorado and 56% in Wyoming. Because of the
location of the Cheyenne Refinery, we are able to sell a significant portion of
its diesel product from a truck rack at the Refinery, eliminating any
transportation costs. The gasoline and remaining diesel produced by this
Refinery are primarily shipped via pipeline to terminals for distribution by
truck or rail. Pipeline shipments from the Cheyenne Refinery are handled mainly
by the Kaneb pipeline, serving Denver and Colorado Springs, Colorado, and the
ConocoPhillips pipeline, serving Sidney, Nebraska.
 We sell
refined products from our Cheyenne Refinery to a broad base of independent
retailers, jobbers and major oil companies. Refined product prices are
determined by local market conditions at distribution centers known as “terminal
racks.” The customer at a terminal rack typically supplies its own truck
transportation. Prices at the terminal rack are posted daily by sellers. In the
year ended December 31, 2004, approximately 81% of the Cheyenne Refinery’s sales
were made to its 25 largest customers. Occasionally, marketing volumes exceed
the Refinery’s production, in which case we purchase product in the spot market
as needed.
 **El
Dorado Refinery.** The
primary markets for the El Dorado Refinery’s refined products are Colorado and
the Plains States, which include the Kansas City metropolitan area. The
gasoline, diesel and jet fuel produced by the El Dorado Refinery are primarily
shipped via pipeline to terminals for distribution by truck or rail. The Kaneb
pipeline, serving the northern Plains States, the Magellan pipeline serving
Denver, Colorado, the Magellan pipeline serving Kansas City and Carthage,
Missouri and Des Moines, Iowa, and until December 2004 the KCPL pipeline,
serving Kansas City, handle pipeline shipments from our El Dorado Refinery.
 In
connection with our late 1999 acquisition of this Refinery we entered into a
15-year refined product offtake agreement with Shell. For the year ended
December 31, 2004, Shell was the El Dorado Refinery’s largest customer,
representing 71% of total sales. Under the agreement, Shell purchases gasoline,
diesel and jet fuel produced by the El Dorado Refinery at market-based prices.
Initially in 1999, Shell purchased all of the El Dorado Refinery’s production of
these products. Beginning in 2000, we retained and marketed 5,000 bpd of the
Refinery’s gasoline and diesel production. The retained portion is scheduled to
increase by 5,000 bpd each year for ten years. In 2004, we retained 25,000 bpd
of the Refinery’s gasoline and diesel production. Shell
will continue to purchase all jet fuel production for the remainder of the
original 15-year product offtake agreement term. The
agreement allows us to focus on maximizing the operating efficiency of our El
Dorado Refinery during these years. As our sales to Shell under this agreement
decrease, we intend to sell the gasoline and diesel produced by the El Dorado
Refinery in the same markets as Shell currently does, as described
above.
 
 **Competition**
 **Cheyenne
Refinery.** The most
competitive market for the Cheyenne Refinery is the Denver metropolitan area.
Other than the Cheyenne Refinery, four principal refineries serve the Denver
market: a 65,000 bpd refinery near Rawlins, Wyoming and a 22,000 bpd refinery in
Casper, Wyoming, both owned by Sinclair Oil Company (“Sinclair”); a 28,000 bpd
refinery in Denver owned by Valero Energy Corporation (“Valero”); and a 58,000
bpd refinery in Denver owned by Suncor Energy (U.S.A.) (“Suncor”). Five product
pipelines also supply Denver, including three from outside the region that
enable refined products from other regions to be sold in the Denver market.
Refined products shipped from other regions bear the burden of higher
transportation costs.
 The
Valero and Suncor refineries located in Denver have lower product transportation
costs in serving the Denver market than we do. However, the Cheyenne Refinery
has lower crude oil transportation costs because of its proximity to the
Guernsey, Wyoming hub, the major crude oil pipeline hub in the Rocky Mountain
region, and our ownership interest in the Centennial pipeline, which runs from
Guernsey to the Cheyenne Refinery. Moreover, unlike Sinclair, Valero and Suncor,
we only sell our products to the wholesale market. We believe that our
commitment to the wholesale market gives us a customer relation’s advantage over
our principal competitors in the Eastern Slope area, all of which also have
retail outlets, because we are not in direct competition with independent
retailers of gasoline and diesel.
 **El
Dorado Refinery.** The El
Dorado Refinery faces competition from other Plains States and mid continent
refiners, but the principal competitors for the El Dorado Refinery are Gulf
Coast refiners. Although our Gulf Coast competitors typically have lower
production costs because of their size (economies of scale) than the El Dorado
Refinery, we believe that our competitors’ higher refined product transportation
costs allow the El Dorado Refinery to compete effectively with these refineries
in the Plains States and Rocky Mountain region. The Plains States and mid
continent regions are also supplied by three product pipelines that originate
from the Gulf Coast.
 
 **Crude Oil Supply**
 **Cheyenne
Refinery.** In the
year ended December 31, 2004, we obtained approximately 32% of the Cheyenne
Refinery’s crude oil charge from Wyoming, 57% from Canada and 11% from Colorado.
During the same period, heavy crude oil constituted approximately 85% of the
Cheyenne Refinery’s total crude oil charge. Cheyenne is 88 miles south of
Guernsey, Wyoming, the main hub and crude oil trading center for the Rocky
Mountain region. We transport up to 25,000 bpd of crude oil from Guernsey to the
Cheyenne Refinery through the Centennial pipeline. Additional crude oil volumes
are transported on an alternative common carrier pipeline. Ample quantities of
heavy crude oil are available at Guernsey, including both locally produced
Wyoming general sour and imported Canadian heavy crude oil, which is supplied by
the Express pipeline system and the eastern corridor pipeline system including
the Wascana, Poplar and Butte pipelines. The Cheyenne Refinery’s ability to
process up to 100% heavy crude oil feedstocks gives us a distinct advantage over
the four other Eastern Slope refineries, none of which has the necessary
upgrading capacity to process high volumes of heavy crude oil.
 We
purchase crude oil for the Cheyenne Refinery from several suppliers, including
major oil companies, marketing companies and large and small independent
producers under arrangements which contain market-responsive pricing provisions.
Many of these arrangements are subject to cancellation by either party or have
terms that are not in excess of one year and are subject to periodic
renegotiation. In October 2002, we 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. This agreement, effective January 1, 2003,
provides for the purchase of up to 20,000 bpd of a Lloydminster crude oil blend,
a heavy Canadian crude. Initially, we received 9,000 bpd, which increased to
20,000 bpd by October 2003. This type of crude oil typically sells at a discount
to lighter crude oils. Our price for crude oil under the agreement will be equal
to 71% of the simple average of the near month settlement prices of the NYMEX
light sweet crude oil contracts during the month of delivery, plus the cost of
transportation based on the 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 a portion of our dedicated capacity through the
Express pipeline.
 **El
Dorado Refinery.** In the
year ended December 31, 2004, we obtained approximately 57% of the El Dorado
Refinery’s crude oil charge from Texas, 17% from the Middle East, 15% from
Kansas, 10% from Louisiana, and the remaining from the North Sea. El Dorado is
125 miles north of Cushing, Oklahoma, a major crude oil hub. The Cushing hub is
supplied by the Seaway pipeline, which runs from the Gulf Coast; the Basin
pipeline, which runs through Wichita Falls from West Texas; and the Mobil
pipeline, which originates at the Gulf Coast and connects to the Basin pipeline
at Wichita Falls. The Osage pipeline runs from Cushing to El Dorado and
transported approximately 85% of our crude oil charge during the year ended
December 31, 2004. The remainder of our crude oil charge was transported to the
El Dorado Refinery through Kansas gathering system pipelines. During 2004, we
entered into a Transportation Services Agreement (“Agreement”) to transport
crude oil on the Spearhead Pipeline from Griffith, Indiana to Cushing, Oklahoma.
The owner of the Spearhead Pipeline intends to alter an existing pipeline,
including reversing the flow, with an anticipated date to be able to commence
crude oil shipments on or around January 1, 2006. This pipeline will enable us
to transport Canadian crude oil to our El Dorado Refinery. The initial term of
this Agreement is for a period of ten years from the actual commencement date,
although we have the right to extend the Agreement for an additional ten-year
term.
 
 **Safety**
 We are
subject to the requirements of the federal Occupational Safety and Health Act
(“OSHA”) and comparable state occupational safety statutes. We believe that we
have operated in substantial compliance with OSHA requirements, including
general industry standards, record keeping and reporting, hazard communication
and process safety management. The nature of our business may result from time
to time in industrial accidents. It is possible that changes in safety and
health regulations or a finding of non-compliance with current regulations could
result in additional capital expenditures or operating expenses, as well as
fines and penalties.
 The
Cheyenne Refinery reduced its OSHA recordable incident rate from 1.38 in 2003 to
1.03 for 2004. For comparison, the National Petrochemical and Refiner’s
Association (“NPRA”) industry average is 1.46. For the continued improvement in
safety, the personnel at Cheyenne will be awarded four safety awards by the
NPRA, which are:
 (1)
    an
      award for Meritorious Safety Performance for achieving a total recordable
      incidence rate of 1.2 or lower,
 (2)
    the
      Gold Award for a reduction in recordable accidents and no workplace
      injury,
 (3)
    the
      Award for Safety Achievement in Hours for one million or more hours worked
      without a lost time accident, and
 (4)
    the
      Award for Safety Achievement in Years for one or more years worked without
      a lost time accident.
 By the
end of 2004, the Cheyenne employees had worked 825 days without a lost time
accident. Our behavioral safety program initiated in 2000, our Safety Training
Observation Program started in 2002, and our supervisor’s safety training
program added in 2003 have maintained a very positive safety trend at the
Cheyenne Refinery. The combination of our behavioral safety program with the
management driven safety programs has made very positive changes in the safety
culture of the entire workforce at the Cheyenne Refinery. We are determined not
only to sustain our safety record, but also to further improve our safety record
at the Cheyenne Refinery.
 Because
our contractor injury rate is higher than our employee injury rate at our
Cheyenne Refinery, we increased our efforts on contractor safety in 2004. In
addition to the local safety training provided to contractors, personnel at the
Cheyenne Refinery assisted the Wyoming-Montana Safety Council in obtaining
accreditation by the Association to Reciprocal Safety Councils that allows them
to provide contractor safety training with nation-wide reciprocity. This has
been a very successful program in the Gulf Coast region, and we have high
expectations in our geographic region. By improving the training of the
contractor workforce in general, we also improve the safety of the outside labor
that we hire at our Cheyenne Refinery as well as other industrial facilities in
our geographic region.
 The El
Dorado Refinery also improved its safety record last year from an OSHA
recordable incident rate of 2.14 in 2003 to 1.94 for 2004, which is slightly
above the NPRA industry average. Our employees and management continue to
dedicate their efforts to a balanced safety program that combines individual
behavioral elements in a safety-coaching environment with very structured
management driven programs to improve the safety of the facility and operating
procedures. Our objective is a safe working environment for employees who know
how to work safely. Management believes that our implementation of the Active
Safety Participation program introduced in 2004 will drive much improved
performance in 2005. Encouraging all employees to contribute toward improving
safety performance through their personal involvement in safety-related
activities is an industry-proven way to reduce injuries. The El Dorado
Refinery’s performance bonus program will be linked to the overall level of
participation in the safety process and injury prevention. The El Dorado
Refinery is also transitioning from a management driven to an employee driven
behavioral based safety program that we anticipate will also reduce the number
of injuries. To further emphasize the importance of safety in the overall
success of the El Dorado Refinery in 2005, and to ensure all our employees have
personal accountability in this endeavor, the individual portion of the El
Dorado Refinery’s bonus program will be based upon each individual’s commitment
to safety.
 
 **Government Regulation**
 **Environmental
Matters.** Our
operations and many of our manufactured products 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 Refineries during the next several years. The Environmental
Protection Agency (“EPA”) has 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. We have been contacted by the EPA and
invited to meet with them to hear more about the Initiative. At this time, we do
not know how the Initiative may affect us. We have, however, in recognition of
the EPA’s reinterpretation of certain regulatory requirements associated with
the Initiative, determined that we will incur expenditures totaling
approximately $8.0 million to further reduce emissions from our Refineries’
flare systems. At our Cheyenne Refinery, we spent $223,000 in 2004, and estimate
spending an additional $4.0 million, primarily in 2005, on the flare system. At
our El Dorado Refinery, we spent $423,000 in 2004, and we estimate incurring a
total additional $3.3 million during 2005 and 2006, on the flare system. 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. The provisions of a KDHE order have not yet been proposed;
however, Region VII of the EPA has informed the State of Kansas and Frontier
that requirements for reductions in emissions from the El Dorado Refinery’s FCCU
must also be included in any settlement with the State of Kansas if we want
protection from a subsequent EPA enforcement action under the Initiative. We are
currently evaluating interim and final FCCU emission control options.
 In a
settlement entered on February 22, 2005, the WDEQ accepted a penalty payment in
the amount of $120,000 in addition to our commitment to complete the
aforementioned flare system controls and an agreed upon Capital Supplemental
Environmental Project estimated to cost $535,000 to resolve one of the
Initiative’s four concerns and other violations. The settlement
addresses:
 ·
    the
      reduction of flare system emissions,
 ·
    an
      earlier notice of violation regarding excess emissions from our Cheyenne
      Refinery’s crude unit heaters,
 ·
    resolution
      of a 1992 Odor Consent Decree, and
 ·
    two
      recent odor violations associated with the startup of our Cheyenne
      Refinery’s new gasoline desulfurization
equipment.
 During
the first quarter of 2004, we decreased the previously estimated penalty accrual
of $317,000 recorded as of December 31, 2003 to $120,000. This $197,000
reduction is reflected as a reduction of “Refinery operating expenses, excluding
depreciation” on the Consolidated Statement of Income for the year ended
December 31, 2004.
 The EPA
has promulgated regulations requiring the phase-in of gasoline sulfur standards,
which began January 1, 2004 and continues through 2008, with special provisions
for small business refiners. Because we qualify as a small business refiner, we
have elected to extend our small refinery interim gasoline sulfur standard at
each of our Refineries until 2011 and to comply with the highway diesel sulfur
standard by June 2006, as discussed below. Our Cheyenne Refinery has spent
approximately $28.9 million (including capitalized interest) to complete the
project to meet the interim gasoline sulfur standard, which was required by
January 1, 2004. The remaining $7.0 million estimated cost to meet the
additional standard for the Cheyenne Refinery is expected to be incurred in 2009
and 2010. The total capital expenditures estimated as of December 31, 2004 for
the El Dorado Refinery to achieve the final gasoline sulfur standard are
approximately $15 million, which are expected to be incurred between 2006 and
2009. Our approach to achieve the gasoline sulfur standard at the El Dorado
Refinery has been revised from building a new unit to the modification of
existing equipment, thus reducing the cost from the original estimate of $44.0
million.
 The EPA
has promulgated regulations that will limit the sulfur content of highway diesel
fuel beginning in 2006. As indicated above, we have elected to comply with the
highway diesel sulfur standard by June 2006. As of December 31, 2004, capital
costs, including capitalized interest, for diesel desulfurization are estimated
to be approximately $14.0 million for the Cheyenne Refinery and approximately
$106.5 million for the El Dorado Refinery. Approximately $250,000 of the
Cheyenne Refinery expenditures were incurred in 2004, $9.0 million is estimated
to be incurred in 2005, with the remaining $4.7 million estimated to be incurred
in the first half of 2006. Approximately $6.0 million of the El Dorado Refinery
expenditures were incurred in 2004, with $90.5 estimated to be incurred in 2005,
and the remaining $10.0 million estimated to be incurred in the first half of
2006. Certain provisions of The American Jobs Creation Act of 2004 should
benefit us by allowing an accelerated depreciation deduction of 75% of these
qualified capital costs in the years incurred and by providing a $0.05 per
gallon credit on compliant diesel fuel up to an amount equal to the remaining
25% of these qualified capital costs for federal income tax
purposes.
 On June
29, 2004, the EPA promulgated regulations designed to reduce emissions from the
combustion of diesel fuel in non-road applications such as mining, agriculture,
locomotives and marine vessels. We currently participate in this market through
the manufacture and sale of approximately 6,000 bpd of non-road diesel fuel from
our El Dorado Refinery. The new regulations will, in part, require refiners to
reduce the sulfur content of non-road diesel fuel from 5,000 parts per million
(“ppm”) to 500 ppm in 2007 and further to 15 ppm in 2010 for all uses but
locomotive and marine. Diesel fuel used in locomotives and marine operations
will be required to meet the 15 ppm sulfur standard in 2012. Small refiners,
such as Frontier, will be allowed to either postpone the new sulfur limits or,
if the small refiner chooses to meet the new limit on the national schedule, to
increase their gasoline sulfur limits by 20%. We intend to desulfurize all of
our diesel fuel, including non-road, to the 15 ppm sulfur standard by 2006. The
new regulation also clarifies that EPA-approved small business refiners will be
allowed to exceed both the small refiner maximum capacity and/or employee
criteria through merger with or acquisition of another approved small business
refiner without loss of small refiner regulatory status.
 The front
range of Colorado (including the Denver metropolitan area) is a major market for
the products manufactured by our Refineries. During 2004, the State of Colorado
undertook an effort to develop and implement controls necessary to ensure that
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.
On March 25, 2004, the EPA advised the refiners supplying the Denver region that
their request for continuance of the long-standing Reid Vapor Pressure (“RVP”)
waiver would not be granted for the 2004 ozone control period and that gasoline
marketed in the area could not exceed the regulatory standard of 7.8 pounds RVP
beginning May 1, 2004 at the marketing distribution terminals and June 1, 2004
at customer retail locations. During 2004, we incurred $2.0 million in capital
costs at our Cheyenne Refinery to comply with this standard.
 As is the
case with all companies engaged in similar industries, we face potential
exposure from future claims and lawsuits involving environmental matters
including soil and water contamination, air pollution, personal injury and
property damage allegedly caused by substances that we may have manufactured,
handled, used, released or disposed.
 **Cheyenne
Refinery** . We are
party to an agreement with the State of Wyoming requiring the investigation and
possible eventual remediation of certain areas of our 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 approved 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, including the completion of surface impoundment closures,
waste stabilization activities and other site remediation projects totaling
approximately $4.0 million. In addition, we estimate that an ongoing groundwater
remediation program averaging approximately $200,000 in annual operating and
maintenance costs will be required for approximately ten more years. As of
December 31, 2004, we have a reserve of $1.5 million in environmental
liabilities reflecting the estimated present value of these expenditures ($2.0
million, discounted at a rate of 5.0%). The EPA also issued an administrative
consent order with respect to our 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 had been adversely impacted by past operational activities.
Based upon the results of the ongoing investigation, additional remedial action
could be required by a subsequent administrative order or permit.
 In
accordance with permits issued by the State of Wyoming under the federal
National Pollutant Discharge Elimination System (“NPDES”), our Cheyenne Refinery
is permitted to discharge its treated wastewater to either of two receiving
waterways: a creek adjacent to the Cheyenne Refinery or a normally dry ravine
called “Porter Draw.” Certain landowners downstream of the Cheyenne Refinery’s
permitted discharge to Porter Draw expressed their unwillingness to continue to
accommodate this wastewater flow by appealing our discharge permit and by giving
notice of possible legal action. In response, as an alternative to continuing to
discharge into the ravine, we arranged to deliver our treated wastewater
beginning in July 2004 to the City of Cheyenne (“Cheyenne”) municipal treatment
plant for additional treatment and release, and we have entered into settlements
with the landowners. To initiate this wastewater treatment service, we have
agreed to pay Cheyenne a $1.6 million development fee (reflected in “Other
intangible asset” on our Consolidated Balance Sheet as of December 31, 2004).
The $1.6 million fee will be paid in equal installments over five years, with
the first payment having been made in July 2004. In addition, we pay Cheyenne
$2.00 per 1,000 gallons of wastewater treated, which is included as “Refinery
operating expenses, excluding depreciation” in our Consolidated Statements of
Income.
 **El
Dorado Refinery** . Our El
Dorado Refinery is subject to a 1988 consent order with the KDHE. This order,
including various subsequent modifications, requires the El Dorado Refinery to
continue the implementation of a groundwater management program with oversight
provided by the KDHE Bureau of Environmental Remediation. More specifically, the
El Dorado 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 El Dorado Refinery are met. Subject to the terms of the
purchase and sale agreement for the El Dorado Refinery entered into between
Frontier and Shell, Shell is responsible for the costs of continued compliance
with this order.
 **Centennial
Pipeline Regulation.** We have
a 34.72% undivided ownership interest in the Centennial pipeline, which runs
approximately 88 miles from Guernsey to Cheyenne, Wyoming. Suncor Pipe Line
Company is the sole operator of the Centennial pipeline as well as the holder of
the remaining ownership interest. The Cheyenne Refinery receives up to 25,000
bpd of crude oil feedstock through the Centennial pipeline. Under the terms of
the operating agreement for the Centennial pipeline, the costs and expenses
incurred to operate and maintain the Centennial pipeline are allocated to us on
a combined basis, based on our throughput and ownership interest. The Centennial
pipeline is subject to numerous federal, state and local laws and regulations
relating to the protection of health, safety and the environment. We believe
that the Centennial pipeline is operated in accordance with all applicable laws
and regulations. We are not aware of any material pending legal proceedings to
which the Centennial pipeline is a party.
 
 **Employees**
 At
December 31, 2004, we employed approximately 731 full-time employees in the
refining operations, 74 of whom were in the Houston and Denver offices, 261 at
the Cheyenne Refinery, 390 at the El Dorado Refinery and 6 at our asphalt
terminal in Grand Island, Nebraska. The Cheyenne Refinery employees include 91
administrative and technical personnel and 170 union members. The El Dorado
Refinery employees include 134 administrative and technical personnel and 256
union members. The union members at our Cheyenne Refinery are represented by
seven bargaining units, the largest being the Paper, Allied-Industrial, Chemical
and Energy Workers International Union (“PACE”) and the others being affiliated
with the AFL-CIO. At the Cheyenne Refinery, our current contract with PACE
expires in July 2006, while our current contract with the AFL-CIO affiliated
unions expires in June 2009. At the El Dorado Refinery, all union members are
represented by PACE, and our current contract with PACE expires in January
2006.
 
 **Risk Factors Relating to Our Business**
  **Crude
oil prices and refining margins significantly impact our cash flow and have
fluctuated significantly in the past.**
  Our cash
flow from operations is primarily dependent upon producing and selling
quantities of refined products at margins that are high enough to cover our
fixed and variable expenses. In recent years, crude oil costs and crack spreads
(the difference between crude oil prices and refined product sales prices) have
fluctuated substantially. Factors that may affect crude oil costs and refined
product prices include:
 ·
    overall
      demand for crude oil and refined products;
 ·
    general
      economic conditions;
 ·
    the
      level of foreign and domestic production of crude oil and refined
      products;
 ·
    the
      availability of imports of crude oil and refined
  products;
 ·
    the
      marketing of alternative and competing fuels;
 ·
    the
      extent of government regulation;
 ·
    global
      market dynamics;
 ·
    product
      pipeline capacity;
 ·
    local
      market conditions; and
 ·
    the
      level of operations of other refineries in the Plains States and Rocky
      Mountain region.
 Crude oil
supply contracts are generally short-term contracts with price terms that change
as market prices change. Our crude oil requirements are supplied from sources
that include:
 ·
    major
      oil companies;
 ·
    crude
      oil marketing companies;
 ·
    large
      independent producers; and
 ·
    smaller
      local producers.
 The price
at which we can sell gasoline and other refined products is strongly influenced
by the commodity price of crude oil. Generally, an increase or decrease in the
price of crude oil results in a corresponding increase or decrease in the price
of gasoline and other refined products. However, if crude oil prices increase
significantly, our operating margins would fall unless we could pass along these
price increases to our customers. From time to time, we purchase forward crude
oil supply contracts, enter into forward product agreements to hedge excess
inventories and hedge our refined product margins.
 In
addition, our refineries maintain inventories of crude oil, intermediate
products and refined products, the value of each being subject to fluctuations
in market prices. Our inventories of crude oil, unfinished products and finished
products are recorded at the lower of cost on a first-in, first-out (“FIFO”)
basis or market prices. As a result, a rapid and significant increase or
decrease in the market prices for crude oil or refined products could have a
significant short-term impact on our earnings and cash flow.
  **Our
profitability is linked to crude oil differentials, which increased
significantly in 2004 over 2003 levels.**
  The
light/heavy crude oil differential is the average differential between the
benchmark West Texas Intermediate (“WTI”) crude oil priced at Cushing, Oklahoma
and the heavy crude oil priced delivered to the Cheyenne Refinery, and the
WTI/WTS (sweet/sour) crude oil differential is the average differential between
benchmark WTI crude oil priced at Cushing, Oklahoma and West Texas sour crude
oil priced at Midland, Texas. Our profitability at our Cheyenne Refinery is
linked to the light/heavy crude oil differential and our profitability at our El
Dorado Refinery is linked to the WTI/WTS crude oil differential. We prefer to
refine heavy crude oil at the Cheyenne Refinery and sour crude oil at the El
Dorado Refinery because they provide a wider refining margin than light or sweet
crude does. Accordingly, any tightening of these crude oil differentials will
reduce our profitability. The light/heavy crude oil differential averaged $9.90
per barrel in the year ended December 31, 2004, compared to $7.10 per barrel in
the same period in 2003. The WTI/WTS crude oil differential averaged $3.74 per
barrel in the year ended December 31, 2004, compared to $2.68 per barrel in the
same period in 2003. Crude prices were high during 2004, which resulted in both
attractive light/heavy crude oil differentials and WTI/WTS crude oil
differentials. However, crude oil prices may not remain at current levels and
the crude oil differentials may decline again.
  **External
factors beyond our control can cause fluctuations in demand for our products and
in our prices and margins, which may negatively affect income and cash
flow.**
  External factors
can also cause significant fluctuations in demand for our products and
volatility in the prices for our products and other operating costs and can
magnify the impact of economic cycles on our business. Examples of external
factors include:
 ·
    general
      economic conditions;·
    competitor
      actions;·
    availability of raw materials;·
    international
      events and circumstances; and·
    governmental
      regulation in the United States and abroad, including changes in policies
      of theOrganization
      of Petroleum Exporting Countries
(“OPEC”).
 Demand for our
products is influenced by general economic conditions. For example, near record
level refined product margins and crude oil differentials in 2001 declined
substantially in 2002. This decline was attributed to unusually high prices for
oil, reduced market demand for refined products and greater imports of
competitive products, all of which adversely affected our results of operations
in 2002. In 2003, refined product margins and crude oil differentials returned
closer to historical average levels. In 2004, crude oil differentials reached
record levels, and refined product margins exceeded historical average levels.
However, the recurrence of weaker economic and market conditions in the future
may have a negative impact on our business and financial results.
  **Our
Refineries face operating hazards,** ****** **and
the potential limits on insurance coverage could expose us to potentially
significant liability costs.**
  Our
operations are subject to significant interruption, and our profitability is
impacted if any of our refineries experiences a major accident or fire, is
damaged by severe weather or other natural disaster, or otherwise is forced to
curtail its operations or shut down. If a pipeline becomes inoperative, crude
oil would have to be supplied to our Refineries through an alternative pipeline
or from additional tank trucks to the Refineries, which could hurt our business
and profitability. In addition, a major accident, fire or other event could
damage a refinery or the environment or cause personal injuries. If either of
our Refineries experiences a major accident or fire or other event or an
interruption in supply or operations, our business could be materially adversely
affected if the damage or liability exceeds the amounts of business
interruption, property, terrorism and other insurance that we maintain against
these risks.
 Our
Refineries consist of many processing units, a number of which have been in
operation for a long time. One or more of the units may require additional
unscheduled down time for unanticipated maintenance or repairs that are more
frequent than our scheduled turnaround for each unit every one to five years.
Scheduled and unscheduled maintenance could reduce our revenues during the
period of time that our units are not operating.
  **We
face substantial competition from other refining and pipeline companies.**
  The
refining industry is highly competitive. Many of our competitors are large,
integrated, major or independent oil companies that, because of their more
diverse operations, larger refineries and stronger capitalization, may be better
positioned than we are to withstand volatile industry conditions, including
shortages or excesses of crude oil or refined products or intense price
competition at the wholesale level. Many of these competitors have financial and
other resources substantially greater than ours.
  **Our
operating results are seasonal and generally lower in the first and fourth
quarters of the year.**
  Demand
for gasoline and asphalt products is generally higher during the summer months
than during the winter months due to seasonal increases in highway traffic and
road construction work. As a result, our operating results for the first and
fourth calendar quarters are generally lower than those for the second and third
quarters. Diesel demand has historically been more stable because two major
east-west truck routes and two major railroads cross one of our principal
marketing areas for our Cheyenne Refinery. However, reduced road construction
and agricultural work during the winter months somewhat depresses demand for
diesel in the winter months.
  **Our
operations involve environmental risks that may require us to make substantial
capital expenditures to remain in compliance or that could give rise to material
liabilities.**
  Our
results of operations may be affected by increased costs resulting from
compliance with the extensive environmental laws to which our business is
subject and from any possible contamination of our facilities as a result of
accidental spills, discharges or other releases of petroleum or hazardous
substances.
 Our
operations are subject to a variety of federal, state and local environmental
laws and regulations relating to the protection of the environment, including
those governing the emission or discharge of pollutants into the air and water,
product specifications and the generation, treatment, storage, transportation
and disposal, or remediation of solid and hazardous waste and materials.
Environmental laws and regulations that affect the operations, processes and
margins for our refined products are extensive and have become progressively
more stringent. Additional legislation or regulatory requirements or
administrative policies could be imposed with respect to our products or
activities. Compliance with more stringent laws or regulations or more vigorous
enforcement policies of the regulatory agencies could adversely affect our
financial position and results of operations and could require us to make
substantial expenditures. Our business is inherently subject to accidental
spills, discharges or other releases of petroleum or hazardous substances. Past
or future spills related to any of our operations, including our Refineries,
pipelines or product terminals, may give rise to liability (including potential
cleanup responsibility) to governmental entities or private parties under
federal, state or local environmental laws, as well as under common law. This
may involve contamination associated with facilities that we currently own or
operate, facilities that we formerly owned or operated and facilities to which
we sent wastes or by-product for treatment or disposal and other contamination.
Accidental discharges could occur in the future, future action may be taken in
connection with past discharges, governmental agencies may assess penalties
against us in connection with past or future contamination and third parties may
assert claims against us for damages allegedly arising out of any past or future
contamination. The potential penalties and clean-up costs for past or future
releases or spills, the failure of some prior owners of our facilities to
complete their clean-up obligations, the liability to third parties for damage
to their property, or the need to address newly-discovered information or
conditions that may require a response could be significant, and the payment of
these amounts could have a material adverse effect on our business, financial
condition and results of operations.
  **An
adverse decision in a lawsuit pending between Holly Corporation and Frontier
could have a material adverse effect on our financial condition and therefore,
on our results of operations.**
  On August
20, 2003, we filed a lawsuit in the Delaware Court of Chancery seeking
declaratory relief and unspecified damages based on allegations that Holly
Corporation (“Holly”) repudiated its obligations and breached an implied
covenant of good faith and fair dealing under a merger agreement announced in
late March 2003 under which Frontier and Holly were to be combined. On September
2, 2003, Holly filed its answer and counterclaims seeking declaratory judgments
that Holly had not repudiated the merger agreement, that we had repudiated the
merger agreement, that we had breached certain representations made by us in the
merger agreement, that Holly’s obligations under the merger agreement were and
are excused and that Holly may terminate the merger agreement without liability,
and seeking unspecified damages as well as costs and attorneys’ fees. The trial
with respect to our complaint and the Holly answer and counterclaims began in
the Delaware Court of Chancery on February 23, 2004 and was completed on March
5, 2004. In this litigation, the maximum amount of damages currently asserted by
us against Holly is approximately $161 million plus interest, attorneys’ fees
and costs, and the maximum amount of damages currently asserted by Holly against
us is approximately $148 million plus interest, attorneys’ fees and costs.
Post-trial briefing was completed in late April 2004, and on May 4, 2004 the
court heard oral arguments. We are awaiting a decision to be announced by the
court. While we cannot predict the outcome of this litigation, an adverse
decision to us could have a material adverse effect on our business, financial
condition, liquidity, competitive position or prospects.
  **We
may have labor relations difficulties with some of our employees represented by
unions.**
  Approximately
58 percent of our employees were covered by collective bargaining agreements at
December 31, 2004. We believe that our current relations with our employees are
good. However, employees may conduct a strike at some time in the future, which
may adversely affect our operations. See “Business-Employees.”
  **Terrorist
attacks and threats or actual war may negatively impact our
business.**
  Terrorist
attacks in the United States, as well as events occurring in response to or in
connection with them, including future terrorist attacks against U.S. targets,
rumors or threats of war, actual conflicts involving the United States or its
allies, or military or trade disruptions affecting our suppliers or our
customers, may adversely impact our operations. As a result, there could be
delays or losses in the delivery of supplies and raw materials to us, decreased
sales of our products and extension of time for payment of accounts receivable
from our customers.
 
 **Available Information**
 We file
reports with the Securities and Exchange Commission (“SEC”), including annual
reports on Form 10-K, quarterly reports on Form 10-Q and other reports from time
to time. The public may read and copy any materials that we file with the SEC at
the SEC’s Public Reference Room at 450 Fifth Street, NW, Washington, DC 20549.
The public may obtain information on the operation of the Public Reference Room
by calling the SEC at 1-800-SEC-0330. We are an electronic filer, and the SEC’s
Internet site at http://www.sec.gov contains
the reports, proxy and information statements, and other information filed
electronically.
 Our web
site address is: http://www.frontieroil.com . We make
our web site content available for informational purposes only. It should not be
relied upon for investment purposes, nor is it incorporated by reference in this
Form 10-K. 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.
 We filed
our 2004 annual CEO certification with the New York Stock Exchange (“NYSE”) on
April 15, 2004. We anticipate filing our 2005 annual CEO certification with the
NYSE on or about April 20, 2005. Additionally,
we filed with the SEC as exhibits to our Form 10-K for the year ended December
31, 2003 the CEO and CFO certifications required under Section 302 of the
Sarbanes-Oxley Act of 2002.
 
 
 **Item 2.** **Properties**
 **Refining
Operations**
 We own
the 125 acre site of the Cheyenne Refinery in Cheyenne, Wyoming and the
approximately 1,000 acre site of the El Dorado Refinery in El Dorado, Kansas.
The following tables set forth the refining operating statistical information on
a consolidated basis and for each Refinery for 2004, 2003 and 2002. The
statistical information includes the following terms not previously
defined:
  ·
    Charges
      - the quantity of crude oil and other feedstock processed through refinery
      units on bpd basis.·
    Manufactured
      product yields - the volumes of specific materials that are obtained
      through the distilling of crude oil and the operations of other refinery
      process units on a bpd basis.·
    Gasoline
      and diesel crack spreads - The average non-oxygenated gasoline and diesel
      net sales prices that we receive for each product less the average WTI
      crude oil price at Cushing, Oklahoma.
 
 **Consolidated:****Year
      Ended December 31,**
    
    **2004**
    
    **2003**
    
    **2002**Charges
      (bpd)Light
      crude
    
    
    37,486
    
    
    31,314
    
    
    35,684Heavy
      and intermediate crude
    
    
    110,662
    
    
    115,907
    
    
    110,372Other
      feed and blend stocks
    
    
    16,609
    
    
    18,407
    
    
    17,760Total
    
    
    164,757
    
    
    165,628
    
    
    163,816Manufactured
      product yields (bpd)Gasoline
    
    
    82,944
    
    
    83,449
    
    
    84,645Diesel
      and jet fuel
    
    
    53,093
    
    
    53,156
    
    
    53,436Asphalt
    
    
    7,475
    
    
    7,530
    
    
    7,437Chemicals
    
    
    939
    
    
    842
    
    
    369Other
    
    
    16,112
    
    
    16,536
    
    
    14,915Total
    
    
    160,563
    
    
    161,513
    
    
    160,802Total
      product sales (bpd)Gasoline
    
    
    90,698
    
    
    89,842
    
    
    91,989Diesel
      and jet fuel
    
    
    52,818
    
    
    53,606
    
    
    53,378Asphalt
    
    
    7,427
    
    
    7,260
    
    
    7,490Chemicals
    
    
    841
    
    
    842
    
    
    439Other
    
    
    14,205
    
    
    14,117
    
    
    13,236Total
    
    
    165,989
    
    
    165,667
    
    
    166,532Refinery
      operating margin information (per sales barrel)Refined
      products revenue
    
    $
    47.27
    
    $
    35.88
    
    $
    29.82Raw
      material, freight and other costs (FIFO inventory
    accounting)
    
    
    40.04
    
    
    30.77
    
    
    25.71Refinery
      operating expenses, excluding depreciation
    
    
    3.62
    
    
    3.31
    
    
    2.93Depreciation
      and amortization
    
    
    0.53
    
    
    0.47
    
    
    0.44Average
      WTI crude oil price at Cushing, OK (per barrel)
    
    $
    41.85
    
    $
    31.89
    
    $
    26.17Average
      gasoline crack spread (per barrel)
    
    $
    8.61
    
    $
    7.00
    
    $
    5.88Average
      diesel crack spread (per barrel)
    
    
    7.35
    
    
    5.05
    
    
    3.97Average
      sales price (per sales barrel)Gasoline
    
    $
    51.70
    
    $
    39.72
    
    $
    33.08Diesel
      and jet fuel
    
    
    49.81
    
    
    36.91
    
    
    30.35Asphalt
    
    
    24.11
    
    
    24.68
    
    
    21.64Chemicals
    
    
    115.45
    
    
    53.90
    
    
    41.68Other
    
    
    17.63
    
    
    12.24
    
    
    9.24
  
  
 **Cheyenne
      Refinery:****Year
      Ended December 31,**
    
    **2004**
    
    **2003**
    
    **2002**Charges
      (bpd)Light
      crude
    
    
    6,645
    
    
    5,405
    
    
    4,070Heavy
      crude
    
    
    38,408
    
    
    40,284
    
    
    37,231Other
      feed and blend stocks
    
    
    4,392
    
    
    5,966
    
    
    4,882Total
    
    
    49,445
    
    
    51,655
    
    
    46,183Manufactured
      product yields (bpd)Gasoline
    
    
    20,039
    
    
    20,518
    
    
    18,196Diesel
      and jet fuel
    
    
    14,387
    
    
    15,044
    
    
    13,434Asphalt
    
    
    7,475
    
    
    7,530
    
    
    7,437Other
    
    
    5,839
    
    
    6,822
    
    
    5,855Total
    
    
    47,740
    
    
    49,914
    
    
    44,922Total
      product sales (bpd)Gasoline
    
    
    26,744
    
    
    26,836
    
    
    24,559Diesel
      and jet fuel
    
    
    14,581
    
    
    15,091
    
    
    13,361Asphalt
    
    
    7,427
    
    
    7,260
    
    
    7,490Other
    
    
    5,044
    
    
    4,708
    
    
    4,243Total
    
    
    53,796
    
    
    53,895
    
    
    49,653Refinery
      operating margin information (per sales barrel)Refined
      products revenue
    
    $
    45.50
    
    $
    35.61
    
    $
    29.91Raw
      material, freight and other costs (FIFO inventory
    accounting)
    
    
    38.08
    
    
    29.40
    
    
    25.18Refinery
      operating expenses, excluding depreciation
    
    
    3.68
    
    
    3.12
    
    
    3.02Depreciation
      and amortization
    
    
    0.90
    
    
    0.79
    
    
    0.83Average
      light/heavy crude oil differential (per barrel)
    
    $
    9.90
    
    $
    7.10
    
    $
    4.77Average
      gasoline crack spread (per barrel)
    
    $
    9.33
    
    $
    7.32
    
    $
    6.44Average
      diesel crack spread (per barrel)
    
    
    9.34
    
    
    6.57
    
    
    4.99Average
      sales price (per sales barrel)Gasoline
    
    $
    53.28
    
    $
    41.42
    
    $
    35.22Diesel
      and jet fuel
    
    
    52.35
    
    
    39.00
    
    
    32.16Asphalt
    
    
    24.11
    
    
    24.68
    
    
    21.64Other
    
    
    15.98
    
    
    8.44
    
    
    6.68
  
  **El
      Dorado Refinery:****Year
      Ended December 31,**
    
    **2004**
    
    **2003**
    
    **2002**Charges
      (bpd)Light
      crude
    
    
    30,841
    
    
    25,909
    
    
    31,614Heavy
      and intermediate crude
    
    
    72,254
    
    
    75,623
    
    
    73,141Other
      feed and blend stocks
    
    
    12,218
    
    
    12,440
    
    
    12,878Total
    
    
    115,313
    
    
    113,972
    
    
    117,633Manufactured
      product yields (bpd)Gasoline
    
    
    62,905
    
    
    63,931
    
    
    66,449Diesel
      and jet fuel
    
    
    38,706
    
    
    38,111
    
    
    40,002Chemicals
    
    
    939
    
    
    842
    
    
    369Other
    
    
    10,273
    
    
    9,715
    
    
    9,061Total
    
    
    112,823
    
    
    112,599
    
    
    115,881Total
      product sales (bpd)Gasoline
    
    
    63,954
    
    
    63,006
    
    
    67,430Diesel
      and jet fuel
    
    
    38,237
    
    
    38,516
    
    
    40,017Chemicals
    
    
    841
    
    
    842
    
    
    439Other
    
    
    9,161
    
    
    9,410
    
    
    8,993Total
    
    
    112,193
    
    
    111,774
    
    
    116,879Refinery
      operating margin information (per sales barrel)Refined
      products revenue
    
    $
    48.12
    
    $
    36.01
    
    $
    29.78Raw
      material, freight and other costs (FIFO inventory
    accounting)
    
    
    40.98
    
    
    31.43
    
    
    25.93Refinery
      operating expenses, excluding depreciation
    
    
    3.59
    
    
    3.41
    
    
    2.90Refinery
      depreciation
    
    
    0.35
    
    
    0.32
    
    
    0.28WTI/WTS
      crude oil differential (per barrel)
    
    $
    3.74
    
    $
    2.68
    
    $
    1.36Average
      gasoline crack spread (per barrel)
    
    $
    8.31
    
    $
    6.86
    
    $
    5.68Average
      diesel crack spread (per barrel)
    
    
    6.59
    
    
    4.45
    
    
    3.63Average
      sales price (per sales barrel)Gasoline
    
    $
    51.03
    
    $
    38.99
    
    $
    32.30Diesel
      and jet fuel
    
    
    48.84
    
    
    36.09
    
    
    29.75Chemicals
    
    
    115.45
    
    
    53.90
    
    
    41.68Other
    
    
    18.53
    
    
    14.13
    
    
    10.45
 
 
 **Other
Properties**
 We lease
approximately 6,500 square feet of office space in Houston for our corporate
headquarters under a lease expiring in October 2009. For our refining operations
headquarters, we lease approximately 28,000 square feet in Denver, Colorado
under a four and a half year sublease expiring in December 2006. We lease
approximately ten acres of land, including a building and railroad spur in Grand
Island, Nebraska, under a ten-year lease expiring January 31, 2009, on which our
asphalt and terminal storage facility are located.
 
 
 **Item 3.** **Legal
Proceedings**
 
 **Beverly
Hills Lawsuits** .
Our 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 have been named in six such suits: Moss et al. v.
Veneco, Inc. et al., filed in June 2003; Ibraham et al. v. City of Beverly Hills
et al., filed in July 2003; Yeshoua et al. v. Veneco, Inc. et al., filed in
August 2003; Jacobs v. Wainoco Oil & Gas Company et al., filed in December
2003; Bussel et al. v. Veneco, Inc. et al., filed in January 2004; and Steiner
et al. v. Venoco Inc. et al., filed in May 2004. Other defendants in these
lawsuits 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 six pending lawsuits have been
related to one another and have been 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. A case management order has been entered in the case pursuant to
which 12 plaintiffs have been selected as the initial group of plaintiffs to go
to trial, discovery has commenced and a preliminary trial date has been set for
July 25, 2005.
 The oil
production site operated by our subsidiary was a modern facility and was
operated with a high level of safety and responsibility. We believe that our
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, we 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. In October 2003, we paid $6.25 million to the insurance company
(which included an indemnity premium of $5.75 million and a $500,000
administration fee) and also funded with the insurance company a commutation
account of approximately $19.5 million, from which the insurance company is
funding the first costs under the policy including, but not limited to, the
costs of defense of the claims. The policy covers defense costs and any payments
made to claimants, up to an aggregate limit of $120 million, including
coinsurance by us of up to $3.9 million of the coverage between $40 million and
$120 million. As of December 31, 2004, the commutation account balance was
approximately $16.4 million. We also paid $772,500 to the State of California
for insurance tax on the premium in 2003, of which $600,000 was refunded in
2004. We have the right to terminate the policy at any time after September 30,
2004 and prior to September 30, 2008, and receive a refund of the unearned
portion of the premium (approximately $4.0 million as of December 31, 2004, and
declining by approximately $1.1 million each year) 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. We are also
seeking coverage with respect to the Beverly Hills, California claims from the
insurance companies that provided policies to us during the 1985 to 1995
period.
 We
believe that neither the claims that have been made, the six pending lawsuits,
nor other potential future litigation, by which similar or related claims may be
asserted against us or our subsidiary, will result in any material liability or
have any material adverse effect upon our financial position or results of
operations.
 
 **Holly
Lawsuit** . On
August 20, 2003, we announced that Holly had advised us that it was not willing
to proceed with the merger agreement previously announced on March 31, 2003 on
the agreed terms. As a result, we filed suit for damages in the Delaware Court
of Chancery. On September 2, 2003, Holly filed an answer and counterclaims,
denying our claims, asserting that we repudiated the merger agreement by filing
the Delaware lawsuit, and claiming among other things that the Beverly Hills,
California litigation caused us to be in breach of our representations and
warranties in the merger agreement. We have denied all of Holly’s counterclaims.
Trial on the suit and Holly’s counterclaims concluded on March 5, 2004. Oral
arguments were held on May 4, 2004, and we are awaiting a decision. We believe
that the counterclaims filed against us by Holly will not result in any material
liability or have any material adverse effect upon our financial position or
results of operations.
 
 **MTBE
Concentration Lawsuits** . In
November 2003, our El Dorado Refinery (owned by our subsidiary, Frontier El
Dorado Refining Company (“FEDRC”)) was included as one of 52 defendants in four
lawsuits brought on behalf of 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 (the “Kansas Plaintiffs”) alleging
unspecified damages for contamination of groundwater/public water wells by
methyl tertiary butyl ether (“MTBE”) and tertiary butyl alcohol, a degradation
product of MTBE. These four cases were removed to federal court and were then
transferred with other similar cases to a federal district court in New York to
be presided over by one federal court judge. In November 2004, our Cheyenne
Refinery (owned by our subsidiary, Frontier Refining Inc (“FRI”)) was notified
that it had been added as a defendant to these same four cases involving Kansas
Plaintiffs. Because neither FEDRC nor FRI had either manufactured MTBE or
provided MTBE blended gasoline in the Kansas marketplace, the Kansas Plaintiffs
voluntarily dismissed both FEDRC and FRI in January 2005. These voluntary
dismissals are without prejudice. Accordingly, the Kansas Plaintiffs are able,
if they have the required evidentiary support, to add either FEDRC or FRI back
into the litigation. However, given the basis for the dismissals, we continue to
believe that any potential liability would not have a material adverse effect on
our liquidity, financial position or results of operations.
 
 **Other.** We are
also involved in various other lawsuits which are incidental to our business. In
management’s opinion, the adverse determination of such lawsuits would not have
a material adverse effect on our liquidity, financial position or results of
operations.
 
 **Item 4.** **Submission of Matters to a
Vote of Security Holders**
 
 None.
 
 
 **PART
II**
 
 **Item 5.****Market
for Registrant’s Common Equity and Related Stockholder
Matters**
 
 Our
common stock is listed on the New York Stock Exchange under the symbol FTO. The
quarterly high and low sales prices as reported on the New York Stock Exchange
for 2004 and 2003 are shown in the following table:
 
 **2004**
    **High**
    **Low**Fourth
      quarter
      Third
      quarter
      Second
      quarter
      First
      quarter
    $
      26.93
      23.70
      21.19
      19.85
    $
      22.24
      18.23
      17.00
      16.07**2003**
    **High**
    **Low**Fourth
      quarter
      Third
      quarter
      Second
      quarter
      First
      quarter
    $
      17.81
      16.14
      18.16
      18.25
    $
      14.70
      13.91
      15.08
      14.01
 
 The
approximate number of holders of record for our common stock as of February 18,
2005 was 1,046. Quarterly cash dividends of $.05 per share have been declared on
our common stock for each quarter beginning with the quarter ended June 2001 and
through the quarter ended June 30, 2004. The quarterly cash dividend was
increased to $.06 per share for the quarters ended September 30, 2004 and
December 31, 2004.
 
 
 
 **Item 6. Selected Financial Data**
 
 **Five
      Year Financial Data****2004**
    
    **2003**
    
    **2002**
    
    **2001**
    
    **2000***(Dollars
      in thousands except per share amounts)*Revenues
    
    $
    2,861,716
    
    $
    2,170,503
    
    $
    1,813,750
    
    $
    1,888,401
    
    $
    2,045,157Operating
      income
    
    
    143,549
    
    
    51,864
    
    
    27,899
    
    
    164,100
    
    
    70,655Net
      income
    
    
    69,764
    
    
    3,232
    
    
    1,028
    
    
    107,653
    
    
    37,206Basic
      earnings per share
    
    
    2.62
    
    
    0.12
    
    
    0.04
    
    
    4.12
    
    
    1.36Diluted
      earnings per share
    
    
    2.55
    
    
    0.12
    
    
    0.04
    
    
    4.00
    
    
    1.34Net
      cash provided by (used by) operating activities
    
    
    177,899
    
    
    (6,005
    )
    
    50,822
    
    
    138,575
    
    
    66,346Net
      cash used in investing activities
    
    
    (43,107
    )
    
    (34,300
    )
    
    (37,117
    )
    
    (22,824
    )
    
    (12,688
    )Net
      cash used in financing activities
    
    
    (74,923
    )
    
    (7,539
    )
    
    (5,336
    )
    
    (76,202
    )
    
    (27,557
    )Working
      capital
    
    
    97,261
    
    
    38,621
    
    
    108,253
    
    
    109,064
    
    
    43,610Total
      assets
    
    
    754,400
    
    
    642,297
    
    
    628,877
    
    
    581,746
    
    
    588,213Long-term
      debt
    
    
    150,000
    
    
    168,689
    
    
    207,966
    
    
    208,880
    
    
    239,583Shareholders’
      equity
    
    
    240,113
    
    
    169,277
    
    
    168,258
    
    
    169,204
    
    
    81,424Dividends
      declared per common share
    
    
    0.22
    
    
    0.20
    
    
    0.20
    
    
    0.15
    
    
    -Adjusted
      EBITDA (1)
    
    
    180,168
    
    
    80,696
    
    
    55,231
    
    
    189,110
    
    
    93,662
 (1)
    Adjusted
      EBITDA represents income before interest expense, interest income, merger
      financing termination costs (includes both interest expense and income),
      income tax, and depreciation and amortization. Adjusted EBITDA is not a
      calculation based upon generally accepted accounting principles; however,
      the amounts included in the adjusted EBITDA calculation are derived from
      amounts included in our consolidated financial statements included in Item
      8 of this Form 10-K. Adjusted 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. Adjusted EBITDA is not necessarily comparable to
      similarly titled measures of other companies. Adjusted EBITDA is presented
      here because it enhances an investor’s understanding of our ability to
      satisfy principal and interest obligations with respect to our
      indebtedness and to use cash for other purposes, including capital
      expenditures. Adjusted EBITDA is also used for internal analysis and as a
      basis for financial covenants. Our adjusted EBITDA is reconciled to net
      income as follows:
 
 **2004**
    
    **2003**
    
    **2002**
    
    **2001**
    
    **2000***(in
      thousands)*Net
      income
    
    $
    69,764
    
    $
    3,232
    
    $
    1,028
    
    $
    107,653
    
    $
    37,206Add
      provision for income taxes
    
    
    42,339
    
    
    2,956
    
    
    1,060
    
    
    28,073
    
    
    2,075Add
      interest expense and otherfinancing
      costs
    
    
    37,573
    
    
    28,746
    
    
    27,613
    
    
    31,146
    
    
    34,738Subtract
      interest income
    
    
    (1,716
    )
    
    (1,109
    )
    
    (1,802
    )
    
    (2,772
    )
    
    (3,364
    )Add
      merger financing terminationcosts,
      net
    
    
    -
    
    
    18,039
    
    
    -
    
    
    -
    
    
    -Add
      depreciation andamortization
    
    
    32,208
    
    
    28,832
    
    
    27,332
    
    
    25,010
    
    
    23,007Adjusted
      EBITDA
    
    $
    180,168
    
    $
    80,696
    
    $
    55,231
    
    $
    189,110
    
    $
    93,662
 
 
 
 **Five
      Year Operating Data****2004**
    
    **2003**
    
    **2002**
    
    **2001**
    
    **2000**Charges
      (bpd)Light
      crude
    
    
    37,486
    
    
    31,314
    
    
    35,684
    
    
    31,456
    
    
    35,605Heavy
      crude (1)
    
    
    110,662
    
    
    115,907
    
    
    110,372
    
    
    111,061
    
    
    105,529Other
      feed and blend stocks
    
    
    16,609
    
    
    18,407
    
    
    17,760
    
    
    15,538
    
    
    14,884Total
      charges
    
    
    164,757
    
    
    165,628
    
    
    163,816
    
    
    158,055
    
    
    156,018Manufactured
      product yields (bpd)Gasoline
    
    
    82,944
    
    
    83,449
    
    
    84,645
    
    
    78,126
    
    
    76,795Diesel
      and jet fuel
    
    
    53,093
    
    
    53,156
    
    
    53,436
    
    
    51,210
    
    
    50,924Chemicals
      (2)
    
    
    939
    
    
    842
    
    
    369
    
    
    1,370
    
    
    1,804Asphalt
      and other
    
    
    23,587
    
    
    24,066
    
    
    22,352
    
    
    24,483
    
    
    23,363Total
      manufactured product yields
    
    
    160,563
    
    
    161,513
    
    
    160,802
    
    
    155,189
    
    
    152,886Product
      sales (bpd)Gasoline
    
    
    90,698
    
    
    89,842
    
    
    91,989
    
    
    83,737
    
    
    83,070Diesel
      and jet fuel
    
    
    52,818
    
    
    53,606
    
    
    53,378
    
    
    51,539
    
    
    51,568Chemicals
      (2)
    
    
    841
    
    
    842
    
    
    439
    
    
    1,413
    
    
    1,964Asphalt
      and other
    
    
    21,632
    
    
    21,377
    
    
    20,726
    
    
    22,411
    
    
    21,556Total
      product sales
    
    
    165,989
    
    
    165,667
    
    
    166,532
    
    
    159,100
    
    
    158,158Average
      sales price (per barrel)Gasoline
    
    $
    51.70
    
    $
    39.72
    
    $
    33.08
    
    $
    35.85
    
    $
    38.09Diesel
      and jet fuel
    
    
    49.81
    
    
    36.91
    
    
    30.35
    
    
    34.12
    
    
    37.19Chemicals
      (2)
    
    
    115.45
    
    
    53.90
    
    
    41.68
    
    
    70.81
    
    
    70.52Asphalt
      and other
    
    
    19.85
    
    
    16.46
    
    
    13.72
    
    
    14.07
    
    
    16.14Refinery
      operating margin information (per sales barrel)Refined
      products revenue
    
    $
    47.27
    
    $
    35.88
    
    $
    29.82
    
    $
    32.53
    
    $
    35.20Raw
      material, freight and other costs
    
    
    40.04
    
    
    30.77
    
    
    25.71
    
    
    25.69
    
    
    30.41Refinery
      operating expenses,excluding
      depreciation
    
    
    3.62
    
    
    3.31
    
    
    2.93
    
    
    3.27
    
    
    3.07Depreciation
      and amortization
    
    
    0.53
    
    
    0.47
    
    
    0.44
    
    
    0.42
    
    
    0.39Average
      gasoline crack spread (per barrel)
    
    $
    8.61
    
    $
    7.00
    
    $
    5.88
    
    $
    8.91
    
    $
    5.76Average
      diesel crack spread (per barrel)
    
    
    7.35
    
    
    5.05
    
    
    3.97
    
    
    7.91
    
    
    5.64Average
      WTI crude oil price at Cushing, OK (per barrel)
    
    $
    41.85
    
    $
    31.89
    
    $
    26.17
    
    $
    26.09
    
    $
    31.25Average
      light/heavy crude oil differential (per barrel)
    
    $
    9.90
    
    $
    7.10
    
    $
    4.77
    
    $
    7.62
    
    $
    5.88Average
      WTI/WTS crude oil differential (per barrel)
    
    
    3.74
    
    
    2.68
    
    
    1.36
    
    
    3.10
    
    
    2.06
 
 (1)
    Includes
      intermediate varieties of crude oil used by the El Dorado
      Refinery.
 (2)
    During
      2002, the process of shutting down the phenol and cumene units at the El
      Dorado Refinery began and by year-end, we had discontinued the production
      of phenol and acetone and began producing and selling
    benzene.
 ****
 
 **Item 7.  Management’s Discussion and Analysis of Financial
Condition and****Results of Operations**
 
 **General**
 Frontier
operates the Refineries in Cheyenne, Wyoming and El Dorado, Kansas as previously
discussed in Part I, Item 1 of this Form 10-K. We focus our marketing efforts in
the Rocky Mountain and Plains States regions of the United States. We purchase
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 in
Part I, Item 6 of this Form 10-K, which provides key operating information for
our combined Refineries. Data for each Refinery is included in Part I, Item 2 of
this Form 10-K, our quarterly reports on Form 10-Q and on our web site address:
http://www.frontieroil.com.
 The three
significant indicators of our profitability reflected in the operating data of
the analysis referred to above are the gasoline and diesel crack spreads, the
light/heavy crude oil differential and the WTI/WTS crude oil differential. Other
significant factors that influence our results are Refinery utilization, crude
oil price trends, asphalt and by-product margins and refinery operating expenses
(including natural gas prices and turnaround, or planned maintenance activity).
We typically do not use derivative instruments to offset price risk on our base
level of operating inventories. Under our FIFO inventory accounting method,
crude oil price trends can cause significant fluctuation in the inventory
valuation of our crude oil, unfinished products and finished products resulting
in FIFO inventory gains when crude oil prices increase and FIFO inventory losses
when crude oil prices decrease during the reporting period. See “Price Risk
Management Activities” under Item 7A for a discussion of our utilization of
derivative contracts.
 The price
of crude oil on the New York Mercantile Exchange was very volatile during 2004.
The price began the year at $32.52 per barrel, reached a yearly high of $55.17
per barrel in October, and then declined to $43.45 per barrel by December 31,
2004. The price of crude oil increased during 2004 as the oil market
supply/demand fundamentals continued to support higher prices. Demand for crude
oil continued to increase throughout the world in 2004, especially in China,
because of improved economic growth. Excess supply capability within both OPEC
and non-OPEC countries has declined significantly in recent years. Industry
experts estimate that excess supply capacity for OPEC is currently less than 2
million bpd compared to estimated world oil demand of nearly 83 million bpd in
2004. These factors, along with others such as geopolitical risk, have resulted
in higher oil prices and OPEC’s increased ability to manage prices. The increase
in crude oil prices, along with additional crude oil production in 2004 being
primarily heavy and/or sour crude oil, increased our crude oil differentials
during 2004.
 In the
U.S., gasoline demand increased approximately 140,000 bpd, or 2.2%, in 2004.
Production of gasoline in the U.S. and imports of gasoline into the U.S. were
required to comply with the new low sulfur gasoline requirements, and production
was reduced by the elimination of MTBE blending in major markets. At times
during 2004, production was unable to meet supply, thereby resulting in low
levels of gasoline inventories during the 2004 driving season. These factors led
to higher spring and summer gasoline crack spreads than we had received in prior
years. Diesel crack spreads improved later in the year, as diesel inventories
were below five-year averages entering the heating oil season.
 We
believe that many of the market fundamentals that caused higher crude oil prices
and wider crude oil differentials in 2004 will continue into 2005. Although we
believe that gasoline and diesel crack spreads will remain attractive because of
increasing demand, they may not meet or exceed 2004 gasoline and diesel crack
spreads due to higher inventories of gasoline entering the spring and summer
driving seasons of 2005 and less planned turnaround activity in the industry in
early 2005 compared to the same period in 2004.
 
 **2004
Compared with 2003**
 **Overview
of Results:** We had
net income for the year ended December 31, 2004 of $69.8 million, or $2.55 per
diluted share, compared to net income of $3.2 million, or $0.12 per diluted
share, in the same period in 2003. Our operating income of $143.5 million for
the year ended December 31, 2004 was an increase of $91.7 million from the $51.9
million operating income for the comparable period in 2003. The average diesel
crack spread was significantly higher during 2004 ($7.35 per barrel) than in
2003 ($5.05 per barrel). The average gasoline crack spread was also higher
during 2004 ($8.61 per barrel) than in 2003 ($7.00 per barrel), and both the
light/heavy and WTI/WTS crude oil differentials improved.
 Our net
income for the year ended December 31, 2004 was reduced by $14.9 million pretax
($9.2 million after tax) in additional costs associated with the redemption of
our 113⁄4% Senior Notes. We used available cash and proceeds from a new $150.0
million 65⁄8% Senior Notes offering to redeem the 113⁄4% Senior Notes. This
refinancing will reduce interest expense in future years by $10.1 million per
year. Our net income for the year ended December 31, 2004 was also reduced by
the legal costs associated with the termination of the Holly merger and the
Beverly Hills litigation. 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 it was not willing
to proceed with our merger agreement on the agreed terms. As a result, we filed
suit against Holly for damages in Delaware. Merger termination and legal costs
reduced earnings in the year ended December 31, 2004 by $3.8 million pretax
($2.4 million after tax), and costs related to the Beverly Hills litigation
reduced earnings in the year ended December 31, 2004 by an additional $5.6
million pretax ($3.4 million after tax). Our net income for the year ended
December 31, 2004 was increased by $4.4 million pretax ($2.7 million after tax)
from the gain on involuntary conversion of assets related to the fire that
occurred on January 19, 2004 in the furnaces of the Cheyenne Refinery coker.
 **Specific
Variances:** Refined
product revenues increased $702.0 million, or 32%, from $2.2 billion to $2.9
billion for the year ended December 31, 2004 compared to the same period in
2003. This increase was due to increased sales prices ($11.39 higher average per
sales barrel), and slightly higher sales volumes in 2004 (322 more bpd). Sales
prices increased primarily as a result of increased crude oil prices and net
improvements in the gasoline and diesel crack spreads. Average gasoline prices
increased from $39.72 per sales barrel in 2003 to $51.70 per sales barrel in
2004. Sales volumes of gasoline increased from 89,842 bpd in 2003 to 90,698 bpd
in 2004. Average diesel and jet fuel prices increased from $36.91 per sales
barrel in 2003 to $49.81 per sales barrel during 2004. However, sales volumes of
diesel and jet fuel decreased 788 bpd from 53,606 bpd during the year ended
December 31, 2003 to 52,818 bpd during the same period in 2004. Total product
sales volumes overall increased only slightly from 165,667 bpd in the year ended
December 31, 2003 to 165,989 bpd in the same period in 2004.
 Yields of
gasoline decreased 505 bpd, or less than 1%, from 83,449 bpd in the year ended
December 31, 2003 to 82,944 bpd in the same period in 2004. Yields of diesel and
jet fuel remained fairly flat year to year, decreasing only 63 bpd, from 53,156
bpd in the year ended December 31, 2003 to 53,093 bpd in the same period in
2004. Yields for the year ended December 31, 2004 for the El Dorado Refinery
were nearly flat, increasing just 224 bpd from the year ended December 31, 2003.
Yields for the year ended December 31, 2004 for the Cheyenne Refinery were lower
than in the same period in 2003 primarily because of the coker furnace fire (see
Note 3 in the “Notes to Consolidated Financial Statements”). The Cheyenne
Refinery coking unit was out of service for one month in the first quarter of
2004.
 Other
revenues decreased $10.8 million to a $9.9 million loss for the year ended
December 31, 2004 compared to income of nearly $1.0 million for the same period
in 2003 due to $10.3 million in net losses from derivative contracts accounted
for using mark-to-market accounting in the year ended December 31, 2004,
compared to net losses of $268,000 for the same period in 2003. See “Price Risk
Management Activities” under Item 7A for a discussion of our utilization of
commodity derivative contracts. Processing income from our Cheyenne Refinery
coker was $834,000 less during the year ended December 31, 2004, compared to the
same period in 2003 due to the July 2004 conclusion of the long-term resid
processing agreement with Suncor Energy (USA) Inc. (“Suncor”), and the coker
being out of service for a portion of 2004 from the previously mentioned fire.
The processing agreement entitled Suncor to process in the Cheyenne Refinery
coker up to 3,300 bpd of resid, a heavy end by-product of the refining process.
 Raw
material, freight and other costs include crude oil and other raw materials used
in the refining process, purchased products and blendstocks, freight costs for
FOB destination sales, as well as the impact of changes in inventory under the
FIFO inventory accounting method. The average price of crude oil was higher in
the year ended December 31, 2004 than in the same period in 2003. The average
price of WTI crude oil priced at Cushing, Oklahoma was $41.85 per barrel in the
year ended December 31, 2004 compared to $31.89 per barrel in the same period in
2003. Raw material, freight and other costs increased by $571.7 million, or
$9.27 per sales barrel, during the year ended December 31, 2004 when compared to
the same period in 2003. The increase in raw material, freight and other costs
was due to higher average crude prices and more crude oil charges, offset by
higher inventory gains from rising prices in the year ended December 31, 2004
compared to the year ended December 31, 2003. We also benefited from improved
crude oil differentials during the year ended December 31, 2004 when compared to
the same period in 2003. For the year ended December 31, 2004, we realized a
reduction in raw material, freight and other costs as a result of inventory
gains of approximately $19.8 million after tax ($32.0 million pretax, comprised
of $6.1 million at the Cheyenne Refinery and $25.9 million at the El Dorado
Refinery) because of increasing crude oil and refined product prices. For the
year ended December 31, 2003, we realized a reduction 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 a $4.2 million gain for the El
Dorado Refinery and a $3.0 million gain for the Cheyenne Refinery).
 The
Cheyenne Refinery raw material, freight and other costs of $38.08 per sales
barrel for the year ended December 31, 2004 increased from $29.40 per sales
barrel in the same period in 2003 due to higher crude oil prices offset by
higher inventory gains and an improved light/heavy crude oil differential. The
heavy crude oil utilization rate at the Cheyenne Refinery expressed as a
percentage of the total crude oil charge decreased to 85% in the year ended
December 31, 2004 from 88% in 2003, as we processed more light crude oil due to
the coker being out of service for approximately one month. The light/heavy
crude oil differential for the Cheyenne Refinery averaged $9.90 per barrel in
the year ended December 31, 2004 compared to $7.10 per barrel in the same period
in 2003.
 The El
Dorado Refinery raw material, freight and other costs of $40.98 per sales barrel
for the year ended December 31, 2004 increased from $31.43 per sales barrel in
the same period in 2003 due to higher average crude oil prices offset by higher
inventory gains and an improved WTI/WTS crude oil differential. The WTI/WTS
crude oil differential increased from an average of $2.68 per barrel in the year
ended December 31, 2003 to $3.74 per barrel in the same period in
2004.
 Refinery
operating expenses, excluding depreciation, include both the variable costs
(energy and utilities) and the fixed costs (salaries, taxes, maintenance costs
and other) of operating the Refineries. Refinery operating expenses, excluding
depreciation, were $219.8 million, or $3.62 per sales barrel, in the year ended
December 31, 2004 compared to $200.4 million, or $3.31 per sales barrel, in the
comparable period of 2003.
 The
Cheyenne Refinery operating expenses, excluding depreciation, were $72.4
million, or $3.68 per sales barrel, in the year ended December 31, 2004 compared
to $61.4 million, or $3.12 per sales barrel, in the comparable period of 2003.
The increased expenses included higher costs in natural gas ($3.1 million),
maintenance ($3.2 million), salaries ($1.5 million), a 2004 bonus accrual ($1.3
million) and increased environmental expenses ($2.0 million). The higher natural
gas costs resulted primarily from an average increase in price of $1.21 per
mmbtu, along with also utilizing approximately 11% more volumes of natural gas
during the year ended December 31, 2004 when compared to the same period in
2003.
 The El
Dorado Refinery operating expenses, excluding depreciation, were $147.4 million,
or $3.59 per sales barrel, in the year ended December 31, 2004, increasing from
$139.0 million, or $3.41 per sales barrel, for the year ended December 31, 2003
primarily due to higher costs in natural gas ($6.3 million), a 2004 bonus
accrual ($1.9 million) and higher salaries and benefits ($1.0 million), offset
by reduced costs in consulting and legal ($1.0 million). The higher natural gas
costs resulted primarily from an average increase in price of $0.87 per mmbtu,
along with also utilizing approximately 2% more volumes of natural gas during
the year ended December 31, 2004 when compared to the same period in
2003.
 Selling
and general expenses, excluding depreciation, increased $10.0 million, or 50%,
from $19.9 million for the year ended December 31, 2003 to $29.9 million for the
year ended December 31, 2004 due to increased costs related to the Beverly Hills
litigation and increases in salaries. Costs related to the Beverly Hills
litigation during the year ended December 31, 2004 were $5.6 million ($4.1
million in legal costs, substantially all of which have been paid or will be
paid from the Commutation Account, and $1.5 million amortization of the
previously purchased loss mitigation insurance premium), as opposed to $1.8
million in the same period in 2003. Salaries increased by $5.5 million for the
year ended December 31, 2004 compared to the same period in 2003, primarily due
to $3.8 million in bonuses being accrued in 2004, while none were accrued in
2003.
 Merger
termination and legal costs of $3.8 million for the year ended December 31, 2004
include legal costs associated with the termination of the anticipated 2003
Holly merger and resulting lawsuit, compared to $8.7 million in merger
termination and legal costs for the comparable period in 2003.
 Depreciation
and amortization increased $3.4 million, or 12%, for the year ended December 31,
2004 compared to the same period in 2003 because of increased capital investment
in our Refineries.
 Interest
expense and other financing costs of $37.6 million for the year ended December
31, 2004 increased $8.8 million, or 31%, from $28.7 million in the comparable
period in 2003. Interest expense and other financing costs for the year ended
December 31, 2004 included $14.9 million in costs related to the redemption of
our 113⁄4% Senior Notes and subsequent reduced interest expense on our new $150.0
million 65⁄8% Senior Note debt issuance. This refinancing will reduce interest
expense in future years by $10.1 million per year. The $14.9 million in
redemption-related costs includes $10.4 million of premium, the write-off at
redemption of the remaining unamortized $1.5 million of issue discount, $2.7
million for the write-off at redemption of the remaining unamortized debt issue
costs, and $0.3 million of legal and administrative costs to facilitate the
tender offer and redemption. We also had no interest on the 91⁄8% Senior Notes
during the year ended December 31, 2004, as they were redeemed in December 2003
($3.5 million in interest expense for the year ended December 31, 2003).
Interest expense and other financing costs for the year ended December 31, 2003
also included $1.2 million of premium paid upon redemption of our 91⁄8% Senior
Notes in December 2003. Average debt outstanding decreased to $209 million
during the year ended December 31, 2004 from $236 million (excluding merger
debt) for the same period in 2003. Capitalized interest, which reduced interest
expense and other financing costs, was $65,000 during the year ended December
31, 2004 compared to $586,000 in the comparable period of 2003.
 Interest
income increased $607,000, or 55%, from $1.1 million in the year ended December
31, 2003 to $1.7 million in the year ended December 31, 2004, as we had more
cash available to invest.
 The gain
on involuntary conversion of assets relates to the fire that occurred on January
19, 2004 in the furnaces of the coking unit at the Cheyenne Refinery. For the
year ended December 31, 2004, the gain represents the settlement proceeds of
$7.1 million from our insurers less $1.6 million of expenses related to clean-up
costs and $1.1 million of net property, plant and equipment written-off due to
the fire.
 The
merger financing termination costs, net, during the year ended December 31, 2003
were $18.0 million, which related to the 8% Senior Notes issued to finance the
contemplated Holly merger and included interest expense, issue discount,
financing issue costs and redemption premium, net of $752,000 interest income
earned on the escrow account.
 The
provision for income taxes for the year ended December 31, 2004 was $42.3
million on pretax income of $112.1 million (or 37.8%) reflecting the net benefit
of releasing our deferred tax valuation allowance offset by the effect of the
permanent book versus tax differences and prior year adjustments from our
current estimated effective tax rate of 38.2%. As of December 31, 2004, we have
no valuation allowance against our deferred tax assets. See Note 7 in the “Notes
to Consolidated Financial Statements” for detailed information on our deferred
tax assets. 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 2002 and 2003
expenses and an increase of $280,000 in the income tax provision for the year
ended December 31, 2003 resulting from an adjustment to the 2002 tax provision.
The new “American Jobs Creation Act of 2004” (“the Act”) provision providing tax
relief for manufacturers should result in reduced effective federal income tax
rates beginning in 2005. In December 2004, the Financial Accounting Standards
Board (“FASB”) staff issued FASB Staff Position (“FSP”) No. FAS 109-1 to provide
guidance on the application of FAS 109 to the provision within the Act that
provides tax relief to U.S. domestic manufacturers. The FSP states that the
manufacturers’ deduction set forth in the Act should be accounted for as a
special deduction in accordance with FAS 109 and not as a tax rate reduction. A
special deduction is accounted for by recording the benefit of the deduction in
the year in which it can be taken in our tax return, and not by adjusting
deferred tax assets and liabilities in the period of the Act’s enactment. The
FSP was effective upon issuance, and we have properly accounted for our deferred
taxes at December 31, 2004 in accordance with the FSP. Other certain provisions
of the Act should benefit Frontier by allowing us an accelerated depreciation
deduction of 75% of qualified capital costs incurred to achieve low sulfur
diesel fuel requirements and by providing a $0.05 per gallon credit on compliant
diesel fuel up to an amount equal to the remaining 25% of these qualified
capital costs for federal income tax purposes. (See “Environmental” under Note
10 in the “Notes to Consolidated Financial Statements.”)
 
 **2003
Compared with 2002**
 **Overview
of Results:** We had
net income for the year ended December 31, 2003 of $3.2 million, or $0.12 per
diluted share, compared to net income of $1.0 million, or $0.04 per diluted
share, for 2002. Our 2003 net income was negatively impacted by the termination
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 for 2003 increased $24.0 million from $27.9 million for 2002. The
major factors improving operating income were improved gasoline and diesel crack
spreads, increases in the light/heavy crude oil differential and WTI/WTS crude
oil differential 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 at both
Refineries, primarily due to higher natural gas costs.
 **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 bpd from
91,989 bpd during 2002 to 89,842 bpd 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 bpd from 53,378 bpd
during 2002 to 53,606 bpd in 2003. Total product sales volumes overall decreased
less than 1% from 166,532 bpd in 2002 to 165,667 bpd in 2003.
 Yields of
gasoline decreased 1,196 bpd, or 1%, from 84,645 bpd in 2002 to 83,449 bpd in
2003, and yields of diesel and jet fuel decreased 280 bpd, or less than 1%, from
53,436 bpd in 2002 compared to 53,156 bpd 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. During the first quarter of 2003,
the El Dorado Refinery’s charge and yield volumes were 20,682 bpd and 21,161 bpd
less respectively, than the first quarter of 2002; however upon completion of
the turnaround, the El Dorado Refinery operations were very strong during the
remainder of 2003, ending the year at only 3,661 fewer bpd of charges and 3,282
fewer bpd of yields than 2002. 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 resulting in
aggregate small increases in charge volumes of 1,812 bpd and yield volumes of
711 bpd.
 Other
revenues decreased $185,000 to $952,000 for the year ended December 31, 2003
compared to revenues of $1.1 million for the same period in 2002 due to $268,000
in net losses from derivative contracts accounted for using mark-to-market
accounting in the year ended December 31, 2003, compared to net income of
$108,000 for the same period in 2002 (see “Price Risk Management Activities” in
Item 7A), offset by increased processing income from our Cheyenne Refinery
coker.
 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
crude oil differential. 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 crude oil differential 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 crude
oil differential. The WTI/WTS crude oil differential increased from an average
of $1.36 per barrel in 2002 to $2.68 per barrel in 2003.
 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 lower 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
included transaction and ongoing legal costs (on an accrual basis) associated
with the termination of the anticipated merger and resulting lawsuit with
Holly.
 Depreciation
and amortization 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 91⁄8%
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 a 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
provision for income taxes 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 was
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.
 
 **Liquidity
and Capital Resources**
 Net cash
provided by operating activities was $177.9 million during the year ended
December 31, 2004 compared to net cash used by operating activities of $6.0
million during the year ended December 31, 2003. Our improved result of
operations was the largest contributor to improved cash flow, along with working
capital changes.
 Working
capital changes provided a total of $38.6 million of cash flows in the year
ended December 31, 2004 while using $25.9 million of cash flows in the
comparable period in 2003. The most significant provider of cash for working
capital changes during the year ended December 31, 2004 was the increase in
accounts payable of $58.1 million and the increase in accrued liabilities and
other of $11.6 million compared to a decrease in accounts payable of $4.3
million and an increase in accrued liabilities and other of only $1.2 million in
the 2003 comparable period. The increase in accounts payable was due to the
significant increase in crude oil prices during 2004. The increase in accrued
liabilities and other was primarily due to $7.0 million for bonuses accrued as
of December 31, 2004, which were based on 2004 operating results and will be
paid during the first quarter of 2005, compared to no accrued bonuses as of
December 31, 2003. The most significant working capital item offsetting the
positive cash flow impacts during the year ended December 31, 2004 was an
increase in inventories, which utilized cash of $32.9 million in the 2004
period. This was due to higher crude oil prices and resulting higher product
prices.
 During
the year ended December 31, 2004, we made net estimated federal and state income
tax payments of approximately $18.4 million ($21.6 million payments, net of a
federal tax refund received of $3.2 million).
 At
December 31, 2004, we had $124.4 million of cash and cash equivalents, working
capital of $97.3 million and $182.0 million of borrowing base availability for
additional borrowings under our revolving credit facility.
 We have a
Board of Director approved stock repurchase program to repurchase up to eight
million shares of our common stock. Through December 31, 2004, 4,367,366 shares
of common stock had been purchased under the stock repurchase program. We did
not initiate any additional purchases of common stock under the stock repurchase
program in 2004, 2003 nor in 2002. We received 215,599 shares in 2004 and 51,082
shares in 2003 of our common stock, now held as treasury stock, from employees
in cashless stock option exercises. We received 112,752 shares in 2004 and
37,556 shares in 2003 of our common stock, now held as treasury stock, from
employees to cover withholding taxes on stock option exercises. We also received
48,443 shares in 2004, 24,825 shares in 2003, and 19,041 shares in 2002 of our
common stock, now held as treasury stock, from employees to cover withholding
taxes on vested restricted stock.
 Capital
expenditures during the year ended December 31, 2004 were $46.5 million. These
2004 capital expenditures included approximately $19.3 million for the El Dorado
Refinery, $26.8 million for the Cheyenne Refinery, and $364,000 of capital for
expenditures in our Denver and Houston offices, our asphalt terminal in Nebraska
and for our share of crude pipeline projects. The approximately $19.3 million of
capital expenditures for our El Dorado Refinery included approximately $6.0
million to begin the ultra low sulfur diesel compliance project, as well as
operational, payout, safety, administrative, environmental and optimization
projects. The approximately $26.8 million of capital expenditures for our
Cheyenne Refinery included $7.8 million of capital incurred due to the Cheyenne
Refinery coker fire, $6.1 million incurred on the low sulfur gasoline project,
$250,000 to begin the ultra low sulfur diesel compliance project, as well as
environmental, operational, safety, administrative and payout projects.
 Compliance
with the upcoming ultra low sulfur diesel requirements at our Refineries will
require additional capital expenditures through mid-2006. The total capital,
including capitalized interest that we will utilize to comply with the
regulations is estimated to be approximately $14.0 million at the Cheyenne
Refinery and approximately $106.5 million at the El Dorado Refinery. The
expenditures for the ultra low sulfur diesel projects for 2004 were $250,000 at
the Cheyenne Refinery and $6.0 million at the El Dorado Refinery. The remaining
costs for the ultra low sulfur diesel projects at both Refineries are expected
to be spent in 2005 and 2006. The recently enacted “American Jobs Creation Act
of 2004” will allow us, as a small business refiner, to deduct for federal
income tax purposes 75% of the qualified costs related to these low sulfur
diesel expenditures in the years incurred as well as provide tax credits based
on the resulting production of ultra low sulfur diesel up to 25% of the
remaining qualified costs.
 Capital
expenditures aggregating approximately $146.8 million are currently planned for
2005, and include $118.1 million at our El Dorado Refinery, $28.2 million at our
Cheyenne Refinery, and $500,000 for capital expenditures in our Denver and
Houston offices, our asphalt terminal in Nebraska and for our share of crude
pipeline projects. The $118.1 million of planned capital expenditures for our El
Dorado Refinery includes approximately $90.5 million for the ultra low sulfur
diesel project discussed above, nearly $3.0 million of capital on the FCCU, to
be done in conjunction with the turnaround, as well as environmental,
operational, safety, administrative and payout projects. The $28.2 million of
planned capital expenditures for our Cheyenne Refinery includes approximately
$9.0 million for the ultra low sulfur diesel project discussed above, as well as
environmental, operational, safety, administrative and payout projects. Our 2005
capital expenditures will be funded with cash generated by our operations and
the utilization of a portion of our existing cash balance.
 As of
December 31, 2004, we had received payments of $5.0 million from our insurers
for reimbursement of costs related to the coker fire at the Cheyenne Refinery.
Additional proceeds of $2.1 million were received in early 2005 and were accrued
as of December 31, 2004.
 As of
December 31, 2004, we had $150.0 million principal of total consolidated debt,
of which all was long-term debt, as we had no borrowings under our revolving
credit facility. We also had $12.2 million outstanding letters of credit under
our revolving credit facility. We were in compliance with the financial
covenants of our revolving credit facility as of December 31, 2004. We had
shareholders’ equity of $240.1 million as of December 31, 2004. Operating cash
flows are affected by crude oil and refined product prices and other risks as
discussed in “Item 7A. Quantitative and Qualitative Disclosures About Market
Risks.”
 Under the
provisions of the purchase agreement with Shell 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 $60.0 million
per year of the El Dorado Refinery’s annual revenues less material costs and
operating costs, other than depreciation. The total amount of these contingent
payments is capped at $40.0 million, with an annual cap of $7.5 million. Based
on 2003 results, no payment was necessary in 2004. A payment of $7.5 million was
paid in early 2005, based on 2004 results, and was accrued as of December 31,
2004. Such contingency payments are recorded as additional acquisition costs.
Including the payment we made in early 2005, we have paid a total of $15.0
million to date for contingent earn-out payments.
 Our Board
of Directors declared quarterly cash dividends of $.05 per share in December
2003, March 2004, and June 2004 , which were paid in January 2004, April 2004,
and July 2004, respectively. Our Board of Directors declared quarterly cash
dividends of $.06 per share in September 2004 and December 2004, which was paid
in October 2004 and January 2005, respectively. The total cash required for the
dividend declared in December 2004 was approximately $1.6 million and was
accrued at year-end.
 On
October 1, 2004, we issued $150 million principal amount of 65⁄8% Senior Notes due
2011. The 65⁄8% Notes, which mature on October 1, 2011, were issued at par, and we
received net proceeds (after underwriting fees) of $147.2 million. Interest is
paid semi-annually. The 65⁄8% Notes are redeemable, at our option, at 103.313%
after October 1, 2007, declining to 100% in 2010. Prior to October 1, 2007, we
may at our option redeem the 65⁄8% Notes at a defined make-whole amount, plus
accrued and unpaid interest. We used a portion of the net proceeds from this
offering to fund a tender offer and consent solicitation for $64.9 million
principal of our 113⁄4% Senior Notes in October 2004 and redeemed on November 15,
2004, the remaining $105.6 million outstanding principal of our 113⁄4% Senior
Notes. Other cash expenditures related to the redemption included $10.4 million
of premium and $9.1 million of accrued interest payments made at the time of
consummation of the tender offer and redemption. These actions will reduce our
interest expense in future years by $10.1 million per year.
 
 **Contractual
Cash Obligations**
 The table
on the following page 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 2005 through 2011, 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
bpd 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. 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 Refinery. The
first contract, which began in 1997, is for 15 years and for an average of
13,800 bpd 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. Our crude oil supply agreement with Baytex includes an assignment of a
portion of our pipeline capacity obligation to it. In December 2003, we entered
into an expansion capacity agreement on the Express Pipeline for an additional
10,000 bpd of crude oil starting in April 2005 through 2015. Of the additional
10,000 bpd, we assigned 4,000 bpd to another party starting in April 2005
through March 2006. Our remaining Express Pipeline commitments range from a high
of 32,600 bpd in 2005, then reducing to 23,800 bpd in 2006 through early 2012,
and then reducing to 10,000 bpd through 2015. The amounts shown below for
transportation, terminalling and storage contractual obligations are net of
$25.0 million, the approximate cost of the pipeline capacity assigned to other
parties for the initial term of that agreement. The amounts shown below for
transportation, terminalling and storage contractual obligations also include
our anticipated commitments on the Spearhead pipeline. See Note 10 in the “Notes
to Consolidated Financial Statements” for more information on these commitments.
 
 **Contractual
      Cash Obligations**
    
    **Payments
      Due by Period****Total**
    
    **Within**
      **1
      Year**
    
    **Within**
      **2-3
      years**
    
    **Within**
      **4-5
      years**
    
    **After**
      **5
      years***(in
      thousands)*Long-term
      debt (1)
    
    $
    150,000
    
    $
    -
    
    $
    -
    
    $
    -
    
    $
    150,000Operating
      leases
    
    
    96,924
    
    
    12,679
    
    
    21,923
    
    
    19,394
    
    
    42,928Purchase
      obligations:Baytex
      crude supply (2)
    
    
    741,511
    
    
    246,856
    
    
    494,655
    
    
    -
    
    
    -Other
      crude supply, feedstocks andnatural
      gas (2)
    
    
    276,074
    
    
    275,074
    
    
    828
    
    
    172
    
    
    -Transportation,
      terminalling and storage
    
    
    161,686
    
    
    16,073
    
    
    30,703
    
    
    37,006
    
    
    77,904Ultra
      low sulfur diesel refinery projects (3)
    
    
    69,765
    
    
    63,395
    
    
    6,370
    
    
    -
    
    
    -Other
      goods and services
    
    
    6,088
    
    
    6,008
    
    
    80
    
    
    -
    
    
    -Total
      purchase obligations
    
    
    1,255,124
    
    
    607,406
    
    
    532,636
    
    
    37,178
    
    
    77,904Long-term
      accrued turnaround cost
    
    
    13,153
    
    
    -
    
    
    7,659
    
    
    5,350
    
    
    144Pension
      funding requirement (4)
    
    
    1,173
    
    
    1,173
    
    
    -
    
    
    -
    
    
    -Other
      long-term liabilities
    
    
    2,511
    
    
    -
    
    
    660
    
    
    351
    
    
    1,500Total
      contractual cash
    
    $
    1,518,885
    
    $
    621,258
    
    $
    562,878
    
    $
    62,273
    
    $
    272,476
 
 (1)
    Cash
      requirements for interest on the long-term debt are approximately $9.9
      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, $227.7 million
      relate to January and February 2005 feedstock and natural gas requirements
      of the Refineries.
 (3)
    The
      amounts for ultra low sulfur diesel refinery projects reflected here
      relate to our commitments as of December 31, 2004, not the total estimated
      costs of the projects. See “Environmental” under
      “Government Regulation” in Part I, Item I of this Form 10-K for total
      estimated costs of the projects.
 (4)
    Includes
      our estimated pension funding requirement in 2005 to our cash balance
      pension plan. Funding requirements for remaining years will be based on
      actuarial estimates and actual experience. Our retiree health care plan is
      unfunded. Future payments for retiree health care benefits are estimated
      for the next ten years in Note 9 “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”). Neither Frontier nor this entity
participates in any transactions, agreements or other contractual arrangements,
which would result in any off-balance sheet liabilities, or other arrangements
to us.
 
 **Environmental**
 See “Environmental” in Note 10 in the “Notes to Consolidated
Financial Statements.”
 
 **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 Sheets 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.
 **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 we believe that 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. See “New Accounting
Pronouncements,” under Note 2 in the “Notes to Consolidated Financial
Statements” for a discussion of FAS No. 123(R) which will require a change in
our method of accounting for stock based compensation in 2005. This will require
us to record compensation expense based on the fair value of the awards at the
grant date and will result in increased expenses; however, it is not expected to
have a material effect on our financial statements.
 
 **New
Accounting Pronouncements**
 See “New Accounting Pronouncements” under Note 2 in the
“Notes to Consolidated Financial Statements.” No new pronouncements are expected
to have a material impact on our financial statements.
 
 **Market
Risks**
 See the
Item 7A“Quantitative and Qualitative Disclosure about
Market Risk” and Notes 2 and 12in the “Notes to Consolidated Financial Statements” under “Price Risk
Management Activities” 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.
 
 
 **Item 7A. Quantitative and Qualitative Disclosure About Market
Risk**
 
 **Impact
of Changing Prices.** Our
revenues and cash flows, as well as estimates of future cash flows, are very
sensitive to changes in energy prices. Major shifts in the cost of crude oil,
and the prices of refined products and natural gas can result in large changes
in the operating margin from refining operations. These prices also determine
the carrying value of the Refineries’ inventories.
 **Price Risk Management Activities.** **** At times,
we enter into commodity derivative contracts to manage our price exposure to our
inventory positions, 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 the Consolidated Statements of Income as “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” in the Consolidated Statements of Income at each period end.
See “Price Risk Management Activities” under Notes 2
and 12 in the “Notes to Consolidated Financial
Statements.”
 
 
 **Item 8.** **Financial Statements and
Supplementary Data**
 
 **FRONTIER OIL CORPORATION AND
      SUBSIDIAIRES****CONSOLIDATED
      STATEMENTS OF INCOME****Years
      Ended December 31,****2004**
    
    **2003**
    
    **2002***(in
      thousands except per share data)***Revenues:**Refined
      products
    
    $
    2,871,592
    
    $
    2,169,551
    
    $
    1,812,613Other
    
    
    (9,876
    )
    
    952
    
    
    1,1372,861,716
    
    
    2,170,503
    
    
    1,813,750**Costs
      and Expenses:**Raw
      material, freight and other costs
    
    
    2,432,461
    
    
    1,860,795
    
    
    1,562,613Refinery
      operating expenses, excluding depreciation
    
    
    219,781
    
    
    200,383
    
    
    178,295Selling
      and general expenses, excluding depreciation
    
    
    29,893
    
    
    19,890
    
    
    17,611Merger
      termination and legal costs
    
    
    3,824
    
    
    8,739
    
    
    -Depreciation
      and amortization
    
    
    32,208
    
    
    28,832
    
    
    27,3322,718,167
    
    
    2,118,639
    
    
    1,785,851**Operating
      income**
    
    
    143,549
    
    
    51,864
    
    
    27,899Interest
      expense and other financing costs
    
    
    37,573
    
    
    28,746
    
    
    27,613Interest
      income
    
    
    (1,716
    )
    
    (1,109
    )
    
    (1,802
    )Gain
      on involuntary conversion of assets
    
    
    (4,411
    )
    
    -
    
    
    -Merger
      financing termination costs, net
    
    
    -
    
    
    18,039
    
    
    -31,446
    
    
    45,676
    
    
    25,811**Income
      before income taxes**
    
    
    112,103
    
    
    6,188
    
    
    2,088Provision
      for income taxes
    
    
    42,339
    
    
    2,956
    
    
    1,060**Net
      income**
    
    $
    69,764
    
    $
    3,232
    
    $
    1,028**Basic
      earnings per share of common stock**
    
    $
    2.62
    
    $
    0.12
    
    $
    0.04**Diluted
      earnings per share of common stock**
    
    $
    2.55
    
    $
    0.12
    
    $
    0.04The
      accompanying notes are an integral part of these consolidated financial
      statements.
 
 
 **FRONTIER OIL CORPORATION AND
      SUBSIDIAIRES****CONSOLIDATED
      BALANCE SHEETS****December
      31,****2004**
    
    **2003***(in
      thousands except share data)***ASSETS**Current
      assets:Cash
      and cash equivalents
    
    $
    124,389
    
    $
    64,520Trade
      receivables, net of allowance of $500 in both years
    
    
    78,733
    
    
    86,519Other
      receivables
    
    
    9,531
    
    
    1,834Inventory
      of crude oil, products and other
    
    
    156,934
    
    
    123,999Deferred
      tax assets
    
    
    6,748
    
    
    5,967Other
      current assets
    
    
    2,344
    
    
    1,974Total
      current assets
    
    
    378,679
    
    
    284,813Property,
      plant and equipment, at cost:Refineries,
      terminal equipment and pipelines
    
    
    542,356
    
    
    489,502Furniture,
      fixtures and other equipment
    
    
    8,755
    
    
    6,142551,111
    
    
    495,644Less
      – accumulated depreciation and amortization
    
    
    204,348
    
    
    173,196346,763
    
    
    322,448Deferred
      financing costs, net of amortizationof
      $594 and $2,484 in 2004 and 2003, respectively
    
    
    4,328
    
    
    4,009Commutation
      account
    
    
    16,438
    
    
    19,550Prepaid
      insurance, net of amortization
    
    
    4,542
    
    
    6,593Other
      intangible asset, net of amortization of $53 in 2004
    
    
    1,527
    
    
    -Other
      assets
    
    
    2,123
    
    
    4,884Total
      assets
    
    $
    754,400
    
    $
    642,297**LIABILITIES
      AND SHAREHOLDERS’ EQUITY**Current
      liabilities:Accounts
      payable
    
    $
    238,991
    
    $
    177,235Revolving
      credit facility
    
    
    -
    
    
    45,750Accrued
      turnaround cost
    
    
    15,373
    
    
    10,412Accrued
      interest
    
    
    2,487
    
    
    2,513Accrued
      El Dorado Refinery contingent earn-out payment
    
    
    7,500
    
    
    -Accrued
      liabilities and other
    
    
    17,067
    
    
    10,282Total
      current liabilities
    
    
    281,418
    
    
    246,192Long-term
      debt
    
    
    150,000
    
    
    168,689Long-term
      accrued turnaround cost
    
    
    13,153
    
    
    16,229Post-retirement
      employee liabilities
    
    
    23,139
    
    
    20,725Other
      long-term liabilities
    
    
    2,511
    
    
    -Deferred
      compensation liability and other
    
    
    1,516
    
    
    4,255Deferred
      income taxes
    
    
    42,550
    
    
    16,930Commitments
      and contingenciesShareholders’
      equity:Preferred
      stock, $100 par value, 500,000 shares authorized,no
      shares issued
    
    
    -
    
    
    -Common
      stock, no par, 50,000,000 shares authorized, 31,669,524
and30,643,549
      shares issued in 2004 and 2003, respectively
    
    
    57,607
    
    
    57,504Paid-in
      capital
    
    
    119,525
    
    
    106,443Retained
      earnings
    
    
    111,468
    
    
    47,614Accumulated
      other comprehensive loss, net of income taxesof
      $739 and $573, in 2004 and 2003, respectively
    
    
    (1,197
    )
    
    (924
    )Treasury
      stock, at cost, 4,638,467 and 4,264,673shares
      at December 31, 2004 and 2003, respectively
    
    
    (47,024
    )
    
    (39,914
    )Deferred
      employee compensation
    
    
    (266
    )
    
    (1,446
    )Total
      shareholders’ equity
    
    
    240,113
    
    
    169,277Total
      liabilities and shareholders’ equity
    
    $
    754,400
    
    $
    642,297The
      accompanying notes are an integral part of these consolidated financial
      statements.
 
  
 **FRONTIER OIL CORPORATION AND
      SUBSIDIAIRES****CONSOLIDATED
      STATEMENTS OF CASH FLOWS****Years
      Ended December 31,****2004**
    
    **2003**
    
    **2002***(in
      thousands)***Cash
      flows from operating activities:**Net
      income
    
    $
    69,764
    
    $
    3,232
    
    $
    1,028Depreciation
      and amortization
    
    
    32,208
    
    
    28,832
    
    
    27,332Deferred
      income taxes
    
    
    25,005
    
    
    2,655
    
    
    1,149Income
      tax benefits of stock compensation
    
    
    5,168
    
    
    -
    
    
    -Deferred
      finance cost and bond discount amortization
    
    
    5,484
    
    
    10,642
    
    
    2,033Deferred
      employee compensation amortization
    
    
    1,180
    
    
    1,386
    
    
    907Gain
      on involuntary conversion of assets
    
    
    (4,411
    )
    
    -
    
    
    -Long-term
      commutation account and prepaid insurance
    
    
    3,712
    
    
    (26,566
    )
    
    -Amortization
      of long-term prepaid insurance
    
    
    1,451
    
    
    423
    
    
    -(Decrease)
      increase allowance for doubtful trade and note receivables
    
    
    -
    
    
    (186
    )
    
    800Other
    
    
    (281
    )
    
    (501
    )
    
    (199
    )Changes
      in components of working capital from operations:Increase
      in derivative assets
    
    
    (354
    )
    
    -
    
    
    -Decrease
      (increase) in trade, note and other receivables
    
    
    2,231
    
    
    (4,577
    )
    
    (22,178
    )Increase
      in inventory
    
    
    (32,935
    )
    
    (18,839
    )
    
    (17,190
    )(Increase)
      decrease in other current assets
    
    
    (16
    )
    
    536
    
    
    (267
    )Increase
      (decrease) in accounts payable
    
    
    58,138
    
    
    (4,282
    )
    
    64,004Increase
      (decrease) in accrued liabilities and other
    
    
    11,555
    
    
    1,240
    
    
    (6,597
    )Net
      cash provided by (used in) operating activities
    
    
    177,899
    
    
    (6,005
    )
    
    50,822**Cash
      flows from investing activities:**Additions
      to property, plant and equipment
    
    
    (46,502
    )
    
    (33,677
    )
    
    (29,517
    )Net
      proceeds from insurance - involuntary conversion claim
    
    
    3,395
    
    
    -
    
    
    -Proceeds
      from sale of assets
    
    
    -
    
    
    304
    
    
    -Other
      investments
    
    
    -
    
    
    (927
    )
    
    (100
    )El
      Dorado Refinery contingent earn-out payment
    
    
    -
    
    
    -
    
    
    (7,500
    )Net
      cash used in investing activities
    
    
    (43,107
    )
    
    (34,300
    )
    
    (37,117
    )**Cash
      flows from financing activities:**Proceeds
      from issuance of 65⁄8% Senior Notes
    
    
    150,000
    
    
    -
    
    
    -Proceeds
      from issuance of 8% Senior Notes, net of discount
    
    
    -
    
    
    218,143
    
    
    -Repurchases
      of debt:113⁄4%
      Senior Notes
    
    
    (170,449
    )
    
    -
    
    
    -8%
      Senior Notes
    
    
    -
    
    
    (220,000
    )
    
    -91⁄8%
      Senior Notes
    
    
    -
    
    
    (39,475
    )
    
    (1,090
    )(Repayments)
      proceeds of revolving credit facility, net
    
    
    (45,750
    )
    
    45,750
    
    
    -Debt
      issue costs and other
    
    
    (3,954
    )
    
    (7,136
    )
    
    -Proceeds
      from issuance of common stock
    
    
    3,923
    
    
    1,441
    
    
    1,702Purchase
      of treasury stock
    
    
    (3,029
    )
    
    (1,075
    )
    
    (787
    )Dividends
      paid
    
    
    (5,664
    )
    
    (5,187
    )
    
    (5,161
    )Net
      cash used in financing activities
    
    
    (74,923
    )
    
    (7,539
    )
    
    (5,336
    )Increase
      (decrease) in cash and cash equivalents
    
    
    59,869
    
    
    (47,844
    )
    
    8,369Cash
      and cash equivalents, beginning of period
    
    
    64,520
    
    
    112,364
    
    
    103,995Cash
      and cash equivalents, end of period
    
    $
    124,389
    
    $
    64,520
    
    $
    112,364The
      accompanying notes are an integral part of these consolidated financial
      statements.


**FRONTIER OIL CORPORATION AND
      SUBSIDIARIES****CONSOLIDATED
      STATEMENTS OF CHANGES IN SHAREHOLDERS’
      EQUITY AND STATEMENTS OF COMPREHENSIVE INCOME***(in
      thousands except share data)***Common
      Stock**
    
    
    
    
    
    
    
    **Treasury
      Stock**
    
    
    
    
    
    **Total****Number
      of Shares issued**
    
    **Amount**
    
    **Paid-in
      Capital**
    
    **Compre-hensive
      Income**
    
    **Retained
      Earnings**
    
    **Number
      of Shares**
    
    **Amount**
    
    **Deferred
      Employee Compensation**
    
    **Accumulated
      Other Comprehensive Income (Loss)**
    
    **Number
      of Shares**
    
    **Amount****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 plans
    
    
    230,750
    
    
    23
    
    
    1,543
    
    
    
    
    
    -
    
    
    -
    
    
    -
    
    
    -
    
    
    -
    
    
    230,750
    
    
    1,566Directors
      stock plan
    
    
    -
    
    
    -
    
    
    -
    
    
    
    
    
    -
    
    
    3,000
    
    
    13
    
    
    -
    
    
    -
    
    
    3,000
    
    
    13Resricted
      stock issuances, net
    
    
    -
    
    
    -
    
    
    1,544
    
    
    
    
    
    -
    
    
    105,768
    
    
    561
    
    
    (2,105
    )
    
    -
    
    
    105,768
    
    
    -Shares
      received under:Restricted
      stock plan
    
    
    -
    
    
    -
    
    
    -
    
    
    
    
    
    -
    
    
    (19,041
    )
    
    (370
    )
    
    -
    
    
    -
    
    
    (19,041
    )
    
    (370
    )Comprehensive
      income:Net
      income
    
    
    -
    
    
    -
    
    
    -
    
    $
    1,028
    
    
    1,028
    
    
    -
    
    
    -
    
    
    -
    
    
    -
    
    
    -
    
    
    1,028Other
      comprehensive income:Deferred
      net loss on derivative contracts,net
      of tax of $21
    
    
    
    
    
    
    
    
    
    
    
    (33
    )Derivative
      value reclassed to income,net
      of tax of $21
    
    
    
    
    
    
    
    
    
    
    
    33Minimum
      pension liability,net
      of tax of $214
    
    
    
    
    
    
    
    
    
    
    
    (343
    )Other
      comprehensive income
    
    
    
    
    
    
    
    
    
    
    
    (343
    )
    
    
    
    
    
    
    
    
    
    
    
    
    
    (343
    )
    
    -
    
    
    (343
    )Comprehensive
      income
    
    
    
    
    
    
    
    
    
    
    $
    685Income
      tax benefits of stock compensation
    
    
    -
    
    
    -
    
    
    1,424
    
    
    
    
    
    -
    
    
    -
    
    
    -
    
    
    -
    
    
    -
    
    
    -
    
    
    1,424Deferred
      employee compensation:Amortization/vested
      shares
    
    
    -
    
    
    -
    
    
    -
    
    
    
    
    
    -
    
    
    -
    
    
    -
    
    
    907
    
    
    -
    
    
    -
    
    
    907Dividends
      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 plans
    
    
    353,225
    
    
    35
    
    
    2,286
    
    
    
    
    
    -
    
    
    -
    
    
    -
    
    
    -
    
    
    -
    
    
    353,225
    
    
    2,321Shares
      received under:Stock
      option 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
    
    
    -
    
    
    -
    
    
    -
    
    
    -
    
    
    -
    
    
    3,232Other
      comprehensive income:Minimum
      pension liability,net
      of tax of $201
    
    
    
    
    
    
    
    
    
    
    
    (326
    )Other
      comprehensive income
    
    
    
    
    
    
    
    
    
    
    
    (326
    )
    
    
    
    
    
    
    
    
    
    
    
    
    
    (326
    )
    
    -
    
    
    (326
    )Comprehensive
      income
    
    
    
    
    
    
    
    
    
    
    $
    2,906Income
      tax benefits of stock compensation
    
    
    -
    
    
    -
    
    
    1,600
    
    
    
    
    
    -
    
    
    -
    
    
    -
    
    
    -
    
    
    -
    
    
    -
    
    
    1,600Deferred
      employee compensation:Amortization/vested
      shares
    
    
    -
    
    
    -
    
    
    -
    
    
    
    
    
    -
    
    
    -
    
    
    -
    
    
    1,386
    
    
    -
    
    
    -
    
    
    1,386Dividends
      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**Shares
      issued under:Stock
      option plans
    
    
    1,025,975
    
    
    103
    
    
    7,914
    
    
    
    
    
    -
    
    
    -
    
    
    -
    
    
    -
    
    
    -
    
    
    1,025,975
    
    
    8,017Directors
      stock plan
    
    
    -
    
    
    -
    
    
    -
    
    
    
    
    
    -
    
    
    3,000
    
    
    13
    
    
    -
    
    
    -
    
    
    3,000
    
    
    13Shares
      received under:Stock
      option plans
    
    
    -
    
    
    -
    
    
    -
    
    
    
    
    
    -
    
    
    (328,351
    )
    
    (6,222
    )
    
    -
    
    
    -
    
    
    (328,351
    )
    
    (6,222
    )Restricted
      stock plan
    
    
    -
    
    
    -
    
    
    -
    
    
    
    
    
    -
    
    
    (48,443
    )
    
    (901
    )
    
    -
    
    
    -
    
    
    (48,443
    )
    
    (901
    )Comprehensive
      income:Net
      income
    
    
    -
    
    
    -
    
    
    -
    
    $
    69,764
    
    
    69,764
    
    
    -
    
    
    -
    
    
    -
    
    
    -
    
    
    -
    
    
    69,764Other
      comprehensive income:Minimum
      pension liability,net
      of tax of $166
    
    
    
    
    
    
    
    
    
    
    
    (273
    )Other
      comprehensive income
    
    
    
    
    
    
    
    
    
    
    
    (273
    )
    
    
    
    
    
    
    
    
    
    
    
    
    
    (273
    )
    
    -
    
    
    (273
    )Comprehensive
      income
    
    
    
    
    
    
    
    
    
    
    $
    69,491Income
      tax benefits of stock compensation
    
    
    -
    
    
    -
    
    
    5,168
    
    
    
    
    
    -
    
    
    -
    
    
    -
    
    
    -
    
    
    -
    
    
    -
    
    
    5,168Deferred
      employee compensation:Amortization/vested
      shares
    
    
    -
    
    
    -
    
    
    -
    
    
    
    
    
    -
    
    
    -
    
    
    -
    
    
    1,180
    
    
    -
    
    
    -
    
    
    1,180Dividends
      declared
    
    
    -
    
    
    -
    
    
    -
    
    
    
    
    
    (5,910
    )
    
    -
    
    
    -
    
    
    -
    
    
    -
    
    
    -
    
    
    (5,910
    )**December
      31, 2004**
    
    
    **31,669,524**
    
    **$**
    **57,607**
    
    **$**
    **119,525**
    
    
    
    
    **$**
    **111,468**
    
    
    **(4,638,467**
    **)**
    **$**
    **(47,024**
    **)**
    **$**
    **(266**
    **)**
    **$**
    **(1,197**
    **)**
    
    **27,031,057**
    
    **$**
    **240,113**The
      accompanying notes are an integral part of these consolidated financial
      statements
  
 **FRONTIEROIL CORPORATION AND
SUBSIDIARIES**
  **Notes
To Consolidated Financial Statements**
 **For
The Years Ended December 31, 2004, 2003 and 2002**
 
 **1.**
    **Nature of
Operations**
 
 The
financial statements include the accounts of Frontier Oil Corporation, a Wyoming
corporation, and its wholly-owned subsidiaries, 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 have been 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. The
Company’s investment in 8901 Hangar, Inc. was $102,000 and $108,000 at December
31, 2004 and 2003, respectively, and is included in “Other assets” on the
Consolidated Balance Sheets. 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, which range as
follows:
  Refinery
      buildings and equipment
    5
      to 50 yearsPipelines
      and pipeline improvements
    5
      to 20 yearsFurniture,
      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 (“FAS”) 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 the long-term construction of significant
assets. Interest capitalized for the years ended December 31, 2004, 2003 and
2002 was $65,000, $586,000 and $342,000, respectively.
  **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 Sheets in “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.
  **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 (See “New Accounting Pronouncements” below for a discussion of Emerging
Issues Task Force (“EITF”) Issue No. 04-13). 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 6).
 
 **Components
      of Inventory****December
      31,****2004**
    
    **2003***(in
      thousands)*Crude
      oil
    
    $
    52,643
    
    $
    39,374Unfinished
      products
    
    
    45,957
    
    
    31,240Finished
      products
    
    
    40,835
    
    
    34,712Process
      chemicals
    
    
    3,210
    
    
    5,175Repairs
      and maintenance supplies and other
    
    
    14,289
    
    
    13,498$
    156,934
    
    $
    123,999
 
  **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 Consolidated Balance Sheets.
The loss mitigation insurance premium and related expenses (see “Litigation -
Beverly Hills Lawsuits” under Note 10) totaling $6.4 million and $7.0 million at
December 31, 2004 and 2003, respectively, are in “Prepaid insurance” in the
long-term asset portion of the Consolidated Balance Sheets and are reflected net
of accumulated amortization as of each balance sheet date. Of the total
indemnity premium, $1.4 million related to year one of the policy, and was
amortized to expense over the one-year period which began October 1, 2003. The
remaining $4.3 million of the indemnity premium is being amortized over four
years beginning October 1, 2004. The administrative fee and California insurance
tax totaling $673,000 ($1.3 million at December 31, 2003 less $600,000 of
insurance tax refunded in 2004) is being amortized to expense over the five-year
policy term, which began October 1, 2003. Accumulated amortization was $1.9
million and $423,000 at December 31, 2004 and 2003, respectively.
  **Income
Taxes**
 The
Company accounts for income taxes under the provisions of FAS No. 109,
“Accounting for Income Taxes.” FAS 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 that improve a property’s pre-existing condition, and costs that
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.
  **PriceRisk 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 that 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 under FAS No. 133, “Accounting for Derivative
Instruments and Hedging Activities.” 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, 2004, 2003 and 2002. Had compensation costs been
determined based on fair value at the grant dates for awards made in 2004, 2003,
2002 and prior years for the vested portions of the awards in each of the years
2004, 2003 and 2002, the Company’s net income (loss) and EPS would have been the
pro forma amounts listed in the following table for the years ended December 31,
2004, 2003 and 2002:
 
 **2004**
    
    **2003**
    
    **2002***(in
      thousands, except per share amounts**)*Net
      income as reported
    
    $
    69,764
    
    $
    3,232
    
    $
    1,028Pro
      forma compensation expense, net of tax
    
    
    (2,029
    )
    
    (3,070
    )
    
    (2,540
    )Pro
      forma net income (loss)
    
    $
    67,735
    
    $
    162
    
    $
    (1,512
    )**Basic
      EPS:**As
      reported
    
    $
    2.62
    
    $
    0.12
    
    $
    0.04Pro
      Forma
    
    
    2.54
    
    
    0.01
    
    
    (0.06
    )**Diluted
      EPS:**As
      reported
    
    $
    2.55
    
    $
    0.12
    
    $
    0.04Pro
      Forma
    
    
    2.47
    
    
    0.01
    
    
    (0.06
    )
 
 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
2004, 2003 and 2002, respectively: risk-free interest rates of 2.97%, 2.75% and
2.76%; expected volatilities of 47.80%, 50.50% and 51.40%; expected lives of 5.0
years, 5.0 years and 5.0 years; and dividend yields of 1.10%, 1.27% and
1.27%.
 Compensation
costs of $1.2 million, $1.4 million and $907,000 related to restricted stock
awards was recognized for the years ended December 31, 2004, 2003 and 2002,
respectively. See “New Accounting Pronouncements” below for a discussion of FAS
No. 123(R), which will require a change in the Company’s method of accounting
for stock-based compensation in 2005.
  **Asset
Retirement Obligations**
 The
Company accounts for asset retirement obligations as required under FAS No. 143,
“Accounting for Retirement Asset Obligations.” FAS 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. FAS
No. 143 also includes disclosure requirements that provide a description of
asset retirement obligations and reconciliation of changes in the components of
those obligations. The Company has asset retirement obligations related to its
Refineries and certain other assets as a result of environmental and other legal
requirements. The Company is not required to perform the obligations in some
circumstances until it permanently ceases operations of the long-lived assets
and therefore, considers the useful life of the Refineries and certain other
assets indeterminable. Accordingly, the Company cannot calculate an associated
asset retirement obligation at this time. The Company will measure and recognize
the fair value of its asset retirement obligations at such time as the useful
life is determinable, or in the event that the Company decides to cease the use
of a particular refinery, an asset retirement obligation liability would be
recorded at that time.
  **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 maturity, when purchased, of three months or less are
considered to be cash equivalents. Cash equivalents were $115.3 million and
$56.8 million at December 31, 2004 and 2003, respectively.
  **Supplemental
Cash Flow Information**
 Cash
payments for interest, excluding capitalized interest, during 2004, 2003 and
2002 were $20.0 million, $33.5 million and $24.5 million, respectively. Cash
payments for income taxes during 2004, 2003 and 2002 were $21.6 million,
$626,000 and $83,000, respectively.
  **NewAccounting Pronouncements**
 In
December 2004, the FASB issued FAS No. 123(R), “Share-Based Payment,” an
amendment of FASB Statements No. 123 and 95. FAS No. 123(R) replaces FAS No.
123, “Accounting for Stock-Based Compensation,” and supersedes APB Opinion No.
25, “Accounting for Stock Issued to Employees.” This statement requires
companies to recognize the fair value of stock options and other stock-based
compensation to employees prospectively beginning with fiscal periods beginning
after June 15, 2005. This means that Frontier will be required to implement FAS
No. 123(R) no later than the quarter beginning July 1, 2005. The Company
currently measures stock-based compensation in accordance with APB Opinion No.
25 as discussed above. The Company anticipates adopting the modified prospective
method of FAS No. 123(R) on July 1, 2005. Based on the stock options outstanding
as of December 31, 2004, the Company will recognize compensation expense in
future Consolidated Statements of Income of approximately $800,000, $350,000,
and $20,000 in the years ended December 31, 2005, 2006 and 2007, respectively.
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 that may be granted. See “Stock-based
Compensation” earlier in this Note for the pro forma impact that the fair value
method would have had on the Company’s net income for each of the years ended
December 31, 2004, 2003 and 2002.
 In
December 2004, the FASB issued FAS No. 153, “Exchanges of Nonmonetary Assets,”
an amendment of APB Opinion No. 29. This statement was the result of a joint
effort by the FASB and the International Accounting Standards Board (“IASB”) to
improve financial reporting by eliminating certain narrow differences between
their existing standards. One such difference was the exception from fair value
measurement in APB Opinion No. 29, “Accounting for Nonmonetary Transactions,”
for nonmonetary exchanges of similar productive assets. FAS No. 153 replaces
this exception with a general exception from fair value measurement for
exchanges of nonmonetary assets that do not have commercial substance. A
nonmonetary exchange has commercial substance if the future cash flows of the
entity are expected to change significantly as a result of the exchange. This
statement shall be applied prospectively and is effective for nonmonetary asset
exchanges occurring in fiscal periods beginning after June 15, 2005. The Company
does not believe that the adoption of FAS No. 153 will have a material effect on
its financial statements.
 In
November 2004, the FASB issued FAS No. 151, “Inventory Costs, an amendment of
Accounting Research Bulletin (“ARB”) No. 43, Chapter 4.” The FASB issued FAS No.
151 to clarify the accounting for abnormal amounts of idle facility expense,
freight, handling costs and wasted material (spoilage). This statement was a
result of joint effort by the FASB and IASB to improve financial reporting by
eliminating certain narrow differences between their existing standards. One
such difference was the accounting for abnormal inventory costs. Both the FASB
and IASB agree that abnormal expenses should be recognized in the period in
which they are incurred; however wording in ARB No. 43, Chapter 4, “Inventory
Pricing,” led to inconsistent application of that principle. As such, this
statement requires that these items be recognized as current period charges
regardless of whether they meet the “so abnormal” criterion outlined in ARB No.
43. FAS No. 151 also introduces the concept of “normal capacity” and requires
the allocation of fixed production overheads to inventory based on the normal
capacity of the production facilities. Unallocated overheads must be recognized
as an expense in the period in which they are incurred. This statement is
effective for inventory costs incurred during fiscal years beginning after June
15, 2005. The Company does not believe that the adoption of FAS No. 153 will
have a material effect on its financial statements.
 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 are
required to apply the provisions of FIN 46 to those entities immediately. FIN 46
was 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 adopted FIN 46 on January 1, 2004, and the adoption had no
effect on its financial statements.
 In
December 2004, the FASB staff issued FASB Staff Position (“FSP”) No. FAS 109-1,
“Application of FASB Statement No. 109, Accounting for Income Taxes, to the Tax
Deduction on Qualified Production Activities Provided by the American Jobs
Creation Act of 2004” to provide guidance on the application of FAS No. 109 to
the provision within the “American Jobs Creation Act of 2004” that provides tax
relief to U.S. domestic manufacturers. See Note 7 for additional information and
discussion of this FSP.
 The EITF
of the FASB is currently considering Issue No. 04-13, “Accounting for Purchases
and Sales of Inventory with the Same Counterparty.” This Issue addresses
accounting issues that arise when one company both sells inventory to and buys
inventory from another company in the same line of business, specifically, when
it is appropriate to measure purchases and sales of inventory at fair value and
record them in cost of sales and revenues and when they should be recorded as an
exchange measured at the book value of the item sold. The Company has certain
crude oil procurement and product exchange transactions which it accounts for on
a net cost basis. Should the EITF reach a consensus on this Issue, the Company
does not believe that it will have any impact on its revenues or cost of
sales.
 
 **3.**
    **Cheyenne
      Refinery Fire**
 
 On
January 19, 2004, a fire occurred in the furnaces of the coking unit at the
Cheyenne Refinery. The coker was out of service for approximately one month. The
“Gain on involuntary conversion of assets” in the Consolidated Statement of
Income for the year ended December 31, 2004 represents the settlement proceeds
of $7.1 million from the Company’s insurers, less $1.6 million of expenses
related to clean-up costs and $1.1 million of property, plant and equipment
written off due to the fire. Insurance proceeds of $5.0 million (of the total
$7.1 million), had been received as of December 31, 2004, and the remaining $2.1
million was accrued as a receivable as of December 31, 2004, and was received in
early 2005.
 
 **4.**
    **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 it 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 concluded
on March 5, 2004. Oral arguments were held on May 4, 2004, and the Company is
awaiting a decision. Frontier believes that the counterclaims filed against it
by Holly will not result in any material liability or have any material adverse
effect upon Frontier.
 The
operating results for the year ended December 31, 2004 were negatively impacted
by legal costs related to the termination of the Holly merger aggregating $3.8
million pretax ($2.4 million after tax), which are reflected in the Consolidated
Statements of Income as “Merger termination and legal costs.” 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), which were 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 $5.7 million in legal expenses relating
to the Holly lawsuit. The $18.0 million of “Merger financing termination costs,
net” for the year ended December 31, 2003, included 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 5).
 
 **5.**
    **Long-term
      Debt**
 
 **Schedule
of Long-term Debt**
 
 **December
      31,****2004**
    
    **2003***(in
      thousands)*65⁄8%
      Senior Notes, maturing 2011
    
    $
    150,000
    
    $
    -113⁄4%
      Senior Notes, net of unamortized discount
    
    
    -
    
    
    168,689$
    150,000
    
    $
    168,689
 
 **65⁄8%
Senior Notes** . On
October 1, 2004, the Company issued $150.0 million principal amount of 65⁄8%
Senior Notes. The 65⁄8% Senior Notes, which mature on October 1, 2011, were issued
at par, and the Company received net proceeds (after underwriting fees) of
$147.2 million. Interest is paid semi-annually. The 65⁄8%
Senior Notes are redeemable, at the option of the Company, at 103.313% after
October 1, 2007, declining to 100% in 2010. Prior to October 1, 2007, the
Company may at its option redeem the 65⁄8% Senior
Notes at a defined make-whole amount, plus accrued and unpaid interest. The 65⁄8%
Senior Notes may restrict payments, including dividends, and limit the
incurrence of additional indebtedness based on covenants related to interest
coverage ratio and restricted payments tests. Frontier Holdings Inc. and its
subsidiaries are full and unconditional guarantors of the 65⁄8% Senior Notes (see
Note 13 for consolidating financial statements). The Company used a portion of
the net proceeds from this offering, together with other available funds, to
fund a tender offer and consent solicitation for $64.9 million principal of its
113⁄4% Senior Notes in October 2004 and redeemed on November 15, 2004, the
remaining $105.6 million outstanding principal of its 113⁄4% Senior
Notes.
 **113⁄4%
Senior Notes.** On
November 5, 1999, the Company issued $190.0 million principal amount of 113⁄4%
Senior Notes due 2009. The 113⁄4% Senior Notes were issued at a price of 98.562%
and interest was paid semi-annually. The net proceeds were utilized to acquire
the El Dorado Refinery. During 2001 and 2000, the Company purchased and held 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. As
discussed above, the Company redeemed all of the remaining 113⁄4% Senior Notes
during the fourth quarter of 2004 via the tender offer and redemption. Interest
expense and other financing costs for the year ended December 31, 2004, included
$14.9 million in costs related to the redemption of the 113⁄4% Senior Notes. The
$14.9 million in redemption-related costs included $10.4 million of premium, the
write-off at redemption of the remaining unamortized $1.5 million of issue
discount, $2.7 million for the write-off at redemption of the remaining
unamortized debt issue costs, and $0.3 million of legal and administrative costs
to facilitate the tender offer and redemption. In addition, $9.1 million of
accrued interest payments were made at the time of consummation of the tender
offer and redemption.
 **91⁄8%
Senior Notes.** 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 91⁄8% Senior Notes. The original $70.0 million of 91⁄8% Senior Notes
had semi-annual interest payments, 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 91⁄8% Senior Notes, the accounting for which was a reduction of
debt.
 **8%
Senior Notes.** On April
17, 2003, the Company received $218.1 million (net of issue discount and
underwriting fees) from a private placement of $220.0 million of 8% Senior Notes
due April 2013. The net proceeds of the 8% 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 8% Senior Notes offering, along with other amounts
contributed by the Company, were placed in an escrow account. As provided for in
the escrow agreement, because the merger with Holly did not occur, on October
10, 2003, Frontier closed the escrow account and redeemed the 8% Senior 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 8% Senior 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.
 
 **6.**
    **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 was
amended and restated in November 2004 to increase the available commitment and
to extend the current expiration date. The facility has a current expiration
date of June 16, 2008. The Facility is a collateral-based facility with total
borrowing capacity, subject to borrowing base amounts, of up to $225 million,
which capacity may be increased up to $250 million at the Company’s request. Any
unutilized capacity after cash borrowings is available for letters of credit. No
borrowings were outstanding at December 31, 2004 under the Facility. Debt
outstanding under the Facility was $45.8 million at December 31, 2003. Standby
letters of credit outstanding were $12.2 million and $26.2 million at December
31, 2004 and 2003, respectively. As of December 31, 2004, the Company had
borrowing base availability of $182.0 million under the Facility.
 The
Facility, secured by inventory, accounts receivable and related contracts and
intangibles, and certain deposit accounts, 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 the agent bank’s prime
rate plus 0.25% to 1%, prevailing Federal Funds Rate plus 1.25% to 2% or LIBOR
plus 1.25% to 2.0%. 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 2004 was 2.95%. 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, 2004.
 
 **7.**
    **Income
      Taxes**
 
 The
following is the provision for income taxes for the three years ended December
31, 2004, 2003 and 2002.
 
 **Provision
      for Income Taxes****2004**
    
    **2003**
    
    **2002***(in
      thousands)*Current:State
    
    $
    3,375
    
    $
    25
    
    $
    32Federal
    
    
    13,959
    
    
    276
    
    
    (204
    )Canadian
    
    
    -
    
    
    -
    
    
    83Total
      current provision (benefit)
    
    
    17,334
    
    
    301
    
    
    (89
    )Deferred:State
    
    
    1,640
    
    
    411
    
    
    303Federal
    
    
    23,365
    
    
    2,244
    
    
    846Total
      deferred provision
    
    
    25,005
    
    
    2,655
    
    
    1,149Total
      provision
    
    $
    42,339
    
    $
    2,956
    
    $
    1,060
 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, 2004, 2003 and
2002
 
 **Reconciliation
      of Tax Provision****2004**
    
    **2003**
    
    **2002***(in
      thousands)*Provision
      based on statutory rates
    
    $
    39,236
    
    $
    2,166
    
    $
    731Increase
      (decrease) resulting from:State
      and other income taxes
    
    
    5,015
    
    
    436
    
    
    418Federal
      tax effect of state income taxes
    
    
    (1,755
    )
    
    (153
    )
    
    (146
    )Release
      of valuation allowance
    
    
    (955
    )
    
    -
    
    
    -Other
    
    
    798
    
    
    507
    
    
    57Provision
      as reported
    
    $
    42,339
    
    $
    2,956
    
    $
    1,060
 
 Significant
components of deferred tax assets and liabilities are shown below:
 
 **Components
      of Deferred Taxes****December
      31, 2004**
    
    **December
      31, 2003****State**
    
    **Federal**
    
    **Total**
    
    **State**
    
    **Federal**
    
    **Total***(in
      thousands)*Current
      deferred tax assets:Gross
      current assets:Turnaround
      accruals
    
    $
    757
    
    $
    5,380
    
    $
    6,137
    
    $
    522
    
    $
    3,644
    
    $
    4,166Pension
      retirement benefits
    
    
    58
    
    
    411
    
    
    469
    
    
    71
    
    
    498
    
    
    569Restricted
      stock amortization
    
    
    39
    
    
    279
    
    
    318
    
    
    57
    
    
    396
    
    
    453Bad
      debt reserve
    
    
    25
    
    
    175
    
    
    200
    
    
    25
    
    
    175
    
    
    200Other
      liabilities
    
    
    10
    
    
    68
    
    
    78
    
    
    -
    
    
    -
    
    
    -Unrealized
      loss on derivative contracts
    
    
    -
    
    
    -
    
    
    -
    
    
    20
    
    
    140
    
    
    160Charitable
      contributions carryforward
    
    
    -
    
    
    -
    
    
    -
    
    
    12
    
    
    82
    
    
    94Capitalized
      selling and general expenses
    
    
    19
    
    
    133
    
    
    152
    
    
    -
    
    
    -
    
    
    -State
      net operating losses
    
    
    -
    
    
    -
    
    
    -
    
    
    880
    
    
    -
    
    
    880Total
      gross deferred tax assets
    
    
    908
    
    
    6,446
    
    
    7,354
    
    
    1,587
    
    
    4,935
    
    
    6,522Gross
      current liabilities:Unrealized
      gain on derivative contracts
    
    
    (37
    )
    
    (264
    )
    
    (301
    )
    
    -
    
    
    -
    
    
    -State
      deferred taxes
    
    
    -
    
    
    (305
    )
    
    (305
    )
    
    -
    
    
    (555
    )
    
    (555
    )Total
      current net deferred tax assets
    
    $
    871
    
    $
    5,877
    
    $
    6,748
    
    $
    1,587
    
    $
    4,380
    
    $
    5,967Long-term
      deferred tax liabilities:Gross
      long-term assets:Turnaround
      accruals
    
    $
    648
    
    $
    4,604
    
    $
    5,252
    
    $
    813
    
    $
    5,679
    
    $
    6,492Pension
      retirement benefits
    
    
    183
    
    
    1,303
    
    
    1,486
    
    
    199
    
    
    1,391
    
    
    1,590Other
      post-retirement benefits
    
    
    957
    
    
    6,796
    
    
    7,753
    
    
    840
    
    
    5,862
    
    
    6,702Environmental
      liability accrual
    
    
    74
    
    
    525
    
    
    599
    
    
    -
    
    
    -
    
    
    -Deferred
      compensation
    
    
    55
    
    
    390
    
    
    445
    
    
    99
    
    
    692
    
    
    791State
      deferred taxes
    
    
    -
    
    
    2,166
    
    
    2,166
    
    
    -
    
    
    1,850
    
    
    1,850Federal
      net operating loss
    
    
    -
    
    
    -
    
    
    -
    
    
    -
    
    
    6,757
    
    
    6,757Federal
      alternative minimum tax credits
    
    
    -
    
    
    6,316
    
    
    6,316
    
    
    -
    
    
    13,434
    
    
    13,434Gross
      long-term assets
    
    
    1,917
    
    
    22,100
    
    
    24,017
    
    
    1,951
    
    
    35,665
    
    
    37,616Less
      valuation allowance
    
    
    -
    
    
    -
    
    
    -
    
    
    (600
    )
    
    (955
    )
    
    (1,555
    )Total
      long-term net deferred tax assets
    
    
    1,917
    
    
    22,100
    
    
    24,017
    
    
    1,351
    
    
    34,710
    
    
    36,061Gross
      long-term liabilities:Depreciation
    
    
    (8,106
    )
    
    (58,461
    )
    
    (66,567
    )
    
    (6,636
    )
    
    (46,355
    )
    
    (52,991
    )Total
      long-term net deferred tax liabilities
    
    $
    (6,189
    )
    $
    (36,361
    )
    $
    (42,550
    )
    $
    (5,285
    )
    $
    (11,645
    )
    $
    (16,930
    )
 
 At
December 31, 2004, the Company had alternative minimum tax carryforwards of
approximately $6.3 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 Refinery operations prior to
its 1991 acquisition by the Company, which may be subject to certain
limitations. The Company had no federal or state net operating loss
carryforwards as of December 31, 2004. The Company has no income tax
contingencies recorded and has not identified any potential gain or loss income
tax contingencies that must be disclosed in accordance with FAS No. 5.
 The
Company recognizes the amount of taxes payable or refundable for the current
year and recognizes deferred tax liabilities and assets for the expected future
tax consequences of events and transactions that have been recognized in the
Company’s financial statements or tax returns. Deferred tax assets are reduced
by a valuation allowance when, in the opinion of management, it is more likely
than not that some or all of its deferred tax assets will not be realized.
Realization of the deferred income tax assets is dependent on generating
sufficient taxable income in future years. Although realization is not assured,
management believes that it is more likely than not that all of the deferred
income tax assets will be realized and thus, no valuation allowance was provided
for as of December 31, 2004. Since the Company utilized all remaining federal
and state net operating losses and also utilized a significant portion of its
alternative minimum tax credits in 2004, valuation allowances provided in prior
years have also been eliminated in 2004.
 The
Company recognized income tax benefits related to the deductibility of stock
options and restricted stock in the amounts of $5.2 million, $1.6 million and
$1.4 million for the years ended December 31, 2004, 2003 and 2002, respectively.
Such benefits were recorded as an increase in additional paid in capital and a
reduction of either income taxes payable (when the Company had taxable income)
or a reduction in net deferred income tax liabilities (when the Company had tax
net operating losses). The Company also recognized income tax benefits related
to the minimum pension liability reflected in “Accumulated other comprehensive
loss” in the amounts of $166,000, $201,000 and $214,000 for the years ended
December 31, 2004, 2003 and 2002, respectively.
 The new
“American Jobs Creation Act of 2004” (the “Act”) provision providing tax relief
for manufacturers should result in reduced effective federal income tax rates
beginning in 2005. In December 2004, the FASB staff issued FSP No. FAS 109-1 to
provide guidance on the application of FAS No. 109 to the provision within the
Act that provides tax relief to U.S. domestic manufacturers. The FSP states that
the manufacturers’ deduction provided for in the Act should be accounted for as
a special deduction in accordance with FAS 109 and not as a tax rate reduction.
A special deduction is accounted for by recording the benefit of the deduction
in the year in which it can be taken in our tax return, and not by adjusting
deferred tax assets and liabilities in the period of the Act’s enactment. The
FSP was effective upon issuance, and the Company has properly accounted for its
deferred taxes at December 31, 2004 in accordance with the FSP. Other certain
provisions of the Act will benefit Frontier by allowing the Company an
accelerated depreciation deduction of 75% of qualified capital costs incurred to
achieve low sulfur diesel fuel requirements and by providing a $0.05 per gallon
credit on compliant diesel fuel up to an amount equal to the remaining 25% of
these qualified capital costs for federal income tax purposes (See Note
10).
 
 **8.**
    **Common
      Stock**
 
 **Dividends**
 The
Company declared quarterly dividends of $.06 per share of common stock for the
quarters ended September 30, 2004 and December 31, 2004 and $.05 per share for
the quarters ended March 31, 2004 and June 30, 2004. The payment of dividends is
prohibited under the Company’s Revolving Credit Facility only if a default has
occurred and is continuing or such payment would cause a default. The 65⁄8% Notes
may restrict dividend payments based on covenants related to interest coverage
ratio and restricted payments tests.
 
 **Treasury
stock**
 The
Company accounts for its treasury stock under the cost method on a FIFO basis.
The Company has a Board of Director approved stock repurchase program for up to
eight million shares of the Company’s common stock. Through December 2004,
4,367,366 shares of common stock had been purchased under the stock repurchase
program. The Company did not initiate any additional purchases of common stock
under the stock repurchase program in 2004, 2003 or 2002. The Company received
215,599 shares ($4.1 million) in 2004 and 51,082 shares ($880,000) in 2003 of
its common stock, now held as treasury stock, from employees in cashless stock
option exercises. The Company received 112,752 shares in 2004 and 37,556 shares
in 2003 of its common stock, now held as treasury stock, from employees to cover
withholding taxes on stock option exercises. The Company received 48,443 shares
in 2004, 24,825 shares in 2003, and 19,041 shares in 2002 of its common stock,
now held as treasury stock, from employees to cover withholding taxes on vested
restricted stock. The Company issued treasury stock to non-employee directors
under the “Non-employee Directors Stock Grant Plan,” discussed below, of 3,000
shares during each of the years ending December 31, 2004 and 2002. As of
December 31, 2004, the Company had 4,638,467 shares of treasury
stock.
  **Earnings
per Share**
 The
following sets forth the computation of diluted earnings per share (“EPS”) for
the years ended December 31, 2004, 2003 and 2002.
  **2004**
    
    **2003**
    
    **2002****Income
      (Num-erator)**
    
    **Shares
      (Denomi-nator)**
    
    **Per
      Share Amount**
    
    **Income
      (Num-erator)**
    
    **Shares
      (Denomi-nator)**
    
    **Per
      Share Amount**
    
    **Income
      (Num-erator)**
    
    **Shares
      (Denomi-nator)**
    
    **Per
      Share Amount**(*in
      thousands except per share amounts)*Basic
      EPS:Net
      income
    
    $
    69,764
    
    
    26,673
    
    $
    2.62
    
    $
    3,232
    
    
    25,939
    
    $
    0.12
    
    $
    1,028
    
    
    25,780
    
    $
    0.04**Dilutive
      securities:**Stock
      options andrestricted
      stock
    
    
    -
    
    
    728
    
    
    -
    
    
    -
    
    
    1,052
    
    
    -
    
    
    -
    
    
    1,154
    
    
    -**Diluted
      EPS:**Net
      income
    
    $
    69,764
    
    
    27,401
    
    $
    2.55
    
    $
    3,232
    
    
    26,991
    
    $
    0.12
    
    $
    1,028
    
    
    26,934
    
    $
    0.04
 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) were none
for the year ended December 31, 2004, and 1,546,700 and 702,700 shares, for the
years ended December 31, 2003 and 2002, 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 was to provide a part of non-employee directors’
compensation in Company stock. The plan was 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 could have granted an aggregate of 60,000
shares of the Company’s common stock held in treasury. The Company made
aggregate grants to non-employee directors under this plan of 3,000 shares
during each of the years ending December 31, 2004 and 2002, and expensed
compensation in the amount of $13,500 in each of those years. No grants were
made under this plan during the year ended December 31, 2003. Through December
31, 2004, a total of 21,000 shares had been granted under this plan. No further
grants will be made under this plan as it expired on December 31,
2004.
  **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, 2004 has reserved
for issuance a total of 3,600,000 shares of common stock, of which 3,501,250
shares have been granted (1,930,850 are still outstanding) and 98,750 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. The Company received 215,599 shares ($4.1 million) in 2004
and 51,082 shares ($880,000) in 2003 of its common stock, now held as treasury
stock, from employees in cashless stock option exercises.
  **Prior
Stock Option Plans**
 There are
options granted and outstanding to purchase a total of 157,600 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 2004, 2003 and 2002 in outstanding options are presented
below:
 
 **2004**
    
    **2003**
    
    **2002****Number
      of Options**
    
    **Weighted-Average
      Exercise Price**
    
    **Number
      of Options**
    
    **Weighted-Average
      Exercise Price**
    
    **Number
      of Options**
    
    **Weighted-Average
      Exercise Price**Outstanding
      atbeginning
      of year
    
    
    3,071,525
    
    $
    13.21
    
    
    2,581,250
    
    $
    11.18
    
    
    2,159,700
    
    $
    7.22Granted
    
    
    45,000
    
    
    18.65
    
    
    844,000
    
    
    16.65
    
    
    702,400
    
    
    21.85Exercised
    
    
    (1,025,975
    )
    
    7.82
    
    
    (353,225
    )
    
    6.57
    
    
    (230,750
    )
    
    6.79Expired
    
    
    (2,100
    )
    
    21.85
    
    
    (500
    )
    
    8.60
    
    
    (50,100
    )
    
    10.21Outstanding
      at endof
      year
    
    
    2,088,450
    
    
    15.97
    
    
    3,071,525
    
    
    13.21
    
    
    2,581,250
    
    
    11.18Exercisable
      at endof
      year
    
    
    1,460,050
    
    
    15.02
    
    
    1,945,801
    
    
    10.88
    
    
    1,512,325
    
    
    8.63Available
      for grant at endof
      year
    
    
    98,750
    
    
    
    
    
    141,650
    
    
    
    
    
    985,650Weighted-average
      fairvalue
      of optionsgranted
      during the year
    
    
    
    
    
    7.67
    
    
    
    
    
    7.01
    
    
    
    
    
    9.34
 
 The
following table summarizes information about stock options outstanding at
December 31, 2004:
 
 **Options
      Outstanding**
    
    **Options
      Exercisable****Range
      of Exercise Prices**
    
    **Number
      Outstanding at 12/31/04**
    
    **Weighted-Average
      Remaining Contractual Life (Years)**
    
    **Weighted-Average
      Exercise Price**
    
    **Exercisable
      at 12/31/04**
    
    **Weighted-Average
      Exercise Price**$6.44
      to $7.00
    
    
    227,500
    
    
    0.17
    
    $
    6.98
    
    
    227,500
    
    $
    6.98$8.60
      to $8.75
    
    
    330,250
    
    
    1.16
    
    
    8.60
    
    
    330,250
    
    
    8.60$12.10
      to $16.65
    
    
    822,500
    
    
    3.10
    
    
    16.54
    
    
    400,500
    
    
    16.42$18.65
      to $21.85
    
    
    708,200
    
    
    2.41
    
    
    21.65
    
    
    501,800
    
    
    21.78
  **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.
 The
Company made grants of restricted stock during the years ended December 31, 2002
and 2001. As of December 31, 2004, there were 54,698 shares of unvested
restricted stock outstanding, which represents the remaining shares from the
2002 grants, which will vest in March 2005. No grants were made in the years
ended December 31, 2004 or 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, 2004, 2003 and 2002 was $1.2 million, $1.4 million and
$907,000, respectively. The Company received 48,443 shares in 2004, 24,825
shares in 2003 and 19,041 shares in 2002 of its common stock, now held as
treasury stock, from employees to cover withholding taxes on vested restricted
stock.
 
 **9.**
    **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 years ended December 31, 2004, 2003 and
2002 was $5.6 million, $5.1 million and $5.1 million, respectively.
 
 **Deferred
Compensation Plan**
 The
Company sponsors a deferred compensation plan for certain employees or directors
whose eligibility to participate in the plan is determined by the Company’s
compensation committee. Participants may contribute a portion of their earnings
to the plan, and the Company makes basis and/or matching contributions on behalf
of eligible employees. The contributions and any earnings are held in an
irrevocable trust known as a “rabbi trust” by an independent trustee. The trust
account balance and related liability are reflected in “Other assets” and
“Deferred compensation liability and other,” respectively, in the Consolidated
Balance Sheets.
  **Defined
Benefit Plans**
 The
Company established a defined cash balance pension plan, effective January 1,
2000, for eligible El Dorado Refinery employees to supplement retirement
benefits that 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 $6.9 million at December 31, 2004, 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, 2004 and 2003. The post-retirement
health care plan requires retirees to pay between 20% and 40% of total health
care costs based on age and length of service. The plan’s prescription drug
benefits are at least equivalent to the new Medicare Part D benefits.
 The
Company uses a December 31st measurement date for its plans. 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:
  **Pension
      Benefits**
    
    **Post-retirement
      Healthcare and Other Benefits (1)****2004**
    
    **2003**
    
    **2004**
    
    **2003***(in
      thousands)***Change
      in benefit obligation:**Benefit
      obligation at January 1
    
    $
    10,695
    
    $
    9,794
    
    $
    23,250
    
    $
    19,380Service
      cost
    
    
    -
    
    
    -
    
    
    862
    
    
    803Interest
      cost
    
    
    632
    
    
    611
    
    
    1,460
    
    
    1,262Plan
      participant contributions
    
    
    -
    
    
    -
    
    
    -
    
    
    -Actuarial
      losses
    
    
    485
    
    
    355
    
    
    3,614
    
    
    1,894Benefits
      paid
    
    
    (2
    )
    
    (65
    )
    
    (147
    )
    
    (89
    )Benefit
      obligation at December 31
    
    $
    11,810
    
    $
    10,695
    
    $
    29,039
    
    $
    23,250**Change
      in plan assets:**Fair
      value of plan assets at January 1
    
    $
    5,298
    
    $
    3,777
    
    $
    -
    
    $
    -Actual
      return on plan assets
    
    
    504
    
    
    200
    
    
    -
    
    
    -Employer
      contribution
    
    
    1,115
    
    
    1,386
    
    
    147
    
    
    89Plan
      participant contributions
    
    
    -
    
    
    -
    
    
    -
    
    
    -Benefits
      paid
    
    
    (2
    )
    
    (65
    )
    
    (147
    )
    
    (89
    )Fair
      value of plan assets at December 31
    
    $
    6,915
    
    $
    5,298
    
    $
    -
    
    $
    -Funded
      status
    
    $
    (4,895
    )
    $
    (5,397
    )
    $
    (29,039
    )
    $
    (23,250
    )Unrecognized
      net actuarial loss
    
    
    1,936
    
    
    1,498
    
    
    9,622
    
    
    6,498Net
      amount recognized
    
    $
    (2,959
    )
    $
    (3,899
    )
    $
    (19,417
    )
    $
    (16,752
    )Amounts
      recognized in the balance sheets:Accrued
      benefit liability (2)
    
    $
    (4,895
    )
    $
    (5,397
    )
    $
    (19,417
    )
    $
    (16,752
    )Accumulated
      other comprehensive loss
    
    
    1,936
    
    
    1,498
    
    
    -
    
    
    -Net
      amount recognized
    
    $
    (2,959
    )
    $
    (3,899
    )
    $
    (19,417
    )
    $
    (16,752
    )
  
 **Pension
      Benefits**
    
    **Post-retirement
      Healthcare**
      **and
      Other Benefits****2004**
    
    **2003**
    
    **2002**
    
    **2004**
    
    **2003**
    
    **2002***(in
      thousands)***Components
      of net periodic benefit cost for the year ended December
      31:**Service
      cost
    
    $
    -
    
    $
    -
    
    $
    -
    
    $
    863
    
    $
    803
    
    $
    691Interest
      cost
    
    
    632
    
    
    611
    
    
    582
    
    
    1,460
    
    
    1,262
    
    
    1,071Expected
      return on plan assets
    
    
    (479
    )
    
    (373
    )
    
    (162
    )
    
    -
    
    
    -
    
    
    -Amortization
      of prior service cost
    
    
    -
    
    
    -
    
    
    -
    
    
    -
    
    
    -
    
    
    -Recognized
      net actuarial loss
    
    
    22
    
    
    -
    
    
    -
    
    
    490
    
    
    337
    
    
    136Net
      periodic benefit cost
    
    $
    175
    
    $
    238
    
    $
    420
    
    $
    2,813
    
    $
    2,402
    
    $
    1,898
 
 **Weighted
      average assumptions:**Benefit
      obligation discount rate
      as
      of December 31
    
    
    5.50
    %
    
    6.00
    %
    
    -
    
    
    5.50
    %
    
    6.00
    %
    
    -Net
      periodic benefit cost discount rate
      for
      the year ended December 31
    
    
    6.00
    %
    
    6.25
    %
    
    6.82
    %
    
    6.00
    %
    
    6.25
    %
    
    6.82
    %Expected
      return on plan assets (3)
    
    
    8.00
    %
    
    8.00
    %
    
    8.00
    %
    
    -
    
    
    -
    
    
    -
 
 (1)
    The
      disclosed post-retirement healthcare obligations and net periodic costs
      for 2004 reflect government subsidies for prescription drugs as allowed
      under the Medicare Prescription Drug, Improvement and Modernization Act.
      The subsidy reduced the benefit obligation at December 31, 2004, by
      approximately $3.0 million and net periodic cost for the year ended
      December 31, 2004, by $0.1 million.
 (2)
    The
      portion of the liability of the pension benefit plan which is expected to
      be funded during the next year is included in “Accrued liabilities and
      other” in the current liability section on the Consolidated Balance
      Sheets. The current portion as of December 31, 2004 and 2003 was $1.2
      million and $1.4 million, respectively. The remainder of the liabilities
      are reflected in “Post-retirement employee liabilities” in the long-term
      liability section of the Consolidated Balance
Sheets.
 (3)
    The
      cash balance pension plan assumes an 8% expected long-term rate of return
      on assets based on a blend of historic returns of equity and debt
      securities. Actual returns on the Company’s plan assets exceeded 8% during
      2004.
 **Post-retirement
      Healthcare****and
      Other Benefits****2004**
    
    **2003**
    
    **2002***(dollars
      in thousands)***Healthcare
      cost-trend rate:**13.00
    %
    
    13.00
    %
    
    15.00
    %ratable to
    
    
    ratable
      to
    
    
    ratable
      to5.00
    %
    
    5.00
    %
    
    5.00
    %from 2008
    
    
    from
      2007
    
    
    from
      2007**Sensitivity
      Analysis:**Effect
      of 1% (-1%) change in healthcare cost-trend rate:Year-end
      benefit obligation
    
    $
    6,094
    
    $
    5,036
    
    $
    4,258(4,767
    )
    
    (3,926
    )
    
    (3,313
    )Total
      of service and interest cost
    
    
    502
    
    
    467
    
    
    394(392
    )
    
    (363
    )
    
    (307
    )
 At
December 31, 2004, the estimated future benefit payments to be paid out in the
next ten years are as follows:
 
 **Estimated
      future benefit payments**
      **For
      year ending December 31,**
      ***(in
      thousands)***
    
    **Pension
      Benefits**
    
    **Post-retirement
      Healthcare**
      **and
      Other Benefits**Payment
    
    Payment
    
    Subsidy
      Receipts2005
    
    $
    133
    
    $
    255
    
    $
    -2006
    
    
    214
    
    
    394
    
    
    72007
    
    
    305
    
    
    546
    
    
    112008
    
    
    303
    
    
    730
    
    
    142009
    
    
    436
    
    
    907
    
    
    21Next
      5 fiscal years thereafter
    
    
    5,433
    
    
    7,705
    
    
    258
  
  **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, 2004 and 2003, by asset category are as
follows:
 
 **Percentage
      of Plan Assets at December 31****,****2004**
    
    **2003**Asset
      Category:Cash
      equivalents
    
    
    16
    %
    
    47
    %Equity
      common trust funds
    
    
    52
    %
    
    16
    %Fixed
      income common trust funds
    
    
    26
    %
    
    37
    %Stock
      fund common trust funds
    
    
    6
    %
    
    -
    %Total
    
    
    100
    %
    
    100
    %
 
 The
Company does not have a definitive target for the percentage allocation of
assets in the plan. Management reviews the earnings on plan assets each year and
compares them to the expected return utilized by the actuary in the prior year.
If the actual returns vary dramatically from the expected returns, management
may direct the trustee to make changes in the allocation of types of
investments. 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.
 The
Company expects to make contributions into the Fund during the year ending
December 31, 2005, of approximately $1.2 million.
 
 **10.**
    **Commitments and Contingencies**
 
 **Lease
and Other Commitments**
 On
November 16, 1999, Frontier acquired the 110,000 barrels per day (“bpd”) 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
$60.0 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 $40.0 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. A
contingent earn-out payment of $7.5 million was required based on 2004 results;
this amount was accrued at December 31, 2004 and was paid in January 2005. 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 2005 through 2011. Operating lease rental
expense was approximately $10.4 million, $9.0 million and $11.3 million for the
years ended December 31, 2004, 2003 and 2002, respectively. The approximate
future minimum lease payments for operating leases as of December 31, 2004 are
$12.7 million for 2005, $12.0 million for 2006, $10.0 million for 2007, $9.4
million for 2008, $9.9 million for 2009 and $42.9 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 bpd of a Lloydminster
crude oil blend, a heavy Canadian crude. Initially, the Company received 9,000
bpd, which increased to 20,000 bpd 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 bpd 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. The Company has assigned a portion of its contracted
pipeline capacity to Baytex in connection with the crude supply agreement
discussed above. In December 2003, the Company entered into an expansion
capacity agreement on the Express Pipeline for an additional 10,000 bpd starting
in April 2005 through 2015. Of the additional 10,000 bpd, the Company assigned
4,000 bpd to another party starting in April 2005 through March 2006. The
Company’s remaining commitment for pipeline capacity, based on the current
tariff, and after reducing for the commitments assigned to other parties, is
approximately $3.2 million for 2005, $4.8 million for 2006, $5.1 million for
2007, an average of $12.0 million for each of the years 2008 through 2011, $7.4
million for 2012, approximately $5.8 million for each of the years 2013 and 2014
and $1.5 million for 2015. Should the Baytex agreement be extended beyond the
initial term ending December 31, 2007, as provided for in the agreement, a
portion of the Company’s commitment for pipeline capacity will continue to be
assigned to Baytex in the years 2008 through 2012.
 During
2004, the Company entered into a Transportation Services Agreement (“Agreement”)
to transport crude oil on the Spearhead Pipeline from Griffith, Indiana to
Cushing, Oklahoma. The owner of the Spearhead Pipeline intends to alter an
existing pipeline, including reversing the flow, with an anticipated date to be
able to commence crude oil shipments on or around January 1, 2006. This pipeline
will enable Frontier to transport Canadian crude oil to its El Dorado Refinery.
The initial term of this Agreement is for a period of ten years from the actual
commencement date, with the Company having the right to extend the Agreement for
an additional ten-year term. The Company has committed to transport a minimum
volume of 20,000 bpd of crude oil, with the right to increase that commitment.
Under this Agreement, the Company has an annual commitment of $5.5 million in
crude oil pipeline tariffs for each of the ten years in the term of the
Agreement.
 The
Company had a Resid Processing Agreement, as amended, with ConocoPhillips, which
was to expire after the earlier of a certain number of barrels processed, but no
later than December 2006. During 2003, this agreement was assigned from
ConocoPhillips to Suncor Energy (U.S.A.) (“Suncor”), when Suncor purchased the
refinery in Denver from ConocoPhillips. Suncor was entitled to process in the
Cheyenne Refinery coker up to 3,300 bpd of resid, a heavy end by-product of the
refining process. The Company earned a processing fee ranging from $0.80 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. This agreement expired in
July 2004 due to the required number of 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.”
  **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 have been named in six
such suits: Moss et al. v. Veneco, Inc. et al., filed in June 2003; Ibraham et
al. v. City of Beverly Hills et al., filed in July 2003; Yeshoua et al. v.
Veneco, Inc. et al., filed in August 2003; Jacobs v. Wainoco Oil & Gas
Company et al., filed in December 2003; Bussel et al. v. Veneco, Inc. et al.,
filed in January 2004; and Steiner et al. v. Venoco Inc. et al., filed in May
2004. Other defendants in these lawsuits 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 six
pending lawsuits have been related to one another and have been 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. A case management order has been
entered in the case pursuant to which 12 plaintiffs have been selected as the
initial group of plaintiffs to go to trial, discovery has commenced and a
preliminary trial date has been set for July 25, 2005.
 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. In October 2003, the Company paid $6.25 million to the
insurance company for loss mitigation insurance (which included an indemnity
premium of $5.75 million and a $500,000 administration fee) and also funded with
the insurance company a commutation account of approximately $19.5 million, from
which the insurance company is funding the first costs under the policy
including, but not limited to, the costs of defense of the claims. 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. As of December 31, 2004,
the commutation account balance was approximately $16.4 million. The Company
also paid $772,500 to the State of California for insurance tax on the premium
in 2003, of which $600,000 was refunded in 2004. Frontier has the right to
terminate the policy at any time after September 30, 2004 and prior to September
30, 2008, and receive a refund of the unearned portion of the premium
(approximately $4.0 million as of December 31, 2004, and declining by
approximately $1.1 million each year) 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.
 Frontier
believes that neither the claims that have been made, the six 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.
 
 **Holly
Lawsuit.** See Note 4 “Holly Merger Agreement and Litigation.”
 
 **MTBE
Concentration Lawsuits.** In
November 2003, the El Dorado Refinery (owned by the Company’s subsidiary,
Frontier El Dorado Refining Company (“FEDRC”)) was included as one of 52
defendants in four lawsuits brought on behalf of 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 (the “Kansas
Plaintiffs”) alleging unspecified damages for contamination of
groundwater/public water wells by methyl
tertiary butyl ether (“ MTBE”)
and tertiary butyl alcohol, a degradation product of MTBE. These four cases were
removed to federal court and were then transferred with other similar cases to a
federal district court in New York to be presided over by one federal court
judge. In November 2004, the Cheyenne Refinery (owned by the Company’s
subsidiary, Frontier Refining Inc (“FRI”)) was notified that it had been added
as a defendant to these same four cases involving Kansas Plaintiffs. Because
neither FEDRC nor FRI had either manufactured MTBE or provided MTBE blended
gasoline in the Kansas marketplace, the Kansas Plaintiffs voluntarily dismissed
both FEDRC and FRI in January 2005. These voluntary dismissals are without
prejudice. Accordingly, the Kansas Plaintiffs are able, if they have the
required evidentiary support, to add either FEDRC or FRI back into the
litigation. However, given the basis for the dismissals, the Company continues
to believe that any potential liability would not have a material adverse effect
on its liquidity, financial position or results of operations.
 
 **Other** **.** The
Company is also involved in various other 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 5,000 bpd
of the El Dorado Refinery’s gasoline and diesel production. The retained portion
is scheduled to increase by 5,000 bpd each year for ten years. In 2004, Frontier
retained 25,000 bpd of the Refinery’s gasoline and diesel production. 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 produced
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. No bad debt
losses were recorded during the year ended December 31, 2004. 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 $1.4 billion, $1.1 billion and $1.1 billion in the years
2004, 2003 and 2002, respectively, which accounted for 49% of consolidated
refined products revenues in 2004, 53% of consolidated refined products revenues
in 2003 and 58% of consolidated refined products revenues in 2002.
  **Environmental**
 The
Company accounts for environmental costs as indicated in Note 2. The Company’s
operations and many of its manufactured products 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 Refineries during the next several years. The Environmental
Protection Agency (“EPA”) has 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 the Initiative may affect the Company. The Company
has, however, in recognition of the EPA’s reinterpretation of certain regulatory
requirements associated with the Initiative, determined that Frontier will incur
expenditures totaling approximately $8.0 million to further reduce emissions
from the Refineries’ flare systems. At the Cheyenne Refinery, the Company spent
$223,000 in 2004, and estimates spending an additional $4.0 million, primarily
in 2005, on the flare system. At the El Dorado Refinery, the Company spent
$423,000 in 2004, and it estimates incurring a total additional $3.3 million
during 2005 and 2006, on the flare system. 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; however, Region VII of the EPA has
informed the State of Kansas and the Company that requirements for reductions in
emissions from the El Dorado Refinery’s Fluid Catalytic Cracking Unit (“FCCU”)
must also be included in any settlement with the State of Kansas if the Company
wants protection from a subsequent EPA enforcement action under the Initiative.
The Company is currently evaluating interim and final FCCU emission control
options.
 In a
settlement entered on February 22, 2005, the WDEQ has accepted a penalty in the
amount of $120,000 in addition to the Company’s commitment to complete the
aforementioned flare system controls and an agreed upon Capital Supplemental
Environmental Project estimated to cost $535,000 to resolve one of the
Iniative’s four concerns and other prior violations. The settlement
addresses:
 ·
    the
      reduction of flare system emissions,·
    an
      earlier notice of violation regarding excess emissions from the Cheyenne
      Refinery’scrude unit heaters,·
    resolution
      of a 1992 Odor Consent Decree, and·
    two
      recent odor violations associated with the startup of the Cheyenne
      Refinery’s new gasoline desulfurization
equipment.
 During
the first quarter of 2004, the Company decreased the previously estimated
penalty accrual of $317,000 recorded as of December 31, 2003 to $120,000. This
$197,000 reduction is reflected as a reduction of “Refinery operating expenses,
excluding depreciation” on the Consolidated Statement of Income for the year
ended December 31, 2004.
 The EPA
has promulgated regulations requiring the phase-in of gasoline sulfur standards,
which began January 1, 2004 and continues through 2008, with special provisions
for small business refiners. Because the Company qualifies as a small business
refiner, Frontier has elected to extend its small refinery interim gasoline
sulfur standard at each of the Refineries until 2011 and to comply with the
highway diesel sulfur standard by June 2006 as discussed below. The Cheyenne
Refinery has spent approximately $28.9 million (including capitalized interest)
to complete the project to meet the interim gasoline sulfur standard, which was
required by January 1, 2004. The remaining $7.0 million estimated cost to meet
the additional standard for the Cheyenne Refinery is expected to be incurred in
2009 and 2010. The total capital expenditures estimated as of December 31, 2004,
for the El Dorado Refinery to achieve the final gasoline sulfur standard are
approximately $15 million, which are expected to be incurred between 2006 and
2009. The Company’s approach to achieve the gasoline sulfur standard at the El
Dorado Refinery has been revised from building a new unit to the modification of
existing equipment, thus reducing the cost from the original estimate of $44.0
million.
 The EPA
has promulgated regulations that will limit the sulfur content of highway diesel
fuel beginning in 2006. As indicated above, Frontier has elected to comply with
the highway diesel sulfur standard by June 2006. As of December 31, 2004,
capital costs, including capitalized interest, for diesel desulfurization are
estimated to be approximately $14.0 million for the Cheyenne Refinery and
approximately $106.5 million for the El Dorado Refinery. Approximately $250,000
of the Cheyenne Refinery expenditures were incurred in 2004, $9.0 million is
estimated to be incurred in 2005, and the remaining $4.7 million is estimated to
be incurred in the first half of 2006. Approximately $6.0 million of the El
Dorado Refinery expenditures were incurred in 2004, $90.5 is estimated to be
incurred in 2005, and the remaining $10.0 million is estimated to be incurred in
the first half of 2006. Certain provisions of The American Jobs Creation Act of
2004 should benefit Frontier by allowing the Company an accelerated depreciation
deduction of 75% of these qualified capital costs in the years incurred and by
providing a $0.05 per gallon credit on compliant diesel fuel up to an amount
equal to the remaining 25% of these qualified capital costs for federal income
tax purposes.
 On June
29, 2004, the EPA promulgated regulations designed to reduce emissions from the
combustion of diesel fuel in non-road applications such as mining, agriculture,
locomotives and marine vessels. The Company currently participates in this
market through the manufacture and sale of approximately 6,000 bpd of non-road
diesel fuel from the El Dorado Refinery. The new regulations will, in part,
require refiners to reduce the sulfur content of non-road diesel fuel from 5,000
parts per million (“ppm”) to 500 ppm in 2007 and further to 15 ppm in 2010 for
all uses but locomotive and marine. Diesel fuel used in locomotives and marine
operations will be required to meet the 15 ppm sulfur standard in 2012. Small
refiners, such as Frontier, will be allowed to either postpone the new sulfur
limits or, if the small refiner chooses to meet the new limit on the national
schedule, to increase their gasoline sulfur limits by 20%. Frontier intends to
desulfurize all of its diesel fuel, including non-road, to the 15 ppm sulfur
standard by 2006. The new regulation also clarifies that EPA-approved small
business refiners will be allowed to exceed both the small refiner maximum
capacity and/or employee criteria through merger with or acquisition of another
approved small business refiner without loss of small refiner regulatory
status.
 The front
range of Colorado (including the Denver metropolitan area) is a major market for
the products manufactured by the Company’s Refineries. During 2004, the State of
Colorado undertook an effort to develop and implement controls necessary to
ensure that 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. On March 25, 2004, the EPA advised the refiners supplying the
Denver region that their request for continuance of the long-standing Reid Vapor
Pressure (“RVP”) waiver would not be granted for the 2004 ozone control period
and that gasoline marketed in the area could not exceed the regulatory standard
of 7.8 pounds RVP beginning May 1, 2004 at the marketing distribution terminals
and June 1, 2004 at customer retail locations. During 2004, the Company incurred
$2.0 million in capital costs at our Cheyenne Refinery to comply with this
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, including 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.
 **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, the Company addressed tasks required under a consent
decree approved 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, including the completion of surface
impoundment closures, waste stabilization activities and other site remediation
projects totaling approximately $4.0 million. In addition, the Company estimates
that an ongoing groundwater remediation program averaging approximately $200,000
in annual operating and maintenance costs will be required for approximately ten
more years. As of December 31, 2004, the Company has a reserve included in
“Other long-term liabilities” of $1.5 million in environmental liabilities
reflecting the estimated present value of these expenditures ($2.0 million,
discounted at a rate of 5.0%). The EPA also 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 had been adversely impacted by past operational activities. Based
upon the results of the ongoing investigation, additional remedial action could
be required by a subsequent administrative order or permit.
 In
accordance with permits issued by the State of Wyoming under the federal
National Pollutant Discharge Elimination System (“NPDES”), the Cheyenne Refinery
is permitted to discharge its treated wastewater to either of two receiving
waterways: a creek adjacent to the Cheyenne Refinery or a normally dry ravine
called “Porter Draw.” Certain landowners downstream of the Cheyenne Refinery’s
permitted discharge to Porter Draw expressed their unwillingness to continue to
accommodate this wastewater flow by appealing the Company’s discharge permit and
by giving notice of possible legal action. In response, as an alternative to
continuing to discharge into the ravine, the Company arranged to deliver its
treated wastewater beginning in July 2004 to the City of Cheyenne (“Cheyenne”)
municipal treatment plant for additional treatment and release, and it has
entered into settlements with the landowners. To initiate this wastewater
treatment service, Frontier has agreed to pay Cheyenne a $1.6 million
development fee (reflected in “Other intangible asset, net of accumulated
amortization” on the Consolidated Balance Sheet as of December 31, 2004). This
fee will be amortized over 15 years with the amortization expense included in
“Depreciation and amortization” in the Consolidated Statements of Income. The
$1.6 million fee will be paid in equal installments over five years, with the
first payment having been made in July 2004. In addition, beginning in July
2004, the Cheyenne Refinery pays Cheyenne $2.00 per 1,000 gallons of wastewater
treated, which is included as “Refinery operating expenses, excluding
depreciation” in the Consolidated Statement of Income.
 **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 for the El
Dorado Refinery entered into between the Company and Shell, Shell is responsible
for the costs of continued compliance with this order.
  **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 58% of the Company’s work
force at December 31, 2004.
 
 **11.**
    **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, 2004 and 2003, the carrying amounts of long-term debt instruments
were $150.0 million and $168.7 million, respectively, and the estimated fair
values were $151.5 million and $185.8 million, respectively. For cash and cash
equivalents, trade receivables, inventory and accounts payable, the carrying
amount is a reasonable estimate of fair value.
 
 **12.**
    **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
2004, 2003 and 2002, 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 excess crude oil, intermediate
      and finished product inventory for both the Cheyenne and El Dorado
      Refineries.**As
      of December 31, 2004, the Company had reported $354,000 in unrealized
      gains on open derivative contracts. During the year ended December 31,
      2004, the Company recorded $8.1 million in realized losses on these types
      of positions. During the year ended December 31, 2003, the Company
      recorded $130,000 in realized gains on these types of positions. During
      the year ended December 31, 2002, the Company recorded $740,000 in net
      realized losses on these positions.****
 ·
    **Derivative
      contracts to fix the heavy crude differential to the New York Mercantile
      Exchange light crude oil contract price for a portion of the committed
      purchases under the Company’s crude oil supply agreement with
      Baytex.**
 During
the year ended December 31, 2004, the Company recorded losses of approximately
$2.5 million on contracts purchased for this purpose. During the year ended
December 31, 2003, the Company recorded realized and unrealized losses totaling
$417,000 on contracts for this purpose. No derivative contracts were utilized
for this purpose in 2002.
  **Hedging
Activities**
 During
the year ended December 31, 2004, the Company had no derivative contracts which
were accounted for as hedges. During 2003 and 2002, the Company had the
following derivatives which were appropriately designated and accounted for as
hedges:
 
 ·
    **Crude
      Purchases.**During the year ended December 31, 2003, the Company had derivative
      contracts on 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. The Company also utilized derivative contracts on
      barrels of crude oil to hedge two foreign crude cargos purchased for the
      El Dorado Refinery during the year ended December 31, 2003. 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
      utilized derivative contracts on barrels of crude oil to hedge foreign
      crude purchases for the El Dorado Refinery and recorded net losses of $9.8
      million, of which $10.7 million increased crude costs and $848,000 income
      was reflected in “Other revenues” for the ineffective portion of those
      hedges. These contracts were accounted for as fair value hedges.
 ·
    **Natural
      Gas Collars.**The Company entered into price swaps on natural gas for the purpose of
      hedging against natural gas price increases for the El Dorado Refinery in
      2003, which resulted in a realized $1.7 million gain and which reduced
      “Refinery operating expenses, excluding depreciation” for the year ended
      December 31, 2003. 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, which resulted in $434,000 net realized gains and reduced “Refinery
      operating expenses, excluding depreciation” for the year ended December
      31, 2002. These contracts were accounted for as cash flow hedges.
 
 **13.**
    **Consolidating
      Financial Statements**
 
 Frontier
Holdings Inc. and its subsidiaries (“FHI”) are full and unconditional guarantors
of the Company’s 65⁄8% Senior Notes. Presented on the following pages are the
Company’s consolidating balance sheets, statements of operations, and cash flows
as required by Rule 3-10 of Regulation S-X of the Securities Exchange Act of
1934, as amended. As specified in Rule 3-10, the condensed consolidating balance
sheets, statement of operations, and cash flows presented below meet the
requirements for financial statements of the issuer and each guarantor of the
notes because guarantors are all direct or indirect wholly-owned subsidiaries of
Frontier, and all of the guarantees are full and unconditional on a joint and
several basis. The Company files a consolidated U.S. federal income tax return
and consolidated state income tax returns in the majority of states in which it
does business. Each subsidiary calculates its income tax provisions on a
separate company basis, which are eliminated in the consolidation
process.
 
 
 **CONSOLIDATING
FINANCIAL STATEMENTS**
 
 **FRONTIER
      OIL CORPORATION****Condensed
      Consolidating Statement of Operations****For
      the Year Ended December 31, 2004***(in
      thousands)***FOC
      (Parent)**
    
    **FHI
      (Guarantor Subsidiaries)**
    
    **Other
      Non-Guarantor Subsidiaries**
    
    **Eliminations**
    
    **Consolidated****Revenues:**Refined
      products
    
    $
    -
    
    $
    2,871,592
    
    $
    -
    
    $
    -
    
    $
    2,871,592Other
    
    
    (6
    )
    
    (9,932
    )
    
    62
    
    
    -
    
    
    (9,876
    )****
    
    
    (6
    )
    
    2,861,660
    
    
    62
    
    
    -
    
    
    2,861,716******Costs
      and expenses:**Raw
      material, freight and other costs
    
    
    -
    
    
    2,432,461
    
    
    -
    
    
    -
    
    
    2,432,461Refinery
      operating expenses,
      excluding
      depreciation
    
    
    -
    
    
    219,781
    
    
    -
    
    
    -
    
    
    219,781Selling
      and general expenses,
      excluding
      depreciation
    
    
    15,590
    
    
    14,303
    
    
    -
    
    
    -
    
    
    29,893Merger
      termination and legal costs
    
    
    3,824
    
    
    -
    
    
    -
    
    
    -
    
    
    3,824Depreciation
      and amortization
    
    
    75
    
    
    32,688
    
    
    -
    
    
    (555
    )
    
    32,20819,489
    
    
    2,699,233
    
    
    -
    
    
    (555
    )
    
    2,718,167**Operating
      income**
    
    
    (19,495
    )
    
    162,427
    
    
    62
    
    
    555
    
    
    143,549Interest
      expense and other financing costs
    
    
    35,004
    
    
    2,609
    
    
    -
    
    
    (40
    )
    
    37,573Interest
      income
    
    
    (1,545
    )
    
    (171
    )
    
    -
    
    
    -
    
    
    (1,716
    )Equity
      in earnings of subsidiaries
    
    
    (165,038
    )
    
    -
    
    
    -
    
    
    165,038
    
    
    -Gain
      on involuntary conversion of assets
    
    
    -
    
    
    (4,411
    )
    
    -
    
    
    -
    
    
    (4,411
    )(131,579
    )
    
    (1,973
    )
    
    -
    
    
    164,998
    
    
    31,446**Income
      before income taxes**
    
    
    112,084
    
    
    164,400
    
    
    62
    
    
    (164,443
    )
    
    112,103Provision
      for income taxes
    
    
    42,320
    
    
    62,429
    
    
    -
    
    
    (62,410
    )
    
    42,339**Net
      income**
    
    $
    69,764
    
    $
    101,971
    
    $
    62
    
    $
    (102,033
    )
    $
    69,764
  
  **FRONTIER
      OIL CORPORATION****Condensed
      Consolidating Statement of Operations****For
      the Year Ended December 31, 2003***(in
      thousands)***FOC
      (Parent)**
    
    **FHI
      (Guarantor Subsidiaries)**
    
    **Other
      Non-Guarantor Subsidiaries**
    
    **Eliminations**
    
    **Consolidated****Revenues:**Refined
      products
    
    $
    -
    
    $
    2,169,551
    
    $
    -
    
    $
    -
    
    $
    2,169,551Other
    
    
    (17
    )
    
    922
    
    
    47
    
    
    -
    
    
    952****
    
    
    (17
    )
    
    2,170,473
    
    
    47
    
    
    -
    
    
    2,170,503**Costs
      and expenses:**Raw
      material, freight and other costs
    
    
    -
    
    
    1,860,795
    
    
    -
    
    
    -
    
    
    1,860,795Refinery
      operating expenses,
      excluding
      depreciation
    
    
    -
    
    
    200,383
    
    
    -
    
    
    -
    
    
    200,383Selling
      and general expenses,
      excluding
      depreciation
    
    
    7,936
    
    
    11,954
    
    
    -
    
    
    -
    
    
    19,890Merger
      termination and legal costs
    
    
    8,739
    
    
    -
    
    
    -
    
    
    -
    
    
    8,739Depreciation
      and amortization
    
    
    113
    
    
    29,275
    
    
    -
    
    
    (556
    )
    
    28,83216,788
    
    
    2,102,407
    
    
    -
    
    
    (556
    )
    
    2,118,639**Operating
      income**
    
    
    (16,805
    )
    
    68,066
    
    
    47
    
    
    556
    
    
    51,864Interest
      expense and other financing costs
    
    
    26,981
    
    
    1,765
    
    
    -
    
    
    -
    
    
    28,746Interest
      income
    
    
    (1,004
    )
    
    (105
    )
    
    -
    
    
    -
    
    
    (1,109
    )Equity
      in earnings of subsidiaries
    
    
    (48,949
    )
    
    -
    
    
    -
    
    
    48,949
    
    
    -Merger
      financing termination costs, net
    
    
    -
    
    
    -
    
    
    18,039
    
    
    -
    
    
    18,039(22,972
    )
    
    1,660
    
    
    18,039
    
    
    48,949
    
    
    45,676**Income
      (loss) before income taxes**
    
    
    6,167
    
    
    66,406
    
    
    (17,992
    )
    
    (48,393
    )
    
    6,188Provision
      for income taxes
    
    
    2,935
    
    
    25,506
    
    
    -
    
    
    (25,485
    )
    
    2,956**Net
      income (loss)**
    
    $
    3,232
    
    $
    40,900
    
    $
    (17,992
    )
    $
    (22,908
    )
    $
    3,232
 
 
 
 **FRONTIER
      OIL CORPORATION****Condensed
      Consolidating Statement of Operations****For
      the Year Ended December 31, 2002***(in
      thousands)***FOC
      (Parent)**
    
    **FHI
      (Guarantor Subsidiaries)**
    
    **Other
      Non-Guarantor Subsidiaries**
    
    **Eliminations**
    
    **Consolidated****Revenues:**Refined
      products
    
    $
    -
    
    $
    1,812,613
    
    $
    -
    
    $
    -
    
    $
    1,812,613Other
    
    
    (1
    )
    
    1,113
    
    
    25
    
    
    -
    
    
    1,137****
    
    
    (1
    )
    
    1,813,726
    
    
    25
    
    
    -
    
    
    1,813,750**Costs
      and expenses:**Raw
      material, freight and other costs
    
    
    -
    
    
    1,562,613
    
    
    -
    
    
    -
    
    
    1,562,613Refinery
      operating expenses,
      excluding
      depreciation
    
    
    -
    
    
    178,295
    
    
    -
    
    
    -
    
    
    178,295Selling
      and general expenses,
      excluding
      depreciation
    
    
    6,208
    
    
    11,403
    
    
    -
    
    
    -
    
    
    17,611Depreciation
      and amortization
    
    
    247
    
    
    27,640
    
    
    -
    
    
    (555
    )
    
    27,3326,455
    
    
    1,779,951
    
    
    -
    
    
    (555
    )
    
    1,785,851**Operating
      income**
    
    
    (6,456
    )
    
    33,775
    
    
    25
    
    
    555
    
    
    27,899Interest
      expense and other financing costs
    
    
    24,858
    
    
    2,755
    
    
    -
    
    
    -
    
    
    27,613Interest
      income
    
    
    (1,698
    )
    
    (104
    )
    
    -
    
    
    -
    
    
    (1,802
    )Equity
      in earnings of subsidiaries
    
    
    (31,704
    )
    
    -
    
    
    -
    
    
    31,704
    
    
    -(8,544
    )
    
    2,651
    
    
    -
    
    
    31,704
    
    
    25,811**Income
      before income taxes**
    
    
    2,088
    
    
    31,124
    
    
    25
    
    
    (31,149
    )
    
    2,088Provision
      for income taxes
    
    
    1,060
    
    
    12,364
    
    
    -
    
    
    (12,364
    )
    
    1,060**Net
      income**
    
    $
    1,028
    
    $
    18,760
    
    $
    25
    
    $
    (18,785
    )
    $
    1,028
 
 
 
 **FRONTIER
      OIL CORPORATION****Condensed
      Consolidating Balance Sheet****As
      of December 31, 2004***(in
      thousands)***FOC
      (Parent)**
    
    **FHI
      (Guarantor Subsidiaries)**
    
    **Other
      Non-Guarantor Subsidiaries**
    
    **Eliminations**
    
    **Consolidated****ASSETS**Current
      assets:Cash
      and cash equivalents
    
    $
    105,409
    
    $
    18,980
    
    $
    -
    
    $
    -
    
    $
    124,389Trade
      and other receivables
    
    
    7,013
    
    
    81,251
    
    
    -
    
    
    -
    
    
    88,264Receivable
      from affiliated companies
    
    
    -
    
    
    431
    
    
    99
    
    
    (530
    )
    
    -Inventory
    
    
    -
    
    
    156,934
    
    
    -
    
    
    -
    
    
    156,934Deferred
      tax assets
    
    
    6,748
    
    
    6,626
    
    
    -
    
    
    (6,626
    )
    
    6,748Other
      current assets
    
    
    105
    
    
    2,239
    
    
    -
    
    
    -
    
    
    2,344Total
      current assets
    
    
    119,275
    
    
    266,461
    
    
    99
    
    
    (7,156
    )
    
    378,679Property,
      plant and equipment, at cost:
    
    
    1,114
    
    
    561,010
    
    
    -
    
    
    (11,013
    )
    
    551,111Less
      - accumulated depreciationand
      amortization
    
    
    941
    
    
    210,812
    
    
    -
    
    
    (7,405
    )
    
    204,348173
    
    
    350,198
    
    
    -
    
    
    (3,608
    )
    
    346,763Deferred
      financing costs, net
    
    
    3,252
    
    
    1,076
    
    
    -
    
    
    -
    
    
    4,328Commutation
      account
    
    
    16,438
    
    
    -
    
    
    -
    
    
    -
    
    
    16,438Prepaid
      insurance, net
    
    
    4,542
    
    
    -
    
    
    -
    
    
    -
    
    
    4,542Other
      intangible assets, net
    
    
    -
    
    
    1,527
    
    
    -
    
    
    -
    
    
    1,527Other
      assets
    
    
    2,108
    
    
    15
    
    
    -
    
    
    -
    
    
    2,123Investment
      in subsidiaries
    
    
    295,764
    
    
    -
    
    
    -
    
    
    (295,764
    )
    
    -Total
      assets
    
    $
    441,552
    
    $
    619,277
    
    $
    99
    
    $
    (306,528
    )
    $
    754,400**LIABILITIES
      AND SHAREHOLDERS’ EQUITY**Current
      Liabilities:Accounts
      payable
    
    $
    853
    
    $
    238,138
    
    $
    -
    
    $
    -
    
    $
    238,991Accrued
      turnaround cost
    
    
    -
    
    
    15,373
    
    
    -
    
    
    -
    
    
    15,373Accrued
      interest
    
    
    2,485
    
    
    2
    
    
    -
    
    
    -
    
    
    2,487Accrued
      liabilities and other
    
    
    3,505
    
    
    20,793
    
    
    269
    
    
    -
    
    
    24,567Total
      current liabilities
    
    
    6,843
    
    
    274,306
    
    
    269
    
    
    -
    
    
    281,418Long-term
      debt
    
    
    150,000
    
    
    -
    
    
    -
    
    
    -
    
    
    150,000Long-term
      accrued and other liabilities
    
    
    -
    
    
    38,803
    
    
    -
    
    
    -
    
    
    38,803Deferred
      compensation liabilityand
      other
    
    
    1,516
    
    
    -
    
    
    -
    
    
    -
    
    
    1,516Deferred
      income taxes
    
    
    42,550
    
    
    50,462
    
    
    -
    
    
    (50,462
    )
    
    42,550Payable
      to affiliated companies
    
    
    530
    
    
    7,353
    
    
    -
    
    
    (7,883
    )
    
    -****Shareholders’
      equity
    
    
    240,113
    
    
    248,353
    
    
    (170
    )
    
    (248,183
    )
    
    240,113****Total
      liabilities and shareholders’ equity
    
    $
    441,552
    
    $
    619,277
    
    $
    99
    
    $
    (306,528
    )
    $
    754,400
  
  **FRONTIER
      OIL CORPORATION****Condensed
      Consolidating Balance Sheet****As
      of December 31, 2003***(in
      thousands)***FOC**
      **(Parent)**
    
    **FHI
      (Guarantor Subsidiaries)**
    
    **Other
      Non-Guarantor Subsidiaries**
    
    **Eliminations**
    
    **Consolidated****ASSETS**Current
      assets:Cash
      and cash equivalents
    
    $
    59,846
    
    $
    4,674
    
    $
    -
    
    $
    -
    
    $
    64,520Trade
      and other receivables
    
    
    710
    
    
    87,643
    
    
    -
    
    
    -
    
    
    88,353Receivable
      from affiliated companies
    
    
    -
    
    
    692
    
    
    40
    
    
    (732
    )
    
    -Inventory
    
    
    -
    
    
    123,999
    
    
    -
    
    
    -
    
    
    123,999Deferred
      tax assets
    
    
    5,967
    
    
    5,201
    
    
    -
    
    
    (5,201
    )
    
    5,967Other
      current assets
    
    
    68
    
    
    1,906
    
    
    -
    
    
    -
    
    
    1,974Total
      current assets
    
    
    66,591
    
    
    224,115
    
    
    40
    
    
    (5,933
    )
    
    284,813Property,
      plant and equipment, at cost:
    
    
    1,111
    
    
    505,586
    
    
    -
    
    
    (11,053
    )
    
    495,644Less
      - accumulated depreciation
    
    
    866
    
    
    179,180
    
    
    -
    
    
    (6,850
    )
    
    173,196245
    
    
    326,406
    
    
    -
    
    
    (4,203
    )
    
    322,448Deferred
      financing costs, net
    
    
    3,299
    
    
    710
    
    
    -
    
    
    -
    
    
    4,009Commutation
      account
    
    
    19,550
    
    
    -
    
    
    -
    
    
    -
    
    
    19,550Prepaid
      insurance, net
    
    
    6,593
    
    
    -
    
    
    -
    
    
    -
    
    
    6,593Other
      assets
    
    
    4,884
    
    
    -
    
    
    -
    
    
    -
    
    
    4,884Investment
      in subsidiaries
    
    
    264,016
    
    
    -
    
    
    -
    
    
    (264,016
    )
    
    -Total
      assets****
    
    $
    365,178
    
    $
    551,231
    
    $
    40
    
    $
    (274,152
    )
    $
    642,297**LIABILITIES
      AND SHAREHOLDERS’ EQUITY**Current
      liabilities:Accounts
      payable
    
    $
    1,736
    
    $
    175,496
    
    $
    3
    
    $
    -
    
    $
    177,235Revolving
      credit facility
    
    
    -
    
    
    45,750
    
    
    -
    
    
    -
    
    
    45,750Accrued
      turnaround cost
    
    
    -
    
    
    10,412
    
    
    -
    
    
    -
    
    
    10,412Accrued
      interest
    
    
    2,504
    
    
    9
    
    
    -
    
    
    -
    
    
    2,513Accrued
      liabilities and other
    
    
    1,587
    
    
    8,426
    
    
    269
    
    
    -
    
    
    10,282Total
      current liabilities****
    
    
    5,827
    
    
    240,093
    
    
    272
    
    
    -
    
    
    246,192Long-term
      debt
    
    
    168,689
    
    
    -
    
    
    -
    
    
    -
    
    
    168,689Long-term
      accrued and other liabilities
    
    
    -
    
    
    36,954
    
    
    -
    
    
    -
    
    
    36,954Deferred
      compensation liabilityand
      other
    
    
    3,723
    
    
    532
    
    
    -
    
    
    -
    
    
    4,255Deferred
      income taxes
    
    
    16,930
    
    
    38,183
    
    
    -
    
    
    (38,183
    )
    
    16,930Payable
      to affiliated companies
    
    
    732
    
    
    3,271
    
    
    -
    
    
    (4,003
    )
    
    -****Shareholders’
      equity
    
    
    169,277
    
    
    232,198
    
    
    (232
    )
    
    (231,966
    )
    
    169,277****Total
      liabilities and shareholders’ equity
    
    $
    365,178
    
    $
    551,231
    
    $
    40
    
    $
    (274,152
    )
    $
    642,297
  
 
 **FRONTIER
      OIL CORPORATION****Condensed
      Consolidating Statement of Cash Flows****For
      the Year Ended December 31, 2004***(in
      thousands)***FOC**
      **(Parent)**
    
    **FHI
      (Guarantor Subsidiaries)**
    
    **Other
      Non-Guarantor Subsidiaries**
    
    **Eliminations**
    
    **Consolidated****Cash
      flows from operating activities:**Net
      income
    
    $
    69,764
    
    $
    101,971
    
    $
    62
    
    $
    (102,033
    )
    $
    69,764Equity
      in earnings of subsidiaries
    
    
    (165,038
    )
    
    -
    
    
    -
    
    
    165,038
    
    
    -Depreciation
      and amortization
    
    
    75
    
    
    32,688
    
    
    -
    
    
    (555
    )
    
    32,208Deferred
      income taxes
    
    
    25,005
    
    
    -
    
    
    -
    
    
    -
    
    
    25,005Income
      tax benefits of stockcompensation
    
    
    5,168
    
    
    -
    
    
    -
    
    
    -
    
    
    5,168Income
      taxes eliminated inconsolidation
    
    
    -
    
    
    62,410
    
    
    -
    
    
    (62,410
    )
    
    -Deferred
      finance cost and bonddiscount
      amortization
    
    
    5,180
    
    
    304
    
    
    -
    
    
    -
    
    
    5,484Deferred
      employeecompensation
      amortization
    
    
    1,180
    
    
    -
    
    
    -
    
    
    -
    
    
    1,180Gain
      on involuntaryconversion
      of assets
    
    
    -
    
    
    (4,411
    )
    
    -
    
    
    -
    
    
    (4,411
    )Long-term
      commutation accountand
      prepaid insurance
    
    
    3,712
    
    
    -
    
    
    -
    
    
    -
    
    
    3,712Amortization
      of long-termprepaid
      insurance
    
    
    1,451
    
    
    -
    
    
    -
    
    
    -
    
    
    1,451Other
    
    
    582
    
    
    (863
    )
    
    -
    
    
    -
    
    
    (281
    )Changes
      in components ofworking
      capital
    
    
    (5,664
    )
    
    44,286
    
    
    (3
    )
    
    -
    
    
    38,619Net
      cash provided by (used in)operating
      activities
    
    
    (58,585
    )
    
    236,385
    
    
    59
    
    
    40
    
    
    177,899**Cash
      flows from investing activities:**Additions
      to property, plant andequipment
    
    
    (3
    )
    
    (46,459
    )
    
    -
    
    
    (40
    )
    
    (46,502
    )Net
      proceeds from insurance - involuntary conversion claim
    
    
    -
    
    
    3,395
    
    
    -
    
    
    -
    
    
    3,395Net
      cash used in investing activities
    
    
    (3
    )
    
    (43,064
    )
    
    -
    
    
    (40
    )
    
    (43,107
    )**Cash
      flows from financing activities:**Proceeds
      from issuance of65⁄8%
      Senior Notes
    
    
    150,000
    
    
    -
    
    
    -
    
    
    -
    
    
    150,000Repurchase
      of 113⁄4% Senior Notes
    
    
    (170,449
    )
    
    -
    
    
    -
    
    
    -
    
    
    (170,449
    )Repayments
      of revolving creditfacility,
      net
    
    
    -
    
    
    (45,750
    )
    
    -
    
    
    -
    
    
    (45,750
    )Proceeds
      from issuance ofcommon
      stock
    
    
    3,923
    
    
    -
    
    
    -
    
    
    -
    
    
    3,923Purchase
      of treasury stock
    
    
    (3,029
    )
    
    -
    
    
    -
    
    
    -
    
    
    (3,029
    )Dividends
      paid
    
    
    (5,664
    )
    
    -
    
    
    -
    
    
    -
    
    
    (5,664
    )Debt
      issue costs and other
    
    
    (3,279
    )
    
    (675
    )
    
    -
    
    
    -
    
    
    (3,954
    )Intercompany
      transactions
    
    
    132,649
    
    
    (132,590
    )
    
    (59
    )
    
    -
    
    
    -Net
      cash provided by (used in)financing
      activities
    
    
    104,151
    
    
    (179,015
    )
    
    (59
    )
    
    -
    
    
    (74,923
    )Increase
      in cash andcash
      equivalents
    
    
    45,563
    
    
    14,306
    
    
    -
    
    
    -
    
    
    59,869Cash
      and cash equivalents,beginning
      of period
    
    
    59,846
    
    
    4,674
    
    
    -
    
    
    -
    
    
    64,520Cash
      and cash equivalents,end
      of period
    
    $
    105,409
    
    $
    18,980
    
    $
    -
    
    $
    -
    
    $
    124,389
  **FRONTIER
      OIL CORPORATION****Condensed
      Consolidating Statement of Cash Flows****For
      the Year Ended December 31, 2003***(in
      thousands)*
 **FOC
      (Parent)**
    
    **FHI
      (Guarantor Subsidiaries)**
    
    **Other
      Non-Guarantor Subsidiaries**
    
    **Eliminations**
    
    **Consolidated****Cash
      flows from operating activities:**Net
      income
    
    $
    3,232
    
    $
    40,900
    
    $
    (17,992
    )
    $
    (22,908
    )
    $
    3,232Equity
      in earnings of subsidiaries
    
    
    (48,949
    )
    
    -
    
    
    -
    
    
    48,949
    
    
    -Depreciation
      and amortization
    
    
    113
    
    
    29,275
    
    
    -
    
    
    (556
    )
    
    28,832Deferred
      income taxes
    
    
    2,655
    
    
    -
    
    
    -
    
    
    -
    
    
    2,655Income
      taxes eliminated inconsolidation
    
    
    -
    
    
    25,485
    
    
    -
    
    
    (25,485
    )
    
    -Deferred
      finance cost and bonddiscount
      amortization
    
    
    2,206
    
    
    322
    
    
    8,114
    
    
    -
    
    
    10,642Deferred
      employee compensationamortization
    
    
    1,386
    
    
    -
    
    
    -
    
    
    -
    
    
    1,386Long-term
      commutation accountand
      prepaid insurance
    
    
    (26,566
    )
    
    -
    
    
    -
    
    
    -
    
    
    (26,566
    )Amortization
      of long-term prepaidinsurance
    
    
    423
    
    
    -
    
    
    -
    
    
    -
    
    
    423Other
    
    
    (264
    )
    
    (423
    )
    
    -
    
    
    -
    
    
    (687
    )Changes
      in components ofworking
      capital
    
    
    49
    
    
    (25,946
    )
    
    (25
    )
    
    -
    
    
    (25,922
    )Net
      cash provided by (used in)operating
      activities
    
    
    (65,715
    )
    
    69,613
    
    
    (9,903
    )
    
    -
    
    
    (6,005
    )**Cash
      flows from investing activities:**Additions
      to property, plantand
      equipment
    
    
    (47
    )
    
    (33,630
    )
    
    -
    
    
    -
    
    
    (33,677
    )Proceeds
      from sale of assets
    
    
    240
    
    
    64
    
    
    -
    
    
    -
    
    
    304Other
      investments
    
    
    (32
    )
    
    (895
    )
    
    -
    
    
    -
    
    
    (927
    )Investment
      in subsidiaries
    
    
    (18,039
    )
    
    -
    
    
    18,039
    
    
    -
    
    
    -Net
      cash (used in) provided byinvesting
      activities
    
    
    (17,878
    )
    
    (34,461
    )
    
    18,039
    
    
    -
    
    
    (34,300
    )**Cash
      flows from financing activities:**Proceeds
      from issuance of 8%Senior
      Notes, net of discount
    
    
    -
    
    
    -
    
    
    218,143
    
    
    -
    
    
    218,143Repurchase
      of 91⁄8% Senior Notes
    
    
    (39,475
    )
    
    -
    
    
    -
    
    
    -
    
    
    (39,475
    )Repurchase
      of 8% Senior Notes
    
    
    -
    
    
    -
    
    
    (220,000
    )
    
    -
    
    
    (220,000
    )Proceeds
      of revolving creditfacility
      borrowings, net
    
    
    -
    
    
    45,750
    
    
    -
    
    
    -
    
    
    45,750Proceeds
      from issuance ofcommon
      stock
    
    
    1,441
    
    
    -
    
    
    -
    
    
    -
    
    
    1,441Purchase
      of treasury stock
    
    
    (1,075
    )
    
    -
    
    
    -
    
    
    -
    
    
    (1,075
    )Dividends
      paid
    
    
    (5,187
    )
    
    -
    
    
    -
    
    
    -
    
    
    (5,187
    )Debt
      issue costs and other
    
    
    -
    
    
    (879
    )
    
    (6,257
    )
    
    -
    
    
    (7,136
    )Intercompany
      transactions
    
    
    81,617
    
    
    (81,595
    )
    
    (22
    )
    
    -
    
    
    -Net
      cash provided by (used in)financing
      activities
    
    
    37,321
    
    
    (36,724
    )
    
    (8,136
    )
    
    -
    
    
    (7,539
    )Increase
      in cash and cashequivalents
    
    
    (46,272
    )
    
    (1,572
    )
    
    -
    
    
    -
    
    
    (47,844
    )Cash
      and cash equivalents,beginning
      of period
    
    
    106,118
    
    
    6,246
    
    
    -
    
    
    -
    
    
    112,364Cash
      and cash equivalents,end
      of period
    
    $
    59,846
    
    $
    4,674
    
    $
    -
    
    $
    -
    
    $
    64,520
  **FRONTIER
      OIL CORPORATION****Condensed
      Consolidating Statement of Cash Flows****For
      the Year Ended December 31, 2002***(in
      thousands)*
 **FOC
      (Parent)**
    
    **FHI
      (Guarantor Subsidiaries)**
    
    **Other
      Non-Guarantor Subsidiaries**
    
    **Eliminations**
    
    **Consolidated****Cash
      flows from operating activities:**Net
      income
    
    $
    1,028
    
    $
    18,760
    
    $
    25
    
    $
    (18,785
    )
    $
    1,028Equity
      in earnings of subsidiaries
    
    
    (31,704
    )
    
    -
    
    
    -
    
    
    31,704
    
    
    -Depreciation
      and amortization
    
    
    247
    
    
    27,640
    
    
    -
    
    
    (555
    )
    
    27,332Deferred
      income taxes
    
    
    1,149
    
    
    -
    
    
    -
    
    
    -
    
    
    1,149Income
      taxes eliminated inconsolidation
    
    
    -
    
    
    12,364
    
    
    -
    
    
    (12,364
    )
    
    -Deferred
      finance cost and bonddiscount
      amortization
    
    
    1,123
    
    
    910
    
    
    -
    
    
    -
    
    
    2,033Deferred
      employee compensationamortization
    
    
    907
    
    
    -
    
    
    -
    
    
    -
    
    
    907Other
    
    
    365
    
    
    236
    
    
    -
    
    
    -
    
    
    601Changes
      in components ofworking
      capital
    
    
    3,035
    
    
    14,721
    
    
    16
    
    
    -
    
    
    17,772Net
      cash provided by (used in) operating activities
    
    
    (23,850
    )
    
    74,631
    
    
    41
    
    
    -
    
    
    50,822**Cash
      flows from investing activities:**Additions
      to property, plantand
      equipment
    
    
    (250
    )
    
    (29,267
    )
    
    -
    
    
    -
    
    
    (29,517
    )Other
      investments
    
    
    (100
    )
    
    -
    
    
    -
    
    
    -
    
    
    (100
    )El
      Dorado Refinery -contingent
      earn-out payment
    
    
    -
    
    
    (7,500
    )
    
    -
    
    
    -
    
    
    (7,500
    )Investment
      in subsidiaries
    
    
    (181,867
    )
    
    -
    
    
    181,867
    
    
    -
    
    
    -Net
      cash (used in) provided by investing activities
    
    
    (182,217
    )
    
    (36,767
    )
    
    181,867
    
    
    -
    
    
    (37,117
    )**Cash
      flows from financing activities:**Repurchase
      of 91⁄8% Senior Notes
    
    
    (1,090
    )
    
    -
    
    
    -
    
    
    -
    
    
    (1,090
    )Proceeds
      from issuance ofcommon
      stock
    
    
    1,702
    
    
    -
    
    
    -
    
    
    -
    
    
    1,702Purchase
      of treasury stock
    
    
    (787
    )
    
    -
    
    
    -
    
    
    -
    
    
    (787
    )Dividends
      paid
    
    
    (5,161
    )
    
    -
    
    
    -
    
    
    -
    
    
    (5,161
    )Intercompany
      transactions
    
    
    214,061
    
    
    (32,153
    )
    
    (181,908
    )
    
    -
    
    
    -Net
      cash provided by (used in)financing
      activities****
    
    
    208,725
    
    
    (32,153
    )
    
    (181,908
    )
    
    -
    
    
    (5,336
    )Increase
      in cash and cashequivalents
    
    
    2,658
    
    
    5,711
    
    
    -
    
    
    -
    
    
    8,369Cash
      and cash equivalents,beginning
      of period
    
    
    103,460
    
    
    535
    
    
    -
    
    
    -
    
    
    103,995Cash
      and cash equivalents,end
      of period
    
    $
    106,118
    
    $
    6,246
    
    $
    -
    
    $
    -
    
    $
    112,364
 **REPORTOF 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 (the “Company”) as of December 31, 2004 and 2003, and the
related consolidated statements of income, changes in shareholders’ equity and
comprehensive income, and cash flows for each of the three years in the period
ended December 31, 2004. Our audits also included the financial statement
schedules listed in the Index at Item 15. These financial statements and
financial statement schedules are the responsibility of the Company’s
management. Our responsibility is to express an opinion on the financial
statements and financial statement schedules based on our audits.
 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, 2004 and 2003, and the results of their operations and their
cash flows for each of the three years in the period ended December 31, 2004, in
conformity with accounting principles generally accepted in the United States of
America. Also, in our opinion, such financial statement schedules, when
considered in relation to the basic consolidated financial statements taken as a
whole, present fairly, in all material respects, the information set forth
therein.
 We have
also audited, in accordance with the standards of the Public Company Accounting
Oversight Board (United States), the effectiveness of the Company’s internal
control over financial reporting as of December 31, 2004, based on the criteria
established in Internal Control—Integrated Framework issued by the Committee of
Sponsoring Organizations of the Treadway Commission and our report dated March
1, 2005 expressed an unqualified opinion on management’s assessment of the
effectiveness of the Company’s internal control over financial reporting and an
unqualified opinion on the effectiveness of the Company’s internal control over
financial reporting.
 
 DELOITTE
& TOUCHE LLP
 
 Houston,
Texas
 March 1,
2005
 
 
 
 **SELECTEDQUARTERLY FINANCIAL AND OPERATING
      DATA***(Dollars
      in thousands, except per share)***2004**
    
    **2003****Unaudited**
    
    **Fourth**
    
    **Third**
    
    **Second**
    
    **First**
    
    **Fourth**
    
    **Third**
    
    **Second**
    
    **First**Revenues
    
    $
    803,404
    
    $
    785,076
    
    $
    735,904
    
    $
    537,332
    
    $
    542,943
    
    $
    594,763
    
    $
    533,413
    
    $
    499,384Operating
      income
    
    
    15,881
    
    
    42,557
    
    
    85,433
    
    
    (322
    )
    
    14,830
    
    
    27,304
    
    
    8,599
    
    
    1,131Net
      income (loss)
    
    
    239
    
    
    23,792
    
    
    49,469
    
    
    (3,736
    )
    
    4,102
    
    
    3,822
    
    
    (992
    )
    
    (3,700
    )Basic
      earnings (loss) per share
    
    
    0.01
    
    
    0.89
    
    
    1.86
    
    
    (0.14
    )
    
    0.16
    
    
    0.15
    
    
    (0.04
    )
    
    (0.14
    )Diluted
      earnings (loss) per share
    
    
    0.01
    
    
    0.87
    
    
    1.81
    
    
    (0.14
    )
    
    0.15
    
    
    0.14
    
    
    (0.04
    )
    
    (0.14
    )Net
      cash provided by (used in)operating
      activities
    
    
    72,443
    
    
    42,058
    
    
    79,248
    
    
    (15,850
    )
    
    (35,322
    )
    
    29,341
    
    
    19,315
    
    
    (19,339
    )Net
      cash used in investingactivities
    
    
    (10,057
    )
    
    (2,950
    )
    
    (12,111
    )
    
    (17,989
    )
    
    (7,544
    )
    
    (7,193
    )
    
    (12,956
    )
    
    (6,607
    )Net
      cash provided by (used in)financing
      activities
    
    
    (60,738
    )
    
    (4,453
    )
    
    (41,685
    )
    
    31,953
    
    
    770
    
    
    6,646
    
    
    (42,468
    )
    
    27,513Adjusted
      EBITDA (1)
    
    
    27,978
    
    
    50,723
    
    
    93,970
    
    
    7,497
    
    
    22,475
    
    
    34,460
    
    
    15,670
    
    
    8,091Refining
      operations:Total
      charges (bpd) (2)
    
    
    164,581
    
    
    169,436
    
    
    172,951
    
    
    152,015
    
    
    166,347
    
    
    177,364
    
    
    173,610
    
    
    144,824Gasoline
      yields (bpd) (3)
    
    
    85,997
    
    
    84,477
    
    
    86,782
    
    
    74,468
    
    
    87,937
    
    
    86,014
    
    
    85,056
    
    
    74,614Diesel
      and jet fuel yields(bpd)
      (3)
    
    
    54,898
    
    
    55,057
    
    
    54,917
    
    
    47,459
    
    
    53,059
    
    
    57,321
    
    
    59,324
    
    
    42,760Total
      product sales (bpd)
    
    
    169,518
    
    
    174,204
    
    
    171,460
    
    
    148,642
    
    
    169,233
    
    
    176,914
    
    
    171,215
    
    
    144,921Average
      gasoline crack spread(per
      bbl)
    
    $
    3.71
    
    $
    8.88
    
    $
    14.23
    
    $
    7.49
    
    $
    5.22
    
    $
    9.70
    
    $
    7.24
    
    $
    5.85Average
      diesel crack spread(per
      bbl)
    
    
    9.84
    
    
    8.10
    
    
    7.39
    
    
    4.07
    
    
    5.57
    
    
    4.75
    
    
    3.91
    
    
    5.95Average
      light/heavy crude oildifferential
      (per bbl)
    
    
    13.34
    
    
    9.28
    
    
    8.81
    
    
    8.17
    
    
    7.66
    
    
    6.81
    
    
    6.56
    
    
    7.37Average
      WTI/WTS crude oildifferential
      (per bbl)
    
    
    5.82
    
    
    2.95
    
    
    3.29
    
    
    2.88
    
    
    2.71
    
    
    2.44
    
    
    3.19
    
    
    2.38
 
 (1)
    Adjusted
      EBITDA represents income before interest expense, interest income, merger
      financing termination costs (includes both interest expense and income),
      income tax, and depreciation and amortization. Adjusted EBITDA is not a
      calculation based upon generally accepted accounting principles; however,
      the amounts included in the adjusted EBITDA calculation are derived from
      amounts included in the consolidated financial statements of the Company.
      Adjusted EBITDA should not be considered as an alternative to net income
      or operating income, as an indication of operating performance of the
      Company or as an alternative to operating cash flow as a measure of
      liquidity. Adjusted EBITDA is not necessarily comparable to similarly
      titled measures of other companies. Adjusted 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. Adjusted EBITDA is also used for internal analysis and as a
      basis for financial covenants. Frontier’s adjusted EBITDA is reconciled to
      net income as follows (*in
      thousands*):
 **2004**
    
    **2003****Fourth**
    
    **Third**
    
    **Second**
    
    **First**
    
    **Fourth**
    
    **Third**
    
    **Second**
    
    **First**Net
      income (loss)
    
    $
    239
    
    $
    23,792
    
    $
    49,469
    
    $
    (3,736
    )
    $
    4,102
    
    $
    3,822
    
    $
    (992
    )
    $
    (3,700
    )Add
      provision (benefit) forincome
      taxes
    
    
    330
    
    
    13,437
    
    
    30,813
    
    
    (2,241
    )
    
    2,526
    
    
    2,940
    
    
    (288
    )
    
    (2,222
    )Add
      interest expense and otherfinancing
      costs
    
    
    19,955
    
    
    5,813
    
    
    5,949
    
    
    5,856
    
    
    7,997
    
    
    6,590
    
    
    6,733
    
    
    7,426Subtract
      interest income
    
    
    (826
    )
    
    (485
    )
    
    (204
    )
    
    (201
    )
    
    (202
    )
    
    (260
    )
    
    (274
    )
    
    (373
    )Add
      merger financing terminationcosts,
      net
    
    
    -
    
    
    -
    
    
    -
    
    
    -
    
    
    407
    
    
    14,212
    
    
    3,420
    
    
    -Add
      depreciation and amortization
    
    
    8,280
    
    
    8,166
    
    
    7,943
    
    
    7,819
    
    
    7,645
    
    
    7,156
    
    
    7,071
    
    
    6,960Adjusted
      EBITDA
    
    $
    27,978
    
    $
    50,723
    
    $
    93,970
    
    $
    7,497
    
    $
    22,475
    
    $
    34,460
    
    $
    15,670
    
    $
    8,091
 
 (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.
  
 **Item 9.****Changes in and
Disagreements With Accountants on Accounting and Financial
Disclosure**
 
 None.
 
 
 **Item 9A.** **Controls And
Procedures**
 
 The
information contained in this Form 10-K, as well as the financial and
operational data we present concerning the Company, 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
maintain a set of disclosure controls and procedures that are designed to ensure
that information required to be disclosed by us in the reports filed by us under
the Securities Exchange Act of 1934, as amended (“Exchange Act”) is recorded,
processed, summarized and reported within the time periods specified in the
SEC’s rules and forms. As of the end of the period covered by this report, we
evaluated, under the supervision and with the participation of our management,
including our Chairman of the Board, President and Chief Executive Officer and
our Executive Vice President - Finance & Administration, Chief Financial
Officer, the effectiveness of our disclosure controls and procedures pursuant to
Rule 13a-15 of the Exchange Act. Based on that evaluation, our Chairman of the
Board, President and Chief Executive Officer and our Executive Vice President -
Finance & Administration, Chief Financial Officer concluded that our
disclosure controls and procedures are effective.
 During
the most recent fiscal quarter, there have been no changes in our internal
control over financial reporting that have materially affected, or is reasonably
likely to materially affect, our internal control over financial reporting.
 
 
 
 **MANAGEMENT’S
REPORT ON INTERNAL**
 **CONTROL
OVER FINANCIAL REPORTING**
 
 The
management of Frontier Oil Corporation is responsible for establishing and
maintaining adequate internal control over financial reporting. Our internal
control system was designed to provide reasonable assurance to the Company’s
management and board of directors regarding the preparation and fair
presentation of published financial statements. All internal control systems, no
matter how well designed, have inherent limitations. Therefore, even those
systems determined to be effective can provide only reasonable assurance with
respect to financial statement preparation and presentation.
 Frontier
Oil Corporation’s management assessed the effectiveness of the Company’s
internal control over financial reporting as of December 31, 2004. In making
this assessment, it used the criteria set forth by the Committee of Sponsoring
Organizations of the Treadway Commission in Internal Control-Integrated
Framework. Based on our assessment, we believe that, as of December 31, 2004,
the Company’s internal control over financial reporting is effective based on
those criteria.
 Frontier
Oil Corporation’s independent auditors have issued an audit report on our
assessment of the Company’s internal control over financial reporting. This
report appears on the following page.
 
 February
22, 2005
 
 **James
R. Gibbs**
 Chairman
of the Board, President and
 Chief
Executive Officer
 
 **Julie
H. Edwards**
 Executive
Vice President - Finance and Administration,
 Chief
Financial Officer
 
 **Nancy
J. Zupan**
 Vice
President - Controller
 
 
 
 **REPORT
OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM**
 
 **To
the Board of Directors and Shareholders of Frontier Oil
Corporation:**
 We have
audited management’s assessment, included in the accompanying Management’s
Report on Internal Control Over Financial Reporting, that Frontier Oil
Corporation (the “Company”) maintained effective internal control over financial
reporting as of December 31, 2004, based on criteria established in Internal
Control—Integrated Framework issued by the Committee of Sponsoring Organizations
of the Treadway Commission. The Company’s management is responsible for
maintaining effective internal control over financial reporting and for its
assessment of the effectiveness of internal control over financial reporting.
Our responsibility is to express an opinion on management’s assessment and an
opinion on the effectiveness of the Company’s internal control over financial
reporting based on our audit.
 We
conducted our audit 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 effective
internal control over financial reporting was maintained in all material
respects. Our audit included obtaining an understanding of internal control over
financial reporting, evaluating management’s assessment, testing and evaluating
the design and operating effectiveness of internal control, and performing such
other procedures as we considered necessary in the circumstances. We believe
that our audit provides a reasonable basis for our opinions.
 A
company’s internal control over financial reporting is a process designed by, or
under the supervision of, the company’s principal executive and principal
financial officers, or persons performing similar functions, and effected by the
company’s board of directors, management, and other personnel to provide
reasonable assurance regarding the reliability of financial reporting and the
preparation of financial statements for external purposes in accordance with
generally accepted accounting principles. A company’s internal control over
financial reporting includes those policies and procedures that (1) pertain to
the maintenance of records that, in reasonable detail, accurately and fairly
reflect the transactions and dispositions of the assets of the company; (2)
provide reasonable assurance that transactions are recorded as necessary to
permit preparation of financial statements in accordance with generally accepted
accounting principles, and that receipts and expenditures of the company are
being made only in accordance with authorizations of management and directors of
the company; and (3) provide reasonable assurance regarding prevention or timely
detection of unauthorized acquisition, use, or disposition of the company’s
assets that could have a material effect on the financial
statements.
 Because
of the inherent limitations of internal control over financial reporting,
including the possibility of collusion or improper management override of
controls, material misstatements due to error or fraud may not be prevented or
detected on a timely basis. Also, projections of any evaluation of the
effectiveness of the internal control over financial reporting to future periods
are subject to the risk that the controls may become inadequate because of
changes in conditions, or that the degree of compliance with the policies or
procedures may deteriorate.
 In our
opinion, management’s assessment that the Company maintained effective internal
control over financial reporting as of December 31, 2004, is fairly stated, in
all material respects, based on the criteria established in Internal
Control—Integrated Framework issued by the Committee of Sponsoring Organizations
of the Treadway Commission. Also in our opinion, the Company maintained, in all
material respects, effective internal control over financial reporting as of
December 31, 2004, based on the criteria established in Internal
Control—Integrated Framework issued by the Committee of Sponsoring Organizations
of the Treadway Commission.
 We have
also audited, in accordance with the standards of the Public Company Accounting
Oversight Board (United States), the consolidated financial statements and
financial statement schedules as of and for the year ended December 31, 2004 of
the Company and our report dated March 1, 2005 expressed an unqualified opinion
on those consolidated financial statements and financial statement
schedules.
 
 DELOITTE
& TOUCHE LLP
 
 Houston,
Texas
 March 1,
2005
 
 
 **PART III**
 The
information called for by Part III of this Form is incorporated by reference
from the Company’s definitive proxy statement to be filed with the SEC pursuant
to Regulation 14A within 120 days after the close of its last fiscal
year.
 
 
 **PART
IV**
 
 **Item 15.  Exhibits and Financial Statement
Schedules**
 
 (a)1.Financial
      Statements and Supplemental DataConsolidated Statements of IncomeConsolidated Balance SheetsConsolidated Statements of Cash
  FlowsConsolidated Statements of Changes in Shareholders’
      Equity andStatements of Comprehensive
  IncomeNotes to Consolidated Financial
    StatementsReports of Independent Registered Public Accounting
      FirmSelected Quarterly Financial
Data
 
 (a)2.Financial
      Statements SchedulesSchedule I - Condensed Financial Information of
      RegistrantSchedule II - Valuation and Qualifying
      AccountsOther
      Schedules are omitted because of the absence of the conditions under which
      they are required or because the required information is included in the
      financial statements or notes thereto.
 
 
 (a)3.  List of
Exhibits
 
 *
    2.1
    Agreement
      and Plan of Merger, dated March 30, 2003, by and among Frontier Oil
      Corporation (the “Company”), Front Range Himalaya Corporation, Front Range
      Merger Corporation, Himalaya Merger Corporation and Holly Corporation
      (incorporated by reference and filed as Exhibit 99.2 to Form 8-K dated
      March 30, 2003, filed April 2, 2002, File Number
  1-07627).
 *
    3.1
    Restated
      Articles of Incorporation of Wainoco Oil Corporation (now Frontier Oil
      Corporation) dated August 5, 1987 (Exhibit 3.1.1 to Registration Statement
      No. 333-120643, filed November 19, 2004).
 *
    3.2
    Articles
      of Amendment to the Restated Articles of Incorporation of Wainoco Oil
      Corporation (now Frontier Oil Corporation) dated June 14, 1988 (Exhibit
      3.1.2 to Registration Statement Number 333-120643, filed November 19,
      2004).
 *
    3.3
    Articles
      of Amendment to the Restated Articles of Incorporation of Wainoco Oil
      Corporation (now Frontier Oil Corporation) dated April 24, 1992 (Exhibit
      3.1.3 to Registration Statement Number 333-120643, filed November 19,
      2004).
 *
    3.4
    Articles
      of Amendment to the Restated Articles of Incorporation of Wainoco Oil
      Corporation (now Frontier Oil Corporation) dated April 27, 1998 (Exhibit
      3.1.4 to Registration Statement Number 333-120643, filed November 19,
      2004).
 *
    3.5
    Fourth
      Restated Bylaws of Wainoco Oil Corporation (now Frontier Oil Corporation),
      as amended through February 20, 2002 (Exhibit 3.2 to Wainoco Oil
      Corporation’s Annual Report on Form 10-K, File Number 1-07627, filed March
      10, 1993).
 *
    4.1
    Indenture,
      dated as of February 9, 1998, between the Company and Chase Bank of Texas,
      National Association, as Trustee relating to the Company’s 91⁄8% Senior
      Notes due 2006 (filed as Exhibit 4.8 to Registration Statement Number
      333-47745, filed March 11, 1998).
 *
    4.2
    Indenture,
      dated as of November 12, 1999, among the Company and Chase Bank of Texas,
      National Association, as Trustee relating to the Company’s 113⁄4% Senior
      Notes due 2009 (Exhibit 4.1 to Form 8-K, File Number 1-07627, filed
      November 19, 1999).
 *
    4.3
    Indenture,
      dated as of October 1, 2004, among the Company, as issuer, the guarantors
      party thereto and Wells Fargo Bank, N.A., as trustee relating to the
      Company’s 65⁄8% Senior Notes due 2011 (Exhibit 4.1 to Form 8-K, File
      Number1-07627, filed October 4, 2004).
 *
    4.4
    Registration
      Rights Agreement, dated as of October 1, 2004, among the Company, each of
      the guarantors party thereto and Bear, Stearns & Co. Inc., BNP Paribas
      Securities Corp. and TD Securities (USA) Inc. (Exhibit 4.2 to Form 8-K,
      File Number1-07627, filed October 4, 2004).
 *
    10.1
    Asset
      Purchase and Sale Agreement, dated as of October 19, 1999, among Frontier
      El Dorado Refining Company, as buyer, the Company, as Guarantor, and
      Equilon Enterprises LLC, as seller (Exhibit 10.1 to Form 8-K, File Number
      1-07627, filed December 1, 1999).
 *
    10.2
    Purchase
      and Sale Agreement dated May 5, 1997, for the sale of Canadian oil and gas
      properties (Exhibit to Form 8-K, File Number 1-07627, filed June 30,
      1997).
 *2
    10.3
    1968
      Incentive Stock Option Plan as amended and restated (Exhibit 10.1 to Form
      10-K dated December 31, 1987, File Number 1-07627, filed March 3,
      1998).
 *2
    10.4
    1995
      Stock Grant Plan for Non-employee Directors (Exhibit 10.14 to Form 10-Q,
      File Number 1-07627, filed August 3, 1995).
 *2
    10.5
    Frontier
      Deferred Compensation Plan (previously named Wainoco Deferred Compensation
      Plan dated October 29, 1993 and filed as Exhibit 10.19 to Form 10-K, File
      Number 1-07627, filed March 17, 1995).
 *2
    10.6
    Frontier
      Deferred Compensation Plan for Directors (previously named Wainoco
      Deferred Compensation Plan for Directors dated May 1, 1994 and filed as
      Exhibit 10.20 to Form 10-K, File Number 1-07627, filed March 17,
      1995).
 *2
    10.7
    Executive
      Employment Agreement dated December 18, 2000, between the Company and W.
      Reed Williams (Exhibit 10.10 to Form 10-K, File Number 1-07627, filed
      March 1, 2002).
 *2
    10.8
    Executive
      Employment Agreement dated December 18, 2000, between the Company and
      James R. Gibbs (Exhibit 10.11 to Form 10-K, File Number 1-07627, filed
      March 1, 2002).
 *2
    10.9
    Executive
      Employment Agreement dated December 18, 2000, between the Company and
      Julie H. Edwards (Exhibit 10.12 to Form 10-K, File Number 1-07627, filed
      March 1, 2002).
 *2
    10.10
    Executive
      Employment Agreement dated December 18, 2000, between the Company and J.
      Currie Bechtol (Exhibit 10.13 to Form 10-K, File Number 1-07627, filed
      March 1, 2002).
 *2
    10.11
    Executive
      Employment Agreement dated December 18, 2000, between the Company and Jon
      D. Galvin (Exhibit 10.14 to Form 10-K, File Number 1-07627, filed March 1,
      2002).
 *2
    10.12
    Executive
      Employment Agreement dated December 18, 2000, between the Company and
      Gerald B. Faudel (Exhibit 10.15 to Form 10-K, File Number 1-07627, filed
      March 1, 2002).
 *2
    10.13
    Executive
      Employment Agreement dated February 28, 2001, between the Company and
      Nancy J. Zupan (Exhibit 10.16 to Form 10-K, File Number 1-07627, filed
      March 1, 2002).
 *2
    10.14
    Frontier
      Oil Corporation Restricted Stock Plan (Exhibit 99.1 to Registration
      Statement Number 333-56946, filed March 13,
2001).
 *2
    10.15
    Amended
      and Restated Frontier Oil Corporation 1999 Stock Plan (Exhibit 99.1 to
      Registration Statement Number 333-89876, filed June 6,
    2002).
 *
    10.16
    Crude
      Oil Supply Agreement dated October 15, 2002, between Baytex Energy Ltd.
      and Frontier Oil and Refining Company (Exhibit 10.2 to Form 10-Q, File
      Number 1-07627, filed October 30, 2002). On November 28, 2002, this
      agreement was assigned by Baytex Energy Ltd. to its wholly-owned
      subsidiary, Baytex Marketing Ltd.
 *
    10.17
    Amended
      and Restated Revolving Credit Agreement, dated May 27, 2003, among the
      Company, Frontier Oil and Refining Company, as borrower, the lenders named
      therein, Union Bank of California, N.A., as administrative agent,
      documentation agent and lead arranger, and PNB Paribas, as syndication
      agent (Exhibit 99.2 to Form 8-K, File Number 1-07627, filed May 29,
      2003).
 *
    10.18
    Second
      Amended and Restated Revolving Credit Agreement dated November 22, 2004,
      among the Company, Frontier Oil and Refining Company, as borrower, the
      lenders named therein, Union Bank of California, N.A., as administrative
      agent, and PNB Paribas, as syndication agent (Exhibit 10.1 to Form 8-K,
      File Number 1-07627, filed November 24,
2004).
 21
    Subsidiaries of the
Registrant.
 23
    Consent of Deloitte & Touche
  LLP.
 31.1
    Certification by Chief Executive Officer pursuant to 18
      U.S.C. Section 1350, as adopted pursuant to Section 302 of the
      Sarbanes-Oxley Act of 2002.
 31.2
    Certification by Chief Financial Officer pursuant to 18
      U.S.C. Section 1350, as adopted pursuant to Section 302 of the
      Sarbanes-Oxley Act of 2002.
 32.1
    Certification pursuant to 18 U.S.C. Section 1350, as
      adopted pursuant to Section 906 of the Sarbanes-Oxley Act of
      2002.
 32.2
    Certification pursuant to 18 U.S.C. Section 1350, as
      adopted pursuant to Section 906 of the Sarbanes-Oxley Act of
      2002.
 
 *  Asterisk
indicates exhibits incorporated by reference as shown.
 2  Diamond
indicates management contract or compensatory plan or arrangement.
 
 (b)
    Exhibits
 
 The
Company’s 2004 Annual Report is available upon request. Shareholders of the
Company may obtain a copy of any exhibits to this Form 10-K at a charge of $0.05
per page. Requests should be directed to:
 
 Investor
Relations
 Frontier
Oil Corporation
 10000
Memorial Drive, Suite 600
 Houston,
Texas 77024-3411
 
 
 **FrontierOil Corporation****Condensed
      Financial Information of Registrant****Balance
      Sheet****As
      of December 31,**
    
    
    
    **Schedule
      I**2004
    
    
    2003ASSETS
    
    *(in
      thousands)*Current
      Assets:Cash
      and cash equivalents
    
    $
    105,409
    
    
    
    $
    59,846Trade
      and other receivables
    
    
    7,013
    
    
    
    
    710Deferred
      tax assets
    
    
    6,748
    
    
    
    
    5,967Other
      current assets
    
    
    105
    
    
    
    
    68Total
      current assets
    
    
    119,275
    
    
    
    
    66,591Property,
      plant and equipment, at cost -Furniture,
      fixtures and other
    
    
    1,114
    
    
    
    
    1,111Less
      - accumulated depreciation
    
    
    941
    
    
    
    
    866173
    
    
    
    
    245Deferred
      financing costs, net
    
    
    3,252
    
    
    
    
    3,299Commutation
      account
    
    
    16,438
    
    
    
    
    19,550Prepaid
      insurance, net
    
    
    4,542
    
    
    
    
    6,593Other
      assets
    
    
    2,108
    
    
    
    
    4,884Investment
      in subsidiaries
    
    
    295,764
    
    
    
    
    264,016Total
      assets
    
    $
    441,552
    
    
    
    $
    365,178LIABILITIES
      AND SHAREHOLDERS’ EQUITYCurrent
      Liabilities:Accounts
      payable
    
    $
    853
    
    
    
    $
    1,736Accrued
      interest
    
    
    2,485
    
    
    
    
    2,504Accrued
      liabilities and other
    
    
    3,505
    
    
    
    
    1,587Total
      current liabilities
    
    
    6,843
    
    
    
    
    5,827Long-term
      debt
    
    
    150,000
    
    
    
    
    168,689Deferred
      compensation liability
    
    
    1,516
    
    
    
    
    3,723Deferred
      income taxes
    
    
    42,550
    
    
    
    
    16,930Payable
      to affiliated companies
    
    
    530
    
    
    
    
    732Shareholders’
      equity
    
    
    240,113
    
    
    
    
    169,277Total
      liabilities and shareholders’ equity
    
    $
    441,552
    
    
    
    $
    365,178
 
 
 
 The
“Notes to Condensed Financial Information of Registrant” and the “Notes to
Consolidated Financial Statements” in Item 8 of this Form 10-K are an integral
part of these financial statements.
  
 **Frontier
      Oil Corporation****Condensed
      Financial Information of Registrant****Statements
      of Income****For
      the three years ended December 31,**
    
    
    
    **Schedule
      I**2004
    
    2003
    
    2002*(in
      thousands)*Revenues
    
    $
    (6
    )
    $
    (17
    )
    $
    (1
    )(6
    )
    
    (17
    )
    
    (1
    )Costs
      and expenses:Selling
      and general expenses, excluding depreciation
    
    
    15,590
    
    
    7,936
    
    
    6,208Merger
      termination and legal costs
    
    
    3,824
    
    
    8,739
    
    
    -Depreciation
    
    
    75
    
    
    113
    
    
    24719,489
    
    
    16,788
    
    
    6,455Operating
      income
    
    
    (19,495
    )
    
    (16,805
    )
    
    (6,456
    )Interest
      expense and other financing costs
    
    
    35,004
    
    
    26,981
    
    
    24,858Interest
      income
    
    
    (1,545
    )
    
    (1,004
    )
    
    (1,698
    )Equity
      in earnings of subsidiaries
    
    
    (165,038
    )
    
    (48,949
    )
    
    (31,704
    )(131,579
    )
    
    (22,972
    )
    
    (8,544
    )Income
      before income taxes
    
    
    112,084
    
    
    6,167
    
    
    2,088Provision
      for income taxes
    
    
    42,320
    
    
    2,935
    
    
    1,060Net
      income
    
    $
    69,764
    
    $
    3,232
    
    $
    1,028
  
 The
“Notes to Condensed Financial Information of Registrant” and the “Notes to
Consolidated Financial Statements” in Item 8 of this Form 10-K are an integral
part of these financial statements.


**Frontier
      Oil Corporation****Condensed
      Financial Information of Registrant****Statements
      of Cash Flows****For
      the three years ended December 31,**
    
    
    
    **Schedule
      I****2004**
    
    **2003**
    
    **2002***(in
      thousands)*Operating
      ActivitiesNet
      income
    
    $
    69,764
    
    $
    3,232
    
    $
    1,028Equity
      in earnings of subsidiaries
    
    
    (165,038
    )
    
    (48,949
    )
    
    (31,704
    )Depreciation
    
    
    75
    
    
    113
    
    
    247Deferred
      income taxes
    
    
    25,005
    
    
    2,655
    
    
    1,149Income
      tax benefits of stock compensation
    
    
    5,168
    
    
    -
    
    
    -Deferred
      finance cost and bond discount amortization
    
    
    5,180
    
    
    2,206
    
    
    1,123Deferred
      employee compensation amortization
    
    
    1,180
    
    
    1,386
    
    
    907Long-term
      commutation account and prepaid insurance
    
    
    3,712
    
    
    (26,566
    )
    
    -Amortization
      of long-term prepaid insurance
    
    
    1,451
    
    
    423
    
    
    -Other
    
    
    582
    
    
    (264
    )
    
    365Changes
      in components of working capital
    
    
    (5,664
    )
    
    49
    
    
    3,035Net
      cash used by operating activities
    
    
    (58,585
    )
    
    (65,715
    )
    
    (23,850
    )Investing
      ActivitiesAdditions
      to property, plant and equipment
    
    
    (3
    )
    
    (47
    )
    
    (250
    )Proceeds
      from sale of asset
    
    
    -
    
    
    240
    
    
    -Other
      investments
    
    
    -
    
    
    (32
    )
    
    (100
    )Investment
      in subsidiaries
    
    
    -
    
    
    (18,039
    )
    
    (181,867
    )Net
      cash used by investing activities
    
    
    (3
    )
    
    (17,878
    )
    
    (182,217
    )Financing
      ActivitiesProceeds
      from issuance of 65⁄8% Senior Notes
    
    
    150,000
    
    
    -
    
    
    -Repurchases
      of debt:113⁄4%
      Senior Notes
    
    
    (170,449
    )
    
    -
    
    
    -91⁄8%
      Senior Notes
    
    
    -
    
    
    (39,475
    )
    
    (1,090
    )Proceeds
      from issuance of common stock
    
    
    3,923
    
    
    1,441
    
    
    1,702Purchase
      of treasury stock
    
    
    (3,029
    )
    
    (1,075
    )
    
    (787
    )Intercompany
      transactions, net
    
    
    (202
    )
    
    117
    
    
    (30,453
    )Dividends
      paid to shareholders
    
    
    (5,664
    )
    
    (5,187
    )
    
    (5,161
    )Dividends
      received from subsidiaries
    
    
    132,851
    
    
    81,500
    
    
    244,514Debt
      issue costs
    
    
    (3,279
    )
    
    -
    
    
    -Net
      cash provided by financing activities
    
    
    104,151
    
    
    37,321
    
    
    208,725Increase
      (decrease) in cash and cash equivalents
    
    
    45,563
    
    
    (46,272
    )
    
    2,658Cash
      and cash equivalents, beginning of period
    
    
    59,846
    
    
    106,118
    
    
    103,460Cash
      and cash equivalents, end of period
    
    $
    105,409
    
    $
    59,846
    
    $
    106,118
 
 The
“Notes to Condensed Financial Information of Registrant” and the “Notes to
Consolidated Financial Statements” in Item 8 of this Form 10-K are an integral
part of these financial statements.
  
 **Frontier
Oil Corporation**
 **Notes
to Condensed Financial Information of Registrant**
 **December
31, 2004** **Schedule
I**
 
 (1)
    General
 The
accompanying condensed financial statements of Frontier Oil Corporation
(Registrant) should be read in conjunction with the consolidated financial
statements of the Registrant and its subsidiaries included in Item 8 of this
Form 10-K.
 
 (2)
    Long-term
      debt
 The
components of long-term debt are as follows:
 
 **2004**
    
    **2003***(in
      thousands)*65⁄8%
      Senior Notes
    
    $
    150,000
    
    $
    -113⁄4%
      Senior Notes, net of unamortized discount
    
    
    -
    
    
    168,689$
    150,000
    
    $
    168,689
 
 (3)
    Five-year
      maturities of long-term debt
 There are
no maturities of long-term debt within the next five years.
 
 (4)
    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 concluded on March 5, 2004. Oral arguments were held on May
      4, 2004, and the Company is awaiting a decision. Frontier believes that
      the counterclaims filed against it by Holly will not result in any
      material liability or have any material adverse effect upon
      Frontier.
 
 The
operating results for the years ended December 31, 2004 and 2003 were negatively
impacted by transaction costs and legal costs related to the termination of the
Holly merger aggregating $3.8 million and $8.7 million, respectively, and are
reflected in the statements of income as “Merger termination and legal costs.”
Additional net costs of approximately $18.0 million related to the issuance and
termination of debt for the anticipated merger have reduced the “Equity in
earnings of subsidiaries” on the Company’s 2003 statement of income.
 
 
 **Frontier Oil Corporation****Valuation
      and Qualifying Accounts**For
      the three years ended December 31,
    
    
    
    
    
    **Schedule
      II****Description**
    
    Balance
      at beginning of period
    
    Additions
    
    Deductions
    
    Balance
      at end of period*(in
      thousands)***2004**Allowance
      for doubtful accounts
    
    $
    500
    
    $
    -
    
    $
    -
    
    $
    500Turnaround
      accruals (1)
    
    
    26,641
    
    
    13,531
    
    
    11,646
    
    
    28,526Valuation
      allowance on deferred tax assets
    
    
    1,555
    
    
    -
    
    
    1,555
    
    
    -**2003**Allowance
      for doubtful accounts
    
    
    1,300
    
    
    103
    
    
    903
    
    
    500Turnaround
      accruals (1)
    
    
    26,862
    
    
    12,163
    
    
    12,384
    
    
    26,641Valuation
      allowance on deferred tax assets
    
    
    1,555
    
    
    -
    
    
    -
    
    
    1,555**2002**Allowance
      for doubtful accounts
    
    
    500
    
    
    800
    
    
    -
    
    
    1,300Turnaround
      accruals (1)
    
    
    25,837
    
    
    10,969
    
    
    9,944
    
    
    26,862Valuation
      allowance on deferred tax assets
    
    
    -
    
    
    1,555
    
    
    -
    
    
    1,555
 
 (1) The
turnaround accrual deductions are actual costs incurred.
 
 
 
 **SIGNATURES**
 Pursuant
to the requirements of Section 13 or 15(d) of the Securities Exchange Act of
1934, the registrant has duly caused this report to be signed on its behalf by
the undersigned, thereunto duly authorized on the date indicated.
  **FRONTIER OIL
      CORPORATION**By:
    /s/ James
      R. GibbsJames
      R. Gibbs
      Chairman
      of the Board, President and
      Chief
      Executive Officer
      (chief
      executive officer)
 Date:
March 2, 2005
 
 
  
 Pursuant
to the requirements of the Securities Exchange Act of 1934, this report has been
signed below by the following persons on behalf of Frontier Oil Corporation and
in the capacities and on the date indicated.
 
 /s/ James
      R. Gibbs
    
    
    /s/ T.
      Michael DosseyJames
      R. Gibbs
      Chairman
      of the Board, President and
      Chief
      Executive Officer and Director
      (chief
      executive officer)
    
    
    T.
      Michael Dossey
      Director
 /s/ Julie H. Edwards
    
    
    /s/ James H. LeeJulie H. Edwards
      Executive Vice President -
      Finance and Administration,
      Chief Financial Officer
      (principal financial officer)
    
    
    James H. Lee
      Director
 
 /s/ Nancy J. Zupan
    
    
    /s/  Paul B. Loyd, Jr.Nancy J. Zupan
      Vice President - Controller
      (principal accounting officer)
    
    
    Paul B. Loyd, Jr.
      Director
 /s/ Douglas Y. Bech
    
    
    /s/ Carl W. SchaferDouglas Y. Bech
      Director
    
    
    Carl W. Schafer
      Director
 
 /s/ G. Clyde BuckG. Clyde Buck
      Director
 
 Date:
March 2, 2005