Attached files
UNITED
STATES
SECURITIES
AND EXCHANGE COMMISSION
Washington,
D.C. 20549
FORM
10-K
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ANNUAL
REPORT PURSUANT TO SECTION 13 OR 15(d)
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OF
THE SECURITIES EXCHANGE ACT OF 1934
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For
the Fiscal Year Ended: December 31, 2009
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OR
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TRANSITION
REPORT PURSUANT TO SECTION 13 OR 15(d)
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OF
THE SECURITIES EXCHANGE ACT OF 1934
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For
the transition period from . . . . to . . . .
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Commission File Number: 1-7627
FRONTIER
OIL CORPORATION
(Exact
name of registrant as specified in its charter)
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Wyoming
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74-1895085
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(State
or other jurisdiction of
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(I.R.S.
Employer
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incorporation
or organization)
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Identification
No.)
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10000
Memorial Drive, Suite 600
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77024-3411
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Houston,
Texas
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(Zip
Code)
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(Address
of principal executive offices)
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Registrant’s
telephone number, including area code: (713) 688-9600
Securities
registered pursuant to Section 12(b) of the Act:
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Name
of Each Exchange
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Title of Each Class
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on Which Registered
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Common
Stock
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New
York Stock Exchange
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Securities
registered pursuant to Section 12(g) of the Act:
None
Indicate
by check mark if the registrant is a well-known seasoned issuer, as defined in
Rule 405 of the Securities Act.
Yes þ No ¨
Indicate
by check mark if the registrant is not required to file reports pursuant to
Section 13 or Section 15(d) of the Act.
Yes ¨ No þ
Indicate
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.
Yes þ No ¨
Indicate
by check mark whether the registrant has submitted electronically and posted on
its corporate Web site, if any, every Interactive Data File required to be
submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this
chapter) during the preceding 12 months (or for such shorter period that the
registrant was required to submit and post such files).
Yes ¨ No ¨
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.
Indicate
by check mark whether the registrant is a large accelerated filer, an
accelerated filer, a non-accelerated filer, or a smaller reporting
company. See the definitions of “large accelerated filer,”
“accelerated filer” and “smaller reporting company” in Rule 12b-2 of the
Exchange Act.
(Check
one)
Large
accelerated filer þ Accelerated
filer ¨ Non-accelerated
filer ¨ Smaller
reporting company ¨
(Do not
check if a smaller reporting company)
Indicate
by check mark whether the registrant is a shell company (as defined in Rule
12b-2 of the Act).
Yes ¨ No þ
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, 2009 was $1.2 billion.
The
number of shares of common stock outstanding as of February 19, 2010 was
104,684,956.
DOCUMENTS
INCORPORATED BY REFERENCE
Portions
of the Annual Proxy Statement for the registrant’s 2010 annual meeting of
shareholders are incorporated by reference
into Items 10 through 14 of Part III.
TABLE
OF CONTENTS
Forward-Looking
Statements
This Form
10-K contains “forward-looking statements” as defined by the Securities and
Exchange Commission (“SEC”). Such statements are those concerning
contemplated transactions and strategic plans, expectations and objectives for
future operations. These include, without limitation:
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statements,
other than statements of historical fact, that address activities, events
or developments that we expect, believe or anticipate will or may occur in
the future;
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statements
relating to future financial performance, future capital sources and other
matters; and
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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.
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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.
All
forward-looking statements contained in this Form 10-K only speak as of the date
of this document. 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.
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Business
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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, western Nebraska, Montana
and Utah, and when we use the term “Plains States,” we refer to the states of
Kansas, Oklahoma, eastern Nebraska, Iowa, Missouri, North Dakota and South
Dakota.
Overview
We are an
independent energy company, organized in the State of Wyoming in 1977, 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
approximately 187,000 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 value 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 oil
capacity of 52,000 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
extensive amounts of heavy crude oil for use as a feedstock when economical. The
ability to process heavy crude oil lowers our raw material costs because heavy
crude oil is generally less expensive than lighter types of crude oil. For the
year ended December 31, 2009, heavy crude oil constituted approximately 50% of
the Cheyenne Refinery’s total crude oil charge. For the year ended
December 31, 2009, the Cheyenne Refinery’s product yield included gasoline
(48%), diesel fuel (37%) and asphalt and other refined petroleum products
(15%).
El Dorado
Refinery. The El Dorado Refinery is one of the largest
refineries in the Plains States and the Rocky Mountain region with crude oil
capacity of 135,000 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 pipelines to west Texas, the Gulf Coast and to
Canada. 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. We have a refined product offtake agreement
for gasoline and diesel production at this Refinery with Shell Oil Products US
(“Shell”) that terminates at the end of 2014. Shell has also agreed
to purchase all jet fuel production until the end of the product offtake
agreement. We market gasoline and diesel in the same markets where
Shell currently sells the El Dorado Refinery’s products, primarily in Denver and
throughout the Plains States. For the year ended December 31, 2009,
the El Dorado Refinery’s product yield included gasoline (49%), diesel and jet
fuel (41%) and chemicals and other refined petroleum products
(10%).
Other Assets. The
Company owns Ethanol Management Company (“EMC”) which is a 25,000 bpd products
terminal and blending facility located near Denver, Colorado. We also
purchased in December 2009 a refined products pipeline which runs from Cheyenne,
Wyoming to Sidney, Nebraska and the associated refined products terminal and
truck rack at Sidney, Nebraska.
Varieties of Crude Oil and
Products. 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 proportion of high value 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 value by-products and heavy residual oils. The discount at which heavy crude oil sells compared to light crude oil is known in the industry as the light/heavy spread or differential, while the discount at which sour crude oil sells compared to sweet crude oil is known as the sweet/sour, or WTI/WTS, spread or differential. Coking units, such as the ones at 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 value refined products from the same initial barrel of crude oil.
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 and generally increases a refinery’s complexity rating. Upgrading
capacity refers to the ability of a refinery to produce high yields of high
value refined products such as gasoline and diesel from heavy and intermediate
crude oil. In contrast, refiners with low upgrading capacity must
process primarily light, sweet crude oil to produce a similar yield of gasoline
and diesel. Some low complexity refineries may be capable of
processing heavy and intermediate crude oil, but they will produce large volumes
of by-products, including heavy residual oils and asphalt. 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 majority of our production.
Refinery
Maintenance. Each of the processing units at our Refineries
requires scheduled significant 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
between our two Refineries. Turnarounds are implemented using our regular
personnel as well as additional contract labor. Once started,
turnaround work typically proceeds 24 hours per day to minimize unit
downtime. We defer the costs of turnarounds, reflected as “Deferred
turnaround costs” on the Consolidated Balance Sheets, and subsequently amortize
them on a straight-line basis over the period of time estimated to lapse until
the next turnaround occurs. We normally schedule our 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.
During
2009, major turnaround work at the El Dorado Refinery involved the fluid
catalytic cracking unit (“FCCU”), gasoil hydrotreater and a distillate
hydrotreater. The timing of these outages coincided with the
completion of major capital projects including the catalytic cracker reliability
project and the first phase of the gasoil hydrotreater revamp
project. Turnaround work during 2010 at the El Dorado Refinery is
modest in scope and is limited to annual catalyst reformer regenerations and
coker furnace cleaning. In conjunction with these turnaround
projects, we plan to integrate the gasoil hydrotreater revamp project in
2010.
At the
Cheyenne Refinery, 2009 turnaround work was limited in scope and included two
catalyst regenerations for the reformer and outages on its associated
hydrotreater. In 2010, the plant will have another catalyst
regeneration for the reformer during the spring, then major turnaround activity
during the fall on the FCCU, alkylation unit, distillate hydrotreater, and
scanfiner.
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, 2009, we sold approximately 75% of the Cheyenne Refinery’s gasoline volumes
in Colorado and 20% in Wyoming. For the year ended December 31, 2009,
we sold approximately 71% of the Cheyenne Refinery’s diesel in Wyoming and 18%
in Colorado. Because of the location of the Cheyenne Refinery, we are able to
sell a significant portion of its diesel product from the truck rack at the
Refinery, thereby eliminating product 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 Plains All
American Pipeline (formerly Rocky Mountain Pipeline), serving Denver and
Colorado Springs, Colorado, and the Frontier Pipeline (formerly 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,” and prices at the terminal racks are posted daily by
sellers. The customer at a terminal rack typically supplies its own
truck transportation. In the year ended December 31, 2009,
approximately 90% of the Cheyenne Refinery’s sales were made to its 25 largest
customers compared to the year ended December 31, 2008, when approximately 87%
of the Cheyenne Refinery’s sales were made to its 25 largest
customers. Occasionally, volumes sold 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 NuStar Pipeline Operating
Partnership L.P. Pipeline, serving the northern Plains States, the Magellan
Pipeline Company, L.P. (“Magellan”) mountain pipeline serving Denver, Colorado,
and the Magellan mid-continent pipeline serving the Plains States handle
shipments from our El Dorado Refinery.
For the
year ended December 31, 2009, Shell was the El Dorado Refinery’s largest
customer, and our only customer which represented more than 10% of our total
consolidated sales. For 2009, sales to Shell represented
approximately 49% of the El Dorado Refinery’s total sales and 38% of our total
consolidated sales. Under the offtake agreement, Shell purchases
gasoline, diesel and jet fuel produced by the El Dorado Refinery at market-based
prices through December 2014. In aggregate during 2009, we retained
and marketed 60,000 bpd of the Refinery’s gasoline and diesel production while
the remaining production was sold to Shell. 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 general markets currently served
by Shell, as previously described.
Cheyenne
Refinery. The most competitive market for the Cheyenne
Refinery’s products is the Denver metropolitan area. Other than the Cheyenne
Refinery, three principal refineries serve the Denver market: an approximate
70,000 bpd refinery near Rawlins, Wyoming and an approximate 25,000 bpd refinery
in Casper, Wyoming, both owned by Sinclair Oil Company (“Sinclair”); and a
90,000 bpd refinery located in Denver and owned by Suncor Energy (U.S.A.) Inc.
(“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 typically bear the burden of higher transportation costs.
The
Suncor refinery located in Denver has lower product transportation costs to
serve 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. Moreover, unlike Sinclair and Suncor, we only sell our
products to the wholesale market. We believe that our commitment to
the wholesale market gives us certain marketing advantages over our principal
competitors in the Eastern Slope area, all of which also have retail outlets,
because we do not compete directly 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 our El Dorado
Refinery to compete effectively in the Plains States and Rocky Mountain region
with the Gulf Coast refineries. The Plains States and mid-continent
regions are supplied by three product pipelines (Magellan Midstream Partners,
L.P., Explorer Pipeline and Nustar Energy L.P.) that originate from the Gulf
Coast.
Crude Oil Supply
We
purchase crude oil from numerous suppliers, including major oil companies,
marketing companies and large and small independent producers, under
arrangements which contain market-responsive pricing provisions. Most
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. We intend to continue purchasing crude oil from
a variety of suppliers and typically under short-term commitments. In
the event we become unable to purchase crude oil from any one of these sources,
we believe that adequate alternative supplies of crude oil would be
available. Crude oil charges are the quantity of crude oil and other
feedstock processed through Refinery units.
Cheyenne
Refinery. In the year ended December 31, 2009, we obtained
approximately 40% of the Cheyenne Refinery’s crude oil charge from Canada, 25%
from Wyoming, 25% Bakken crude oil from North Dakota and Montana, 9% from
Colorado and 1% from other domestic sources. During the same period,
heavy crude oil constituted approximately 50% of the Cheyenne Refinery’s total
crude oil charge, compared to 76% in 2008. Due to the deterioration
of the light/heavy crude oil differential in 2009 and a reduced economic benefit
from processing heavy crude oil, the Company processed significantly less heavy
crude in 2009 compared to 2008. Cheyenne is 88 miles south of
Guernsey, Wyoming, the main hub and crude oil trading center for the Rocky
Mountain region. We transport crude oil from Guernsey to the Cheyenne
Refinery via common carrier pipelines owned by Plains All American Pipeline and
Suncor Energy. 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. This type of crude oil typically sells at a discount from
lighter crude oil prices.
El Dorado
Refinery. In the year ended December 31, 2009, we obtained
approximately 58% of the El Dorado Refinery’s crude oil charge from Texas, 27%
from Canada, 6% from the Gulf of Mexico, 4% from Kansas, and the remaining 5%
from other foreign and domestic locations. 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, Texas from West Texas; the Sun
Pipeline, which originates at the Gulf Coast and connects to the Basin Pipeline
at Wichita Falls; and the Spearhead Pipeline, which connects at Flanagan,
Illinois with the Enbridge Pipeline to bring crude oil from
Canada. The Osage Pipeline runs from Cushing to El Dorado and
transported approximately 96% of our crude oil charge during the year ended
December 31, 2009. The remainder of our crude oil charge was
transported to the El Dorado Refinery through Kansas gathering system
pipelines. We have a Transportation Services Agreement to transport
up to 38,000 bpd of crude oil on the Spearhead Pipeline from Flanagan, Illinois
to Cushing, Oklahoma, enabling us to transport Canadian crude oil to our El
Dorado Refinery. The initial term of this agreement expires in
2016. We have the right to extend the agreement for an additional ten
years and to increase the volume transported under a preferential tariff to
50,000 bpd.
Government Regulation
Environmental
Matters. See “Environmental” in Note 13 in the “Notes to
Consolidated Financial Statements.”
We are
subject to the requirements of the federal Occupational Safety and Health Act
(“OSHA”) and comparable state occupational safety statutes.
The
Cheyenne Refinery’s OSHA recordable incident rate in 2009 was 2.0, which was a
20% improvement over 2008 but remains higher than the latest reported U.S.
refining industry average of 1.1 as compiled by the United States Department of
Labor. We continue to emphasize safety at all levels of the Cheyenne
Refinery organization to continue the improvement in performance we have seen
over the past few years. An area of greater improvement in Cheyenne
was the 2009 contractor recordable rate which dropped 76%, from 2.9 in 2008 to
0.7 in 2009.
The El
Dorado Refinery sustained its OSHA recordable incident rate of 0.6 in 2009,
which is significantly better than the refining industry average of
1.1. Management and employees at the El Dorado Refinery remain
committed to programs, processes and behaviors that drive safety
excellence. A key initiative for the El Dorado Refinery during 2009
was to facilitate an improvement in the safety performance of its
contractors. This focus resulted in the contractor recordable rate at
the El Dorado Refinery improving to 1.4, a 30% reduction versus
2008.
During
2010, we will continue with the safety processes and initiatives that have
proven to promote and sustain continued safety improvement in our
Refineries. These efforts include programs in both areas of
occupational and process safety and are comprehensive across all areas of the
Refineries. Behavior-based safety programs have been in place at both
Refineries for many years, and continue to evolve in response to our
performance. Process safety became a more focused aspect of our
safety management systems three years ago, with dedicated process safety
departments at both Refineries. Our employees and management continue
to dedicate their efforts to a balanced safety program that combines individual
behavioral elements and risk-based process safety elements in a safety-coaching
environment with structured, management-driven programs to improve the safety of
our facilities. Our objective is to provide a safe working
environment for employees and contractors and continue educating them about how
to work safely. Encouraging all employees and contractors to
contribute toward improving safety performance through personal involvement in
safety-related activities is an industry-proven method of reducing
injuries.
At
December 31, 2009, we employed 843 full-time employees: 94 in the Houston and
Denver offices, 313 at the Cheyenne Refinery, and 436 at the El Dorado
Refinery. The Cheyenne Refinery employees included 116 administrative
and technical personnel and 197 union members. The El Dorado Refinery
employees included 154 administrative and technical personnel and 282 union
members. The union members at our El Dorado Refinery are represented
by the United Steel, Paper and Forestry, Rubber, Manufacturing, Energy, Allied
Industrial and Service Workers International Union (“USW”). The union
members at our Cheyenne Refinery are represented by seven bargaining units, the
largest being the USW and the others being various craft unions.
For our
Cheyenne Refinery, the current contract between the Company, the USW, and its
Local 8-0574 expires in March 2012. The current contract between the
Company, the craft unions, and its various local chapters expires in June
2012.
At our El
Dorado Refinery, the current contract between the Company, the USW, and its
Local 5-241 expires in January 2012.
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Risk
Factors Relating to Our Business
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Crude
oil prices and refining margins significantly impact our cash flow and have
fluctuated substantially in the past.
Our cash
flow from operations is primarily dependent upon producing and selling 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 refined product sales prices and crude oil 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
production from competing refineries.
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 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.
Our
profitability is affected by crude oil differentials, which has declined and
accordingly decreased our profitability.
The
light/heavy crude oil differentials that we report are the average differential
between the benchmark West Texas Intermediate (“WTI”) crude oil priced on the
New York Mercantile Exchange and the heavy crude oil priced as delivered to our
Cheyenne Refinery or El Dorado Refinery, respectively. The WTI/WTS
(sweet/sour) crude oil differential is the average differential between
benchmark WTI crude oil priced on the New York Mercantile Exchange and West
Texas sour crude oil priced at Midland, Texas. Our profitability at
our Cheyenne Refinery is affected by the light/heavy crude oil differential, and
our profitability at our El Dorado Refinery is affected by the WTI/WTS crude oil
differential and the light/heavy crude oil
differential. Traditionally, we have preferred to refine heavy sour
crude oil at the Cheyenne Refinery and intermediate sour crude oil at the El
Dorado Refinery because these crudes have provided a higher refining margin than
light or sweet crude oil. Accordingly, the reduction of these crude
oil differentials from 2008 to 2009 reduced our profitability. The
Cheyenne Refinery light/heavy crude oil differential averaged $6.61 per barrel
in the year ended December 31, 2009, compared to $17.15 per barrel in the same
period in 2008. The El Dorado Refinery light/heavy crude oil
differential averaged $6.01 per barrel in the year ended December 31, 2009
compared to $17.85 per barrel in 2008. The WTI/WTS crude oil
differential averaged $1.65 per barrel in the year ended December 31, 2009,
compared to $3.92 per barrel in the same period in 2008. Crude oil
prices dropped dramatically during the latter part of 2008 and trended upward
through 2009, without a corresponding upward trend in crude oil
differentials. This resulted in significant narrowing of the
light/heavy crude oil differentials and WTI/WTS crude oil
differentials. In addition, the light/heavy crude oil differential
has declined rapidly due to the significant industry investment over the last
few years in equipment to process heavy/sour crude oil as well as a decline in
availability of these types of crudes. The crude oil differentials
may continue this trend and thus continue to negatively impact on our
profitability.
Our
risk management activities may generate substantial losses and limit potential
gains.
In order
to hedge and limit potential financial losses on certain of our inventories, we
from time to time enter into derivative contracts to make forward sales or
purchases of crude oil, refined products, natural gas and other commodities and
to hedge interest rate risk. We may also use options or swaps to
accomplish similar objectives. During the year ended December 31,
2009, we incurred pre-tax hedging losses of $11.7 million recorded in “Other
revenues” in the Consolidated Statements of Operations. To the extent
we use progressively more Canadian crude oil at our Refineries, both our total
crude oil inventories and the amount of hedged inventories are likely to
increase in future periods. See “Quantitative and Qualitative
Disclosures about Market Risk” in Part II, Item 7A.
Instability
and volatility in the financial markets could have a negative impact on our
business, financial condition, results of operations and cash
flows.
The
financial markets have recently experienced substantial and unprecedented
volatility as a result of dislocations in the credit markets. Market
disruptions such as those currently being experienced in the United States and
abroad may increase our cost of borrowing or adversely affect our ability to
access sources of liquidity upon which we may rely to finance our operations and
satisfy our obligations as they become due, and capital may not be available on
terms that are reasonably acceptable to us, or at all. These
disruptions may include turmoil in the financial services industry, including
substantial uncertainty surrounding particular lending institutions with which
we do business, reduction in available trade credit due to counterparties
liquidity concerns, more strict lending requirements, unprecedented volatility
in the markets where our outstanding securities trade, and general economic
downturns in the areas where we do business. In addition, a general
economic slowdown or the lack of liquidity may result in contractual
counterparties with which we do business being unable to satisfy their
obligations to us in a timely manner, or at all.
We
maintain significant amounts of cash and cash equivalents at several financial
institutions that are in excess of federally insured
limits. During the year ended December 31, 2008, we recorded a
loss of $499,000 on money market funds that had investments in Lehman Brothers,
which filed for bankruptcy. Given the current instability of
financial institutions, we may experience further losses on our cash and cash
equivalents.
External
factors beyond our control can cause fluctuations in demand for our products,
prices and margins, which may negatively affect income and cash
flow.
Among
these factors is the demand for crude oil and refined products, which is largely
driven by the conditions of local and worldwide economies as well as by weather
patterns and the taxation of these products relative to other energy
sources. Governmental regulations and policies, particularly in the
areas of taxation, energy and the environment, also have a significant impact on
our activities. Operating results can be affected by these industry factors and
by competition in the particular geographic areas that we serve. The
demand for crude oil and refined products can also be reduced due to a local or
national recession or other adverse economic condition that results in lower
spending by businesses and consumers on gasoline and diesel fuel, a shift by
consumers to more fuel-efficient vehicles or alternative fuel vehicles (such as
ethanol or wider adoption of gas/electric hybrid vehicles), or an increase in
vehicle fuel economy, whether as a result of technological advances by
manufacturers, legislation mandating or encouraging higher fuel economy or the
use of alternative fuel.
In
addition, our profitability depends largely on the spread between market prices
for refined petroleum products and crude oil prices. This margin is
continually changing and may fluctuate significantly from time to
time. Crude oil and refined products are commodities whose price
levels are determined by market forces beyond our control. Due to the
seasonality of refined products markets and refinery maintenance schedules,
results of operations for any particular quarter of a fiscal year are not
necessarily indicative of results for the full year. In general,
prices for refined products are influenced by the price of crude
oil. Although an increase or decrease in the price of crude oil may
result in a similar increase or decrease in prices for refined products, there
may be a time lag in the realization of the similar increase or decrease in
prices for refined products. The effect of changes in crude oil
prices on operating results therefore depends in part on how quickly refined
product prices adjust to reflect these changes. A substantial or
prolonged increase in crude oil prices without a corresponding increase in
refined product prices, a substantial or prolonged decrease in refined product
prices without a corresponding decrease in crude oil prices, or a substantial or
prolonged decrease in demand for refined products could have a significant
negative effect on our results of operations and cash flows. This
potential negative impact on our income and cash flows from these external
factors could result in an impairment of our property, plant and equipment or if
significant enough the closure of one or both of our Refineries.
We
are dependent on others to supply us with substantial quantities of raw
materials.
Our
business involves converting crude oil and other refinery charges into liquid
fuels. We own no crude oil or natural gas reserves and depend on
others to supply these feedstocks to our Refineries. We use large
quantities of natural gas and electricity to provide heat and mechanical energy
required by our processing units. Disruption to our supply of crude oil, natural
gas or electricity, or the continued volatility in the costs thereof, could have
a material adverse effect on our operations. In addition, our
investment in inventory is affected by the general level of crude oil prices,
and significant increases in crude oil prices could result in substantial
working capital requirements to maintain inventory volumes.
Our
Refineries face operating hazards, and the potential
limits on insurance coverage could expose us to significant liability
costs.
Our
operations could be subject to significant interruption, and our profitability
could be impacted if either of our Refineries experienced a major accident or
fire, was damaged by severe weather or other natural disaster, or was otherwise
forced to curtail its operations or shut down. If a crude oil
pipeline that supplies crude oil to our Refineries became inoperative, crude oil
would have to be supplied to our Refineries through an alternative pipeline or
from additional tank truck deliveries to the Refineries. Alternative
supply arrangements could require additional capital expenditures, hurt our
business and profitability and cause us to operate the affected Refinery at less
than full capacity until pipeline access was restored or crude oil
transportation was fully replaced. In addition, a major accident,
fire or other event could damage our Refineries 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 many years. 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 such units. 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 companies, and greater
competition in the markets where we sell refined products could adversely affect
our sales and profitability.
The
refining industry is highly competitive. Many of our competitors are
either large integrated oil companies or major independent refining 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.
We are
not engaged in the petroleum exploration and production business and therefore
do not produce any of our crude oil feedstocks. We do not have a
retail business and therefore are dependent upon others for outlets for our
refined products. Certain of our competitors, however, obtain a
portion of their feedstocks from company-owned oil and gas production and also
have retail outlets. Competitors that have their own crude oil
production or extensive retail outlets, with brand-name recognition, are at
times able to offset losses from refining operations with profits from producing
or retailing operations, and may be better positioned to withstand periods of
depressed refining margins or feedstock shortages. In addition, we
compete with other industries, such as wind, solar and hydropower that provide
alternative means to satisfy the energy and fuel requirements of our industrial,
commercial and individual consumers. If we are unable to compete
effectively with these competitors, both within and outside our industry, there
could be a material adverse effect on our business, financial condition and
results of operations.
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 of complying 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 extensive federal, state and local environmental and
health and safety 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, 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, including such resulting from the impact of
climate changes. Legislation regarding increases in the mandated use of
alternative or renewable fuels and/or the reduction of greenhouse gas emissions
from either transportation fuels or manufacturing processes is under
consideration by the U.S. Congress. In addition, the EPA has recently
determined that greenhouse gases, including carbon dioxide, present a danger to
human health and the environment, which may result in future regulation of such
gases. If climate change legislation is enacted or regulations
promulgated, these requirements could materially impact the operations and
financial position of the Company. 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. Any
noncompliance with these laws and regulations could subject us to material
administrative, civil or criminal penalties or other liabilities. For
examples of existing and potential future regulations and their possible effects
on us, please see “Environmental” in Note 13 in the “Notes to Consolidated
Financial Statements.”
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,
could 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 could 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 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.
Our
operations are subject to various laws and regulations relating to occupational
health and safety, which could give rise to increased costs and material
liabilities.
The
nature of our business may result from time to time in industrial
accidents. Our operations are subject to various laws and regulations
relating to occupational health and safety. Continued efforts to
comply with applicable health and safety laws and 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.
We
could incur substantial costs or disruptions in our business if we cannot obtain
or maintain necessary permits and authorizations.
Our
operations require numerous permits and authorizations under various laws and
regulations, including environmental and health and safety laws and
regulations. These authorizations and permits are subject to
revocation, renewal or modification and can require operational changes, which
may involve significant costs, to limit impacts or potential impacts on the
environment and/or health and safety. A violation of these
authorization or permit conditions or other legal or regulatory requirements
could result in substantial fines, criminal sanctions, permit revocations,
injunctions and/or refinery shutdowns. In addition, major
modifications of our operations could require changes to our existing permits or
expensive upgrades to our existing pollution control equipment, which could have
a material adverse effect on our business, financial condition or results of
operations.
Hurricanes
along the Gulf Coast could disrupt our supply of crude oil and our ability to
complete capital investment projects in a timely manner.
In 2005
and 2008, tropical hurricanes and related storm activity, such as windstorms,
storm surges, floods and tornadoes, caused extensive and catastrophic physical
damage in and to coastal and inland areas located in the Gulf Coast region of
the United States (parts of Texas, Louisiana, Mississippi and Alabama) and
certain other parts of the southeastern parts of the United
States. Some of the materials we use for our capital projects are
fabricated at facilities located along the Gulf Coast. Should other
storms of this nature occur in the future, it is possible that the storms and
their collateral effects could result in delays or cost increases for our
capital investment projects.
In
addition, supplies of crude oil to our El Dorado Refinery are sometimes shipped
from Gulf Coast production or terminalling facilities. This crude oil
supply source could be potentially threatened in the event of future
catastrophic damage to such facilities.
We
may have labor relations difficulties with some of our employees represented by
unions.
Approximately
57 percent of our employees were covered by collective bargaining agreements at
December 31, 2009. Our El Dorado Refinery union contract expires in
January 2012 and our Cheyenne Refinery union contracts expire by March 2012, and
there is no assurance that we will be able to enter into new contracts on terms
acceptable to us or at all. A failure to do so may increase our costs
or result in an interruption of our business. See Item 1
“Business-Employees.” In addition, employees may conduct a strike at
some time in the future, which may adversely affect our operations.
Terrorist
attacks and threats or actual war may negatively impact our
business.
Terrorist
attacks in the United States and the war in Iraq, 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, could adversely impact our operations. In
addition, any terrorist attack could have an adverse impact on energy prices,
including prices for our crude oil and refined products, and an adverse impact
on the margins from our refining and marketing 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 extensions of time for
payment of accounts receivable from our customers.
|
Unresolved
Staff Comments
|
None.
|
Properties
|
Refining
and Terminal Operations
We own an
approximately 255 acre site on which the Cheyenne Refinery is located in
Cheyenne, Wyoming and an approximately 1,000 acre site on which the El Dorado
Refinery is located in El Dorado, Kansas. We lease the approximately
two acre site in Henderson, Colorado on which our products and blending terminal
is located. We own an approximately 17 acre site on which our
products terminal in Sidney, Nebraska is located. We also own a 31
acre site on which a products terminal was previously located in North Platte,
Nebraska.
Other
Properties
We lease
approximately 6,500 square feet of office space in Houston, Texas for our
corporate headquarters under a lease expiring in October 2014. We
also lease approximately 28,000 square feet of office space in Denver, Colorado
under a lease expiring in August 2015 for our refining, marketing and raw
material supply operations.
|
Legal
Proceedings
|
See
“Litigation” and “Environmental” in Note 13 in the “Notes to Consolidated
Financial Statements.”
|
Submission
of Matters to a Vote of Security
Holders
|
None.
Available Information
We file
reports with the 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 100 F Street, N.E., Room 1580, 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.
As
required by Section 402 of the Sarbanes-Oxley Act of 2002, we have adopted a
code of ethics that applies to our chief executive officer, chief financial
officer and principal accounting officer. This code of ethics is
posted on our web site. 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.
|
Item 5.
|
Market
for Registrant’s Common Equity, Related Stockholder Matters and Issuer
Purchases of Equity Securities
|
Our
common stock is listed on the New York Stock Exchange under the symbol
FTO. The quarterly high and low sales as reported on the New York
Stock Exchange for 2009 and 2008 are shown in the following table:
|
2009
|
High
|
Low
|
||||||
|
Fourth
quarter
|
$ | 16.54 | $ | 11.03 | ||||
|
Third
quarter
|
15.15 | 12.00 | ||||||
|
Second
quarter
|
18.40 | 12.09 | ||||||
|
First
quarter
|
16.84 | 11.80 | ||||||
|
2008
|
High
|
Low
|
||||||
|
Fourth
quarter
|
$ | 18.38 | $ | 7.51 | ||||
|
Third
quarter
|
24.26 | 16.49 | ||||||
|
Second
quarter
|
33.00 | 23.03 | ||||||
|
First
quarter
|
41.00 | 25.22 | ||||||
The
approximate number of holders of record for our common stock as of February 19,
2010 was 910. The quarterly cash dividend was $0.05 per share for the quarters
ended June 30, 2007 through March 31, 2008. The quarterly cash
dividend was $0.06 per share for the quarters ended June 30, 2008 through
December 31, 2009. Our 6.625% Senior Notes, our 8.5% Senior Notes and
our Revolving Credit Facility may restrict dividend payments based on the
covenants related to interest coverage and restricted payments. See
Notes 7 and 8 in the “Notes to Consolidated Financial Statements.” Based on
current market conditions and after giving effect to the change in inventory
valuation method (see “Change in Accounting Principle – Inventory” in Note 3 of
the “Consolidated Financial Statements”), the Company will be contractually
unable to pay cash dividends in the foreseeable future under the restricted
payments provision of the Company’s senior notes indentures.
The
following graph indicates the performance of our common stock against the
S&P 500 Index and against a refining peer group which is comprised of Sunoco
Inc., Holly Corporation, Valero Energy Corporation and Tesoro
Corporation. The following information in this Item 5 of this Annual
Report on Form 10-K is not deemed to be “soliciting material” or to be “filed”
with the SEC or subject to Regulation 14A or 14C under the Securities Exchange
Act of 1934 or to the liabilities of Section 18 of the Securities Exchange Act
of 1934, and will not be deemed to be incorporated by reference into any filing
under the Securities Act of 1933 or the Securities Exchange Act of 1934, except
to the extent we specifically incorporate it by reference into such a
filing.
Item 6. Selected Financial Data
|
Five
Year Financial Data
|
||||||||||||||||||||
|
(Unaudited)
|
Years
Ended December 31,
|
|||||||||||||||||||
|
2009
|
2008
As
Adjusted
(1)
|
2007
As
Adjusted
(1)
|
2006
As
Adjusted
(1)
|
2005
As
Adjusted
(1)
|
||||||||||||||||
|
(Dollars
in thousands, except per share amounts)
|
||||||||||||||||||||
|
Revenues
|
$ | 4,237,213 | $ | 6,498,780 | $ | 5,188,740 | $ | 4,795,953 | $ | 4,001,162 | ||||||||||
|
Operating
income (loss)
|
(105,370 | ) | 351,444 | 600,059 | 566,597 | 392,171 | ||||||||||||||
|
Cumulative
effect of accounting change,
net of income taxes (2)
|
- | - | - | - | (2,503 | ) | ||||||||||||||
|
Net
income (loss)
|
(83,760 | ) | 226,053 | 402,332 | 374,565 | 239,160 | ||||||||||||||
|
Basic
earnings (loss) per share:
|
||||||||||||||||||||
|
Before
cumulative effect of accounting
change
|
$ | (0.81 | ) | $ | 2.19 | $ | 3.77 | $ | 3.36 | $ | 2.18 | |||||||||
|
Cumulative
effect of accounting change
(2)
|
- | - | - | - | (0.02 | ) | ||||||||||||||
|
Net
income (loss)
|
$ | (0.81 | ) | $ | 2.19 | $ | 3.77 | $ | 3.36 | $ | 2.16 | |||||||||
|
Diluted
earnings per share:
|
||||||||||||||||||||
|
Before
cumulative effect of accounting
change
|
$ | (0.81 | ) | $ | 2.18 | $ | 3.73 | $ | 3.33 | $ | 2.13 | |||||||||
|
Cumulative
effect of accounting change
(2)
|
- | - | - | - | (0.02 | ) | ||||||||||||||
|
Net
income (loss)
|
$ | (0.81 | ) | $ | 2.18 | $ | 3.73 | $ | 3.33 | $ | 2.11 | |||||||||
|
Working
capital (current assets less
current liabilities)
|
$ | 498,190 | $ | 639,188 | $ | 371,527 | $ | 418,328 | $ | 213,667 | ||||||||||
|
Total
assets
|
2,147,895 | 2,006,305 | 1,705,865 | 1,462,735 | 1,166,579 | |||||||||||||||
|
Long-term
debt
|
347,485 | 347,220 | 150,000 | 150,000 | 150,000 | |||||||||||||||
|
Long-term
liabilities
|
317,258 | 254,158 | 173,721 | 138,373 | 121,250 | |||||||||||||||
|
Shareholders'
equity
|
943,976 | 1,038,976 | 880,631 | 714,664 | 422,214 | |||||||||||||||
|
Dividends
declared per common share
|
$ | 0.240 | $ | 0.230 | $ | 0.180 | $ | 0.100 | $ | 0.575 | ||||||||||
|
(1)
In the fourth quarter of 2009, we adopted a change in accounting principle
for inventory cost methods from a FIFO (first-in, first-out) basis to a
LIFO (last-in, first-out) basis. Each individual prior period
presented above has been adjusted to reflect the period specific effects
of applying the new accounting principle. See Note 3 in the "Notes to
Consolidated Financial Statements."
|
||||||||||||||||||||
|
(2)
As of December 31, 2005, we adopted FASB Accounting Standards Codification
("ASC") 410 "Asset Retirement and Environmental
Obligations."
|
||||||||||||||||||||
|
Item 7. Management’s Discussion and
Analysis of Financial Condition and Results of
Operations
|
General
Frontier
operates 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 crude oil to be refined and market refined
petroleum products, including various grades of gasoline, diesel, jet fuel,
asphalt and other by-products.
Results
of Operations
To assist
in understanding our operating results, please refer to the operating data at
the end of this analysis which provides key operating information for our
Refineries. Refinery operating data is also included in our quarterly
reports on Form 10-Q and on our web site at
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.
Overview
Our
Refineries have a total annual average crude oil capacity of approximately
187,000 bpd. The four significant indicators of our profitability,
which are reflected and defined in the operating data at the end of this
analysis, are the gasoline crack spread, the diesel crack spread, the
light/heavy crude oil differential and the WTI/WTS crude oil
differential. Other significant factors that influence our financial
results are refinery utilization, crude oil price trends, asphalt and by-product
margins and refinery operating expenses (including natural gas and
maintenance). During the fourth quarter of 2009, the Company changed
its inventory valuation method for crude oil, unfinished products and finished
products to the last-in, first-out (LIFO) method from the first-in, first-out
(FIFO) method as previously disclosed. See “Change in Accounting
Principle – Inventory” in Note 3 in the “Consolidated Financial Statements” for
additional information. We typically do not use derivative
instruments to offset price risk on our base level of operating
inventories. See “Price Risk Management Activities” under Item 7A for
a discussion of our utilization of futures trading.
Crude oil
market fundamentals, changes in the macro-economy and geopolitical
considerations have caused crude oil prices to be highly
volatile. Our decreased profitability for the year ended December 31,
2009 was due to the decline of certain profitability indicators, including the
diesel crack spread and crude oil differentials. The decline in crude
oil differentials has been caused by several factors, including significant
industry equipment investments over the last few years to process heavy/sour
crude oil and declining availability of these types of crudes. We
expect the U.S. recession, which has reduced demand for gasoline and diesel, and
less attractive crude oil differentials could continue to negatively impact our
2010 results.
The poor
refined product market conditions have resulted in an excess of refining
capacity in the U.S. and worldwide. This over-capacity is likely to
continue until demand for refined products increases or capacity is
reduced. Our Cheyenne Refinery is more drastically impacted by these
market conditions, and we are taking actions to improve the profitability at our
Cheyenne Refinery. These actions include a combination of cost
reductions and projects aimed at energy efficiency, yield improvements and crude
type flexibility. At this time, we are unable to project when
industry conditions will improve or what additional steps we may take in
response. We will continue to evaluate the need to impair any of our
assets should market conditions continue to deteriorate.
2009
Compared with 2008
(2008
as Adjusted, see Note 3 to “Consolidated Financial Statements”)
Overview
of Results
We had a
net loss for the year ended December 31, 2009, of $83.8 million, or $0.81 per
diluted share, compared to net income of $226.1 million, or $2.18 per diluted
share, for the same period in 2008. Our operating loss of $105.4
million for the year ended December 31, 2009 reflected a decrease of $456.8
million from the $351.4 million operating income for the comparable period in
2008. The decrease in our results to a net loss for the year ended
December 31, 2009, when compared to our net income for 2008, was due to the
decline of the aforementioned profitability indicators during the year ended
December 31, 2009, including the average diesel crack spread ($8.25 per barrel
in 2009 compared to $24.59 per barrel in 2008), and the crude oil
differentials. The light/heavy crude oil differential decreased from
$17.38 per barrel for the year ended December 31, 2008 to $6.34 per barrel for
the comparable period of 2009. The WTI/WTS crude oil differential
decreased from $3.92 per barrel for the year ended December 31, 2008 to $1.65
per barrel for the comparable period of 2009. Our results did benefit
slightly from a higher average gasoline crack spread during the year ended
December 31, 2009 ($7.60 per barrel) than in 2008 ($4.75 per
barrel).
Product
yields and sales volumes were higher during the year ended December 31, 2009
because of a 25,000 bpd increase in capacity that resulted from the crude vacuum
tower project and the major turnaround work completed at the El Dorado Refinery
during the second quarter of 2008. In addition, during the first
quarter of 2009, we received the benefit, primarily at our El Dorado Refinery,
from purchasing discounted WTI crude oil versus a NYMEX WTI benchmark price
because of the excess supply of crude oil at Cushing, Oklahoma. This
crude benefit has moderated since March 2009.
Specific
Variances
Refined product
revenues. Refined product revenues decreased $2.10 billion, or
33%, from $6.34 billion to $4.24 billion for the year ended December 31, 2009
compared to 2008. This decrease was due to a decrease in average
product sales prices ($37.83 lower per sales barrel) partially offset by higher
product sales volumes in 2009 (8,900 more bpd). Sales prices
decreased primarily because of lower crude oil prices, and correspondingly lower
refined product prices during 2009 compared to 2008.
Manufactured product
yields. Manufactured product yields (“yields”) are the volumes
of specific materials obtained through the distilling of crude oil and the
operations of other refinery process units. Yields increased 9,314
bpd at the El Dorado Refinery (as described above) and decreased 1,940 bpd at
the Cheyenne Refinery for the year ended December 31, 2009 compared to
2008.
Other
revenues. Other revenues decreased $162.4 million to a $5.8
million loss for the year ended December 31, 2009 compared to a $156.6 million
gain for 2008, the primary source of which was $11.7 million in net realized and
unrealized losses from derivative contracts to hedge in-transit crude oil and
excess inventories during the year ended December 31, 2009 compared to $146.5
million in net realized and unrealized gains from derivative contracts to hedge
in-transit crude oil and excess inventories in 2008. See “Price Risk
Management Activities” under Item 7A and Note 14 in the “Notes to Consolidated
Financial Statements” for a discussion of our utilization of commodity
derivative contracts. We had gasoline sulfur credit sales of $1.9
million in 2009 compared to $4.6 million in 2008 and $4.6 million of ethanol
Renewable Identification Number (“RIN”) sales in 2009 compared to $4.5 million
in 2008. Ethanol RINs were created to assist in tracking the
compliance with national EPA regulations for blending of renewable
fuels.
Raw material, freight and other
costs. 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. Raw material, freight and other costs decreased
by $1.83 billion, or 32%, during the year ended December 31, 2009, from $5.72
billion in 2008 to $3.89 billion in 2009. The decrease in raw
material, freight and other costs was due to lower average crude oil prices and
decreased purchased products, partially offset by increased overall crude oil
charges and lower crude oil differentials during the year 2009 when compared to
2008. The average NYMEX WTI priced on the New York Mercantile
Exchange was $61.82 per barrel for the year ended December 31, 2009 compared to
$99.75 per barrel for the year ended December 31, 2008. Average crude
oil charges were 153,786 bpd for the year ended December 31, 2009 compared to
142,938 bpd in 2008.
The
Cheyenne Refinery raw material, freight and other costs of $62.17 per sales
barrel for the year ended December 31, 2009 decreased from $89.29 per sales
barrel in the same period in 2008 due to lower average crude oil prices and
lower purchased products costs, partially offset by lower light/heavy crude oil
differentials and decreased overall crude oil charges. Average crude
oil charges of 41,475 bpd for the year ended December 31, 2009 were lower than
the 43,590 bpd in 2008 because of the intentional reduction in charges during
part of the year due to the low refined product margins. The heavy
crude oil utilization rate at the Cheyenne Refinery expressed as a percentage of
the total crude oil charge decreased to 50% in the year ended December 31, 2009,
from 76% in 2008 because we chose to process more light crude oils due to the
narrowing of the light/heavy crude differential in 2009 (and thus the economic
benefit of heavy crude oil). The light/heavy crude oil differential
for the Cheyenne Refinery averaged $6.61 per barrel in the year ended December
31, 2009 compared to $17.15 per barrel in 2008.
The El
Dorado Refinery raw material, freight and other costs of $60.25 per sales barrel
for the year ended December 31, 2009 decreased from $95.84 per sales barrel in
the same period in 2008 due to lower average crude oil prices, partially offset
by increased overall crude oil charges and lower crude oil
differentials. Average crude oil charges were 112,312 bpd for
the year ended December 31, 2009, compared to 99,347 bpd in 2008. The
increase in average crude oil charges was due to the 25,000 bpd increase in
capacity that resulted from the crude vacuum tower project and the major
turnaround work completed at the El Dorado Refinery in the second quarter of
2008. We realized a light/heavy crude oil differential of $6.01 per
barrel during 2009 compared to $17.85 per barrel in 2008. For the
year ended December 31, 2009, the heavy crude oil utilization rate at our El
Dorado Refinery expressed as a percentage of the total crude oil charge was
approximately 15%, compared to 17% in 2008. The WTI/WTS crude oil
differential decreased from an average of $3.92 per barrel in the year ended
December 31, 2008 to an average of $1.65 per barrel in 2009.
Refinery operating
expenses. 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,
decreased $65,000, to $321.3 million in the year ended December 31, 2009 from
$321.4 million in 2008.
The
Cheyenne Refinery operating expenses, excluding depreciation, were $122.0
million in the year ended December 31, 2009 compared to $116.7 million in
2008. The increased expenses for 2009 compared to 2008 included:
increased environmental costs ($7.7 million, primarily due to an accrual for a
proposed EPA penalty), increased salaries and benefits ($4.6 million, including
$2.7 million of increased bonus expense based on calculated FIFO proforma
income, see Note 3 “Change in Accounting Principle – Inventory” in the “Notes to
Consolidated Financial Statements”), increased electricity costs ($852,000) and
increased water costs ($859,000). These increases were partially
offset by decreased maintenance costs ($5.4 million) as 2008 maintenance costs
included various unplanned tank, coker repairs and outages, decreased natural
gas costs ($2.5 million due to decreased prices partially offset by higher
volumes), and decreased consulting and legal expenses ($1.2
million).
The El
Dorado Refinery operating expenses, excluding depreciation, were $199.3 million
in the year ended December 31, 2009, decreasing from $204.7 million for the year
ended December 31, 2008. Natural gas costs decreased by $17.5 million
due to lower volumes and prices, partially offset by increased costs in several
areas. The primary areas of increased costs for the 2009 period
compared to the 2008 period were: increased salaries and benefits ($5.5 million,
including $2.0 million of increased bonus expense as previously discussed),
increased electricity costs ($2.8 million), increased environmental costs ($1.5
million), higher turnaround amortization ($1.1 million) and higher property
taxes ($1.1 million).
Selling and general
expenses. Selling and general expenses, excluding
depreciation, increased $14.5 million, or 33%, from $44.2 million for the year
ended December 31, 2008 to $58.7 million for the year ended December 31, 2009,
primarily due to a $14.0 million increase in salaries and benefits (which
included a $9.8 million increase in bonus expense (as previously discussed) and
an increase in deferred compensation expense of $2.2 million.
Depreciation, amortization and
accretion. Depreciation, amortization and accretion increased
$8.6 million (including $5.3 million for the El Dorado Refinery and $3.3 million
for the Cheyenne Refinery), or 13%, from $65.8 million for the year ended
December 31, 2008 to $74.3 million in 2009 because of increased capital
investments in our Refineries, including the phase one completion of the gasoil
hydrotreater revamp and the catalytic cracker reliability projects at the El
Dorado Refinery placed into service in the fourth quarter of 2009 as well as the
El Dorado Refinery’s crude unit and vacuum tower expansion project placed into
service in the second quarter of 2008. The Cheyenne Refinery’s
depreciation increased due to numerous projects placed into service in
2009.
Interest expense and other financing
costs. Interest expense and other financing costs of $28.2
million for the year ended December 31, 2009 increased $13.1 million, or 86%,
from $15.1 million in 2008. The increase in interest expense
primarily related to $12.1 million more interest expense on the 8.5% Senior
Notes (issued in September 2008). Other increases included $1.2
million more of interest expense on income tax contingencies, $715,000 more of
debt discount and finance cost amortization expense (due to the 8.5% Senior
Notes) and $529,000 increased interest and facility fees on our revolving credit
facility. Capitalized interest for the year ended December 31, 2009
was $5.3 million compared to $6.6 million in 2008. These negative
variances were partially offset by $2.2 million less interest expense on the
Utexam Master Crude Oil Purchase and Sale Contract (“Utexam Arrangement”) (see
“Leases and Other Commitments” in Note 13 in the “Notes to Consolidated
Financial Statements”). We utilized the Utexam facility less during
2009 than during 2008 as we purchased less Canadian crude
oil. Average debt outstanding (excluding amounts reflected as
accounts payable under the Utexam Arrangement) increased to $350.0 million
during the year ended December 31, 2009 from $214.4 million for the same period
in 2008.
Interest and investment
income. Interest and investment income decreased $3.1 million,
or 58%, from $5.4 million in the year ended December 31, 2008 to $2.3 million in
the year ended December 31, 2009, due to $5.9 million less interest income
resulting from lower interest rates on invested cash, offset by investment gains
of $967,000 in 2009 compared to investment losses of $1.8 million in
2008.
Provision for income
taxes. The benefit for income taxes for the year ended
December 31, 2009 was $47.5 million on a pretax loss of $131.3
million (or 36.2%)
compared to a $115.7 million provision on pretax income of $341.7 million (or
33.9%) in 2008. As discussed in Note 3 “Change in Accounting
Principle – Inventory” in the “Notes to Consolidated Financial Statements”, we
adopted the LIFO inventory method for GAAP purposes and retrospectively adjusted
our previously reported financial statements. For income tax
reporting purposes, the effective date of utilizing the LIFO inventory method is
January 1, 2009, resulting in a book to tax basis difference in
inventory. Utilizing the LIFO method of accounting for inventory for
both GAAP and income taxes greatly contributed to the 2009 net operating loss,
which we plan to carryback to 2004 and 2005 (as provided for under The Worker,
Homeownership and Business Assistance Act of 2009) to offset previously reported
taxable income which will result in estimated refunds of approximately $74.5
million. Our estimated 2009 taxable loss also includes accelerated deductions
resulting from filing for a change in accounting method for income taxes for
certain expenditures which are capitalized and depreciated under GAAP but which
we will be allowed to deduct in the year incurred for income tax
purposes. The Housing and Economic Recovery Act of 2008 and the
American Recovery and Investment Act of 2009 also provided accelerated tax
depreciation for our capital projects which were started after January 1, 2008
and which we placed into service in 2009 and 2008. This
accelerated deduction allows an expense deduction of 50% of such costs in the
year the qualified projects are placed in service with the remaining costs
depreciable under regular tax depreciation rules. The Energy Policy Act of 2005
added Section 179C to the Internal Revenue Code which provides an accelerated
deduction for qualified capital costs incurred to expand an existing
refinery. This accelerated deduction allows an expense deduction of
50% of such costs in the year the qualified projects are placed in service with
the remaining costs depreciable under regular tax depreciation
rules. These accelerated deductions were major factors in our 2009
and 2008 taxable losses. Our 2009 and 2008 income tax provisions
included the benefit from $4.5 million and $23.3 million, respectively, of
Kansas income tax credits for expansion projects at our El Dorado
Refinery. See “Income Taxes” in Note 9 in the “Notes to
Consolidated Financial Statements” for more information on our income taxes and
detailed information on our deferred tax assets.
2008
Compared with 2007
(As
Adjusted, see Note 3 to “Consolidated Financial Statements”)
Overview
of Results
We had
net income for the year ended December 31, 2008, of $226.1 million, or $2.18 per
diluted share, compared to net income of $402.3 million, or $3.73 per diluted
share, for the same period in 2007. Our operating income of $351.4
million for the year ended December 31, 2008 reflected a decrease of $248.6
million from the $600.1 million operating income for the comparable period in
2007. The average gasoline crack spread was significantly lower
during 2008 ($4.75 per barrel) than in 2007 ($17.99 per barrel), and the
light/heavy crude oil differentials also decreased. The average
diesel crack spread was higher during 2008 ($24.59 per barrel) than in 2007
($22.19 per barrel).
Specific
Variances
Refined product
revenues. Refined product revenues increased $1.07 billion, or
20%, from $5.27 billion to $6.34 billion for the year ended December 31, 2008
compared to 2007. This increase was due to an increase in average
product sales prices ($19.30 higher per sales barrel) partially offset by lower
product sales volumes in 2008 (3,776 fewer bpd). Sales prices increased
primarily because of higher average crude oil prices in 2008 compared to
2007.
Manufactured product
yields. Manufactured product yields (“yields”) are the volumes
of specific materials obtained through the distilling of crude oil and the
operations of other refinery process units. Yields decreased 5,139
bpd at the El Dorado Refinery and increased 1,773 bpd at the Cheyenne Refinery
for the year ended December 31, 2008 compared to 2007. The decrease
in yields at the El Dorado Refinery was due to lower crude oil throughput from
the planned major turnaround work on the crude unit, the coker and the reformer
during March and April of 2008.
Other
revenues. Other revenues increased $237.6 million to a $156.6
million gain for the year ended December 31, 2008 compared to an $80.9 million
loss for 2007, the primary source of which was $146.5 million in net realized
and unrealized gains from derivative contracts to hedge in-transit crude oil and
excess inventories during the year ended December 31, 2008 compared to $86.4
million in net realized and unrealized losses from derivative contracts to hedge
in-transit crude oil and excess inventories in 2007. See “Price Risk
Management Activities” under Item 7A and Note 11 in the “Notes to Consolidated
Financial Statements” for a discussion of our utilization of commodity
derivative contracts. We had gasoline sulfur credit sales of $4.6
million in 2008 compared to $4.8 million in 2007 and $4.5 million of ethanol
Renewable Identification Number (“RIN”) sales in 2008 (none in
2007).
Raw material, freight and other
costs. 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. Raw material, freight and other costs increased
by $1.52 billion, or 36%, during the year ended December 31, 2008, from $4.19
billion in 2007 to $5.72 billion in 2008. The increase in raw
material, freight and other costs when compared to 2007 was due to higher
average crude prices, increased purchased products, lower light/heavy crude oil
differentials and during 2007, the Company reduced certain inventory quantities
resulting in a liquidation of LIFO inventory quantities carried at lower costs
prevailing in prior years compared to the cost of 2007 purchases (which lowered
2007 costs by $13.2 million), partially offset by decreased overall crude oil
charges during the year ended December 31, 2008 compared to 2007. The
average NYMEX WTI priced on the New York Mercantile Exchange was $99.75 per
barrel for the year ended December 31, 2008 compared to $72.39 per barrel for
the year ended December 31, 2007. Average crude oil charges were
142,938 bpd for the year ended December 31, 2008 compared to 146,046 bpd in
2007.
The
Cheyenne Refinery raw material, freight and other costs of $89.29 per sales
barrel for the year ended December 31, 2008 increased from $64.61 per sales
barrel in the same period in 2007 due to higher average crude oil prices,
increased purchased products, and lower light/heavy crude oil
differentials. Average crude oil charges of 43,590 bpd for the year
ended December 31, 2008 were higher than the 41,778 bpd in 2007 because of a
spring 2007 turnaround, a temporary shutdown of the FCCU in the third quarter of
2007, and a December 2007 fire in the coker unit at the Cheyenne
Refinery. The heavy crude oil utilization rate at the Cheyenne
Refinery expressed as a percentage of the total crude oil charge increased to
76% in the year ended December 31, 2008, from 72% in 2007. The
light/heavy crude oil differential for the Cheyenne Refinery averaged $17.15 per
barrel in the year ended December 31, 2008 compared to $18.95 per barrel in
2007.
The El
Dorado Refinery raw material, freight and other costs of $95.84 per sales barrel
for the year ended December 31, 2008 increased from $68.75 per sales barrel in
the same period in 2007 due to higher average crude oil prices, and lower
light/heavy differentials. Average crude oil charges were 99,347 bpd
for the year ended December 31, 2008, compared to 104,268 bpd in
2007. The decrease in average crude oil charges was due to the
planned major turnaround work on the crude unit, the coker and the reformer
during March and April of 2008. We realized a light/heavy crude oil
differential of $17.85 per barrel during 2008 compared to $21.00 per barrel in
2007. For the year ended December 31, 2008, the heavy crude oil
utilization rate at our El Dorado Refinery expressed as a percentage of the
total crude oil charge was approximately 17%, compared to 15% in
2007. The WTI/WTS crude oil differential decreased from an average of
$5.02 per barrel in the year ended December 31, 2007 to an average of $3.92 per
barrel in 2008.
Refinery operating
expenses. 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,
increased $20.8 million, or 7%, to $321.4 million in the year ended December 31,
2008 from $300.5 million in 2007.
The
Cheyenne Refinery operating expenses, excluding depreciation, were $116.7
million in the year ended December 31, 2008 compared to $109.2 million in
2007. The increased expenses and the 2008 compared to 2007 variances
included: increased additives and chemicals costs ($4.4 million due to both
price and volume increases), higher turnaround amortization ($2.8 million due to
amortization of costs of 2007 turnarounds), higher electricity costs ($1.1
million due to both price and volume increases), increased natural gas costs
($819,000 due to increased prices partially offset by lower volumes), higher
property and other taxes ($720,000 due to refinery
additions), demurrage ($443,000) and training
($397,000). These increases were partially offset by decreased
maintenance costs ($3.8 million) as 2007 maintenance costs included $3.8 million
of costs relating to repairs from the December 2007 coker unit fire, and
decreased environmental costs ($879,000).
The El
Dorado Refinery operating expenses, excluding depreciation, were $204.7 million
in the year ended December 31, 2008, increasing from $191.3 million for the year
ended December 31, 2007. The primary areas of increased costs and the variance
amounts for the 2008 period compared to the 2007 period were: increased
maintenance costs ($9.5 million, primarily related to demolition, catalyst and
repair costs incurred during the March 2008 turnaround), increased salaries and
benefits expenses ($3.0 million, mostly due to increased overtime in relation to
the March 2008 turnaround), higher electricity costs ($1.5 million), increased
operating supplies costs ($710,000) and higher turnaround amortization
($571,000). These increases were partially offset by decreased
environmental costs of $1.6 million because 2007 included $1.2 million in
environmental penalties and there were no penalties in 2008.
Selling and general
expenses. Selling and general expenses, excluding
depreciation, decreased $11.2 million, or 20%, from $55.3 million for the year
ended December 31, 2007 to $44.2 million for the year ended December 31, 2008,
primarily due to the $6.3 million recognition of the loss on the Beverly Hills
settlement during the year ended December 31, 2007. In addition,
salaries and benefits expense (including stock-based compensation expense)
during the year ended December 31, 2008 decreased $3.8 million compared to the
same period in 2007. See “Stock-based Compensation” under Note 10 in
the “Notes to Consolidated Financial Statements” for a detailed discussion of
our stock-based compensation. Stock-based compensation expense was
$17.2 million for the year ended December 31, 2008 compared to $20.0 million in
2007.
Depreciation, amortization and
accretion. Depreciation, amortization and accretion increased
$12.7 million, or 24%, from $53.0 million for the year ended December 31, 2007
to $65.8 million in 2008 because of increased capital investments in our
Refineries, including our El Dorado Refinery crude unit and vacuum tower
expansion project placed into service in the second quarter of
2008.
Net gains on sales of
assets. The $44,000 gain on the sale of assets during the year
ended December 31, 2008 compares to a $15.2 million gain on sale of assets in
2007. The 2007 gain resulted from a gain of $17.3 million from the
sale of our 34.72% interest in a crude oil pipeline in Wyoming and a 50%
interest in two crude oil tanks in Guernsey, Wyoming in September 2007,
partially offset by the buyout and sale of a leased aircraft.
Interest expense and other financing
costs. Interest expense and other financing costs of $15.1
million for the year ended December 31, 2008 increased $6.4 million, or 72%,
from $8.8 million in 2007. The increase in interest expense related
to interest of $4.9 million on the new 8.5% Senior Notes offering, $540,000
higher interest expense on the Utexam Master Crude Oil Purchase and Sale
Contract (“Utexam Arrangement”) (see “Leases and Other Commitments” in Note 13
in the “Notes to Consolidated Financial Statements”), and $711,000 increased
interest and facility fees on our revolving credit
facility. Capitalized interest for the year ended December 31, 2008
was $6.6 million compared to $8.1 million in 2007. These increased
expenses were partially offset by a $1.2 million reversal of interest expense
for 2004 income tax contingency interest accruals due to the statute of
limitations expiring. Average debt outstanding (excluding
amounts payable under the Utexam Arrangement) increased to $214.4 million during
the year ended December 31, 2008 from $150.0 million for the same period in
2007.
Interest and investment
income. Interest and investment income decreased $16.4
million, or 75%, from $21.9 million in the year ended December 31, 2007 to $5.4
million in the year ended December 31, 2008, due to lower cash balances during
the first eight months (prior to receiving the proceeds from our 8.5% Senior
Notes offering) of 2008 and lower interest rates on invested cash.
Provision for income
taxes. The provision for income taxes for the year ended
December 31, 2008 was $115.7 million on pretax income of $341.7 million (or
33.9%) compared to $210.8 million on pretax income of $613.1 million (or 34.4%)
in 2007. The effective tax rate for the year ended December 31, 2008 was lower
than the effective tax rate in the comparable period in 2007 primarily from
recognizing the benefit from $23.3 million of Kansas income tax credits for
expansion projects at our El Dorado Refinery which reduced the effective tax
rate (net of federal tax impact) by approximately 4%. The American
Jobs Creation Act of 2004 (“the Act”) created Internal Revenue Code Section 199
(“Section 199”), which provides an income tax benefit to domestic
manufacturers. We recorded income tax benefits under Section 199 of
approximately $15.4 million and $5.7 million, in our 2007 and 2006 income tax
provisions, respectively. The effective tax rate in 2008 was
increased by approximately 1.0% due to reversing previously recognized 2007 and
2006 production activities deductions from filing an amended 2006 return in 2008
and the planned carryback of the 2008 taxable loss. The Company did
not recognize a benefit from the production activities deduction in 2008, as it
had a taxable loss. The Act also benefited our 2006 current income taxes payable
by allowing us an accelerated depreciation deduction of 75% of qualified capital
costs incurred to achieve low sulfur diesel fuel requirements (see
“Environmental” under Note 13 in the “Notes to Consolidated Financial
Statements”). The Act also provided for a $0.05 per gallon federal
income tax credit on compliant diesel fuel up to an amount equal to the
remaining 25% of these qualified capital costs. The $0.05 per gallon
federal income tax credit allowed us to realize an $8.5 million federal income
tax credit ($5.5 million excess tax benefit) and a $22.4 million federal income
tax credit ($14.5 million excess tax benefit) in the years ended December 31,
2007 and 2006, respectively. This credit reduced our 2007 and 2006
income taxes payable and reduced our overall effective income tax rate for those
years. The Energy Policy Act of 2005 added Section 179C to the
Internal Revenue Code which provides an accelerated deduction for qualified
capital costs incurred to expand an existing refinery. This
accelerated deduction allows an expense deduction of 50% of such costs in the
year the qualified projects are placed in service with the remaining costs
depreciable under regular tax depreciation rules. This Section 179C
deduction has benefited our cash flow for income taxes by reducing our taxable
income for 2006 and 2007 and is a primary factor in our 2008 taxable
loss. See “Income Taxes” in Note 9 in the “Notes to Consolidated
Financial Statements” for more information on our income taxes and detailed
information on our deferred tax assets.
Liquidity
and Capital Resources
Cash flows from operating
activities. Net cash provided by operating activities was
$140.9 million for the year ended December 31, 2009 compared to net cash
provided by operating activities of $297.3 million during the year ended
December 31, 2008.
Working
capital changes provided a total of $98.1 million in 2009 and used $169.4
million of cash in 2008. The most significant working capital item
providing cash during the year ended December 31, 2009 was an increase in trade
and crude payables of $175.1 million. The increase in trade and crude
payables was primarily due to higher average prices of both crude oil and
refined products at December 31, 2009 compared to December 31,
2008.
Working
capital uses of cash during the year ended December 31, 2009 included an
increase trade and other receivables of $56.0 million and an increase in
inventory of $57.0 million. The increase in inventory was mainly due to
increased volumes at December 31, 2009 compared to December 31, 2008 (1.3
million more barrels due to increased pipeline line fill commitments). The
increase in trade, note and other receivables primarily resulted from an
estimated income tax receivable of $174.6 million as of December 31, 2009
compared to $116.1 million as of December 31, 2008.
We made
estimated federal and state income tax payments of $36.0 million and $179,000,
respectively, during the year ended December 31, 2009. As of December
31, 2009, we had estimated receivables for federal income taxes of $164.1
million and state income taxes of $10.5 million.
At
December 31, 2009, we had $425.3 million of cash and cash equivalents, working
capital of $498.2 million and $399.4 million available for borrowings under our
revolving credit facility. Our 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.”
Cash flows used in investing
activities. Capital expenditures during the year ended
December 31, 2009 were $168.7 million, which included approximately $117.8
million for the El Dorado Refinery and $50.3 million for the Cheyenne
Refinery. The $117.8 million of capital expenditures for our El
Dorado Refinery included $42.3 million on the gasoil hydrotreater revamp, $16.7
million on the catalytic cracker regenerator emission control project, $15.6
million for the catalytic cracker reliability project and $8.2 million for the
catalytic cracker electrical infrastructure, as well as operational, payout,
safety, administrative, environmental and optimization projects. The catalytic
cracker reliability project cost $20.7 million and was completed in the fourth
quarter of 2009. The catalytic cracker regenerator emission control
project, with a fourth quarter 2009 completion date and total cost of $33.4
million, added a scrubber to improve the environmental performance of the unit,
specifically as it relates to flue-gas emissions. This project is
necessary to meet various EPA requirements (see “Environmental” in Note 13 in
the “Notes to Consolidated Financial Statements”). The $50.3
million of capital expenditures for our Cheyenne Refinery included approximately
$8.1 million on the new Cheyenne Refinery office and control buildings, $7.3
million for the cat gas hydrotreater project, $6.9 million on the groundwater
boundary wall control system and $5.2 million for the waste water treatment
plant flotation system, as well as environmental, operational, safety,
administrative and payout projects. We funded our 2009 capital
expenditures with cash generated from our operations and from available
cash.
Cash flows from financing
activities. During the year ended December 31, 2009, we paid
$25.4 million in dividends. Treasury stock also increased by 220,339
shares ($3.0 million) from stock surrendered by employees to pay minimum
withholding taxes on stock-based compensation which vested during
2009.
As of
December 31, 2009, we had $347.5 million of long-term debt, of which $150.0
million is due in 2011, and no borrowings under our revolving credit facility.
We had $53.0 million of 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, 2009. We had
shareholders’ equity of $944.0 million as of December 31, 2009.
Our Board
of Directors declared regular quarterly cash dividends of $0.06 per share in
November 2008, and February, April, September, and November 2009, which were
paid in January, April, July and October 2009 and January 2010,
respectively. The total cash required for the dividend declared in
November 2009 was approximately $6.2 million and was accrued as a dividend
payable at year-end. “Accrued dividends” are included in the line
item “Accrued Liabilities and Other” on the Consolidated Balance Sheets and
includes dividends accrued to date on restricted stock, which are not paid until
the restricted stock vests. Based on current market conditions and
after giving effect to the change in inventory valuation method (see “Change in
Accounting Principle – Inventory” in Note 3 of the “Notes to Consolidated
Financial Statements”), the Company will be contractually unable to pay cash
dividends under the restricted payments provision of the Company’s senior notes
indentures for an undefined period of time.
Future
capital expenditures
Significant future capital
projects. The gasoil hydrotreater revamp at the El Dorado
Refinery is the key project to achieve gasoline sulfur compliance for our El
Dorado Refinery and has a total estimated cost of $94.0 million ($74.6 million
incurred as of December 31, 2009) (see “Environmental” in Note 13 in the “Notes
to Consolidated Financial Statements”). The project will also result
in a significant yield improvement for the catalytic cracking unit, and the
first phase was completed in the fourth quarter of 2009 with the second phase
anticipated to be completed mid-2010. As of December 31, 2009,
outstanding non-cancelable purchase commitments for the gasoil hydrotreater
revamp were $2.0 million. At the Cheyenne Refinery, we plan to comply
with the low sulfur gasoline requirements with the completion of the cat
gasoline hydrotreater project (see “Environmental” in Note 13 in the “Notes to
Consolidated Financial Statements”). This project is expected to be
completed during the fourth quarter of 2010 at an estimated total cost of $40.0
million ($11.4 million incurred as of December 31, 2009). As of
December 31, 2009, outstanding non-cancelable purchase commitments for the cat
gasoline hydrotreater project were $1.2 million. In addition at the
Cheyenne Refinery, we are working on a liquefied petroleum gas (LPG) recovery
project that will recover significant quantities of saleable propane and butane
and other LPG's for alkylation unit feed from the refinery fuel gas
system. The total estimated cost of this project is $40.0 million,
and at December 31, 2009, there were no material outstanding non-cancellable
purchase commitments related to this project. This project is
estimated to be completed by mid-2011. The above amounts include
estimated capitalized interest.
2010 capital
expenditures. Including the projects discussed above, 2010
capital expenditures aggregating approximately $141.0 million are currently
planned, and include $88.0 million at our Cheyenne Refinery, $51.0 million at
our El Dorado Refinery, $1.2 million for our pipeline and product terminals and
blending facility and $620,000 at our Denver and Houston offices. The
$88.0 million of planned capital expenditures for our Cheyenne Refinery includes
$29.0 million for the cat gasoline hydrotreater project and $28.0 million for
the LPG recovery project, both mentioned above, as well as environmental,
operational, safety, payout and administrative projects. The $51.0
million of planned capital expenditures for our El Dorado Refinery includes
$23.0 million for the gasoil hydrotreater revamp project, as mentioned above, as
well as environmental, operational, safety, payout and administrative
projects. We expect that our 2010 capital expenditures will be funded
with cash generated by our operations and/or by using a portion of our existing
cash balance or additional borrowings, if necessary. We will continue
to review our capital expenditures in light of market conditions. We
may experience cost overruns and/or schedule delays or adjust the scope on any
of these projects.
Contractual
Cash Obligations
The table
below lists the contractual cash obligations we have by period. These
items include our long-term debt based on their maturity dates, our operating
lease commitments, our capital leases, purchase obligations and other long-term
liabilities.
Our
operating leases include building, equipment, aircraft and vehicle leases, which
expire from 2010 through 2017, 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. This lease has both
a fixed and a variable component.
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.
The
amounts shown below for transportation, terminalling and storage contractual
obligations include our anticipated commitments based on our agreements for
shipping crude oil on the Express Pipeline, the Spearhead Pipeline, the Plains
All American Pipeline and the Osage Pipeline.
For more
information on the agreements discussed above, see “Lease and Other Commitments”
in Note 13 in the “Notes to Consolidated Financial Statements.”
|
Payments
Due by Period
|
||||||||||||||||||||
|
Contractual Cash
Obligations
|
Total
|
Within
1 year
|
Within
2-3 years
|
Within
4-5 years
|
After
5 years
|
|||||||||||||||
|
(in
thousands)
|
||||||||||||||||||||
|
Long-term
debt
|
$ | 350,000 | $ | - | $ | 150,000 | $ | - | $ | 200,000 | ||||||||||
|
Interest
on long-term debt
|
131,433 | 26,938 | 41,453 | 34,000 | 29,042 | |||||||||||||||
|
Operating
leases
|
55,097 | 12,864 | 17,674 | 13,464 | 11,095 | |||||||||||||||
|
Capital
leases
|
3,812 | 418 | 952 | 1,131 | 1,311 | |||||||||||||||
|
Purchase
obligations:
|
||||||||||||||||||||
|
Crude
supply, feedstocks and natural gas
(1)
|
$ | 525,151 | $ | 525,151 | $ | - | $ | - | $ | - | ||||||||||
|
Transportation,
terminalling and storage
|
296,789 | 59,512 | 98,819 | 75,828 | 62,630 | |||||||||||||||
|
Refinery
capital projects
|
3,225 | 3,225 | - | - | - | |||||||||||||||
|
Other
goods and services
|
4,733 | 3,849 | 521 | 363 | - | |||||||||||||||
|
Total
purchase obligations
|
$ | 829,898 | $ | 591,737 | $ | 99,340 | $ | 76,191 | $ | 62,630 | ||||||||||
|
Contingent
income tax liabilities (2)
|
- | - | - | - | - | |||||||||||||||
|
Other
long-term liabilities
|
20,560 | - | 9,585 | 4,886 | 6,089 | |||||||||||||||
|
Post-retirement
healthcare estimated future
benefit payments (3)
|
- | - | - | - | - | |||||||||||||||
|
Total
contractual cash
|
$ | 1,390,800 | $ | 631,957 | $ | 319,004 | $ | 129,672 | $ | 310,167 | ||||||||||
|
(1)
Crude supply, feedstocks and natural gas future obligations were
calculated using current market prices and/or prices established in
applicable contracts. Of these obligations, $472.1 million relate to
January and February 2010 feedstock and natural gas requirements of the
Refineries.
|
||||||||||||||||||||
|
(2)
Contingent income tax liabilities of $29.3 million are not included
in the table because the timing and certainty cannot be reasonably
estimated.
|
||||||||||||||||||||
|
(3)
Our post-retirement health care plan is unfunded. Future
payments for retiree health care benefits are estimated for the next ten
years in Note 11 "Employee Benefit Plans" in the "Notes to Consolidated
Financial Statements."
|
||||||||||||||||||||
Off-Balance
Sheet Arrangements
We have
an interest in one unconsolidated entity (see Note 1 “Nature of Operations” in
the “Notes to Consolidated Financial Statements”). Other than
facility and equipment leasing agreements, we do not participate in any
transactions, agreements or other contractual arrangements which would result in
any off-balance sheet liabilities or other arrangements to us.
Environmental
We will
be making significant future capital expenditures to comply with various
environmental regulations. See “Environmental” in Note 13 in the
“Notes to Consolidated Financial Statements.”
Application
of Critical Accounting Policies
The
preparation of financial statements in accordance with United States generally
accepted accounting principles requires our management to make estimates and
assumptions that affect the amounts reported in the consolidated financial
statements and accompanying notes. Actual results could differ from
those estimates. The following summary provides information about our
critical accounting policies, including identification of those involving
critical accounting estimates, and should be read in conjunction with Note 2
“Significant Accounting Policies” in the “Notes to Consolidated Financial
Statements.”
Turnarounds. Normal
maintenance and repairs are expensed as incurred. Planned major
maintenance (“turnarounds”) is the scheduled and required shutdown of refinery
processing units for significant overhaul and
refurbishment. Turnaround costs include contract services, materials
and rental equipment. The costs of turnarounds are deferred when
incurred and amortized on a straight-line basis over the period of time
estimated to lapse until the next turnaround occurs. These deferred
charges are included in our Consolidated Balance Sheets in “Deferred turnaround
costs.” Also included in our Consolidated Balance Sheets in “Deferred catalyst
costs” are the costs of the catalyst that is replaced at periodic intervals when
the quality of the catalyst has deteriorated beyond its prescribed
function. The catalyst costs are deferred when incurred and amortized
on a straight-line basis over the estimated useful life of the specific
catalyst. The amortization expenses for deferred turnaround and catalyst costs
are included in “Refinery operating expenses, excluding depreciation” in our
Consolidated Statements of Operations. Since these policies rely on
our estimated timing for the next turnaround and the useful lives of the
catalyst, adjustments can occur in the amortization expenses as these estimates
change.
Inventories. During
the fourth quarter of 2009, the Company changed its inventory valuation method
for crude oil, unfinished products and finished products to the LIFO method from
the FIFO method as previously disclosed. See “Change in Accounting
Principle – Inventory” in Note 3 of the “Notes to Consolidated Financial
Statements” for additional information.
Inventories
of crude oil, unfinished products and all finished products are recorded at the
lower of cost on a LIFO 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.
Asset Retirement
Obligations. GAAP requires that the fair value of a liability
for an asset retirement obligation be recognized in the period in which the
liability is incurred, with the associated asset retirement costs being
capitalized as a part of the carrying amount of the long-lived
asset. GAAP also includes disclosure requirements that provide a
description of asset retirement obligations and reconciliation of changes in the
components of those obligations.
The GAAP
guidance clarifies that the term “conditional asset retirement obligation” as
used in the current language refers to a legal obligation to perform an asset
retirement activity in which the timing and/or method of settlement are
conditional on a future event that may or may not be within the control of the
reporting entity. Since the obligation to perform the asset
retirement activity is unconditional, the guidance provides that a liability for
the fair value of a conditional asset obligation should be recognized if that
fair value can be reasonably estimated, even though uncertainty exists about the
timing and/or method of settlement. The guidance also clarifies when
an entity would have sufficient information to reasonably estimate the fair
value of a conditional asset retirement obligation under GAAP. At
December 31, 2009, our asset retirement obligation was $5.4
million.
Asset
retirement obligations are affected by regulatory changes and refinery
operations as well as changes in pricing of services. In order to
determine fair value, management must make certain estimates and assumptions,
including, among other things, projected cash flows, a credit-adjusted risk-free
interest rate, and an assessment of market conditions that could significantly
impact the estimated fair value of the asset retirement
obligation. These estimates and assumptions are subjective and are
currently based on historical costs with adjustments for estimated future
changes in the associated costs. Therefore, we expect the dollar
amount of these obligations to change as more information is
obtained. A 1% change in pricing of services would cause an
approximate $50,000 change to the asset retirement obligation. We
believe that we adequately accrued for our asset retirement obligations as of
December 31, 2009 and that changes in estimates in future periods will not have
a significant effect on our results of operations or financial
condition. See “Significant Accounting Policies” in Note 2 in the
“Notes to Consolidated Financial Statements” for further information about asset
retirement obligations.
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. Such estimates are subject to change due
to many factors, including the identification of new sites requiring
remediation, changes in environmental laws and regulations and their
interpretation, additional information related to the extent and nature of
remediation efforts, and potential improvements in remediation
technologies.
Post-retirement Benefit
Obligations. We have significant post-retirement benefit
liabilities and costs that are developed from actuarial
valuations. Inherent in these valuations are key assumptions,
including discount rates and health care inflation rates. Changes in
these assumptions are primarily influenced by factors outside of our
control. These assumptions can have a significant effect on the
amounts reported in our consolidated financial statements. See Note
11 “Employee Benefit Plans” in the “Notes to Consolidated Financial Statements”
for more information about these plans and the current assumptions
used.
Income Taxes. In
accordance with GAAP, we record deferred tax assets and liabilities to account
for the expected future tax consequences of events that have been recognized in
our financial statements and our tax returns. We routinely assess the
realizability of our deferred tax assets and if we conclude that it is more
likely than not that some portion or all of the deferred tax assets will not be
realized, the tax asset would be reduced by a valuation allowance. We
consider future taxable income in making such assessments, which requires
numerous judgments and assumptions. We record contingent income tax
liabilities, interest and penalties, based on our estimate as to
whether, and the extent to which, additional taxes may be due.
New
Accounting Pronouncements
See “New
Accounting Pronouncements” in Note 2 in the “Notes to Consolidated Financial
Statements.”
Market
Risks
See Item
7A “Quantitative and Qualitative Disclosure about Market Risk” and Notes 2 and
14 in the “Notes to Consolidated Financial Statements” under “Price and Interest
Risk Management Activities” for a discussion of our various price risk
management activities. When we make the decision to manage our price
exposure, our objective is generally to avoid losses from negative price
changes, realizing we will not obtain the benefit of positive price
changes.
|
Item 7A. Quantitative and Qualitative
Disclosures About Market Risk
|
Impact of Changing Energy
Prices. Our earnings and cash flows, as well as estimates of
future cash flows, are sensitive to changes in energy prices. The
prices of crude oil and refined products have fluctuated substantially in recent
years. These prices depend on many factors, including the overall
demand for crude oil and refined products, which in turn depend on, among other
factors, 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 regulations and global market
dynamics. The prices we receive for refined products are also
affected by factors such as local market conditions and the level of operations
of other refineries in our markets. The prices at which we can sell
gasoline and other refined products are strongly influenced by the 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. The timing of the relative movement of the
prices, however, can impact profit margins, which could significantly affect our
earnings and cash flows.
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. The
commodity derivative contracts used by us may take the form of futures
contracts, collars or price swaps. We believe that there is minimal
credit risk with respect to its counterparties. We account for our
commodity derivative contracts that do not qualify for hedge accounting under
GAAP, under mark-to-market accounting and gains and losses on transactions are
reflected in “Other revenues” on the Consolidated Statements of Operations for
each period. When the derivative contracts are designated as fair
value hedges for accounting purposes, the gains or losses are recognized in the
related inventory in “Inventory of crude oil, products and other” on the
Consolidated Balance Sheets and ultimately, when the inventory is charged or
sold, in “Raw material, freight and other costs” on the Consolidated Statements
of Operations. See “Price Risk Management Activities” under Note 14
in the “Notes to Consolidated Financial Statements.”
Our
outstanding derivative sale contracts and net unrealized losses as of December
31, 2009 are summarized below:
|
Commodity
|
Period
|
Volume
(thousands of
bbls)
|
Expected
Close
Out
Date
|
Unrealized
Net Loss
(in
thousands)
|
||||
|
Crude
Oil
|
February
2010
|
1,086
|
January
2010
|
$(2,780)
|
||||
|
Crude
Oil
|
March
2010
|
1,069
|
February
2010
|
(3,771)
|
Interest Rate
Risk. Borrowings under our revolving credit
facility bear a current market rate of interest. A one percent
increase or decrease in the interest rates on our revolving credit facility
would not significantly affect our earnings or cash flows. Our $150.0 million
principal 6.625% Senior Notes due 2011 and $200.0 million 8.5% Senior Notes due
2016 that were outstanding at December 31, 2008 have fixed interest
rates. However, in October 2009, due to current advantageous market
conditions, the Company entered into fixed to floating interest rate swaps of
$150.0 million to reduce exposure related to our 6.625% Senior
Notes. These interest rate swaps expose that portion of our long-term
debt to cash flow risk from interest rate changes. Our long-term debt
is also exposed to fair value risk. The estimated fair value of our
6.625% Senior Notes was $150.8 million and our 8.5% Senior Notes was $207.0
million at December 31, 2009.
Operating
Data
The
following tables set forth the refining operating statistical information on a
consolidated basis and for each Refinery for 2009, 2008 and 2007. The
statistical information includes the following terms:
|
●
|
NYMEX
WTI - the benchmark West Texas Intermediate crude oil priced on the New
York Mercantile Exchange.
|
|
●
|
Charges
- the quantity of crude oil and other feedstock processed through Refinery
units on a 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 NYMEX
WTI crude oil price.
|
|
●
|
Cheyenne
light/heavy crude oil differential - the average differential between the
NYMEX WTI crude oil price and the heavy crude oil delivered to the
Cheyenne Refinery.
|
|
●
|
WTI/WTS
crude oil differential - the average differential between the NYMEX WTI
crude oil price and the West Texas sour crude oil priced at Midland,
Texas.
|
|
●
|
El
Dorado Refinery light/heavy crude oil differential - the average
differential between the NYMEX WTI crude oil price and the heavy crude oil
delivered to the El Dorado
Refinery.
|
|
Years
Ended December 31,
|
||||||||||||
|
Consolidated:
|
2009
|
2008
|
2007
|
|||||||||
|
Charges
(bpd)
|
||||||||||||
|
Light
crude
|
49,892 | 30,265 | 31,171 | |||||||||
|
Heavy
and intermediate crude
|
103,894 | 112,673 | 114,875 | |||||||||
|
Other
feed and blendstocks
|
16,125 | 18,899 | 18,831 | |||||||||
|
Total
|
169,911 | 161,837 | 164,877 | |||||||||
|
Manufactured
product yields (bpd)
|
||||||||||||
|
Gasoline
|
80,201 | 76,573 | 76,974 | |||||||||
|
Diesel
and jet fuel
|
66,039 | 58,748 | 55,889 | |||||||||
|
Asphalt
|
2,194 | 3,477 | 5,945 | |||||||||
|
Other
|
16,456 | 18,717 | 22,074 | |||||||||
|
Total
|
164,890 | 157,515 | 160,882 | |||||||||
|
Total
product sales (bpd)
|
||||||||||||
|
Gasoline
|
91,127 | 85,515 | 88,744 | |||||||||
|
Diesel
and jet fuel
|
65,623 | 58,139 | 56,862 | |||||||||
|
Asphalt
|
2,035 | 3,900 | 5,988 | |||||||||
|
Other
|
16,487 | 18,818 | 18,554 | |||||||||
|
Total
|
175,272 | 166,372 | 170,148 | |||||||||
|
Refinery
operating margin information (per sales barrel)
|
||||||||||||
|
Refined
products revenue
|
$ | 66.32 | $ | 104.15 | $ | 84.85 | ||||||
|
Raw
material, freight and other costs (1)
|
60.78 | 93.87 | 67.55 | |||||||||
|
Refinery
operating expenses, excluding depreciation
|
5.02 | 5.28 | 4.84 | |||||||||
|
Depreciation,
amortization and accretion
|
1.16 | 1.08 | 0.85 | |||||||||
|
Average
NYMEX WTI (per barrel)
|
$ | 61.82 | $ | 99.75 | $ | 72.39 | ||||||
|
Average
light/heavy differential (per barrel)
|
6.34 | 17.38 | 19.65 | |||||||||
|
Average
gasoline crack spread (per barrel)
|
7.60 | 4.75 | 17.99 | |||||||||
|
Average
diesel crack spread (per barrel)
|
8.25 | 24.59 | 22.19 | |||||||||
|
Average
sales price (per sales barrel)
|
||||||||||||
|
Gasoline
|
$ | 70.83 | $ | 105.64 | $ | 92.15 | ||||||
|
Diesel
and jet fuel
|
70.01 | 123.69 | 94.55 | |||||||||
|
Asphalt
|
66.94 | 65.74 | 44.69 | |||||||||
|
Other
|
26.63 | 45.02 | 33.18 | |||||||||
|
(1)
Prior period amounts are adjusted to reflect current year
presentation on a LIFO inventory basis.
|
||||||||||||
|
Years
Ended December 31,
|
||||||||||||
|
Cheyenne Refinery:
|
2009
|
2008
|
2007
|
|||||||||
|
Charges
(bpd)
|
||||||||||||
|
Light
crude
|
20,378 | 10,128 | 11,545 | |||||||||
|
Heavy
and intermediate crude
|
21,097 | 33,462 | 30,233 | |||||||||
|
Other
feed and blendstocks
|
1,633 | 1,283 | 1,304 | |||||||||
|
Total
|
43,108 | 44,873 | 43,082 | |||||||||
|
Manufactured
product yields (bpd)
|
||||||||||||
|
Gasoline
|
19,797 | 19,379 | 17,504 | |||||||||
|
Diesel
|
15,391 | 13,528 | 12,281 | |||||||||
|
Asphalt
|
2,194 | 3,477 | 5,945 | |||||||||
|
Other
|
4,049 | 6,987 | 5,868 | |||||||||
|
Total
|
41,431 | 43,371 | 41,598 | |||||||||
|
Total
product sales (bpd)
|
||||||||||||
|
Gasoline
|
27,454 | 26,920 | 27,427 | |||||||||
|
Diesel
|
15,168 | 13,112 | 12,486 | |||||||||
|
Asphalt
|
2,035 | 3,900 | 5,988 | |||||||||
|
Other
|
3,830 | 6,013 | 3,577 | |||||||||
|
Total
|
48,487 | 49,945 | 49,478 | |||||||||
|
Refinery
operating margin information (per sales barrel)
|
||||||||||||
|
Refined
products revenue
|
$ | 67.45 | $ | 100.96 | $ | 83.04 | ||||||
|
Raw
material, freight and other costs (1)
|
62.17 | 89.29 | 64.61 | |||||||||
|
Refinery
operating expenses, excluding depreciation
|
6.89 | 6.38 | 6.05 | |||||||||
|
Depreciation,
amortization and accretion
|
1.67 | 1.44 | 1.29 | |||||||||
|
Average
light/heavy crude oil differential (per barrel)
|
$ | 6.61 | $ | 17.15 | $ | 18.95 | ||||||
|
Average
gasoline crack spread (per barrel)
|
7.48 | 5.99 | 17.53 | |||||||||
|
Average
diesel crack spread (per barrel)
|
9.55 | 27.80 | 25.61 | |||||||||
|
Average
sales price (per sales barrel)
|
||||||||||||
|
Gasoline
|
$ | 71.47 | $ | 106.54 | $ | 92.55 | ||||||
|
Diesel
|
73.00 | 128.04 | 98.84 | |||||||||
|
Asphalt
|
66.94 | 65.74 | 44.69 | |||||||||
|
Other
|
16.93 | 39.82 | 19.20 | |||||||||
|
El Dorado Refinery:
|
||||||||||||
|
Charges
(bpd)
|
||||||||||||
|
Light
crude
|
29,515 | 20,137 | 19,626 | |||||||||
|
Heavy
and intermediate crude
|
82,797 | 79,210 | 84,642 | |||||||||
|
Other
feed and blendstocks
|
14,491 | 17,616 | 17,527 | |||||||||
|
Total
|
126,803 | 116,963 | 121,795 | |||||||||
|
Manufactured
product yields (bpd)
|
||||||||||||
|
Gasoline
|
60,403 | 57,194 | 59,470 | |||||||||
|
Diesel
and jet fuel
|
50,647 | 45,220 | 43,608 | |||||||||
|
Other
|
12,408 | 11,730 | 16,205 | |||||||||
|
Total
|
123,458 | 114,144 | 119,283 | |||||||||
|
Total
product sales (bpd)
|
||||||||||||
|
Gasoline
|
63,673 | 58,595 | 61,318 | |||||||||
|
Diesel
and jet fuel
|
50,455 | 45,027 | 44,376 | |||||||||
|
Other
|
12,657 | 12,804 | 14,977 | |||||||||
|
Total
|
126,785 | 116,426 | 120,671 | |||||||||
|
Refinery
operating margin information (per sales barrel)
|
||||||||||||
|
Refined
products revenue
|
$ | 65.89 | $ | 105.52 | $ | 85.59 | ||||||
|
Raw
material, freight and other costs (1)
|
60.25 | 95.84 | 68.75 | |||||||||
|
Refinery
operating expenses, excluding depreciation
|
4.31 | 4.80 | 4.34 | |||||||||
|
Depreciation,
amortization and accretion
|
0.96 | 0.92 | 0.67 | |||||||||
|
Average
WTI/WTS crude oil differential (per barrel)
|
$ | 1.65 | $ | 3.92 | $ | 5.02 | ||||||
|
Average
light/heavy crude oil differential (per barrel)
|
6.01 | 17.85 | 21.00 | |||||||||
|
Average
gasoline crack spread (per barrel)
|
7.65 | 4.18 | 18.19 | |||||||||
|
Average
diesel crack spread (per barrel)
|
7.86 | 23.66 | 21.23 | |||||||||
|
Average
sales price (per sales barrel)
|
||||||||||||
|
Gasoline
|
$ | 70.56 | $ | 105.22 | $ | 91.98 | ||||||
|
Diesel
and jet fuel
|
69.12 | 122.42 | 93.34 | |||||||||
|
Other
|
29.57 | 47.47 | 36.52 | |||||||||
|
(1)
Prior period amounts are adjusted to reflect current year
presentation on a LIFO inventory basis.
|
||||||||||||
|
Item 8.
|
Financial
Statements and Supplementary Data
|
REPORT
OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To
the Board of Directors and Shareholders of Frontier Oil
Corporation:
We have
audited the accompanying consolidated balance sheets of Frontier Oil Corporation
and subsidiaries (the “Company”) as of December 31, 2009 and 2008, and the
related consolidated statements of operations, changes in shareholders’ equity
and comprehensive income, and cash flows for each of the three years in the
period ended December 31, 2009. Our audits also included the financial statement
schedules listed in the Index at Item 15. These consolidated 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, 2009 and 2008, and the results of their operations and their
cash flows for each of the three years in the period ended December 31, 2009, 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.
As
discussed in Note 3 to the consolidated financial statements, during the fourth
quarter of 2009, the Company changed its inventory valuation method for crude
oil, unfinished products, and finished products to the last-in, first-out (LIFO)
method from the first-in, first-out (FIFO) method.
We have
also audited, in accordance with the standards of the Public Company Accounting
Oversight Board (United States), the Company’s internal control over financial
reporting as of December 31, 2009, 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 February 24, 2010 expressed an
unqualified opinion on the Company’s internal control over financial
reporting.
DELOITTE
& TOUCHE LLP
Denver,
Colorado
February
24, 2010
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, 2009. 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, 2009, the Company’s internal control over financial
reporting is effective based on those criteria.
Frontier
Oil Corporation’s independent registered public accounting firm has issued an
audit report on the effectiveness of the Company’s internal control over
financial reporting. This report appears on the following
page.
February
24, 2010
Michael
C. Jennings
President
and Chief Executive Officer
Doug
S. Aron
Executive
Vice President and Chief Financial Officer
Nancy
J. Zupan
Vice
President and Chief Accounting Officer
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING
FIRM
To
the Board of Directors and Shareholders of Frontier Oil
Corporation:
We have
audited the internal control over financial reporting of Frontier Oil
Corporation and its subsidiaries (the “Company”) as of December 31, 2009 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, included in the accompanying Management’s
Report on Internal Control Over Financial Reporting. Our
responsibility is to express an opinion on 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, assessing the risk that a material
weakness exists, testing and evaluating the design and operating effectiveness
of internal control based on the assessed risk, and performing such other
procedures as we considered necessary in the circumstances. We
believe that our audit provides a reasonable basis for our opinion.
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, the Company maintained, in all material respects, effective internal
control over financial reporting as of December 31, 2009, 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, 2009 of
the Company and our report dated February 24, 2010 expressed an unqualified
opinion on those consolidated financial statements and financial statement
schedules and included an explanatory paragraph regarding the Company’s change
in its inventory valuation method for crude oil, unfinished products, and
finished products to the last-in, first-out (LIFO) method from the first-in,
first-out (FIFO) method.
DELOITTE
& TOUCHE LLP
Denver,
Colorado
February
24, 2010
|
FRONTIER OIL CORPORATION AND SUBSIDIARIES
|
||||||||||||
|
Consolidated
Statements of Operations
|
||||||||||||
|
Years
Ended December 31,
|
||||||||||||
|
2009
|
2008
As
Adjusted
(Note
3)
|
2007
As
Adjusted
(Note
3)
|
||||||||||
|
(in
thousands, except per share data)
|
||||||||||||
|
Revenues:
|
||||||||||||
|
Refined
products
|
$ | 4,242,966 | $ | 6,342,144 | $ | 5,269,674 | ||||||
|
Other
|
(5,753 | ) | 156,636 | (80,934 | ) | |||||||
| 4,237,213 | 6,498,780 | 5,188,740 | ||||||||||
|
Costs
and expenses:
|
||||||||||||
|
Raw
material, freight and other costs
|
3,888,308 | 5,716,091 | 4,194,971 | |||||||||
|
Refinery
operating expenses, excluding depreciation
|
321,299 | 321,364 | 300,542 | |||||||||
|
Selling
and general expenses, excluding depreciation
|
58,668 | 44,169 | 55,343 | |||||||||
|
Depreciation,
amortization and accretion
|
74,308 | 65,756 | 53,039 | |||||||||
|
Net
gains on sales of assets
|
- | (44 | ) | (15,214 | ) | |||||||
| 4,342,583 | 6,147,336 | 4,588,681 | ||||||||||
|
Operating
(loss) income
|
(105,370 | ) | 351,444 | 600,059 | ||||||||
|
Interest
expense and other financing costs
|
28,187 | 15,130 | 8,773 | |||||||||
|
Interest
and investment income
|
(2,279 | ) | (5,425 | ) | (21,851 | ) | ||||||
| 25,908 | 9,705 | (13,078 | ) | |||||||||
|
(Loss)
income before income taxes
|
(131,278 | ) | 341,739 | 613,137 | ||||||||
|
(Benefit)
provision for income taxes
|
(47,518 | ) | 115,686 | 210,805 | ||||||||
|
Net
(loss) income
|
$ | (83,760 | ) | $ | 226,053 | $ | 402,332 | |||||
|
Basic
(loss) earnings per share of common stock
|
$ | (0.81 | ) | $ | 2.19 | $ | 3.77 | |||||
|
Diluted
(loss) earnings per share of common stock
|
$ | (0.81 | ) | $ | 2.18 | $ | 3.73 | |||||
|
The
accompanying notes are an integral part of these consolidated financial
statements.
|
||||||||||||
|
FRONTIER OIL CORPORATION AND SUBSIDIARIES
|
||||||||
|
Consolidated
Balance Sheets
|
||||||||
|
December
31,
|
||||||||
|
2009
|
2008
As
Adjusted
(Note
3)
|
|||||||
|
(in
thousands, except share data)
|
||||||||
|
ASSETS
|
||||||||
|
Current
assets:
|
||||||||
|
Cash
and cash equivalents
|
$ | 425,280 | $ | 483,532 | ||||
|
Trade
receivables, net of allowance of $1,000 and $500
at 2009 and 2008, respectively
|
95,261 | 84,110 | ||||||
|
Income
taxes receivable
|
174,627 | 116,118 | ||||||
|
Other
receivables
|
7,842 | 25,216 | ||||||
|
Inventory
of crude oil, products and other
|
293,476 | 236,505 | ||||||
|
Deferred
income tax assets - current
|
26,373 | 16,301 | ||||||
|
Commutation
account
|
- | 6,319 | ||||||
|
Other
current assets
|
14,507 | 37,038 | ||||||
|
Total
current assets
|
1,037,366 | 1,005,139 | ||||||
|
Property,
plant and equipment, at cost:
|
||||||||
|
Refineries,
pipeline and terminal equipment
|
1,446,287 | 1,291,106 | ||||||
|
Furniture,
fixtures and other equipment
|
17,284 | 15,638 | ||||||
| 1,463,571 | 1,306,744 | |||||||
|
Accumulated
depreciation and amortization
|
(442,162 | ) | (373,301 | ) | ||||
|
Property,
plant and equipment, net
|
1,021,409 | 933,443 | ||||||
|
Deferred
turnaround costs
|
56,355 | 47,465 | ||||||
|
Deferred
catalyst costs
|
12,136 | 9,726 | ||||||
|
Deferred
financing costs, net of accumulated amortization of $3,893 and
$2,404 at 2009 and 2008, respectively
|
4,711 | 6,201 | ||||||
|
Intangible
assets, net of accumulated amortization of $614 and $492 at 2009
and 2008, respectively
|
1,216 | 1,338 | ||||||
|
Deferred
income tax assets - noncurrent
|
10,767 | - | ||||||
|
Other
assets
|
3,935 | 2,993 | ||||||
|
Total
assets
|
$ | 2,147,895 | $ | 2,006,305 | ||||
|
LIABILITIES
AND SHAREHOLDERS' EQUITY
|
||||||||
|
Current
liabilities:
|
||||||||
|
Accounts
payable
|
$ | 474,377 | $ | 308,867 | ||||
|
Accrued
liabilities and other
|
64,799 | 57,084 | ||||||
|
Total
current liabilities
|
539,176 | 365,951 | ||||||
|
Long-term
debt
|
347,485 | 347,220 | ||||||
|
Contingent
income tax liabilities
|
29,348 | 28,057 | ||||||
|
Post-retirement
employee liabilities
|
33,138 | 31,128 | ||||||
|
Long-term
capital lease obligation
|
3,394 | 3,548 | ||||||
|
Other
long-term liabilities
|
20,560 | 12,211 | ||||||
|
Deferred
income tax liabilities
|
230,818 | 179,214 | ||||||
|
Commitments
and contingencies
|
||||||||
|
Shareholders'
equity:
|
||||||||
|
Preferred
stock, $100 par value, 500,000 shares authorized, no shares issued
|
- | - | ||||||
|
Common
stock, no par value, 180,000,000 shares authorized, 131,850,356
shares issued at both periods
|
57,736 | 57,736 | ||||||
|
Paid-in
capital
|
252,513 | 236,183 | ||||||
|
Retained
earnings
|
1,030,203 | 1,139,512 | ||||||
|
Accumulated
other comprehensive loss
|
(1,234 | ) | (723 | ) | ||||
|
Treasury
stock, at cost, 27,165,400 and 27,945,884 shares
at 2009 and 2008, respectively
|
(395,242 | ) | (393,732 | ) | ||||
|
Total
shareholders' equity
|
943,976 | 1,038,976 | ||||||
|
Total
liabilities and shareholders' equity
|
$ | 2,147,895 | $ | 2,006,305 | ||||
|
The
accompanying notes are an integral part of these consolidated financial
statements.
|
||||||||
|
FRONTIER OIL CORPORATION AND
SUBSIDIARIES
|
||||||||||||
|
Consolidated
Statements of Cash Flows
|
||||||||||||
|
Years
Ended December 31,
|
||||||||||||
|
2009
|
2008
As
Adjusted
(Note
3)
|
2007
As
Adjusted
(Note
3)
|
||||||||||
|
(in
thousands)
|
||||||||||||
|
Cash
flows from operating activities:
|
||||||||||||
|
Net
income (loss)
|
$ | (83,760 | ) | $ | 226,053 | $ | 402,332 | |||||
|
Adjustments
to reconcile net income to net cash from operating activities:
|
||||||||||||
|
Depreciation,
amortization and accretion
|
93,793 | 83,571 | 67,512 | |||||||||
|
Deferred
income taxes
|
31,082 | 169,766 | (60,859 | ) | ||||||||
|
Stock-based
compensation expense
|
20,608 | 20,014 | 22,553 | |||||||||
|
Excess
income tax benefits of stock-based compensation
|
(244 | ) | (3,191 | ) | (6,962 | ) | ||||||
|
Amortization
of debt issuance costs
|
1,489 | 978 | 769 | |||||||||
|
Senior
Notes discount amortization
|
264 | 60 | - | |||||||||
|
Allowance
for investment loss and bad debts
|
500 | 499 | - | |||||||||
|
Net
gains on sales of assets
|
- | (44 | ) | (15,214 | ) | |||||||
|
Decrease
in long-term commutation account
|
- | - | 1,009 | |||||||||
|
Amortization
of long-term prepaid insurance
|
- | 909 | 1,211 | |||||||||
|
Increase
(decrease) in other long-term liabilities
|
10,829 | (3,173 | ) | 27,365 | ||||||||
|
Changes
in deferred turnaround costs, deferred catalyst costs and
other
|
(31,728 | ) | (28,758 | ) | (29,287 | ) | ||||||
|
Changes
in components of working capital from operations:
|
||||||||||||
|
Increase
in trade, income taxes and other receivables
|
(56,041 | ) | (28,801 | ) | (45,018 | ) | ||||||
|
(Increase)
decrease in inventory
|
(56,971 | ) | 11,107 | 28,385 | ||||||||
|
Decrease
(increase) in other current assets
|
28,849 | (14,984 | ) | (12,724 | ) | |||||||
|
Increase
(decrease) in accounts payable
|
175,085 | (117,443 | ) | 30,312 | ||||||||
|
Increase
(decrease) in accrued liabilities and other
|
7,187 | (19,288 | ) | 17,629 | ||||||||
|
Net
cash provided by operating activities
|
140,942 | 297,275 | 429,013 | |||||||||
|
Cash
flows from investing activities:
|
||||||||||||
|
Additions
to property, plant and equipment
|
(168,670 | ) | (209,381 | ) | (291,174 | ) | ||||||
|
Proceeds
from sales of assets
|
- | 46 | 22,222 | |||||||||
|
El
Dorado Refinery contingent earn-out payment
|
- | (7,500 | ) | (7,500 | ) | |||||||
|
Other
acquisitions and leasehold improvements
|
(2,100 | ) | - | (3,561 | ) | |||||||
|
Net
cash used in investing activities
|
(170,770 | ) | (216,835 | ) | (280,013 | ) | ||||||
|
Cash
flows from financing activities:
|
||||||||||||
|
Proceeds
from issuance of 8.5% Senior Notes
|
- | 197,160 | - | |||||||||
|
Purchase
of treasury stock
|
(3,008 | ) | (67,030 | ) | (248,486 | ) | ||||||
|
Proceeds
from issuance of common stock
|
70 | 405 | 2,303 | |||||||||
|
Dividends
paid
|
(25,349 | ) | (23,144 | ) | (17,271 | ) | ||||||
|
Excess
income tax benefits of stock-based compensation
|
244 | 3,191 | 6,962 | |||||||||
|
Debt
issuance costs and other
|
(381 | ) | (4,889 | ) | (588 | ) | ||||||
|
Net
cash provided by (used in) financing activities
|
(28,424 | ) | 105,693 | (257,080 | ) | |||||||
|
Increase
(decrease) in cash and cash equivalents
|
(58,252 | ) | 186,133 | (108,080 | ) | |||||||
|
Cash
and cash equivalents, beginning of period
|
483,532 | 297,399 | 405,479 | |||||||||
|
Cash
and cash equivalents, end of period
|
$ | 425,280 | $ | 483,532 | $ | 297,399 | ||||||
|
The
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
|
Comprehensive
Income
|
Retained
Earnings
As
Adjusted (Note 3)
|
Number
of Shares
|
Amount
|
Deferred
Compensation
|
Accumulated
Other Comprehensive Income (Loss)
|
Number
of Shares
|
Amount
As
Adjusted (Note 3)
|
||||||||||||||||||||||||||||||||||
|
December
31, 2006, as reported
|
134,509,256 | $ | 57,802 | $ | 181,386 | $ | 719,802 | (24,164,808 | ) | $ | (183,392 | ) | $ | - | $ | 256 | 110,344,448 | $ | 775,854 | |||||||||||||||||||||||||
|
Change
in accounting principle (Note 3)
|
(61,190 | ) | (61,190 | ) | ||||||||||||||||||||||||||||||||||||||||
|
January
1, 2007, as adjusted
|
134,509,256 | $ | 57,802 | $ | 181,386 | $ | 658,612 | (24,164,808 | ) | $ | (183,392 | ) | $ | - | $ | 256 | 110,344,448 | $ | 714,664 | |||||||||||||||||||||||||
|
Adoption
of new income tax contingency principles
|
- | - | - | (1,016 | ) | - | - | - | - | - | (1,016 | ) | ||||||||||||||||||||||||||||||||
|
Shares
issued under stock-based compensation plans
|
- | - | 951 | - | 1,188,168 | 1,574 | - | - | 1,188,168 | 2,525 | ||||||||||||||||||||||||||||||||||
|
Shares
received under:
|
||||||||||||||||||||||||||||||||||||||||||||
|
Stock
repurchase plan
|
- | - | - | - | (6,443,700 | ) | (243,568 | ) | - | - | (6,443,700 | ) | (243,568 | ) | ||||||||||||||||||||||||||||||
|
Stock-based
compensation plans
|
- | - | - | - | (132,499 | ) | (5,139 | ) | - | - | (132,499 | ) | (5,139 | ) | ||||||||||||||||||||||||||||||
|
Comprehensive
income:
|
||||||||||||||||||||||||||||||||||||||||||||
|
Net
income
|
- | - | - | $ | 402,332 | 402,332 | - | - | - | - | - | 402,332 | ||||||||||||||||||||||||||||||||
|
Other
comprehensive income:
|
||||||||||||||||||||||||||||||||||||||||||||
|
Defined
benefit plans, net of tax of $805
|
- | - | - | 1,322 | - | - | - | - | 1,322 | - | 1,322 | |||||||||||||||||||||||||||||||||
|
Other
comprehensive income
|
1,322 | - | - | |||||||||||||||||||||||||||||||||||||||||
|
Comprehensive
income
|
$ | 403,654 | - | - | ||||||||||||||||||||||||||||||||||||||||
|
Income
tax benefits of stock-based compensation, net of
contingency
|
- | - | 6,434 | - | - | - | - | - | - | 6,434 | ||||||||||||||||||||||||||||||||||
|
Treasury
stock retirements
|
(2,658,900 | ) | (66 | ) | - | (102,895 | ) | 2,658,900 | 102,961 | - | - | - | - | |||||||||||||||||||||||||||||||
|
Stock-based
compensation expense
|
- | - | 22,553 | - | - | - | - | - | - | 22,553 | ||||||||||||||||||||||||||||||||||
|
Dividends
declared
|
- | - | - | (19,476 | ) | - | - | - | - | - | (19,476 | ) | ||||||||||||||||||||||||||||||||
|
December
31, 2007
|
131,850,356 | $ | 57,736 | $ | 211,324 | $ | 937,557 | (26,893,939 | ) | $ | (327,564 | ) | $ | - | $ | 1,578 | 104,956,417 | $ | 880,631 | |||||||||||||||||||||||||
|
Shares
issued under stock-based compensation plans
|
(457 | ) | 904,996 | 1,168 | 904,996 | 711 | ||||||||||||||||||||||||||||||||||||||
|
Shares
received under:
|
||||||||||||||||||||||||||||||||||||||||||||
|
Stock
repurchase plan
|
(1,561,367 | ) | (56,260 | ) | (1,561,367 | ) | (56,260 | ) | ||||||||||||||||||||||||||||||||||||
|
Stock-based
compensation plans
|
(395,574 | ) | (11,076 | ) | (395,574 | ) | (11,076 | ) | ||||||||||||||||||||||||||||||||||||
|
Comprehensive
income:
|
||||||||||||||||||||||||||||||||||||||||||||
|
Net
income
|
$ | 226,053 | 226,053 | - | 226,053 | |||||||||||||||||||||||||||||||||||||||
|
Other
comprehensive income (loss):
|
||||||||||||||||||||||||||||||||||||||||||||
|
Defined
benefit plans, net of tax of $1,405
|
(2,301 | ) | (2,301 | ) | - | (2,301 | ) | |||||||||||||||||||||||||||||||||||||
|
Other
comprehensive income (loss)
|
(2,301 | ) | - | - | ||||||||||||||||||||||||||||||||||||||||
|
Comprehensive
income
|
$ | 223,752 | - | - | ||||||||||||||||||||||||||||||||||||||||
|
Income
tax benefits of stock-based compensation, net of
contingency
|
5,302 | - | 5,302 | |||||||||||||||||||||||||||||||||||||||||
|
Stock-based
compensation expense
|
20,014 | - | 20,014 | |||||||||||||||||||||||||||||||||||||||||
|
Dividends
declared
|
(24,098 | ) | - | (24,098 | ) | |||||||||||||||||||||||||||||||||||||||
|
December
31, 2008
|
131,850,356 | $ | 57,736 | $ | 236,183 | $ | 1,139,512 | (27,945,884 | ) | $ | (393,732 | ) | $ | - | $ | (723 | ) | 103,904,472 | $ | 1,038,976 | ||||||||||||||||||||||||
|
Shares
issued under stock-based compensation plans
|
(1,428 | ) | 1,000,823 | 1,498 | 1,000,823 | 70 | ||||||||||||||||||||||||||||||||||||||
|
Shares
received under:
|
||||||||||||||||||||||||||||||||||||||||||||
|
Stock-based
compensation plans
|
(220,339 | ) | (3,008 | ) | (220,339 | ) | (3,008 | ) | ||||||||||||||||||||||||||||||||||||
|
Comprehensive
income (loss):
|
||||||||||||||||||||||||||||||||||||||||||||
|
Net
loss
|
$ | (83,760 | ) | (83,760 | ) | - | (83,760 | ) | ||||||||||||||||||||||||||||||||||||
|
Other
comprehensive income (loss):
|
||||||||||||||||||||||||||||||||||||||||||||
|
Defined
benefit plans, net of tax of $317
|
(511 | ) | (511 | ) | - | (511 | ) | |||||||||||||||||||||||||||||||||||||
|
Other
comprehensive income (loss)
|
(511 | ) | - | - | ||||||||||||||||||||||||||||||||||||||||
|
Comprehensive
income (loss):
|
$ | (84,271 | ) | - | - | |||||||||||||||||||||||||||||||||||||||
|
Income
tax benefits of stock-based compensation, net of
contingency
|
(2,850 | ) | - | (2,850 | ) | |||||||||||||||||||||||||||||||||||||||
|
Stock-based
compensation expense
|
20,608 | - | 20,608 | |||||||||||||||||||||||||||||||||||||||||
|
Dividends
declared
|
(25,549 | ) | - | (25,549 | ) | |||||||||||||||||||||||||||||||||||||||
|
December
31, 2009
|
131,850,356 | $ | 57,736 | $ | 252,513 | $ | 1,030,203 | (27,165,400 | ) | $ | (395,242 | ) | $ | - | $ | (1,234 | ) | 104,684,956 | $ | 943,976 | ||||||||||||||||||||||||
|
The
accompanying notes are an integral part of these consolidated
financial statements.
|
||||||||||||||||||||||||||||||||||||||||||||
FRONTIER OIL CORPORATION AND SUBSIDIARIES
Notes
To Consolidated Financial Statements
For
The Years Ended December 31, 2009, 2008 and 2007
|
1.
|
Nature
of Operations
|
The
financial statements include the accounts of Frontier Oil Corporation (“FOC”), 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 Ethanol Management Company
(“EMC”), a products terminal and blending facility located near Denver,
Colorado. The Company also purchased in December 2009, a refined
products pipeline which runs from Cheyenne, Wyoming to Sidney, Nebraska and the
associated refined products terminal and truck rack at Sidney,
Nebraska. This purchase is included in “Other acquisitions and
leasehold improvements” on the Consolidated Statements of Cash
Flows.
The
Company also owned, until their sale in September 2007, 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 were accounted for as undivided
interests. Each of these assets and the associated liabilities,
revenues and expenses were reported on a proportionate gross basis until their
disposition. 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 $82,000 and $89,000 at December 31, 2009 and 2008,
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 Rocky Mountain region includes the states of Colorado,
Wyoming, western Nebraska, Montana and Utah, and the Plains States include the
states of Kansas, Oklahoma, eastern Nebraska, Iowa, Missouri, North Dakota and
South Dakota. 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
|
Revenue
Recognition
Revenues
from sales of refined products are earned and realized upon transfer of title to
the customer based on the contractual terms of delivery (including payment terms
and prices). 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). Nonmonetary product exchanges and certain buy/sell
crude oil transactions which are entered into in the normal course of business
are included on a net cost basis in “Raw material, freight and other costs” on
the Consolidated Statements of Operations. Taxes collected from
customers and remitted to governmental authorities are not included in reported
revenues.
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:
|
|
Refineries,
pipeline and terminal equipment
|
2
to 50 years
|
|
|
Furniture,
fixtures and other equipment
|
2
to 20 years
|
The costs
of components of property, net of salvage value, retired or abandoned are
charged or credited to accumulated depreciation. Gains or losses on
sales or other dispositions of property are recorded in operating income and are
reported in “Net gains on sales of assets” in the Consolidated Statements of
Operations.
The
Company reviews long-lived assets for impairments whenever events or changes in
circumstances indicate that the carrying value of an asset may not be
recoverable. If the undiscounted future cash 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, 2009,
2008 and 2007 was $5.3 million, $6.6 million and $8.1 million,
respectively.
Turnarounds
Normal
maintenance and repairs are expensed as incurred. Planned major
maintenance is the scheduled and required shutdowns of refinery processing units
for significant overhaul and refurbishment
(“turnarounds”). Turnaround costs include contract services,
materials and rental equipment. The costs of turnarounds are deferred
when incurred and amortized on a straight-line basis over the period of time
estimated to lapse until the next turnaround occurs. These deferred
charges are included in the Company’s Consolidated Balance Sheets in “Deferred
turnaround costs.” Also included in the Consolidated Balance Sheets, in
“Deferred catalyst costs,” are the costs of the catalyst that is replaced at
periodic intervals when the quality of the catalyst has deteriorated beyond its
prescribed function. The catalyst costs are deferred when incurred
and amortized on a straight-line basis over the estimated useful life of the
specific catalyst. The amortization expenses resulting from the
turnaround and catalyst costs are included in “Refinery operating expenses,
excluding depreciation” in the Company’s Consolidated Statements of
Operations.
Inventories
During
the fourth quarter of 2009, the Company changed its inventory valuation method
for crude oil, unfinished products and finished products to the last-in,
first-out (LIFO) method from the first-in, first-out (FIFO) method as previously
disclosed. See Note 3 “Change in Accounting Principle – Inventory”
for additional information. As a result of the adjustment, the
Company’s previously reported December 31, 2008, inventory balance has decreased
by $19.6 million. Inventories of crude oil, unfinished products and
all finished products are now recorded at the lower of cost on a LIFO basis or
market, which is determined using current estimated selling
prices. Crude oil includes both domestic and foreign crude oil
volumes at its cost and associated freight and other
costs. Unfinished products (work in process) include any crude oil
that has entered into the refining process, and other feedstocks that are not
finished as far as refining operations are concerned. These include
unfinished gasoline and diesel, blendstocks and other
feedstocks. Finished product inventory includes saleable gasoline,
diesel, jet fuel, chemicals, asphalt and other finished
products. Unfinished and finished products inventory values have
components of raw material, the associated raw material freight and other costs,
and direct refinery operating expense allocated when refining begins relative to
their proportionate market values. Refined product exchange
transactions are considered asset exchanges with deliveries offset against
receipts. The net exchange balance is included in
inventory. Inventories of process chemicals and repairs and
maintenance supplies and other 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 8 “Revolving
Credit Facility.”) The components of inventory as of December 31,
2009 and 2008 were as follows:
|
December
31,
|
||||||||
|
2009
|
2008
As
Adjusted
|
|||||||
|
(in
thousands)
|
||||||||
|
Crude
oil
|
$ | 343,154 | $ | 121,973 | ||||
|
Unfinished
products
|
101,436 | 55,915 | ||||||
|
Finished
products
|
94,239 | 54,332 | ||||||
|
LIFO
reserve - adjustment to inventories
|
(272,634 | ) | (19,624 | ) | ||||
| 266,195 | 212,596 | |||||||
|
Process
chemicals
|
1,162 | 1,385 | ||||||
|
Repairs
and maintenance supplies and other
|
26,119 | 22,524 | ||||||
| $ | 293,476 | $ | 236,505 | |||||
The
Company uses the double extension, dollar value approach to price LIFO
inventory. A single material business unit pool is used for all crude
oil and unfinished and finished products inventories. An actual
valuation of inventory under the LIFO method is made annually at the end of each
fiscal year based on the inventory levels at that time. Interim LIFO
calculations are based on year to date inventory levels at the interim period
end. The interim LIFO calculations are subject to the annual LIFO
inventory valuation at year end; accordingly, annual results may differ from
interim results. There were no material liquidations of LIFO
inventory layers for the years ended December 31, 2009 and
2008. During the year ended December 31, 2007, the Company reduced
certain inventory quantities resulting in a liquidation of LIFO inventory
quantities carried at lower costs prevailing in prior years compared to the cost
of 2007 purchases. The effect of these reductions resulted in a
decrease of “Raw material, freight and other costs” of $13.2 million and an
increase in “Net income” of $8.2 million after tax or $0.08 per diluted share in
2007.
Prepaid
Insurance
The
Company charges the amounts paid for insurance policies to expense over the term
of the policy. Prepaid insurance related to policies with terms of
one year or less are included in “Other current assets” on the Consolidated
Balance Sheets.
Income
Taxes
The
Company accounts for income taxes under the provisions of accounting principles
generally accepted in the United States of America (“GAAP”) which 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 the
financial statement carrying amounts of assets and liabilities and their
respective tax basis. The Company recognizes liabilities, interest
and penalties for potential tax issues based on its estimate of whether, and the
extent to which, additional taxes may be due as determined under
GAAP. See Note 9 “Income Taxes” for further information.
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.
Price
Risk Management Activities
The
Company, at times, enters into commodity derivative contracts to manage its
price exposure to its inventory positions and purchases of foreign crude oil and
to fix margins on certain future production. See Note 14, “Price and
Interest Risk Management Activities” for detailed information on the Company’s
price risk management activities.
Stock-based
Compensation
The
Company accounts for stock-based compensation in accordance with GAAP which
requires companies to recognize the fair value of stock options and other
stock-based compensation in the financial statements. See Note 10,
under “Stock-based Compensation”, for detailed information on the Company’s
stock-based compensation.
Asset
Retirement Obligations
The
Company accounts for asset retirement obligations as required under
GAAP. GAAP 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.
The term
“conditional asset retirement obligation” as used in GAAP literature refers to a
legal obligation to perform an asset retirement activity in which the timing
and/or method of settlement are conditional on a future event that may or may
not be within the control of the entity. Because the obligation to
perform the asset retirement activity is unconditional, the guidance provides
that a liability for the fair value of a conditional asset obligation should be
recognized if that fair value can be reasonably estimated, although uncertainty
exists about the timing and/or method of settlement. The guidance
also clarifies when an entity would have sufficient information to reasonably
estimate the fair value of a conditional asset retirement obligation under
GAAP.
The
Company’s Consolidated Balance Sheets as of December 31, 2009 and 2008
recognized a net asset retirement obligation of $5.4 million and $6.3 million,
respectively. At December 31, 2009, $919,000 of the $5.4 million was
classified as current in “Accrued liabilities and other” and $4.5 million was
included in “Other long-term liabilities.” Changes in the Company’s
asset retirement obligations for the year ended December 31, 2009 were as
follows (in thousands):
|
Balance
as of December 31, 2008
|
$ | 6,281 | ||
|
Liabilities
incurred
|
442 | |||
|
Liabilities
settled
|
(1,602 | ) | ||
|
Accretion
expense
|
376 | |||
|
Revisions
to timing of estimated cash flows
|
(105 | ) | ||
|
Balance
as of December 31, 2009
|
$ | 5,392 |
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 such work in
some circumstances until it permanently ceases operations of the long-lived
assets. Because the Company considers the operational life of the
Refineries and certain other assets indeterminable, an associated asset
retirement obligation cannot be calculated at this time. The Company
has recorded an asset retirement obligation for the handling and disposal of
hazardous and non-hazardous substances that the Company is legally obligated to
incur in connection with maintaining and improving the Refineries and certain
other assets.
Foreign
currency transactions
The
Company has receivables and payables denominated in Canadian dollars from
certain crude oil purchases and related taxes on such
purchases. These amounts are accounted for in accordance with
generally accepted accounting principles on the Consolidated Balance Sheets by
translating the balances at the applicable exchange rates until they are
settled. The corresponding gain or loss is recognized in the
Consolidated Statements of Operations. For the years ended December
31, 2009, 2008 and 2007, the Company recognized a loss in “Other Revenues” of
$1.3 million, $457,000 and $0, respectively, due to the translation of its
foreign denominated assets and liabilities.
Principles
of Consolidation
The
Consolidated Financial Statements include the accounts of FOC and all 100% owned
subsidiaries, as well as the Company’s undivided interests in a crude oil
pipeline and crude oil tanks up until their sale in September 2007. The Company
utilizes the equity method of accounting for investments in entities in which it
does not have the ability to exercise control. Entities in which the
Company has the ability to exercise significant influence and control are
consolidated. All
intercompany transactions and balances are eliminated in
consolidation.
Use
of Estimates
The
preparation of financial statements in conformity with GAAP 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.
Subsequent
Events
The
Company has evaluated subsequent events through February 24, 2010.
Cash
Equivalents
Highly
liquid investments with maturity, when purchased, of three months or less are
considered to be cash equivalents. Cash equivalents were $424.3
million and $482.4 million at December 31, 2009 and 2008,
respectively.
Supplemental
Cash Flow Information
Cash
payments for interest, net of capitalized interest, during 2009, 2008 and 2007
were $21.7 million, $4.8 million and $5.5 million, respectively. Cash
payments for income taxes during 2009, 2008 and 2007 were $36.2 million, $59.7
million and $294.1 million, respectively. Cash refunds of income
taxes during 2009, 2008 and 2007 were $52.5 million, $24.9 million and none,
respectively. Noncash investing activities include accrued capital
expenditures of $17.1 million, $26.9 million and $27.1 million as of December
31, 2009, 2008 and 2007, respectively.
Related
Party Transactions
In
February 2010, subsequent to the balance sheet date, the Company made a
relocation-related loan to an officer of one of its subsidiaries in the amount
of $120,000 with a maximum term of one year.
New
Accounting Pronouncements
In
September 2006, the Financial Accounting Standards Board (“FASB”) issued
Accounting Standards Codification (“ASC”) 820, “Fair Value Measurements and
Disclosures.” ASC 820 defines fair value, establishes a framework for
measuring fair value and expands disclosure requirements regarding fair value
measurement. Where applicable, this statement simplifies and codifies
fair value related guidance previously issued within GAAP. ASC 820
was effective for financial statements issued for fiscal years beginning after
November 15, 2007, and interim periods within those fiscal years. The
Company was required to apply ASC 820 to non-recurring financial and
non-financial instruments effective January 1, 2009 in addition to all other
financial instruments. See Note 12 “Fair Value Measurement” for
related disclosures.
In March
2008, the FASB released additional disclosure requirements for derivative
instruments and hedging activities under ASC 815-10-50. ASC 815-10-50
disclosure provisions apply to all entities with derivative instruments subject
to current guidance under GAAP. The provisions also apply to related
hedged items, bifurcated derivatives, and nonderivative instruments that are
designated and qualify as hedging instruments. Entities with
instruments subject to ASC 815-10-50 must provide more robust qualitative
disclosures and expanded quantitative disclosures. The disclosure
requirements are effective for financial statements issued for fiscal years and
interim periods beginning after November 15, 2008; thus, the Company adopted ASC
815-10-50 on January 1, 2009. See Note 14 “Price and Interest Risk
Management Activities” for additional disclosures required under ASC
815-10-50.
In April
2009, the FASB issued ASC 820-10-65-4, “Determining Fair Value When the Volume
and Level of Activity for the Asset or Liability Have Significantly Decreased
and Identifying Transactions That Are Not Orderly.” This issuance by
the FASB provides additional guidance on determining whether a market for a
financial asset is not active and a transaction is not distressed for fair value
measurements under ASC 820, “Fair Value Measurements and
Disclosures.” The additional requirements were effective for interim
and annual periods ending after June 15, 2009. The adoption of these
requirements did not have a material impact on the Company’s financial
statements.
In April
2009, the FASB issued additional guidance under ASC 320-10-65-1, “Recognition
and Presentation of Other-Than-Temporary Impairments.” This guidance
amends the other-than-temporary impairment guidance in GAAP to make the guidance
more operational and to improve the presentation of other-than-temporary
impairments in the financial statements. To avoid considering an impairment to
be other than temporary, this guidance modifies the requirement that management
must assert that it has both the intent and the ability to hold an impaired
security for a period of time sufficient to allow for any anticipated recovery
in fair value. This guidance is effective for interim and annual
reporting periods ending after June 15, 2009. The adoption of this
new guidance did not have a material impact on the Company’s financial
statements.
In April
2009, the FASB issued additional guidance under ASC 825-10-65-1, “Interim
Disclosures about Fair Value of Financial Instruments.” This
additional guidance amends current fair value guidance within GAAP, to require
disclosures about the fair value of financial instruments in interim financial
statements as well as in annual financial statements. The new
guidance is effective for interim and annual reporting periods ending after June
15, 2009. The adoption of this guidance did not have a material
impact on the Company’s financial statements. See Note 12 “Fair Value
Measurement” for additional disclosures required under this
guidance.
In April
2009, the FASB issued additional guidance under ASC 805-20 to address concerns
about the application of current guidance to assets and liabilities arising from
contingencies in a business combination. The new guidance establishes
a model similar to the one entities used under current guidance to account for
pre-acquisition contingencies. This new guidance is effective for
business combinations whose acquisition date is at or after the beginning of the
first annual reporting period beginning on or after December 15,
2008. The adoption of this new guidance did not have a material
impact on the Company’s financial statements.
In May
2009, the FASB issued ASC 855, “Subsequent Events.” ASC 855 provides
guidance on management’s assessment of subsequent events. Companies
had historically relied upon U.S. auditing literature for guidance on assessing
and disclosing subsequent events. ASC 855 represents the inclusion of
guidance on subsequent events in the accounting literature and is directed
specifically to management. ASC 855 is not expected to significantly
change practice, but the new standard specifically clarifies that management
must evaluate, as of each reporting period, events or transactions that occur
after the balance sheet date “through the date that the financial statements are
issued or are available to be issued.” The statement is effective prospectively
for interim or annual financial periods ending after June 15,
2009. The Company’s adoption of ASC 855 did not have a material
impact on the Company’s financial statements.
In
December 2008, the FASB released ASC 715-20-65-2, “Employers' Disclosures about
Postretirement Benefit Plan Assets,” which amends current guidance in ASC
715-20, “Compensation-Retirement Benefits, Defined Benefit Plans,” to require
disclosure of additional information about assets held in a defined benefit
pension or other postretirement plan. Specifically, the additional disclosures
cover (1) investment policies and strategies, (2) categories of plan assets, (3)
fair value measurements of plan assets, and (4) significant concentrations of
risk. The additional disclosure requirements are effective for fiscal
years ending after December 15, 2009, with earlier application
permitted. The adoption of this new guidance did not have a material
impact on the Company’s financial statements.
In June
2009, the FASB issued ASC 105 “Generally Accepted Accounting Principles”
effectively establishing the Accounting Standards Codification as the source of
authoritative U.S. GAAP recognized by the FASB to be applied to rules and
interpretive releases of the SEC under federal securities laws as authoritative
GAAP for SEC registrants. The Codification, established as part of
ASC 105, supersedes existing FASB, American Institute of Certified Public
Accountants, Emerging Issues Task Force and related literature. All
guidance within the Codification has equal authority and all other accounting
literature is considered non-authoritative. ASC 105 was adopted by
the Company during the period ended September 30, 2009. The adoption
of ASC 105 changed the way the Company cites authoritative guidance within the
Company’s financial statements and accounting policies; however, the impact was
not material.
In August
2009, the FASB issued Accounting Standards Update (“ASU”) 2009-05 to provide
guidance on measuring the fair value of liabilities under ASC
820. This ASU clarifies that the quoted price for the identical
liability, when traded as an asset in the active market, is also a Level 1
measurement for that liability when no adjustment is made to the quoted
price. This ASU was effective immediately after its
release. The adoption of this ASU did not have a material impact on
the Company's financial statements or disclosures.
In
October 2009, the FASB issued ASU 2009-13 “Multiple-Deliverable Revenue
Arrangements”. This ASU addresses the unit of accounting for
arrangements involving multiple deliverables. It also addresses how
consideration should be allocated to the separate units of
accounting. This ASU retains previous criteria for when delivered
items in a multiple-deliverable arrangement should be considered separate units
of accounting; however, it removes the previous separation criterion under
previously issued guidance, that objective and reliable evidence of the fair
value of any undelivered items must exist for the delivered items to be
considered a separate unit or units of accounting. ASU 2009-13 is
effective for fiscal years beginning on or after June 15, 2010. The
Company is currently evaluating the potential impact of ASU 2009-13 on its
financial statements and disclosures.
|
3.
|
Change
in Accounting Principle – Inventory
|
During
the fourth quarter of 2009, the Company changed its inventory valuation method
for crude oil, unfinished products and finished products to the LIFO method from
the FIFO method as previously disclosed. All of the Company’s
other inventories will continue to be valued at the lower of average cost or
market. The Company believes the change to the LIFO method is
preferable because it will improve matching of current costs with revenues and
improve comparability with its industry peers.
The
Company has determined that it is impracticable to determine the cumulative
effect of applying this change for years prior to 2001 as the prior period
specific information necessary to value inventory under LIFO was
unavailable. Therefore, the Company has retrospectively adjusted the
consolidated financial statements for the change for all periods to the
beginning of 2001. As a result of the change in accounting principle,
retained earnings as of January 1, 2007 decreased from $719.8 million, as
originally reported under the FIFO method, to $658.6 million under the LIFO
method. The following consolidated financial statement line items as
of December 31, 2009 and 2008 and for the years ended December 31, 2009, 2008
and 2007 were affected by the change in accounting principle. For
2009, the FIFO numbers are calculated and presented assuming the Company had not
adopted the LIFO method.
|
Year
Ended December 31, 2009
|
||||||||||||
|
As
Computed under FIFO
|
As
Reported under LIFO
|
Change
|
||||||||||
|
(in
thousands - except per share data )
|
||||||||||||
|
Consolidated
Statement of Operations:
|
||||||||||||
|
Raw
material, freight and other costs
|
$ | 3,635,298 | $ | 3,888,308 | $ | 253,010 | ||||||
|
Operating
income (loss)
|
147,640 | (105,370 | ) | (253,010 | ) | |||||||
|
Income
(loss) before income taxes
|
121,732 | (131,278 | ) | (253,010 | ) | |||||||
|
Provision
(benefit) for income taxes
|
46,237 | (47,518 | ) | (93,755 | ) | |||||||
|
Net
income (loss)
|
$ | 75,495 | $ | (83,760 | ) | $ | (159,255 | ) | ||||
|
Basic
earnings (loss) per share
|
$ | 0.73 | $ | (0.81 | ) | $ | (1.54 | ) | ||||
|
Diluted
earnings (loss) per share
|
$ | 0.72 | $ | (0.81 | ) | $ | (1.53 | ) | ||||
|
Consolidated
Statement of Cash Flows:
|
||||||||||||
|
Net
income (loss)
|
$ | 75,495 | $ | (83,760 | ) | $ | 159,255 | |||||
|
Adjustments
to reconcile net income to net income from
operating activities:
|
||||||||||||
|
Deferred
income taxes
|
39,326 | 31,082 | 8,244 | |||||||||
|
Changes
in components of working capital from operations:
|
||||||||||||
|
Decrease
(increase) in trade, income taxes and
other receivables
|
29,470 | (56,041 | ) | 85,511 | ||||||||
|
Decrease
(increase) in inventory
|
(309,981 | ) | (56,971 | ) | (253,010 | ) | ||||||
|
Net
cash provided by operating activities
|
$ | 140,942 | $ | 140,942 | $ | - | ||||||
|
Years
Ended December 31,
|
||||||||||||||||||||||||
|
2008
|
2007
|
|||||||||||||||||||||||
|
As
Originally
Reported
|
As
Adjusted
|
Change
|
As
Originally
Reported
|
As
Adjusted
|
Change
|
|||||||||||||||||||
|
(in
thousands - except per share data)
|
||||||||||||||||||||||||
|
Consolidated
Statements of Operations:
|
||||||||||||||||||||||||
|
Raw
material, freight and other costs
|
$ | 5,950,782 | $ | 5,716,091 | $ | (234,691 | ) | $ | 4,039,235 | $ | 4,194,971 | $ | 155,736 | |||||||||||
|
Operating
income
|
116,753 | 351,444 | 234,691 | 755,795 | 600,059 | (155,736 | ) | |||||||||||||||||
|
Income
before income taxes
|
107,048 | 341,739 | 234,691 | 768,873 | 613,137 | (155,736 | ) | |||||||||||||||||
|
Provision
for income taxes
|
26,814 | 115,686 | 88,872 | 269,748 | 210,805 | (58,943 | ) | |||||||||||||||||
|
Net
income
|
$ | 80,234 | $ | 226,053 | $ | 145,819 | $ | 499,125 | $ | 402,332 | $ | (96,793 | ) | |||||||||||
|
Basic
earnings per share
|
$ | 0.78 | $ | 2.19 | $ | 1.41 | $ | 4.67 | $ | 3.77 | $ | (0.90 | ) | |||||||||||
|
Diluted
earnings per share
|
$ | 0.77 | $ | 2.18 | $ | 1.41 | $ | 4.62 | $ | 3.73 | $ | (0.89 | ) | |||||||||||
|
Consolidated
Statements of Cash Flows:
|
`
|
|||||||||||||||||||||||
|
Net
income
|
$ | 80,234 | $ | 226,053 | $ | 145,819 | $ | 499,125 | $ | 402,332 | $ | (96,793 | ) | |||||||||||
|
Adjustments
to reconcile net income
to net income from
operating
activities:
|
||||||||||||||||||||||||
|
Deferred
income taxes
|
80,894 | 169,766 | 88,872 | (1,916 | ) | (60,859 | ) | (58,943 | ) | |||||||||||||||
|
Changes
in componenets of working
capital from operations:
|
||||||||||||||||||||||||
|
Decrease
(increase) in inventory
|
245,798 | 11,107 | (234,691 | ) | (127,351 | ) | 28,385 | 155,736 | ||||||||||||||||
|
Net
cash provided by operating
activities
|
$ | 297,275 | $ | 297,275 | $ | - | $ | 429,013 | $ | 429,013 | $ | - | ||||||||||||
|
December
31, 2009
|
December
31, 2008
|
|||||||||||||||||||||||
|
As
Computed under FIFO
|
As
Reported under LIFO
|
Change
|
As
Originally
Reported
|
As
Adjusted
|
Change
|
|||||||||||||||||||
|
(in
thousands)
|
||||||||||||||||||||||||
|
Consolidated
Balance Sheet:
|
||||||||||||||||||||||||
|
Income
taxes receivable
|
$ | 89,116 | $ | 174,627 | $ | 85,511 | $ | 116,118 | $ | 116,118 | $ | - | ||||||||||||
|
Inventory
of crude oil, products and
other
|
566,110 | 293,476 | (272,634 | ) | 256,129 | 236,505 | (19,624 | ) | ||||||||||||||||
|
Deferred
income tax assets - current
|
18,464 | 26,373 | 7,909 | 8,841 | 16,301 | 7,460 | ||||||||||||||||||
|
Total
current assets
|
$ | 1,216,580 | $ | 1,037,366 | $ | (179,214 | ) | $ | 1,017,303 | $ | 1,005,139 | $ | (12,164 | ) | ||||||||||
|
Deferred
income tax assets - long-term
|
- | 10,767 | 10,767 | - | - | - | ||||||||||||||||||
|
Total
assets
|
$ | 2,316,342 | $ | 2,147,895 | $ | (168,447 | ) | $ | 2,018,469 | $ | 2,006,305 | $ | (12,164 | ) | ||||||||||
|
Deferred
income tax liabilities
|
$ | 227,846 | $ | 230,818 | 2,972 | $ | 179,214 | $ | 179,214 | - | ||||||||||||||
|
Retained
earnings
|
$ | 1,201,622 | $ | 1,030,203 | $ | (171,419 | ) | $ | 1,151,676 | $ | 1,139,512 | $ | (12,164 | ) | ||||||||||
|
Total
liabilities and shareholders'
equity
|
$ | 2,316,342 | $ | 2,147,895 | $ | (168,447 | ) | $ | 2,018,469 | $ | 2,006,305 | $ | (12,164 | ) | ||||||||||
|
4.
|
Other
Receivables
|
|
December
31,
|
||||||||
|
2009
|
2008
|
|||||||
|
(in
thousands)
|
||||||||
|
Investment
fund receivable, net of allowance
|
$ | 2,143 | $ | 6,418 | ||||
|
Realized
futures trading receivable
|
2,341 | 11,854 | ||||||
|
Other
|
3,358 | 6,944 | ||||||
| $ | 7,842 | $ | 25,216 | |||||
The
Company had a $32.7 million money market investment in a money market fund
called the Reserve Primary Fund (“Fund”) that was deemed illiquid in September
2008. The Fund is currently overseen by the SEC, which is determining
the amount and timing of liquidation. Prior to the freeze on the
Fund’s assets, the Company requested its funds in their entirety and reclassed
the $32.7 million investment out of “Cash and cash equivalents” to “Other
receivables” on the Consolidated Balance Sheet. It is currently
estimated that approximately 1.5% of the Company’s original investment is
at-risk for recoverability, primarily due to the bankruptcy of Lehman Brothers,
as the Fund had an investment in Lehman Brothers Holdings, Inc. commercial
paper. Therefore, an allowance of $499,000 was recorded as of
December 31, 2009 and 2008. In addition, the Company received partial
distributions through December 31, 2009 from the Fund totaling $30.1 million,
resulting in a net investment fund receivable of $2.1 million. In
February 2010, subsequent to the balance sheet date, the Company received
another $2.2 million partial distribution, increasing its total distributions to
$32.2 million, leaving no net remaining investment fund
receivable. Any distributions received in excess of our net
receivable will be recorded into subsequent periods as income.
|
5.
|
Other
Current Assets
|
|
December
31,
|
||||||||
|
2009
|
2008
|
|||||||
|
(in
thousands)
|
||||||||
|
Margin
deposits
|
$ | 10,898 | $ | 18,323 | ||||
|
Derivative
assets
|
124 | 8,584 | ||||||
|
Prepaid
insurance
|
1,705 | 8,374 | ||||||
|
Other
|
1,780 | 1,757 | ||||||
| $ | 14,507 | $ | 37,038 | |||||
|
6.
|
Accrued
Liabilities and Other
|
|
December
31,
|
||||||||
|
2009
|
2008
|
|||||||
|
(in
thousands)
|
||||||||
|
Accrued
compensation
|
$ | 26,093 | $ | 12,606 | ||||
|
Accrued
Beverly Hills litigation settlement
|
- | 10,000 | ||||||
|
Accrued
environmental costs
|
7,599 | 10,040 | ||||||
|
Accrued
dividends
|
6,979 | 6,779 | ||||||
|
Accrued
property taxes
|
5,573 | 5,295 | ||||||
|
Accrued
interest
|
7,638 | 7,363 | ||||||
|
Derivative
liabilities
|
6,551 | - | ||||||
|
Accrued
income taxes
|
293 | 326 | ||||||
|
Other
|
4,073 | 4,675 | ||||||
| $ | 64,799 | $ | 57,084 | |||||
|
7.
|
Long-term
Debt
|
|
December
31,
|
||||||||
|
2009
|
2008
|
|||||||
|
(in
thousands)
|
||||||||
|
6.625%
Senior Notes (Due October 1, 2011)
|
$ | 150,000 | $ | 150,000 | ||||
|
8.5%
Senior Notes (Due September 15, 2016)
|
200,000 | 200,000 | ||||||
|
Less
discount
|
(2,515 | ) | (2,780 | ) | ||||
|
8.5%
Senior Notes, net
|
197,485 | 197,220 | ||||||
| $ | 347,485 | $ | 347,220 | |||||
In
September 2008, the Company issued $200.0 million aggregate principal amount of
8.5% Senior Notes. The 8.5% Senior Notes, which mature on September
15, 2016, were issued at a 1.42% discount ($2.8 million) resulting in total
Senior Notes, net of discount, of $197.2 million. The Company
received net proceeds (after underwriting fees) of $195.3
million. Interest is paid semi-annually on March 15 and September
15. The 8.5% Senior Notes are redeemable, at the option of the
Company, at 104.25% after September 15, 2012, declining to 100.00% in
2014. Prior to September 15, 2012, the Company may at its option
redeem the 8.5% Senior Notes at a make-whole price comprised of 104.25% of the
principal amount plus a make-whole amount. The make-whole amount is the excess,
if any, of the present value of the remaining interest and principal payments
due on the 8.5% Senior Notes as if such notes were redeemed on September 15,
2012 computed using a discount rate equal to the Treasury Rate plus 50 basis
points, over the principal amount of the notes. The 8.5% Senior Notes
may restrict payments, including dividends, and limit the incurrence of
additional indebtedness based on covenants related to interest coverage and
restricted payments. Frontier Holdings Inc. and its material
subsidiaries are full and unconditional guarantors of the 8.5% Senior Notes (see
Note 15 “Consolidating Financial Statements”).
In
October 2004, the Company issued $150.0 million principal amount of 6.625%
Senior Notes. The 6.625% 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 (see also Note 13
“Price and Interest Risk Management Activities”). The 6.625% Senior
Notes are redeemable, at the option of the Company, at 101.104% through
September 30, 2010 and at 100% thereafter. The 6.625% Senior Notes
may restrict payments, including dividends, and limit the incurrence of
additional indebtedness based on covenants related to interest coverage and
restricted payments. Frontier Holdings Inc. and its subsidiaries are
full and unconditional guarantors of the 6.625% Senior Notes (see Note 15
“Consolidating Financial Statements”).
|
8.
|
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, collateralized by inventory, accounts receivable and related contracts
and intangibles, and certain deposit accounts, provides working capital
financing for operations, generally the financing of crude oil and product
supply. The Facility matures in August 2012. The maximum
amount available under this agreement is $500 million and has a margin at a
range from 1.5% to 2% plus the base rate or LIBOR rate, as
applicable. The Facility provides for a quarterly commitment fee from
0.30% to .375% per annum plus standard issuance and renewal fees. No
funds were borrowed at any time during 2009 under the Facility, and thus the
Company did not incur any interest expense under the Facility in
2009. The Company had average daily borrowings of $4.8 million during
2008 under the Facility, with interest expense incurred of $193,000 at an
average interest rate of 4.041%. The Facility is subject to
compliance with financial covenants relating to cash coverage, debt leverage and
current ratios and permitted consolidated long-term funded
indebtedness. The Company was in compliance with these covenants at
December 31, 2009. No borrowings were outstanding at December 31,
2009 or 2008, under the Facility. Standby letters of credit
outstanding were $53.0 million and $12.5 million at December 31, 2009 and 2008,
respectively. As of December 31, 2009, the Company had borrowing base
availability of $399.4 million under the Facility.
The
Facility restricts payments to FOC from its subsidiaries and thus, as required
by Regulation 210.5-04 of Regulation S-X of the Securities Exchange Act of 1934,
as amended, the Condensed Financial Information of FOC is included in Schedule I
of this Form 10-K.
|
9.
|
Income
Taxes
|
The
provision (benefit) for income taxes is comprised of the following:
|
Years
ended December 31,
|
||||||||||||
|
2009
|
2008
As
Adjusted
(Note
3)
|
2007 As
Adjusted
(Note
3)
|
||||||||||
|
(in
thousands)
|
||||||||||||
|
Current:
|
||||||||||||
|
Federal
|
$ | (78,177 | ) | $ | (51,136 | ) | $ | 238,555 | ||||
|
State
|
(423 | ) | (2,944 | ) | 33,109 | |||||||
|
Total
current provision (benefit)
|
(78,600 | ) | (54,080 | ) | 271,664 | |||||||
|
Deferred:
|
||||||||||||
|
Federal
|
40,332 | 174,437 | (53,685 | ) | ||||||||
|
State
|
(9,250 | ) | (4,671 | ) | (7,174 | ) | ||||||
|
Total
deferred provision (benefit)
|
31,082 | 169,766 | (60,859 | ) | ||||||||
|
Total
provision (benefit)
|
$ | (47,518 | ) | $ | 115,686 | $ | 210,805 | |||||
The
following is a reconciliation of the provision (benefit) for income taxes
computed at the statutory United States income tax rates on pretax income and
the provision (benefit) for income taxes as reported:
|
Years
ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
(in
thousands)
|
||||||||||||
|
Provision
(benefit) based on statutory rates
|
$ | (45,947 | ) | $ | 119,609 | $ | 214,598 | |||||
|
Increase
(decrease) resulting from:
|
||||||||||||
|
State
income tax provision (benefit)
|
(9,673 | ) | (7,615 | ) | 25,935 | |||||||
|
Federal
tax effect of state income taxes
|
3,385 | 2,666 | (9,077 | ) | ||||||||
|
Federal
tax contingency reversals and adjustments
|
- | (2,856 | ) | - | ||||||||
|
Increase
(benefit) from the Section 199 manufacturers
deduction
|
838 | 3,052 | (15,387 | ) | ||||||||
|
Benefit
of ultra-low sulfur diesel tax credit
|
- | - | (5,525 | ) | ||||||||
|
Other,
including permanent book-tax differences
|
3,879 | 830 | 261 | |||||||||
|
Provision
(benefit) as reported
|
$ | (47,518 | ) | $ | 115,686 | $ | 210,805 | |||||
Significant
components of deferred tax assets and liabilities are shown below:
|
December
31, 2009
|
December
31, 2008
As
Adjusted (Note 3)
|
||||||||||||||||||||||
|
State
|
Federal
|
Total
|
State
|
Federal
|
Total
|
||||||||||||||||||
|
(in
thousands)
|
|||||||||||||||||||||||
|
Current
deferred tax assets:
|
|||||||||||||||||||||||
|
Gross
current assets:
|
|||||||||||||||||||||||
|
Inventory
differences
|
$ | 996 | $ | 7,261 | $ | 8,257 | $ | 910 | $ | 6,868 | $ | 7,778 | |||||||||||
|
Accrued
bonuses
|
917 | 6,685 | 7,602 | 292 | 2,203 | 2,495 | |||||||||||||||||
|
Stock-based
compensation
|
1,053 | 7,681 | 8,734 | 932 | 7,035 | 7,967 | |||||||||||||||||
|
Accrued
legal settlement
|
- | - | - | 293 | 2,212 | 2,505 | |||||||||||||||||
|
Environmental
liability accruals
|
359 | 2,620 | 2,979 | 337 | 2,546 | 2,883 | |||||||||||||||||
|
State
net operating losses
|
- | - | - | 4,034 | - | 4,034 | |||||||||||||||||
|
Kansas
income tax credits
|
304 | - | 304 | 2,332 | - | 2,332 | |||||||||||||||||
|
Unrealized
loss on derivative contracts
|
308 | 2,250 | 2,558 | - | - | - | |||||||||||||||||
|
Current
state income tax liabilities
|
- | 85 | 85 | - | 97 | 97 | |||||||||||||||||
|
Other
|
207 | 1,512 | 1,719 | 198 | 1,491 | 1,689 | |||||||||||||||||
|
Total
gross current assets
|
4,144 | 28,094 | 32,238 | 9,328 | 22,452 | 31,780 | |||||||||||||||||
|
Gross
current liabilities:
|
|||||||||||||||||||||||
|
Prepaid
expenses and other
|
(94 | ) | (685 | ) | (779 | ) | (418 | ) | (3,153 | ) | (3,571 | ) | |||||||||||
|
State
income tax receivables
|
- | (3,669 | ) | (3,669 | ) | - | (5,527 | ) | (5,527 | ) | |||||||||||||
|
State
deferred taxes
|
- | (1,417 | ) | (1,417 | ) | - | (2,979 | ) | (2,979 | ) | |||||||||||||
|
Unrealized
gain on derivative contracts
|
- | - | - | (398 | ) | (3,004 | ) | (3,402 | ) | ||||||||||||||
|
Total
gross current liabilities
|
(94 | ) | (5,771 | ) | (5,865 | ) | (816 | ) | (14,663 | ) | (15,479 | ) | |||||||||||
|
Total
current net deferred tax
assets
|
$ | 4,050 | $ | 22,323 | $ | 26,373 | $ | 8,512 | $ | 7,789 | $ | 16,301 | |||||||||||
|
Long-term
deferred tax liabilities:
|
|||||||||||||||||||||||
|
Gross
long-term assets:
|
|||||||||||||||||||||||
|
Pension
and other post-retirement
benefits
|
$ | 1,590 | $ | 11,598 | $ | 13,188 | $ | 1,446 | $ | 10,906 | $ | 12,352 | |||||||||||
|
Interest
on contingent income
taxes
|
305 | 2,223 | 2,528 | 216 | 1,628 | 1,844 | |||||||||||||||||
|
Environmental
liability accruals
|
188 | 1,374 | 1,562 | 211 | 1,593 | 1,804 | |||||||||||||||||
|
Asset
retirement obligations
|
215 | 1,566 | 1,781 | 214 | 1,617 | 1,831 | |||||||||||||||||
|
Kansas
income tax credits
|
27,356 | - | 27,356 | 20,556 | - | 20,556 | |||||||||||||||||
|
State
net operating losses
|
14,600 | - | 14,600 | - | - | - | |||||||||||||||||
|
Other
|
176 | 1,846 | 2,022 | 131 | 1,561 | 1,692 | |||||||||||||||||
|
State
deferred taxes
|
- | - | - | - | 1,045 | 1,045 | |||||||||||||||||
|
Total
gross long-term assets
|
44,430 | 18,607 | 63,037 | 22,774 | 18,350 | 41,124 | |||||||||||||||||
|
Gross
long-term liabilities
|
|||||||||||||||||||||||
|
Depreciation
|
(30,959 | ) | (225,933 | ) | (256,892 | ) | (23,558 | ) | (177,964 | ) | (201,522 | ) | |||||||||||
|
Deferred
turnaround costs
|
(2,704 | ) | (19,724 | ) | (22,428 | ) | (2,203 | ) | (16,613 | ) | (18,816 | ) | |||||||||||
|
State
deferred taxes
|
- | (3,768 | ) | (3,768 | ) | - | - | - | |||||||||||||||
|
Total
long-term net deferred tax
assets (liabilities)
|
$ | 10,767 | $ | (230,818 | ) | $ | (220,051 | ) | $ | (2,987 | ) | $ | (176,227 | ) | $ | (179,214 | ) | ||||||
As of
December 31, 2009, the Company had federal income taxes receivable of $164.1
million and state income taxes receivable of $10.5 million, which are included
in “Income taxes receivable” on the Consolidated Balance Sheet. The
federal income tax receivable results from the Company having a taxable loss for
the year ended December 31, 2009, which will enable the Company to receive a
refund for all of its 2009 estimated income tax payments of $36.0 million as
well as a carryback of the net operating loss (“NOL”) generated in 2009 to claim
an additional estimated $74.5 million tax refund from prior
years. The Company also has a refund receivable of $35.3 million for
an amended 2006 return filed which carried back the NOL generated in
2008. In addition, the Company has a refund receivable for the $18.4
million overpayment on its federal income tax return for the year ended December
31, 2007.
The
Company recognized the benefits of $4.5 million and $23.3 million, in 2009 and
2008, respectively for Kansas income tax credits related to expansion projects
completed in the years 2006 through 2009 at its El Dorado
Refinery. Of these $27.8 million Kansas income tax credits, the
Company has taken $217,000 on the Company’s amended 2006 Kansas income tax
return and $217,000 on the Company’s 2007 Kansas income tax return, both filed
in 2008. The remaining $27.4 million of Kansas income tax credits
(reflected as deferred tax assets as of December 31, 2009), are scheduled to be
taken over the years 2010 thru 2018. The income tax provision for the
year ended December 31, 2007 was reduced $5.5 million because of an $8.5 million
credit for production of ultra low sulfur diesel fuel (see “Environmental” under
Note 13 “Commitments and Contingencies”).
The
Company generated an estimated federal NOL in 2009 of $218.4 million which, as
indicated above, the Company plans to carryback, enabling it to receive a refund
of taxes paid in prior years. The Company generated a federal NOL in
2008 of $103.9 million, for which, as indicated above, the Company has filed the
necessary return to carryback this NOL, and has a receivable for a refund of
taxes paid in prior years. As of December 31, 2009, the Company also
has estimated state net operating losses generated in 2009 and 2008 of
approximately $155.8 million in Kansas, $54.6 million in Colorado and $13.0
million in Nebraska, which will be carried forward to reduce income taxes
payable in future years.
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 as of December 31, 2009 and 2008.
During
2009, the Company recognized a net decrease in previously recognized income tax
benefits related to the deductibility of stock-based compensation, net of
contingencies, in the amount of $2.9 million. The Company recognized
income tax benefits related to the deductibility of stock-based compensation,
net of contingencies, in the amounts of $5.3 million and $6.4 million for the
years ended December 31, 2008 and 2007, respectively. Such benefits
(or decrease in benefits) were recorded as an increase (decrease) in additional
paid-in capital, a reduction of income taxes payable (or decrease in income
taxes receivable) and an increase or decrease in “Contingent income tax
liabilities.” The Company also recognized an income tax (asset)
liability related to the minimum defined benefit liability reflected in
“Accumulated other comprehensive income (loss)” in the amounts of ($317,000),
($1.4 million) and $805,000 for the years ended December 31, 2009, 2008 and
2007, respectively.
The
Company is currently under a U.S. Federal income tax examination for 2007, 2006
and 2005. The Company has received a Notice of Proposed Adjustment
(“NOPA”) from the Internal Revenue service for approximately $14.4 million of
2005 taxes and approximately $4.7 million of 2006 taxes both related to the
deductibility for income tax purposes of certain stock-based compensation for
executives. The Company has submitted a protest of these
amounts and is in the appeals process. As discussed below, the
Company has provided income tax contingencies for these amounts in the event it
is unsuccessful in its appeal.
The
Company adopted GAAP guidance related to income tax contingencies on January 1,
2007. The Company reviewed all open tax years for all jurisdictions,
primarily U.S. Federal and the states of Kansas, Colorado and Nebraska for the
years 2003 through 2006. As a result of the implementation of the new
rules, the Company recognized approximately a $940,000 increase in the liability
for unrecognized tax benefits and $76,000 in accrued interest, which were
accounted for as reductions to the January 1, 2007 balance of retained
earnings. A reconciliation of the beginning and ending amount of
unrecognized tax benefits, excluding accrued interest and the federal income tax
benefit of state contingencies, for the years ended December 31, 2009, 2008 and
2007 is as follows (in thousands):
|
Years
ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
Balance
beginning of year
|
$ | 24,278 | $ | 28,324 | $ | 27,710 | ||||||
|
Additions
based on tax positions related to the current year
|
- | 521 | 692 | |||||||||
|
Additions
for tax positions of prior years
|
- | 1,294 | - | |||||||||
|
Reductions
for tax positions of prior years
|
(424 | ) | (120 | ) | - | |||||||
|
Settlements
|
- | - | - | |||||||||
|
Reductions
due to lapse of applicable statutes of limitations
|
- | (5,741 | ) | (78 | ) | |||||||
|
Balance
end of year
|
$ | 23,854 | $ | 24,278 | $ | 28,324 | ||||||
The
Company recognizes penalties and interest accrued related to unrecognized tax
benefits in “Interest expense and other financing costs” on the Consolidated
Statements of Operations. During the years ended December 31, 2009,
2008 and 2007, the Company recognized approximately $1.7 million, $530,000 (net
of reversals of $1.2 million), and $2.4 million, respectively, of interest
expense on contingent income tax liabilities. During the years ended December
31, 2009, 2008 and 2007, the Company recorded $1,000, $52,000 and $59,000,
respectively, in tax penalties. The Company had approximately $6.4
million and $4.7 million in accrued interest on income tax contingencies at
December 31, 2009 and 2008, respectively.
The total
contingent income tax liabilities and accrued interest of $29.3 million and
$28.1 million are reflected in the Consolidated Balance Sheet at December 31,
2009 and 2008 in “Contingent income tax liabilities.” These
contingencies relate to the deductibility for income tax purposes of certain
stock-based compensation for executives and the treatment of certain items for
state income tax purposes. The Company has no tax positions for which
the ultimate deductibility is highly certain but for which there is uncertainty
about the timing of such deductibility. Total unrecognized tax
benefits at December 31, 2009 that, if recognized, would affect the effective
tax rate were $1.6 million.
The
regular statutes of limitations for contingencies related to the Company’s 2004
and 2005 income tax returns (totaling $20.9 million, including accrued interest,
as of December 31, 2009) would normally have expired in the third and fourth
quarters of 2009; however, the statute of limitations for the Company’s 2005
federal return has been extended to October 2010 only as it relates to the
issues in question under the NOPA to allow for the appeals process discussed
above. The related state income tax statutes of limitations are
considered also to be automatically extended. These contingencies primarily
relate to the deductibility for income tax purposes of certain stock-based
compensation for executives. The statute of limitations for
contingencies related to certain of the Company’s 2005 and 2006 income tax
returns (totaling $6.2 million, included accrued interest as of December 31,
2009) will currently expire in the third and fourth quarters of
2010.
As of
December 31, 2009, the Company is generally open to examination in the United
States and various individual states for tax years ended December 31, 2006
through December 31, 2009.
|
10.
|
Common
Stock
|
Dividends
The
Company declared a quarterly cash dividend of $0.06 per share of common stock
for the quarters ended March 31, 2009 through December 31, 2009.
All
outstanding common shareholders at the declaration date are eligible to
participate in dividends. 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 6.625% and
8.5% Senior Notes may restrict dividend payments based on covenants related to
interest coverage and a restricted payments calculation. As of
December 31, 2009, the Company had no availability for declaring dividends under
the 6.625% and 8.5% Senior Notes restricted payments covenants.
Treasury
stock
The
Company accounts for its treasury stock under the cost method on a FIFO
basis. Through December 31, 2009, the Company’s Board of Directors
has approved a total of $400.0 million for share repurchases, of which $299.8
million has been utilized (none in 2009), leaving remaining authorization of
$100.2 million for future repurchases of shares. A rollforward of
treasury stock for the year ended December 31, 2009 is as follows:
|
Number
of shares
|
Amount
|
|||||||
|
(in
thousands except share amounts)
|
||||||||
|
Balance
as of December 31, 2008
|
27,945,884 | $ | 393,732 | |||||
|
Shares
received to fund withholding taxes
|
220,339 | 3,008 | ||||||
|
Shares
issued for stock option exercises
|
(15,000 | ) | (20 | ) | ||||
|
Shares
issued for restricted stock unit vestings
|
(52,560 | ) | (96 | ) | ||||
|
Shares
issued for restricted stock grants, net of forfeits
|
(690,594 | ) | (1,037 | ) | ||||
|
Shares
issued for conversion of stock unit awards
|
(242,669 | ) | (345 | ) | ||||
|
Balance
as of December 31, 2009
|
27,165,400 | $ | 395,242 | |||||
Earnings
per Share
The
following sets forth the computation of diluted earnings per share (“EPS”) for
the years ended December 31, 2009, 2008 and 2007.
|
2009
|
2008
As Adjusted
|
2007
As Adjusted
|
||||||||||||||||||||||||||
|
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 (loss)
|
$ | (83,760 | ) | 103,597 | $ | (0.81 | ) | $ | 226,053 | 103,139 | $ | 2.19 | $ | 402,332 | 106,804 | $ | 3.77 | |||||||||||
|
Dilutive
securities:
|
||||||||||||||||||||||||||||
|
Stock
options
|
- | 40 | 291 | |||||||||||||||||||||||||
|
Restricted
stock and stock unit awards
|
- | 428 | 875 | |||||||||||||||||||||||||
|
Diluted
EPS:
|
||||||||||||||||||||||||||||
|
Net
income (loss)
|
$ | (83,760 | ) | 103,597 | $ | (0.81 | ) | $ | 226,053 | 103,607 | $ | 2.18 | $ | 402,332 | 107,970 | $ | 3.73 | |||||||||||
For the
years ended December 31, 2009 and 2008, 434,793 and 449,591 outstanding stock
options that could potentially dilute EPS in future years were not included in
the computation of diluted EPS as they were anti-dilutive. In
addition, for the year ended December 31, 2009, there were 1.2 million
outstanding restricted stock and stock unit awards that could potentially dilute
EPS in future years that were not included in the computation of diluted EPS as
they were anti-dilutive due to the Company’s net loss. For the year
ended December 31, 2007, there were no outstanding stock options that could
potentially dilute EPS in future years that were not included in the computation
of diluted EPS.
Stock-based
Compensation
Stock-based
compensation costs and income tax benefits recognized in the Consolidated
Statements of Operations for the years ended December 31, 2009, 2008 and 2007
are as follows:
|
Years
Ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
(in
thousands)
|
||||||||||||
|
Restricted
shares and units
|
$ | 16,038 | $ | 12,233 | $ | 12,856 | ||||||
|
Stock
options
|
304 | 1,004 | 1,515 | |||||||||
|
Contingently
issuable stock unit awards
|
4,266 | 6,777 | 8,182 | |||||||||
|
Total
stock-based compensation expense
|
$ | 20,608 | $ | 20,014 | $ | 22,553 | ||||||
|
Income
tax benefit recognized in the income statement
|
$ | 7,831 | $ | 6,730 | $ | 8,570 | ||||||
Omnibus Incentive Compensation
Plan. The Company’s Omnibus Incentive Compensation Plan (the
“Plan”) is a broad-based incentive plan that provides for granting stock
options, stock appreciation rights (“SAR”), restricted stock awards, performance
awards, stock units, bonus shares, dividend equivalent rights, other stock-based
awards and substitute awards (“Awards”) to employees, consultants and
non-employee directors of the Company. The maximum number of
shares of the Company’s common stock that may be issued under the Plan with
respect to Awards is 12,000,000 shares, subject to certain adjustments as
provided by the Plan. The number of shares available for Awards will
be reduced by 1.7 times the number of shares for each stock-denominated award
granted, other than an option or a SAR under the Plan, and will be reduced by
1.0 times the number of option shares or SARs granted. As of December
31, 2009, 2,283,313 shares were available to be awarded under the Plan assuming
maximum payout is achieved on the contingently issuable awards made in 2008 and
2009 and an estimated achieved performance level on the 2007 contingently
issuable awards (see “Contingently Issuable Awards” below). For
purposes of determining compensation expense, forfeitures are estimated at the
time Awards are granted based on historical average forfeiture rates and the
group of individuals receiving those Awards. The Plan provides that
the source of shares for Awards may be either newly issued shares or treasury
shares. For the year ended December 31, 2009, treasury shares were
re-issued for stock awards, restricted stock awards and for shares issued due to
the exercise of stock options. The Company does not plan to
repurchase additional treasury shares in 2010 strictly for issuing share Awards;
however, treasury shares that are repurchased or are currently in treasury may
be issued as share Awards in 2010. As of December 31, 2009, there was
$19.6 million of total unrecognized compensation cost related to the Plan
including costs for restricted stock and performance-based awards, which is
expected to be recognized over a weighted-average period of 1.88
years.
Stock
Options. Stock options are issued at the current market price
of the Company’s common stock on the date of grant and generally vest ratably
over three years and expire after five years. The grant date fair
value is calculated using the Black-Scholes option pricing model. The
Company uses historical employee exercise data, including post-vesting
termination behavior, to estimate the expected life of the
options. Expected volatility is calculated using the historical
volatility of the price of the Company’s common stock. The risk-free
interest rate is based on the U.S. Treasury yield curve in effect at the time of
the grant. No stock options were granted during the years ended
December 31, 2009, 2008 or 2007.
For the
fully vested stock options granted in 2006 when common stock dividends are
declared by the Company’s Board of Directors, dividend equivalents will be paid
concurrently with common stock dividends until the options are exercised or
expire.
Stock
option changes during the years ended December 31, 2009, 2008 and 2007 are
presented below:
|
2009
|
2008
|
2007
|
||||||||||||||||||||||||||
|
Number
of
awards
|
Weighted-
Average
Exercise
Price
|
Aggregate
Intrinsic
Value
of
Options
(in
thousands)
|
Number
of
awards
|
Weighted-
Average
Exercise
Price
|
Number
of
awards
|
Weighted-
Average
Exercise
Price
|
||||||||||||||||||||||
|
Outstanding
at beginning
of year
|
464,591 | $ | 28.5868 | 624,591 | $ | 22.4021 | 1,032,126 | $ | 16.3104 | |||||||||||||||||||
|
Granted
|
- | - | - | - | - | - | ||||||||||||||||||||||
|
Exercised
or issued
|
(15,000 | ) | 4.6625 | (160,000 | ) | 4.4438 | (396,761 | ) | 6.3655 | |||||||||||||||||||
|
Expired
or forfeited
|
(14,798 | ) | 29.3850 | - | - | (10,774 | ) | 29.3850 | ||||||||||||||||||||
|
Outstanding
at end of
year
|
434,793 | $ | 29.3850 | $ | - | 464,591 | $ | 28.5868 | 624,591 | $ | 22.4021 | |||||||||||||||||
|
Vested
or expected to vest
at end of year
|
434,793 | $ | 29.3850 | $ | - | 462,489 | $ | 28.5832 | 613,672 | $ | 22.2779 | |||||||||||||||||
|
Exercisable
at end of period
|
434,793 | $ | 29.3850 | $ | - | 235,039 | $ | 27.8072 | 280,249 | $ | 13.8223 | |||||||||||||||||
|
Weighted-average fair
value of
options
granted
during
the year
|
n/a | n/a | n/a | |||||||||||||||||||||||||
The
Company received $70,000, $405,000 and $2.3 million of cash for stock options
exercised during the years ended December 31, 2009, 2008 and 2007,
respectively. The total intrinsic value of stock options exercised
during the years ended December 31, 2009, 2008 and 2007 was $160,000, $3.7
million and $13.6 million, respectively. The Company realized
$61,000, $1.4 million and $5.1 million of income tax benefits, nearly all of
which was excess income tax benefit, during the years ended December 31, 2009,
2008 and 2007, respectively, related to the exercises of stock
options. Excess income tax benefits are the benefits from deductions
that are allowed for income tax purposes in excess of expenses recorded in the
Company’s financial statements. These excess income tax benefits are
recorded as an increase to paid-in capital, and the majority of these amounts
are reflected as cash flows from financing activities in the Consolidated
Statements of Cash Flows. All outstanding stock options were vested
and exercisable at December 31, 2009 with weighted average remaining contractual
lives of 1.32 years.
Restricted Shares and Restricted
Stock Units. Restricted shares and restricted stock units,
when granted, are valued at the closing market value of the Company’s common
stock on the date of issuance and amortized to compensation expense on a
straight-line basis over the nominal vesting period of the stock. The
restricted shares and restricted stock units have vesting dates up to three
years from the issue date. When common stock dividends are declared
by the Company’s Board of Directors, dividends are accrued on the issued
restricted shares but are not paid until the shares vest. When common
stock dividends are declared by the Company’s Board of Directors, dividend
equivalents are accrued on the restricted stock units and paid when the common
stock dividends are paid.
The
following table summarizes the changes in the Company’s restricted shares and
restricted stock units during the years ended December 31, 2009, 2008 and
2007.
|
2009
|
2008
|
2007
|
||||||||||||||||||||||
|
Shares
/
Units
|
Weighted-
Average
Grant-Date
Market
Value
|
Shares
/
Units
|
Weighted-
Average
Grant-Date
Market
Value
|
Shares
/
Units
|
Weighted-
Average
Grant-Date
Market
Value
|
|||||||||||||||||||
|
Nonvested
at beginning of
year
|
571,479 | $ | 29.2473 | 1,053,083 | $ | 24.0234 | 713,026 | $ | 18.5465 | |||||||||||||||
|
Conversion
of stock unit
awards
|
242,669 | 37.5632 | 459,171 | 29.5867 | 657,232 | 29.3850 | ||||||||||||||||||
|
Granted
|
752,300 | 13.6143 | 191,603 | 29.2920 | 127,762 | 30.3280 | ||||||||||||||||||
|
Vested
|
(715,235 | ) | 26.2328 | (1,130,600 | ) | 24.5279 | (415,266 | ) | 25.0136 | |||||||||||||||
|
Forfeited
|
(9,146 | ) | 12.7200 | (1,778 | ) | 28.6345 | (29,671 | ) | 24.4588 | |||||||||||||||
|
Nonvested
at end of year
|
842,067 | 20.4173 | 571,479 | 29.2473 | 1,053,083 | 24.0234 | ||||||||||||||||||
The total
grant date fair value of restricted shares and restricted stock units which
vested during the years ended December 31, 2009, 2008 and 2007 was $18.8
million, $27.7 million and $10.4 million, respectively. The total
intrinsic value of restricted shares and restricted stock units vested during
the years ended December 31, 2009, 2008 and 2007 was $9.6 million, $33.3 million
and $16.0 million, respectively. The vestings for the years ended
December 31, 2009, 2008 and 2007 in the table above include 52,560, 122,250 and
66,884, respectively, of restricted stock units (for which common stock was
issued upon vesting). The Company realized $3.1 million of income tax
benefit for 2009 vestings, and reduced the Company’s available pool of excess
income tax benefits by $3.2 million. The Company realized $11.6
million and $5.8 million of income tax benefits related to the 2008 and 2007
vestings, of which $1.7 million and $2.1 million was excess income tax benefits,
respectively.
In March
2009, following certification by the Compensation Committee of the Company’s
Board of Directors that the specified performance criteria of the Company’s
return of capital employed versus that of a defined peer group had been achieved
for the year ended December 31, 2008, the Company issued 242,669 shares of
restricted stock in connection with the February 2008 grant of contingently
issuable stock unit awards. The 2008 net income goal was not met;
consequently, 242,680 contingently issuable shares awarded in 2008 were not
issued. The following tables summarize the vesting schedules of the
242,669 stock unit awards converted to restricted stock and 743,154 shares of
restricted stock shares and units granted, net of forfeitures, during the year
ending December 31, 2009.
|
Conversion
Date
|
Converted
stock
unit
awards
|
Vesting
Dates and Share Amounts
|
||||||||||||||||||||||||||
|
June
15,
2009(1)
|
June
30,
2009
|
August
2009(1)
|
November
2009
(1)
|
June
2010
|
June
2011
|
|||||||||||||||||||||||
|
March
25, 2009
|
242,669 | 54,762 | 62,635 | 3,968 | 13,889 | 53,708 | 53,707 | |||||||||||||||||||||
| Grant Date |
Shares/Units
Granted
(Net of
Forfeits)
|
Vesting
Dates and Share Amounts
|
||||||||||||||||||||||||||||||
|
March
2009
(1)
|
August
2009
(1)
|
November
2009
(1)
|
December
2009
|
March
2010
|
March
2011
|
March
2012
|
||||||||||||||||||||||||||
|
January
30, 2009
|
52,560 | 52,560 | ||||||||||||||||||||||||||||||
|
February
24, 2009
|
309,445 | 5,684 | 19,490 | 71,068 | 71,068 | 142,135 | ||||||||||||||||||||||||||
|
March
25, 2009
|
365,225 | 124,370 | 1,039 | 9,921 | 57,478 | 57,483 | 114,934 | |||||||||||||||||||||||||
|
April
28, 2009
|
8,424 | 2,106 | 2,106 | 4,212 | ||||||||||||||||||||||||||||
|
September
9, 2009
|
7,500 | 1,875 | 1,875 | 3,750 | ||||||||||||||||||||||||||||
|
Total
|
743,154 | 124,370 | 6,723 | 29,411 | 52,560 | 132,527 | 132,532 | 265,031 | ||||||||||||||||||||||||
|
(1)
Accelerated vesting due to retirement or termination of
employees.
|
||||||||||||||||||||||||||||||||
In March
2008, following certification by the Compensation Committee of the Company’s
Board of Directors that specified performance criteria of the Company’s net
income goal and return of capital employed versus that of a defined peer group
had been achieved for the year ended December 31, 2007, the Company issued
459,171 shares of restricted stock in connection with the February 2007 grant of
contingently issuable stock unit awards. The following tables
summarize the vesting schedules of the 459,171 stock unit awards converted to
restricted stock during the year ending December 31, 2008.
|
Vesting
Dates and Share Amounts
|
||||||||||||||||||||||||||||
|
Conversion
Date
|
Converted
stock
unit
awards
|
June
2008
|
December
2008(1)
|
June
2009
|
August
2009(1)
|
November
2009
(1)
|
June
2010
|
|||||||||||||||||||||
|
March
24, 2008
|
459,171 | 153,092 | 77,776 | 114,157 | 3,888 | 16,666 | 93,592 | |||||||||||||||||||||
|
(1)
Accelerated vesting due to retirement or termination of
employees.
|
||||||||||||||||||||||||||||
Contingently Issuable
Awards. During the year ended December 31, 2009, the Company
granted 506,134 contingently issuable stock unit awards, net of forfeitures, to
be earned if certain net income and return of capital employed versus that of a
defined peer group goals are met for 2009. Depending on achievement
of the performance goals, awards earned could be between 0% and 125% of the base
number of performance stock units. If any of the performance goals
are achieved for 2009 and certified by the Compensation Committee, these stock
unit awards (or a portion thereof) will be converted into restricted stock
during the first quarter of 2010. One-third of these restricted
shares will vest on June 30, 2010, one-third on June 30, 2011 and the final
one-third on June 30, 2012, with the exception of restricted shares related to
severance agreements that will vest immediately upon
certification. As of December 31, 2009, the Company assumed for
purposes of stock-based compensation expense for these awards granted in 2009
that the maximum target (125%) level award (316,335 stock units, net of
forfeitures) would be earned for the net income contingent awards and the
maximum target (125%) level award (316,335 stock units, net of forfeitures)
would be earned for the return of capital employed versus that of a defined peer
group. The stock unit awards were valued at the market value on the
date of grant and amortized to compensation expense on a straight-line basis
over the nominal vesting period, adjusted for retirement-eligible employees, as
required under GAAP.
The
Company also granted 240,007 stock unit awards, net of forfeitures, contingent
upon certain share price performance versus the Company’s peers being met over a
three-year period ending on December 31, 2011. Depending on
achievement of the market-based performance goals, awards earned could be
between 0% and 125% of the base number of market-based stock
units. If any of the performance goals are achieved and certified by
the Compensation Committee, these stock unit awards (or a portion thereof) will
be converted into stock. For stock unit awards subject to such
market-based vesting conditions, the grant date fair value of the award is
estimated using a Monte Carlo valuation model. The Monte Carlo model
is based on random projections of stock price paths and must be repeated
numerous times to achieve a probabilistic assessment. Expected
volatility was calculated using a weighted average of historical daily
volatilities and implied volatility, and represents the extent to which the
Company’s stock price performance, relative to the average stock price
performance of the peer group, is expected to fluctuate during each of the three
calendar periods of the award’s anticipated term ending December 31,
2011. The risk-free rate is based on a U.S. Treasury rate consistent
with the three-year vesting period. The total grant date fair value
of the market-based stock units as determined by the Monte Carlo valuation model
is $2.5 million, net of forfeitures and will be recognized ratably over the
three-year vesting period. The key assumptions used in valuing these
market-based restricted shares are as follows:
|
2009
|
||||
|
Number
of simulations
|
100,000 | |||
|
Expected
volatility
|
67.27 | % | ||
|
Risk-free
rate
|
1.31 | % | ||
As of December 31, 2009, the Company also had outstanding (net of forfeitures) 206,348 contingently issuable stock unit awards issued in 2007 that were earned based on certain share price criteria met over a three-year period ended December 31, 2009. Once the performance goal is certified by the Compensation Committee, these stock unit awards will be converted into stock. In addition, as of December 31, 2009, the Company had outstanding 185,302 contingently issuable stock unit awards issued in 2008 to be earned should certain share price criteria be met over a three-year period ending December 31, 2010. Depending on achievement of the performance goal, awards earned could be between 0% and 125% of the base number of performance stock units. If any of the performance goals are achieved and certified by the Compensation Committee, these stock unit awards (or a portion thereof) will be converted into stock.
When
common stock dividends are declared by the Company’s Board of Directors,
dividend equivalents (on the stock unit awards) and dividends (once the stock
unit awards are converted to restricted stock) are accrued on the contingently
issuable stock units and restricted stock but are not paid until the restricted
stock vests.
|
11.
|
Employee
Benefit Plans
|
Defined
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 pension and/or matching contributions on
behalf of participating employees. The cost of the defined
contribution plans for the years ended December 31, 2009, 2008 and 2007 was $8.0
million, $7.9 million and $7.5 million, respectively.
Deferred
Compensation Plan
The
Company sponsors a deferred compensation plan for certain employees and
directors whose eligibility to participate in the plan is determined by the
Compensation Committee of the Company’s Board of
Directors. Participants may contribute a portion of their earnings to
the plan, and the Company makes pension 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 were $4.0
million at December 31, 2009 ($2.6 million at December 31, 2008). The
current portions are reflected in “Other current assets” and “Accrued
liabilities and other” both of which were $401,000 at December 31, 2009 and none
in 2008, respectively, in the Consolidated Balance Sheets. The
long-term portions are reflected in “Other assets” and “Other long-term
liabilities” both of which were $3.6 million and $2.6 million at December 31,
2009 and 2008, respectively.
Defined
Benefit Plans
In April
2008, the Company’s Board of Directors approved the termination of the defined
benefit cash balance pension plan. In July 2009, the Company
received, from the Internal Revenue Service, a letter stating the termination of
the pension plan does not affect its qualification. The Company
terminated the plan in December 2009. Plan participants received 100%
of their account balance, including interest, in the fourth quarter of
2009.
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 were unfunded as of
December 31, 2009 and 2008. 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 Medicare Part D benefits. The plan was changed
in the first quarter of 2008 to limit the employees’ pre-Medicare insurance
premium to 125% of the active employee rate. Post-retirement
healthcare benefits provided for Medicare eligible retirees were reduced
effective December 31, 2006 to levels stipulated at the time of the El Dorado
Refinery acquisition.
The
tables on the following pages set forth the funded status of the pension plan
and post-retirement healthcare and other benefit plans change in benefit
obligation, items not yet recognized as a component of net periodic benefit
costs and reflected as a component of the ending balance of accumulated Other
Comprehensive Income (“OCI”), net of tax, and the measurement of defined benefit
plan assets and obligations for the years ended December 31, 2009, 2008 and
2007. Also included in the tables on the following pages are weighted
average key assumptions, healthcare cost trend rates and sensitivity analysis
for the years ended December 31, 2009, 2008 and 2007.
|
Pension
Benefits
|
Post-retirement
and
Other
Benefits (1)
|
|||||||||||||||
|
2009
|
2008
|
2009
|
2008
|
|||||||||||||
|
(in
thousands)
|
||||||||||||||||
|
Change
in benefit obligation:
|
||||||||||||||||
|
Benefit
obligation at January 1
|
$ | 11,337 | $ | 9,941 | $ | 31,858 | $ | 28,156 | ||||||||
|
Service
cost
|
- | - | 693 | 628 | ||||||||||||
|
Interest
cost
|
274 | 508 | 1,890 | 1,788 | ||||||||||||
|
Plan
participant contributions
|
- | - | 114 | 62 | ||||||||||||
|
Actuarial
loss (gain)
|
209 | 158 | 27 | 1,556 | ||||||||||||
|
Amendments
|
- | 994 | - | - | ||||||||||||
|
Benefits
paid
|
(11,820 | ) | (264 | ) | (426 | ) | (332 | ) | ||||||||
|
Benefit
obligation at December 31
|
$ | - | $ | 11,337 | $ | 34,156 | $ | 31,858 | ||||||||
|
Change
in plan assets:
|
||||||||||||||||
|
Fair
value of plan assets at January 1
|
11,116 | 10,731 | - | - | ||||||||||||
|
Actual
(loss) return on plan assets
|
104 | (150 | ) | - | - | |||||||||||
|
Employer
contributions
|
600 | 800 | 312 | 270 | ||||||||||||
|
Plan
participant contributions
|
- | - | 114 | 62 | ||||||||||||
|
Benefits
paid
|
(11,820 | ) | (265 | ) | (426 | ) | (332 | ) | ||||||||
|
Fair
value of plan assets at December 31
|
$ | - | $ | 11,116 | $ | - | $ | - | ||||||||
|
Funded
status at December 31
|
$ | - | $ | (221 | ) | $ | (34,156 | ) | $ | (31,858 | ) | |||||
|
Amounts
recognized in the balance sheets:
|
||||||||||||||||
|
Other
assets
|
$ | - | $ | - | $ | - | $ | - | ||||||||
|
Accrued
liabilities and other
|
- | (221 | ) | (1,018 | ) | (730 | ) | |||||||||
|
Post-retirement
employee liabilities
|
- | - | (33,138 | ) | (31,128 | ) | ||||||||||
|
Net
amount recognized
|
$ | - | $ | (221 | ) | $ | (34,156 | ) | $ | (31,858 | ) | |||||
|
Amounts
recognized in accumulated OCI (2)
|
||||||||||||||||
|
(Gain)
loss
|
$ | - | $ | (397 | ) | $ | 9,480 | $ | 10,499 | |||||||
|
Prior
service credit
|
- | 426 | (7,486 | ) | (9,363 | ) | ||||||||||
| $ | - | $ | 29 | $ | 1,994 | $ | 1,136 | |||||||||
|
(1)
The disclosed post-retirement healthcare obligations and net periodic cost
for 2009 and 2008 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, 2009 and 2008, by approximately $5.4 million and $4.3
million, respectively. The Company did not recognize any benefits of
the subsidy during the years ended December 31, 2009 and
2008.
|
||||||||||||||||
|
(2)
For the post-retirement healthcare and other benefits, $1.0 of the $9.5
million net loss and $1.9 million of the $7.5 million of prior
service cost credit will be recognized in the benefit cost in
2010.
|
||||||||||||||||
|
Pension
Benefits
|
Post-retirement
Healthcare and
Other
Benefits
|
|||||||||||||||||||||||
|
2009
|
2008
|
2007
|
2009
|
2008
|
2007
|
|||||||||||||||||||
|
(in
thousands)
|
||||||||||||||||||||||||
|
Components
of net periodic benefit
cost
and other amounts recognized
in
other comprehensive income for
the
year ended December 31:
|
||||||||||||||||||||||||
|
Service
cost
|
$ | - | $ | - | $ | - | $ | 693 | $ | 627 | $ | 752 | ||||||||||||
|
Interest
cost
|
274 | 508 | 562 | 1,890 | 1,788 | 1,611 | ||||||||||||||||||
|
Expected
return on plan assets
|
(2 | ) | (501 | ) | (714 | ) | - | - | - | |||||||||||||||
|
Amortization
of prior service cost
|
426 | 568 | - | (1,876 | ) | (1,876 | ) | (1,876 | ) | |||||||||||||||
|
Amortized
net actuarial loss
|
- | (3 | ) | - | 1,046 | 966 | 1,137 | |||||||||||||||||
|
Net
periodic benefit cost
|
698 | 572 | (152 | ) | 1,753 | 1,505 | 1,624 | |||||||||||||||||
|
Changes
in assets and benefit
obligations
recognized in other
comprehensive
income:
|
||||||||||||||||||||||||
|
Increase
in benefit obligation for plan
amendment
|
- | - | - | - | - | - | ||||||||||||||||||
|
Net
loss (gain)
|
107 | 810 | (598 | ) | 27 | 1,557 | (2,269 | ) | ||||||||||||||||
|
Amortization
of prior service cost
|
- | 3 | - | 1,876 | 1,876 | 1,876 | ||||||||||||||||||
|
Prior
service cost
|
- | 994 | - | - | - | - | ||||||||||||||||||
|
Amortization
of loss
|
(426 | ) | (568 | ) | - | (1,046 | ) | (966 | ) | (1,137 | ) | |||||||||||||
|
Adoption
of SFAS 158
|
289 | - | - | - | - | - | ||||||||||||||||||
|
Total
recognized in other comprehensive
income
|
(30 | ) | 1,239 | (598 | ) | 857 | 2,467 | (1,530 | ) | |||||||||||||||
|
Total
recognized in net periodic benefit cost
and
other comprehensive income
|
$ | 668 | $ | 1,811 | $ | (750 | ) | $ | 2,610 | $ | 3,972 | $ | 94 | |||||||||||
|
Weighted
average assumptions:
|
||||||||||||||||||||||||
|
Benefit
obligation discount rate as of
December
31
(1)
|
n/a | 4.72 | % | 6.25 | % | 5.90 | % | 6.00 | % | 6.25 | % | |||||||||||||
|
Net
periodic benefit cost discount rate for
the
year ended December 31
(1)
|
n/a | 4.16 | % | 5.75 | % | 6.00 | % | 6.25 | % | 5.75 | % | |||||||||||||
|
Expected
return on plan assets (1)
|
n/a | 3.20 | % | 7.50 | % | - | - | - | ||||||||||||||||
|
Salary
increases
|
n/a | n/a | n/a | n/a | n/a | n/a | ||||||||||||||||||
|
(1)
The pension benefit plan was terminated and payouts of all benefits
occurred in the fourth quarter of 2009.
|
||||||||||||||||||||||||
|
Post-retirement
Healthcare and Other Benefits
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
(dollars
in thousands)
|
||||||||||||
|
Healthcare
cost-trend rate:
|
8.00 | % | 9.00 | % | 10.00 | % | ||||||
|
ratable
to
|
ratable
to
|
ratable
to
|
||||||||||
| 5.00 | % | 5.00 | % | 5.00 | % | |||||||
|
from
|
from
|
from
|
||||||||||
| 2012 | 2012 | 2012 | ||||||||||
|
Sensitivity
Analysis:
|
||||||||||||
|
Effect
of 1% (-1%) change in healthcare cost-trend rate:
|
||||||||||||
|
Year-end
benefit obligation
|
$ | 5,471 | $ | 4,932 | $ | 4,761 | ||||||
| (4,463 | ) | (4,030 | ) | (3,852 | ) | |||||||
|
Total
service and interest cost
|
430 | 388 | 662 | |||||||||
| (349 | ) | (316 | ) | (519 | ) | |||||||
At
December 31, 2009, the estimated future benefit payments for post-retirement
healthcare and other benefits to be paid over the next ten years are as
follows:
|
2010
|
$ | 1,019 | ||
|
2011
|
1,351 | |||
|
2012
|
1,632 | |||
|
2013
|
1,939 | |||
|
2014
|
2,202 | |||
|
Next
5 fiscal years thereafter
|
12,533 | |||
Plan Assets. The
pension plan assets were held in a Trust Fund (the “Fund”) whose trustee is
Frost National Bank (“trustee”). The Company contributed $600,000 to
the Fund during 2009. As discussed above, the Company terminated the
plan in December 2009 and Plan participants received 100% of their account
balance, including interest, in the fourth quarter of 2009, thus no assets
remain in the plan as of December 31, 2009. Frontier’s pension plan
weighted-average asset allocations in the Fund at December 31, 2008, by asset
category were 89% cash and cash equivalents and 11% fixed income common trust
funds.
|
12.
|
Fair
Value Measurement
|
GAAP
establishes a three-level valuation hierarchy for disclosure of fair value
measurements. The valuation hierarchy is based upon the transparency
of inputs to the valuation of an asset or liability as of the measurement
date. The three levels are defined as follows:
Level 1 –
inputs to the valuation methodology are quoted prices (unadjusted) for identical
assets or liabilities in active markets.
Level 2 –
inputs to the valuation methodology include quoted prices for similar assets and
liabilities in active markets, and inputs that are observable for the asset or
liability, either directly or indirectly, for substantially the full term of the
financial instrument.
Level 3 –
inputs to the valuation methodology are unobservable and significant to the fair
value measurement.
A
financial instrument’s categorization within the valuation hierarchy is based
upon the lowest level of input that is significant to the fair value
measurement. The Company’s assessment of the significance of a
particular input to the fair value measurement in its entirety requires judgment
and considers factors specific to the asset or liability.
The
following table presents information about the Company’s assets and liabilities
measured at fair value on a recurring basis as of December 31, 2009, and
indicates the fair value hierarchy of the valuation techniques utilized by the
Company to determine such fair value (in thousands):
|
Description
|
Level
1
|
Level
2
|
Level
3
|
Total
|
||||||||||||
|
Derivative
assets
|
$ | 122 | $ | 2 | $ | - | $ | 124 | ||||||||
|
Derivative
liabilities
|
4,710 | 1,841 | - | 6,551 | ||||||||||||
As of
December 31, 2009, the Company’s derivative contracts giving rise to the
liabilities measured under Level 1 are NYMEX crude oil contracts and thus are
valued using quoted market prices at the end of each period. The
Company’s derivative contracts giving rise to the assets measured under Level 1
are NYMEX calendar spread options. The Company’s derivative contracts
giving rise to the liabilities under Level 2 are valued using pricing models
based on NYMEX crude oil contracts. The derivative asset contracts
included in Level 2 valuations are interest rate swap contracts. A
mark-to-market valuation that took into consideration anticipated cash flows
from the transactions using market prices and other economic data and
assumptions were used to value the swaps. Given the degree of varying
assumptions used to value the swaps, it was deemed as having Level 2
inputs. The Company’s crude call options that relate to lease crude
purchases, which at December 31, 2009, had no value, are measured under Level 3,
meaning that the options were valued using internal contract
pricing. The following provides a reconciliation of the beginning and
ending balances of the Company’s Level 3 derivative asset crude call options for
the year ended December 31, 2009 (in thousands):
|
Year
Ended December 31,
|
||||||||
|
2009
|
2008
|
|||||||
|
Beginning
derivative asset balance
|
$ | - | $ | - | ||||
|
Net
increase in derivative assets
|
231 | 437 | ||||||
|
Net
settlements
|
(231 | ) | (437 | ) | ||||
|
Transfers
in (out) of Level 3
|
- | - | ||||||
|
Ending
derivative asset balance
|
$ | - | $ | - | ||||
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, 2009 and 2008, the carrying amounts of
the Company’s 6.625% Senior Notes were $150.0 million, respectively, and the
estimated fair values were $150.8 million and $135.8 million,
respectively. At December 31, 2009 and 2008, the carrying amount of
the Company’s 8.5% Senior Notes were $197.5 million ($200.0 million less the
unamortized discount of $2.5 million) and $197.2 million (unamortized discount
of $2.8 million) and the estimated fair values were $207.0 million and $176.5
million. For cash and cash equivalents, trade receivables, inventory
and accounts payable, the carrying amount is a reasonable estimate of fair
value.
|
13.
|
Commitments
and Contingencies
|
Lease
and Other Commitments
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, which has both a fixed and a variable component, expires in 2016,
although the Company has the option to renew the sublease for an additional
eight years. At the end of the renewal period, 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 2010 through
2017. Operating lease rental expense was approximately $13.1 million,
$13.2 million and $13.6 million for the years ended December 31, 2009, 2008 and
2007, respectively. The approximate future minimum lease payments for operating
leases as of December 31, 2009 were $12.9 million for 2010, $10.4 million for
2011, $7.3 million for 2012, $7.0 million for 2013, $6.4 million for 2014 and
$11.1 million thereafter.
On
December 2, 2009, the Company entered into a guaranteed throughput agreement
with Rocky Mountain Pipeline System Inc. for shipping finished refined products
on pipelines from the Cheyenne Refinery to Sidney, Nebraska through December 31,
2012 with an annual tariff commitment of $1.7 million.
The
Company has commitments for crude oil pipeline capacity on four pipelines (see
below) totaling approximately $35.6 million in 2010, $36.7 million in 2011, an
average of $29.7 million for each of the years 2012 through 2015 and an average
of $10.8 million for each of the years 2016 and 2017. The Company
incurred expenses under these commitments of $44.6 million, $41.1 million and
$16.2 million for the years ended December 31, 2009, 2008 and 2007,
respectively.
The
Company has two contracts for crude oil pipeline capacity on the Express
Pipeline. The first contract, which began in 1997, is for 15 years
and for an average of 13,800 barrels per day (“bpd”) over that 15-year
period. In December 2003, the Company entered into an expansion
capacity agreement on the Express Pipeline for an additional 10,000 bpd from
April 2005 through 2015.
The
Company has a Transportation Services Agreement (“Agreement”) to transport
38,000 bpd of crude oil based on filed tariffs on the Spearhead Pipeline from
Flanagan, Illinois to Cushing, Oklahoma (“Cushing”). This pipeline
enables the Company to transport Canadian crude oil to the El Dorado
Refinery. The initial term of this Agreement is until 2016, although
the Company has the right to extend the Agreement for an additional ten-year
term and increase the volume transported.
The
Company entered into a definitive agreement with Rocky Mountain Pipeline System
LLC, now owned by Plains All American Pipeline, L.P. (“Plains All American”), on
March 31, 2006 to support construction of a new crude pipeline from Guernsey,
Wyoming to Rocky Mountain’s Fort Laramie, Wyoming tank farm and
then to the Cheyenne Refinery. The Company made a ten-year
commitment to ship 35,000 bpd based on a filed tariff on the new pipeline and
will concurrently lease approximately 300,000 barrels of dedicated storage
capacity in the Plains All American tank farm. The pipeline, which is designed
to transport 55,000 bpd of heavy crude and is expandable to 90,000 bpd, first
transported crude oil in October 2007.
The
Company entered into an agreement with Osage Pipeline in 2007 to ship additional
crude oil volumes from Cushing, Oklahoma to its El Dorado
Refinery. The annual average increased commitment of 7,500 bpd
commenced in July 2008 with a term of five years.
In 2006,
the Company’s subsidiary, Frontier Oil and Refining Company (“FORC”), entered
into a Master Crude Oil Purchase and Sale Contract (“Contract”) with Utexam
Limited (“Utexam”), a wholly-owned subsidiary of BNP Paribas
Ireland. In July 2009, the Company entered into the third amendment
of this Contract which decreased the maximum value of crude oil to be purchased
under this contract from $250.0 million to $110.0 million and extends the
maturity date of the contract to March 31, 2010. Under this $110.0
million Contract, Utexam purchases, transports and subsequently sells crude oil
to FORC at locations near Guernsey, Wyoming and Cushing, Oklahoma or other
locations as agreed. Under this agreement, Utexam is the owner of
record of the crude oil as it is transported from the point of injection,
typically Hardisty, Alberta, Canada, to the point of ultimate sale to
FORC. The Company has provided a guarantee of FORC’s obligations
under this Contract, primarily to receive crude oil and make payment for crude
oil purchases arranged under this Contract. The Company accounts for
the transactions under this Contract as a financing arrangement, whereby the
inventory and the associated liability are recorded in the Company’s financial
statements when the crude oil is injected into the pipeline in
Canada. As of December 31, 2009, FORC and Utexam had entered into
certain commitments to purchase and sell crude oil in the first quarter of 2010
under this Contract; however, neither party has a continuing commitment to
purchase or sell crude oil in the future.
Litigation
Other. The Company
is involved in various lawsuits and regulatory actions 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 industries and within limited geographic areas. The
Company sells its Cheyenne Refinery 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 Refinery
gasoline, diesel and jet fuel to Shell at market-based prices under a 15-year
offtake agreement executed 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 2008, the Company entered into an
amendment to the offtake agreement that allowed the Company to retain an
additional 10,000 bpd of diesel production due to the Coker expansion project
and improved Refinery efficiencies. In 2009, Frontier retained and
marketed 60,000 bpd of the El Dorado Refinery’s gasoline and diesel
production. Shell has also agreed to 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 made sales to Shell of approximately $1.6
billion, $2.3 billion and $2.2 billion in the years 2009, 2008 and 2007,
respectively, which accounted for 38%, 37% and 42% of consolidated refined
products revenues in 2009, 2008 and 2007, respectively.
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 customer’s credit risk, past experience and other
factors. The Company recorded a bad debt loss of $198,000 and a net
increase in the allowance for doubtful accounts of $500,000 during the year
ended December 31, 2009. No bad debts were recorded in the year ended
December 31, 2008. For the year ended December 31, 2007, $198,000 of
previously written off bad debts was collected.
Environmental
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 production of cleaner
transportation fuels and the installation of certain air pollution control
devices at the Refineries during the next several years.
The
Environmental Protection Agency (“EPA”) has promulgated regulations requiring
the phase-in of gasoline sulfur standards, which began January 1, 2004 and
continued through 2008, with special provisions for small business refiners such
as Frontier. As allowed by subsequent regulation, Frontier elected to
extend its small refinery interim gasoline sulfur standard at each of the
Refineries until January 1, 2011 by complying with the highway ultra low sulfur
diesel standard by June 2006. To meet final federal gasoline sulfur
standards at the Cheyenne Refinery, the Company expects to spend approximately
$40.0 million ($11.4 million incurred as of December 31, 2009) for the cat
gasoline hydrotreater project comprised of new process unit capacity and
intermediate inventory handling equipment. In addition, new federal
benzene regulations and anticipated state requirements for reduction in gasoline
Reid Vapor Pressure (“RVP”) suggest that additional capital expenditures may be
required for environmental compliance projects. The Company is
presently evaluating projects and the total potential cost in connection with an
overall compliance strategy for the Cheyenne Refinery. Total capital
expenditures estimated as of December 31, 2009 for the El Dorado Refinery to
comply with the final gasoline sulfur standard are approximately $95.0 million,
including capitalized interest, and are expected to be completed in 2010 ($74.7
million incurred as of December 31, 2009). Substantially all of the
estimated $95.0 million of expenditures relates to the El Dorado Refinery’s
gasoil hydrotreater revamp project. The gasoil hydrotreater revamp
project will address most of the El Dorado Refinery’s modifications needed to
achieve gasoline sulfur compliance.
The
Company is a holder of gasoline sulfur credits; some retained from prior
generation years and others generated from operations during 2009 at both the
Cheyenne and the El Dorado Refineries. During the years ended
December 31, 2009, 2008 and 2007, Frontier sold sulfur credits for total
proceeds of $1.9 million, $4.6 million and $4.8 million, respectively, which are
recorded in “Other revenues” on the Consolidated Statements of
Operations.
In March
2009, settlement agreements associated with the EPA’s National Petroleum
Refining Enforcement Initiative were finalized and are now in
effect. The Company currently estimates that, in addition to the
flare gas recovery systems previously installed at each facility in anticipation
of the finalization of the agreement, capital expenditures totaling
approximately $45.0 million ($517,000 incurred as of December 31, 2009) at the
Cheyenne Refinery and $6.0 million ($1.3 million incurred as of December 31,
2009) at the El Dorado Refinery will need to be incurred prior to
2017. The Company may also choose to incur additional costs at the
Cheyenne Refinery and at the El Dorado Refinery to comply with certain
requirements of the agreement if such projects are determined to be the most
cost effective compliance strategy. Notwithstanding these
settlements, many of these same expenditures are required for the Company to
comply with preexisting regulatory requirements or to implement its planned
facility expansions. As an example, a preexisting regulation known as Maximum
Achievable Control Technology II (“MACT II”) required the installation in 2009
of a particulate scrubber at the El Dorado Refinery at a cost of $33.4
million. Consequently, the costs associated with this project and
other more minor projects are not included in the totals above. In
addition to the capital costs described above, the EPA has assessed, and the
Company paid in April 2009, a civil penalty in the amount of $1.9 million,
discounted for a related $96,000 penalty and associated supplemental environment
project (“SEP”) paid to the State of Wyoming in 2005 and further offset by
$902,000 for the completion of additional mutually agreed SEPs. The
EPA also attached to this settlement resolution an enforcement action against
the Company’s El Dorado Refinery related to alleged violations of certain
requirements of the EPA Risk Management Program (“RMP”). Negotiated
civil penalties included in the aforementioned payment regarding resolution of
this issue totaled approximately $484,000, which were reduced to $358,000 by
completion of an approved SEP. The Company accrued for the balance of
these estimated penalties at December 31, 2008, and payment occurred in April
2009. In addition, the settlement agreement provides for stipulated
penalties for violations, which are periodically reported by the
Company. Stipulated penalties under the decree are not automatic but
must be requested by one of the agency signatories. If a stipulated
penalty is requested, the Company will separately report that matter and the
amount of the proposed penalty, if applicable.
The EPA
has promulgated regulations to enact the provisions of the Energy Policy Act of
2005 regarding mandated blending of renewable fuels in gasoline. The
Energy Independence and Security Act of 2007 significantly increased the amount
of renewable fuels that had been required by the 2005 legislation. The Company,
as a small refiner, will be exempt until January 1, 2011 from these
requirements. The Company has renewable fuels blending facilities and
purchases ethanol with Renewable Identification Numbers (RINs) credits
attached. Ethanol RINs were created to assist in tracking the
compliance with these EPA regulations for the blending of renewable
fuels. During the years ended December 31, 2009 and 2008, the Company
sold RIN gallons for $4.6 million and $4.5 million, respectively, which were
recorded in “Other revenues” on the Consolidated Statements of
Operations. There were no sales of RINs during the year ended
December 31, 2007. While not yet enacted or promulgated, other
pending legislation or regulation regarding the mandated use of alternative or
renewable fuels and/or the reduction of greenhouse gas emissions from either
transportation fuels or manufacturing processes is under consideration by the
U.S. Congress. In addition, the EPA has recently determined that
greenhouse gases, including carbon dioxide, present a danger to human health and
the environment, which may result in future regulation of such
gases. If climate change legislation is enacted or regulations
promulgated, these requirements could materially impact the operations and
financial position of the Company (see “Other Future Environmental
Considerations” below).
On
February 26, 2007, the EPA promulgated regulations limiting the amount of
benzene in gasoline. These regulations take effect for large refiners
on January 1, 2011 and for small refiners, such as Frontier, on January 1,
2015. While not yet estimated, the Company anticipates that
potentially material capital expenditures may be necessary to achieve compliance
with the new regulation at its Cheyenne Refinery as discussed
above. Gasoline manufactured at the El Dorado Refinery typically
contains benzene concentrations near the new standard. The Company
therefore believes that necessary benzene compliance expenditures at the El
Dorado Refinery will be substantially less than those at its Cheyenne
Refinery.
As is the
case with 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 investigation and interim remediation actions at the
Cheyenne Refinery’s property that may have been impacted by past operational
activities. As a result of past and ongoing 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. In
addition, the Company estimates that an ongoing groundwater remediation program
will be required for approximately ten more years. As of December 31,
2009 and 2008, the Company had a $4.6 million and $5.0 million accrual,
respectively, included on the Consolidated Balance Sheets related to the
remediation program. The accrual at December 31, 2009 reflects the estimated
present value of a $775,000 cost in 2010 and $575,000 in annual costs for 2011
through 2019, assuming a 3% inflation rate and discounted at a rate of
6.2%. The Company also had accrued a total of $5.7 million and $4.7
million, respectively, as of December 31, 2009 and December 31, 2008, for the
cleanup of a waste water treatment pond located on land adjacent to the Cheyenne
Refinery which the Company had historically leased from the
landowner. Cleanup of the waste water pond pursuant to the
aforementioned agreement with the State of Wyoming has been initiated and is
anticipated to be completed in 2010. Depending upon information
collected during the cleanup, or by a subsequent administrative order or permit,
additional remedial action and costs could be
required. Pursuant to this agreement, in the fourth quarter of
2009, the Company completed an $11.2 million capital project for the
installation of a groundwater boundary control system and associated groundwater
recovery wells.
Frontier
Refining Inc. (which owns the Cheyenne Refinery) has been served with a
Complaint from Region 8 of the EPA alleging unlawful storage of untreated or
partially treated refinery wastewater in an on-site surface impoundment and
proposing a penalty of $6.8 million. The EPA stated in the
accompanying press release that the Complaint was part of a national enforcement
initiative. Frontier Refining Inc. subsequently filed a motion to
dismiss which was followed by an EPA Motion to Amend the original complaint,
consolidating many of the alleged violations and remaining silent on any
proposed penalty amount. Although Frontier Refining Inc. does not
agree with the EPA’s allegations, the Company has entered into settlement
negotiations with the Agency and accrued for the full amount of the proposed
penalty during the third quarter of 2009 which is included in “Other long-term
liabilities” on the December 31, 2009 Consolidated Balance
Sheet. During the first quarter of 2010 negotiations have continued
with the EPA and the Company now expects that the Complaint will be settled for
less than the amount accrued.
The
Company completed in 2007 the negotiation of a settlement of a Notice of
Violation (“NOV”) from the Wyoming Department of Environmental Quality alleging
non-compliance with certain refinery waste management
requirements. The Company has estimated that the minimum capital cost
for required corrective measures will be approximately $2.7 million and is
estimated to be completed in late 2010. In addition, the Company had
accruals of $1.2 million and $995,000 at December 31, 2009 and December 31,
2008, respectively, for additional work related to the corrective
measures. The Company has also negotiated settlements regarding
various NOVs from the Wyoming Department of Environmental Quality for certain
alleged solid and hazardous waste violations noted during site
inspection. The administrative settlement agreement to satisfy
alleged solid and hazardous waste violations specified a civil penalty of
approximately $460,000 and was paid in February 2009. A settlement
agreement regarding alleged wastewater discharge violations specifying a
$650,000 civil penalty and completion of certain Supplemental Environment
Projects (“SEPs”) at a cost of $200,000 was paid in February 2009.
Pursuant
to an agreement with the City of Cheyenne, the Company paid $1.3 million of our
$1.5 million commitment toward a project (completed in 2009) to relocate a city
storm water conveyance pipe, which was previously located on Refinery property
and therefore was potentially subject to contaminants from Refinery
operations.
El Dorado
Refinery. The El Dorado Refinery is subject to a 1988 consent
order with the Kansas Department of Health and Environment
(“KDHE”). Subject to the terms of the purchase and sale agreement for
the El Dorado Refinery entered into between the Company and Shell Oil Products
US (“Shell”), Shell is responsible for the costs of continued compliance with
this order. 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 Refinery are met.
Other Future Environmental
Considerations. Recent scientific studies have suggested that
emissions of certain gases, commonly referred to as “greenhouse gases” and
including carbon dioxide and methane, may be contributing to warming of the
earth’s atmosphere. In response to such studies, the U.S. Congress
has been actively considering legislation to reduce emissions of greenhouse
gases. To that end, on June 26, 2009, the U.S. House of
Representatives passed the “American Clean Energy and Security Act of 2009” (HR
2454) which would, if subsequently adopted by the U.S. Senate and signed into
law by the President, establish a “cap and trade” system with the intent of
reducing future greenhouse gas emissions. If enacted, the Company
could be required to purchase and surrender allowances for greenhouse gas
emissions resulting from its operations and from combustion of fuels that it
produces. In addition, more than one-third of the states already have
begun implementing legal measures to reduce emissions of greenhouse
gases. On April 2, 2007, in Massachusetts, et al. v. EPA the U.S.
Supreme Court held that carbon dioxide may be regulated as an “air pollutant”
under the federal Clean Air Act and that the EPA must consider whether it is
required to regulate greenhouse gas emissions from mobile sources such as cars
and trucks. In July 2008, the EPA released an Advance Notice of
Proposed Rulemaking regarding possible future regulation of greenhouse gas
emissions under the Clean Air Act, in response to the Supreme Court’s decision
in Massachusetts. In the notice, the EPA evaluated the potential
regulation of greenhouse gases under the Clean Air Act and other potential
methods of regulating greenhouse gases. Although the notice did not
propose any specific, new regulatory requirements for greenhouse gases, it
indicates that federal regulation of greenhouse gas emissions could occur in the
near future. On April 17, 2009, the EPA proposed that certain
greenhouse gases, including carbon dioxide, present a danger to public health or
welfare. The proposed “endangerment finding” was promulgated on
December 7, 2009, opening the door to direct regulation of such greenhouse gases
under the provisions and programs of the existing Clean Air Act. Thus, there may
be restrictions imposed on the emission of greenhouse gases even if the U.S.
Congress does not adopt new legislation specifically addressing emissions of
greenhouse gases. Although it is not possible at this time to predict
how legislation or new regulations that may be adopted to address greenhouse gas
emissions would impact the Company’s business, any such future laws and
regulations will most likely result in increased compliance costs or additional
operating restrictions, and could have a material adverse effect on our
business, financial condition and results of operations, including demand for
the refined petroleum products that it produces.
|
14.
|
Price
and Interest Risk Management
Activities
|
The
Company, at times, enters into commodity derivative contracts to manage its
price exposure to its inventory positions, purchases of foreign crude oil and
consumption of natural gas in the refining process or to fix margins on certain
future production or to hedge interest rate risk. The commodity
derivative contracts used by the Company may take the form of futures contracts,
forward contracts, collars or price or interest rate swaps. The
Company, also at times, enters into foreign exchange contracts to manage its
exposure to foreign currency fluctuations on its purchases of foreign crude
oil. The Company believes that there is minimal credit risk with
respect to its counterparties. The Company’s commodity derivative
contracts and foreign exchange contracts, while economic hedges are not
accounted for as cash flow or fair value hedges and thus are accounted for under
mark-to-market accounting and gains and losses recorded directly to
earnings. The Company has derivative contracts which it holds
directly and also derivative contracts, in connection with its crude oil
purchase and sale contract held on Frontier’s behalf by Utexam, in connection
with the Master Crude Oil Purchase and Sale Contract (see Note 13 “Lease and
Other Commitments”). For additional fair value disclosures relating
to the Company’s derivative contracts, see Note 12 “Fair Value
Measurement.” As of December 31, 2009, the Company had the following
outstanding commodity derivative contracts:
|
Commodity
|
Number
of barrels
|
|||
|
(in
thousands)
|
||||
|
Crude
purchases in-transit
|
527 | |||
|
Crude
oil contracts to hedge excess intermediate, finished product and crude oil
inventory
|
1,628 | |||
During
October 2009, the Company entered into two $75.0 million interest rate swap
transactions totaling $150.0 million. These swaps effectively convert
a portion of our interest expense from fixed to variable rate
debt. Under these swap contracts, interest on each of the $75.0
million notional amount is computed using 30-day LIBOR plus a spread of 5.34%
and 5.335%, which equaled an effective interest rate of 5.59% and 5.58%,
respectively, as of the transaction date. The maturity of both swap
transactions is October 1, 2011, corresponding to the maturity of the Company’s
6.625% Senior Notes.
The
following table presents the location of the Company’s outstanding derivative
contracts on the Consolidated Balance Sheet and the related fair values at the
balance sheet dates.
|
Asset
Derivatives in
Other
Current Assets
|
Liability
Derivatives in
Accrued
Liabilities and Other
|
|||||||||||||||
|
December
31,
2009
|
December
31,
2008
|
December
31,
2009
|
December
31,
2008
|
|||||||||||||
|
Fair
Value
|
Fair
Value
|
Fair
Value
|
Fair
Value
|
|||||||||||||
|
(in
thousands)
|
||||||||||||||||
|
Derivatives
not designated as
hedging instruments
|
||||||||||||||||
|
Commodity
contracts
|
$ | - | $ | 8,584 | $ | 6,551 | $ | - | ||||||||
|
Other
contracts
|
124 | - | - | - | ||||||||||||
|
Total
derivatives
|
$ | 124 | $ | 8,584 | $ | 6,551 | $ | - | ||||||||
The
following table presents the location of gains and losses reported in the
Consolidated Statements of Operations for the current and previous periods
presented.
|
Derivatives
gain (loss) recognized in
Other
Revenues
|
||||||||||||
|
Years
Ended December 31,
|
||||||||||||
|
Derivatives
not designated
as
hedging instruments
|
2009
|
2008
|
2007
|
|||||||||
|
(in
thousands)
|
||||||||||||
|
Commodity
contracts
|
$ | (11,723 | ) | $ | 146,482 | $ | (86,434 | ) | ||||
|
Foreign
exchange contracts
|
799 | 375 | - | |||||||||
|
Other
contracts
|
(168 | ) | 313 | - | ||||||||
|
15.
|
Consolidating
Financial Statements
|
Frontier
Holdings Inc. and its subsidiaries (“FHI”) are full and unconditional guarantors
of the Company’s 6.625% Senior Notes and 8.5% Senior Notes. Presented
on the following pages are the Company’s condensed consolidating balance sheets,
statements of operations, and statements of 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 on the
following pages meet the requirements for financial statements of the issuer and
each guarantor of the notes because the guarantors are all direct or indirect
wholly-owned subsidiaries of Frontier Oil Corporation, 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. Accordingly, the equity in earnings of subsidiaries
recorded for Frontier Oil Corporation is equal to the subsidiaries’ net income
adjusted for consolidating pre-tax adjustments and for the portion of the
subsidiaries’ income tax provision which is eliminated in
consolidation.
|
CONSOLIDATING
FINANCIAL STATEMENTS
|
||||||||||||||||||||
|
FRONTIER
OIL CORPORATION
|
||||||||||||||||||||
|
Condensed
Consolidating Statement of Operations
|
||||||||||||||||||||
|
For
the Year Ended December 31, 2009
|
||||||||||||||||||||
|
(in
thousands)
|
||||||||||||||||||||
|
FOC
(Parent)
|
FHI
(Guarantor Subsidiaries)
|
Other
Non-Guarantor Subsidiaries
|
Eliminations
|
Consolidated
|
||||||||||||||||
|
Revenues:
|
||||||||||||||||||||
|
Refined
products
|
$ | - | $ | 4,242,966 | $ | - | $ | - | $ | 4,242,966 | ||||||||||
|
Other
|
(7 | ) | (5,809 | ) | 63 | - | (5,753 | ) | ||||||||||||
| (7 | ) | 4,237,157 | 63 | - | 4,237,213 | |||||||||||||||
|
Costs
and expenses:
|
||||||||||||||||||||
|
Raw
material, freight and other
costs
|
- | 3,888,308 | - | - | 3,888,308 | |||||||||||||||
|
Refinery
operating expenses, excluding
depreciation
|
- | 321,299 | - | - | 321,299 | |||||||||||||||
|
Selling
and general expenses, excluding
depreciation
|
23,836 | 34,832 | - | - | 58,668 | |||||||||||||||
|
Depreciation,
amortization and
accretion
|
70 | 73,608 | - | 630 | 74,308 | |||||||||||||||
| 23,906 | 4,318,047 | - | 630 | 4,342,583 | ||||||||||||||||
|
Operating
(loss) income
|
(23,913 | ) | (80,890 | ) | 63 | (630 | ) | (105,370 | ) | |||||||||||
|
Interest
expense and other financing
costs
|
29,278 | 4,254 | - | (5,345 | ) | 28,187 | ||||||||||||||
|
Interest
and investment income
|
(1,873 | ) | (406 | ) | - | - | (2,279 | ) | ||||||||||||
|
Equity
in earnings of subsidiaries
|
79,986 | - | - | (79,986 | ) | - | ||||||||||||||
| 107,391 | 3,848 | - | (85,331 | ) | 25,908 | |||||||||||||||
|
(Loss)
income before income taxes
|
(131,304 | ) | (84,738 | ) | 63 | 84,701 | (131,278 | ) | ||||||||||||
|
(Benefit)
provision for income taxes
|
(47,544 | ) | (32,523 | ) | 50 | 32,499 | (47,518 | ) | ||||||||||||
|
Net
(loss) income
|
$ | (83,760 | ) | $ | (52,215 | ) | $ | 13 | $ | 52,202 | $ | (83,760 | ) | |||||||
|
FRONTIER
OIL CORPORATION
|
||||||||||||||||||||
|
Condensed
Consolidating Statement of Operations
|
||||||||||||||||||||
|
For
the Year Ended December 31, 2008
|
||||||||||||||||||||
|
As
Adjusted (Note 3)
|
||||||||||||||||||||
|
(in
thousands)
|
||||||||||||||||||||
|
FOC
(Parent)
|
FHI
(Guarantor Subsidiaries)
|
Other
Non-Guarantor Subsidiaries
|
Eliminations
|
Consolidated
|
||||||||||||||||
|
Revenues:
|
||||||||||||||||||||
|
Refined
products
|
$ | - | $ | 6,342,144 | $ | - | $ | - | $ | 6,342,144 | ||||||||||
|
Other
|
(7 | ) | 156,287 | 356 | - | 156,636 | ||||||||||||||
| (7 | ) | 6,498,431 | 356 | - | 6,498,780 | |||||||||||||||
|
Costs
and expenses:
|
||||||||||||||||||||
|
Raw
material, freight and other
costs
|
- | 5,716,091 | - | - | 5,716,091 | |||||||||||||||
|
Refinery
operating expenses, excluding
depreciation
|
- | 321,364 | - | - | 321,364 | |||||||||||||||
|
Selling
and general expenses, excluding
depreciation
|
17,677 | 26,492 | - | - | 44,169 | |||||||||||||||
|
Depreciation,
amortization and
accretion
|
55 | 65,409 | - | 292 | 65,756 | |||||||||||||||
|
Gains
on sales of assets
|
(37 | ) | (7 | ) | - | - | (44 | ) | ||||||||||||
| 17,695 | 6,129,349 | - | 292 | 6,147,336 | ||||||||||||||||
|
Operating
income (loss)
|
(17,702 | ) | 369,082 | 356 | (292 | ) | 351,444 | |||||||||||||
|
Interest
expense and other financing
costs
|
15,939 | 5,570 | - | (6,379 | ) | 15,130 | ||||||||||||||
|
Interest
and investment income
|
(2,868 | ) | (2,557 | ) | - | - | (5,425 | ) | ||||||||||||
|
Equity
in earnings of subsidiaries
|
(371,830 | ) | - | - | 371,830 | - | ||||||||||||||
| (358,759 | ) | 3,013 | - | 365,451 | 9,705 | |||||||||||||||
|
Income
before income taxes
|
341,057 | 366,069 | 356 | (365,743 | ) | 341,739 | ||||||||||||||
|
Provision
for income taxes
|
115,004 | 127,280 | 139 | (126,737 | ) | 115,686 | ||||||||||||||
|
Net
income
|
$ | 226,053 | $ | 238,789 | $ | 217 | $ | (239,006 | ) | $ | 226,053 | |||||||||
|
FRONTIER
OIL CORPORATION
|
||||||||||||||||||||
|
Condensed
Consolidating Statement of Operations
|
||||||||||||||||||||
|
For
the Year Ended December 31, 2007
|
||||||||||||||||||||
|
As
Adjusted (Note 3)
|
||||||||||||||||||||
|
(in
thousands)
|
||||||||||||||||||||
|
FOC
(Parent)
|
FHI
(Guarantor Subsidiaries)
|
Other
Non-Guarantor Subsidiaries
|
Eliminations
|
Consolidated
|
||||||||||||||||
|
Revenues:
|
||||||||||||||||||||
|
Refined
products
|
$ | - | $ | 5,269,674 | $ | - | $ | - | $ | 5,269,674 | ||||||||||
|
Other
|
2 | (80,981 | ) | 45 | - | (80,934 | ) | |||||||||||||
| 2 | 5,188,693 | 45 | - | 5,188,740 | ||||||||||||||||
|
Costs
and expenses:
|
||||||||||||||||||||
|
Raw
material, freight and other
costs
|
- | 4,194,971 | - | - | 4,194,971 | |||||||||||||||
|
Refinery
operating expenses, excluding
depreciation
|
- | 300,542 | - | - | 300,542 | |||||||||||||||
|
Selling
and general expenses, excluding
depreciation
|
30,593 | 24,750 | - | - | 55,343 | |||||||||||||||
|
Depreciation,
amortization and
accretion
|
61 | 53,299 | - | (321 | ) | 53,039 | ||||||||||||||
|
Loss
(gain) on sales of assets
|
2,028 | (17,242 | ) | - | - | (15,214 | ) | |||||||||||||
| 32,682 | 4,556,320 | - | (321 | ) | 4,588,681 | |||||||||||||||
|
Operating
income (loss)
|
(32,680 | ) | 632,373 | 45 | 321 | 600,059 | ||||||||||||||
|
Interest
expense and other financing costs
|
12,723 | 4,122 | - | (8,072 | ) | 8,773 | ||||||||||||||
|
Interest
and investment income
|
(11,202 | ) | (10,649 | ) | - | - | (21,851 | ) | ||||||||||||
|
Equity
in earnings of subsidiaries
|
(646,626 | ) | - | - | 646,626 | - | ||||||||||||||
| (645,105 | ) | (6,527 | ) | - | 638,554 | (13,078 | ) | |||||||||||||
|
Income
before income taxes
|
612,425 | 638,900 | 45 | (638,233 | ) | 613,137 | ||||||||||||||
|
Provision
for income taxes
|
210,093 | 220,230 | 15 | (219,533 | ) | 210,805 | ||||||||||||||
|
Net
income
|
$ | 402,332 | $ | 418,670 | $ | 30 | $ | (418,700 | ) | $ | 402,332 | |||||||||
|
FRONTIER
OIL CORPORATION
|
||||||||||||||||||||
|
Condensed
Consolidating Balance Sheet
|
||||||||||||||||||||
|
As
of December 31, 2009
|
||||||||||||||||||||
|
(in
thousands)
|
||||||||||||||||||||
|
FOC
(Parent)
|
FHI
(Guarantor Subsidiaries)
|
Other
Non-Guarantor Subsidiaries
|
Eliminations
|
Consolidated
|
||||||||||||||||
|
ASSETS
|
||||||||||||||||||||
|
Current
assets:
|
||||||||||||||||||||
|
Cash
and cash equivalents
|
$ | 211,775 | $ | 213,505 | $ | - | $ | - | $ | 425,280 | ||||||||||
|
Trade
and other receivables, net
|
174,843 | 102,887 | - | - | 277,730 | |||||||||||||||
|
Inventory
of crude oil, products
and other
|
- | 293,476 | - | - | 293,476 | |||||||||||||||
|
Deferred
income tax assets - current
|
26,373 | 26,442 | - | (26,442 | ) | 26,373 | ||||||||||||||
|
Other
current assets
|
926 | 13,581 | - | - | 14,507 | |||||||||||||||
|
Total
current assets
|
413,917 | 649,891 | - | (26,442 | ) | 1,037,366 | ||||||||||||||
|
Property,
plant and equipment, at
cost
|
1,298 | 1,446,822 | - | 15,451 | 1,463,571 | |||||||||||||||
|
Accumulated
depreciation and
amortization
|
(924 | ) | (448,242 | ) | - | 7,004 | (442,162 | ) | ||||||||||||
|
Property,
plant and equipment, net
|
374 | 998,580 | - | 22,455 | 1,021,409 | |||||||||||||||
|
Deferred
turnaround costs
|
- | 56,355 | - | - | 56,355 | |||||||||||||||
|
Deferred
catalyst costs
|
- | 12,136 | - | - | 12,136 | |||||||||||||||
|
Deferred
financing costs, net
|
2,857 | 1,854 | - | - | 4,711 | |||||||||||||||
|
Intangible
assets, net
|
- | 1,216 | - | - | 1,216 | |||||||||||||||
|
Deferred
income tax assets - noncurrent
|
10,767 | 7,702 | - | (7,702 | ) | 10,767 | ||||||||||||||
|
Other
assets
|
3,665 | 270 | - | - | 3,935 | |||||||||||||||
|
Receivable
from affiliated companies
(1)
|
- | 61,165 | 516 | (61,681 | ) | - | ||||||||||||||
|
Investment
in subsidiaries
|
1,144,040 | - | - | (1,144,040 | ) | - | ||||||||||||||
|
Total
assets
|
$ | 1,575,620 | $ | 1,789,169 | $ | 516 | $ | (1,217,410 | ) | $ | 2,147,895 | |||||||||
|
LIABILITIES
AND SHAREHOLDERS' EQUITY
|
||||||||||||||||||||
|
Current
liabilities:
|
||||||||||||||||||||
|
Accounts
payable
|
$ | 906 | $ | 473,456 | $ | 15 | $ | - | $ | 474,377 | ||||||||||
|
Accrued
liabilities and other
|
20,916 | 43,883 | - | - | 64,799 | |||||||||||||||
|
Total
current liabilities
|
21,822 | 517,339 | 15 | - | 539,176 | |||||||||||||||
|
Long-term
debt
|
347,485 | - | - | - | 347,485 | |||||||||||||||
|
Contingent
income tax liabilities
|
27,267 | 2,081 | - | - | 29,348 | |||||||||||||||
|
Long-term
capital lease obligations
|
- | 3,394 | - | - | 3,394 | |||||||||||||||
|
Other
long-term liabilities
|
3,578 | 50,120 | - | - | 53,698 | |||||||||||||||
|
Deferred
income tax liabilities
|
230,818 | 224,680 | - | (224,680 | ) | 230,818 | ||||||||||||||
|
Payable
to affiliated companies
|
674 | - | 234 | (908 | ) | - | ||||||||||||||
|
Shareholders'
equity
|
943,976 | 991,555 | 267 | (991,822 | ) | 943,976 | ||||||||||||||
|
Total
liabilities and shareholders'
equity
|
$ | 1,575,620 | $ | 1,789,169 | $ | 516 | $ | (1,217,410 | ) | $ | 2,147,895 | |||||||||
|
(1)
FHI receivable from affiliated companies balance relates to income taxes
receivable from parent under a tax sharing agreement.
|
||||||||||||||||||||
|
FRONTIER
OIL CORPORATION
|
||||||||||||||||||||
|
Condensed
Consolidating Balance Sheet
|
||||||||||||||||||||
|
As
of December 31, 2008
|
||||||||||||||||||||
|
As
Adjusted (Note 3)
|
||||||||||||||||||||
|
(in
thousands)
|
||||||||||||||||||||
|
FOC
(Parent)
|
FHI
(Guarantor Subsidiaries)
|
Other
Non-Guarantor Subsidiaries
|
Eliminations
|
Consolidated
|
||||||||||||||||
|
ASSETS
|
||||||||||||||||||||
|
Current
assets:
|
||||||||||||||||||||
|
Cash
and cash equivalents
|
$ | 254,548 | $ | 228,984 | $ | - | $ | - | $ | 483,532 | ||||||||||
|
Trade
and other receivables, net
|
120,265 | 105,169 | 10 | - | 225,444 | |||||||||||||||
|
Inventory
of crude oil, products
and other
|
- | 236,505 | - | - | 236,505 | |||||||||||||||
|
Deferred
income tax assets
|
16,301 | 16,494 | - | (16,494 | ) | 16,301 | ||||||||||||||
|
Commutation
account
|
6,319 | - | - | - | 6,319 | |||||||||||||||
|
Other
current assets
|
643 | 36,395 | 37,038 | |||||||||||||||||
|
Total
current assets
|
398,076 | 623,547 | 10 | (16,494 | ) | 1,005,139 | ||||||||||||||
|
Property,
plant and equipment, at
cost
|
1,248 | 1,295,420 | - | 10,076 | 1,306,744 | |||||||||||||||
|
Accumulated
depreciation and
amortization
|
(998 | ) | (379,967 | ) | - | 7,664 | (373,301 | ) | ||||||||||||
|
Property,
plant and equipment, net
|
250 | 915,453 | - | 17,740 | 933,443 | |||||||||||||||
|
Deferred
turnaround costs
|
- | 47,465 | - | - | 47,465 | |||||||||||||||
|
Deferred
catalyst costs
|
- | 9,726 | - | - | 9,726 | |||||||||||||||
|
Deferred
financing costs, net
|
3,642 | 2,559 | - | - | 6,201 | |||||||||||||||
|
Intangible
assets, net
|
- | 1,338 | - | - | 1,338 | |||||||||||||||
|
Other
assets
|
2,600 | 393 | - | - | 2,993 | |||||||||||||||
|
Receivable
from affiliated companies
(1)
|
646 | 25,733 | 468 | (26,847 | ) | - | ||||||||||||||
|
Investment
in subsidiaries
|
1,216,054 | - | - | (1,216,054 | ) | - | ||||||||||||||
|
Total
assets
|
$ | 1,621,268 | $ | 1,626,214 | $ | 478 | $ | (1,241,655 | ) | $ | 2,006,305 | |||||||||
|
LIABILITIES
AND SHAREHOLDERS' EQUITY
|
||||||||||||||||||||
|
Current
liabilities:
|
||||||||||||||||||||
|
Accounts
payable
|
$ | 1,168 | $ | 307,684 | $ | 15 | $ | - | $ | 308,867 | ||||||||||
|
Accrued
liabilities and other
|
26,071 | 31,013 | - | - | 57,084 | |||||||||||||||
|
Total
current liabilities
|
27,239 | 338,697 | 15 | - | 365,951 | |||||||||||||||
|
Long-term
debt
|
347,220 | - | - | - | 347,220 | |||||||||||||||
|
Contingent
income tax liabilities
|
26,112 | 1,945 | - | - | 28,057 | |||||||||||||||
|
Long-term
capital lease obligations
|
- | 3,548 | - | - | 3,548 | |||||||||||||||
|
Other
long-term liabilities
|
2,507 | 40,832 | - | - | 43,339 | |||||||||||||||
|
Deferred
income tax liabilities
|
179,214 | 174,597 | - | (174,597 | ) | 179,214 | ||||||||||||||
|
Payable
to affiliated companies
|
- | 1,114 | 209 | (1,323 | ) | - | ||||||||||||||
|
Shareholders'
equity
|
1,038,976 | 1,065,481 | 254 | (1,065,735 | ) | 1,038,976 | ||||||||||||||
|
Total
liabilities and shareholders'
equity
|
$ | 1,621,268 | $ | 1,626,214 | $ | 478 | $ | (1,241,655 | ) | $ | 2,006,305 | |||||||||
|
(1)
FHI receivable from affiliated companies balance relates to income taxes
receivable from parent under a tax sharing agreement.
|
||||||||||||||||||||
|
FRONTIER
OIL CORPORATION
|
||||||||||||||||||||
|
Condensed
Consolidating Statement of Cash Flows
|
||||||||||||||||||||
|
For
the Year Ended December 31, 2009
|
||||||||||||||||||||
|
(in
thousands)
|
||||||||||||||||||||
|
FOC
(Parent)
|
FHI
(Guarantor Subsidiaries)
|
Other
Non-Guarantor Subsidiaries
|
Eliminations
|
Consolidated
|
||||||||||||||||
|
Cash
flows from operating activities:
|
||||||||||||||||||||
|
Net
income
|
$ | (83,760 | ) | $ | (52,215 | ) | $ | 13 | $ | 52,202 | $ | (83,760 | ) | |||||||
|
Adjustments
to reconcile net income to
net cash from operating activities:
|
||||||||||||||||||||
|
Equity
in earnings of subsidiaries
|
79,986 | - | - | (79,986 | ) | - | ||||||||||||||
|
Depreciation,
amortization and accretion
|
70 | 93,093 | - | 630 | 93,793 | |||||||||||||||
|
Deferred
income taxes
|
31,082 | - | - | - | 31,082 | |||||||||||||||
|
Stock-based
compensation expense
|
20,608 | - | - | - | 20,608 | |||||||||||||||
|
Excess
income tax benefits of stock-based
compensation
|
(244 | ) | - | - | - | (244 | ) | |||||||||||||
|
Intercompany
income taxes
|
(30,000 | ) | (2,523 | ) | 24 | 32,499 | - | |||||||||||||
|
Intercompany
dividends
|
21,200 | - | - | (21,200 | ) | - | ||||||||||||||
|
Other
intercompany transactions
|
1,321 | (1,273 | ) | (48 | ) | - | - | |||||||||||||
|
Amortization
of debt issuance costs
|
783 | 706 | - | - | 1,489 | |||||||||||||||
|
Senior
notes discount amortization
|
264 | - | - | - | 264 | |||||||||||||||
|
Allowance
for bad debts
|
- | 500 | - | - | 500 | |||||||||||||||
|
Increase
in other long-term liabilities
|
2,633 | 8,196 | - | - | 10,829 | |||||||||||||||
|
Changes
in deferred turnaround costs, deferred
catalyst costs and
other
|
(1,065 | ) | (30,663 | ) | - | - | (31,728 | ) | ||||||||||||
|
Changes
in components of working capital
from operations
|
(57,416 | ) | 155,233 | 11 | 281 | 98,109 | ||||||||||||||
|
Net
cash (used in) provided by operating
activities
|
(14,538 | ) | 171,054 | - | (15,574 | ) | 140,942 | |||||||||||||
|
Cash
flows from investing activities:
|
||||||||||||||||||||
|
Additions
to property, plant and equipment
|
(194 | ) | (162,850 | ) | - | (5,626 | ) | (168,670 | ) | |||||||||||
|
Other
acquisitions
|
- | (2,100 | ) | - | - | (2,100 | ) | |||||||||||||
|
Net
cash used in investing activities
|
(194 | ) | (164,950 | ) | - | (5,626 | ) | (170,770 | ) | |||||||||||
|
Cash
flows from financing activities:
|
||||||||||||||||||||
|
Purchase
of treasury stock
|
(3,008 | ) | - | - | - | (3,008 | ) | |||||||||||||
|
Proceeds
from issuance of common stock
|
70 | - | - | - | 70 | |||||||||||||||
|
Dividends
paid
|
(25,349 | ) | - | - | - | (25,349 | ) | |||||||||||||
|
Excess
income tax benefits of stock-based
compensation
|
244 | - | - | - | 244 | |||||||||||||||
|
Debt
issuance costs and other
|
2 | (383 | ) | - | - | (381 | ) | |||||||||||||
|
Intercompany
dividends
|
- | (21,200 | ) | - | 21,200 | - | ||||||||||||||
|
Net
cash used in financing activities
|
(28,041 | ) | (21,583 | ) | - | 21,200 | (28,424 | ) | ||||||||||||
|
Decrease
in cash and cash equivalents
|
(42,773 | ) | (15,479 | ) | - | - | (58,252 | ) | ||||||||||||
|
Cash
and cash equivalents, beginning
of period
|
254,548 | 228,984 | - | - | 483,532 | |||||||||||||||
|
Cash
and cash equivalents, end of period
|
$ | 211,775 | $ | 213,505 | $ | - | $ | - | $ | 425,280 | ||||||||||
|
FRONTIER
OIL CORPORATION
|
||||||||||||||||||||
|
Condensed
Consolidating Statement of Cash Flows
|
||||||||||||||||||||
|
For
the Year Ended December 31, 2008
|
||||||||||||||||||||
|
As
Adjusted (Note 3)
|
||||||||||||||||||||
|
(in
thousands)
|
||||||||||||||||||||
|
FOC
(Parent)
|
FHI
(Guarantor Subsidiaries)
|
Other
Non-Guarantor Subsidiaries
|
Eliminations
|
Consolidated
|
||||||||||||||||
|
Cash
flows from operating activities:
|
||||||||||||||||||||
|
Net
income
|
$ | 226,053 | $ | 238,789 | $ | 217 | $ | (239,006 | ) | $ | 226,053 | |||||||||
|
Adjustments
to reconcile net income to
net cash from operating activities:
|
||||||||||||||||||||
|
Equity
in earnings of subsidiaries
|
(371,830 | ) | - | - | 371,830 | - | ||||||||||||||
|
Depreciation,
amortization and accretion
|
55 | 83,224 | - | 292 | 83,571 | |||||||||||||||
|
Deferred
income taxes
|
169,766 | - | - | - | 169,766 | |||||||||||||||
|
Stock-based
compensation expense
|
20,014 | - | - | - | 20,014 | |||||||||||||||
|
Excess
income tax benefits of stock-based
compensation
|
(3,191 | ) | - | - | - | (3,191 | ) | |||||||||||||
|
Intercompany
income taxes
|
(6,000 | ) | 132,598 | 139 | (126,737 | ) | - | |||||||||||||
|
Intercompany
dividends
|
10,000 | - | - | (10,000 | ) | - | ||||||||||||||
|
Other
intercompany transactions
|
(3,261 | ) | 3,433 | (172 | ) | - | - | |||||||||||||
|
Amortization
of debt issuance costs
|
570 | 408 | - | - | 978 | |||||||||||||||
|
Senior
notes discount amortization
|
60 | - | - | - | 60 | |||||||||||||||
|
Allowance
for investment loss
|
41 | 458 | - | - | 499 | |||||||||||||||
|
Gains
on sales of assets
|
(37 | ) | (7 | ) | - | - | (44 | ) | ||||||||||||
|
Amortization
of long-term prepaid insurance
|
909 | - | - | - | 909 | |||||||||||||||
|
(Decrease)
increase in other long-term
liabilities
|
(3,716 | ) | 543 | - | - | (3,173 | ) | |||||||||||||
|
Changes
in deferred turnaround costs, deferred
catalyst costs and
other
|
713 | (29,471 | ) | - | - | (28,758 | ) | |||||||||||||
|
Changes
in components of working capital
from operations
|
(80,054 | ) | (90,758 | ) | (184 | ) | 1,587 | (169,409 | ) | |||||||||||
|
Net
cash (used in) provided by operating
activities
|
(39,908 | ) | 339,217 | - | (2,034 | ) | 297,275 | |||||||||||||
|
Cash
flows from investing activities:
|
||||||||||||||||||||
|
Additions
to property, plant and equipment
|
(129 | ) | (201,286 | ) | - | (7,966 | ) | (209,381 | ) | |||||||||||
|
Proceeds
from sales of assets
|
37 | 9 | - | - | 46 | |||||||||||||||
|
El
Dorado Refinery contingent earn-out
payment
|
- | (7,500 | ) | - | - | (7,500 | ) | |||||||||||||
|
Net
cash used in investing activities
|
(92 | ) | (208,777 | ) | - | (7,966 | ) | (216,835 | ) | |||||||||||
|
Cash
flows from financing activities:
|
||||||||||||||||||||
|
Proceeds
from issuance of 8.5% Senior
Notes
|
197,160 | - | - | - | 197,160 | |||||||||||||||
|
Purchase
of treasury stock
|
(67,030 | ) | - | - | - | (67,030 | ) | |||||||||||||
|
Proceeds
from issuance of common stock
|
405 | - | - | - | 405 | |||||||||||||||
|
Dividends
paid
|
(23,144 | ) | - | - | - | (23,144 | ) | |||||||||||||
|
Excess
income tax benefits of stock-based
compensation
|
3,191 | - | - | - | 3,191 | |||||||||||||||
|
Debt
issuance costs and other
|
(2,402 | ) | (2,487 | ) | - | - | (4,889 | ) | ||||||||||||
|
Intercompany
dividends
|
- | (10,000 | ) | - | 10,000 | - | ||||||||||||||
|
Net
cash provided by (used in) financing
activities
|
108,180 | (12,487 | ) | - | 10,000 | 105,693 | ||||||||||||||
|
Increase
in cash and cash equivalents
|
68,180 | 117,953 | - | - | 186,133 | |||||||||||||||
|
Cash
and cash equivalents, beginning
of period
|
186,368 | 111,031 | - | - | 297,399 | |||||||||||||||
|
Cash
and cash equivalents, end of period
|
$ | 254,548 | $ | 228,984 | $ | - | $ | - | $ | 483,532 | ||||||||||
|
FRONTIER
OIL CORPORATION
|
||||||||||||||||||||
|
Condensed
Consolidating Statement of Cash Flows
|
||||||||||||||||||||
|
For
the Year Ended December 31, 2007
|
||||||||||||||||||||
|
As
Adjusted (Note 3)
|
||||||||||||||||||||
|
(in
thousands)
|
||||||||||||||||||||
|
FOC
(Parent)
|
FHI
(Guarantor Subsidiaries)
|
Other
Non-Guarantor Subsidiaries
|
Eliminations
|
Consolidated
|
||||||||||||||||
|
Cash
flows from operating activities:
|
||||||||||||||||||||
|
Net
income
|
$ | 402,332 | $ | 418,670 | $ | 30 | $ | (418,700 | ) | $ | 402,332 | |||||||||
|
Adjustments
to reconcile net income to
net cash from operating activities:
|
||||||||||||||||||||
|
Equity
in earnings of subsidiaries
|
(646,626 | ) | - | - | 646,626 | - | ||||||||||||||
|
Depreciation,
amortization and accretion
|
61 | 67,772 | - | (321 | ) | 67,512 | ||||||||||||||
|
Deferred
income taxes
|
(60,859 | ) | - | - | - | (60,859 | ) | |||||||||||||
|
Stock-based
compensation expense
|
22,553 | - | - | - | 22,553 | |||||||||||||||
|
Excess
income tax benefits of stock-based
compensation
|
(6,962 | ) | - | - | - | (6,962 | ) | |||||||||||||
|
Intercompany
income taxes
|
317,500 | (97,982 | ) | 15 | (219,533 | ) | - | |||||||||||||
|
Intercompany
dividends
|
212,150 | - | - | (212,150 | ) | - | ||||||||||||||
|
Other
intercompany transactions
|
1,110 | (1,065 | ) | (45 | ) | - | - | |||||||||||||
|
Amortization
of debt issuance costs
|
483 | 286 | - | - | 769 | |||||||||||||||
|
Loss
(gain) on sales of assets
|
2,028 | (17,242 | ) | - | - | (15,214 | ) | |||||||||||||
|
Decrease
in long-term commutation
account
|
1,009 | - | - | - | 1,009 | |||||||||||||||
|
Amortization
of long-term prepaid insurance
|
1,211 | - | - | - | 1,211 | |||||||||||||||
|
Increase
(decrease) in other long-term
liabilities
|
31,058 | (3,693 | ) | - | - | 27,365 | ||||||||||||||
|
Changes
in deferred turnaround costs,
deferred catalyst costs and other
|
(578 | ) | (28,709 | ) | - | - | (29,287 | ) | ||||||||||||
|
Changes
in components of working capital
from operations
|
(46,639 | ) | 66,836 | - | (1,613 | ) | 18,584 | |||||||||||||
|
Net
cash (used in) provided by operating
activities
|
229,831 | 404,873 | - | (205,691 | ) | 429,013 | ||||||||||||||
|
Cash
flows from investing activities:
|
||||||||||||||||||||
|
Additions
to property, plant and equipment
|
(4,310 | ) | (280,405 | ) | - | (6,459 | ) | (291,174 | ) | |||||||||||
|
Proceeds
from sale of assets
|
2,290 | 19,932 | - | - | 22,222 | |||||||||||||||
|
El
Dorado Refinery contingent earn-out
payment
|
- | (7,500 | ) | - | - | (7,500 | ) | |||||||||||||
|
Other
acquisitions and leasehold improvements
|
- | (3,561 | ) | - | - | (3,561 | ) | |||||||||||||
|
Net
cash used in investing activities
|
(2,020 | ) | (271,534 | ) | - | (6,459 | ) | (280,013 | ) | |||||||||||
|
Cash
flows from financing activities:
|
||||||||||||||||||||
|
Purchase
of treasury stock
|
(248,486 | ) | - | - | - | (248,486 | ) | |||||||||||||
|
Proceeds
from issuance of common stock
|
2,303 | - | - | - | 2,303 | |||||||||||||||
|
Dividends
paid
|
(17,271 | ) | - | - | - | (17,271 | ) | |||||||||||||
|
Excess
income tax benefits of stock-based
compensation
|
6,962 | - | - | - | 6,962 | |||||||||||||||
|
Debt
issuance costs and other
|
- | (588 | ) | - | - | (588 | ) | |||||||||||||
|
Intercompany
dividends
|
- | (212,150 | ) | - | 212,150 | - | ||||||||||||||
|
Net
cash used in financing activities
|
(256,492 | ) | (212,738 | ) | - | 212,150 | (257,080 | ) | ||||||||||||
|
Decrease
in cash and cash equivalents
|
(28,681 | ) | (79,399 | ) | - | - | (108,080 | ) | ||||||||||||
|
Cash
and cash equivalents, beginning of
period
|
215,049 | 190,430 | - | - | 405,479 | |||||||||||||||
|
Cash
and cash equivalents, end of period
|
$ | 186,368 | $ | 111,031 | $ | - | $ | - | $ | 297,399 | ||||||||||
16. Selected
Quarterly Financial and Operating Data (Unaudited)
|
As
Adjusted, except for the fourth quarter 2009
(3)
|
||||||||||||||||||||||||||||||||
|
(Dollars
in thousands, except per share and per bbl)
|
||||||||||||||||||||||||||||||||
|
2009
|
2008
|
|||||||||||||||||||||||||||||||
|
Fourth
|
Third
|
Second
|
First
|
Fourth
|
Third
|
Second
|
First
|
|||||||||||||||||||||||||
|
Revenues
|
$ | 1,088,539 | $ | 1,200,582 | $ | 1,101,844 | $ | 846,248 | $ | 1,348,139 | $ | 2,198,302 | $ | 1,766,556 | $ | 1,185,783 | ||||||||||||||||
|
Operating
income (loss) (3)
|
(114,365 | ) | (4,480 | ) | (82,706 | ) | 96,181 | 206,596 | 208,295 | (33,649 | ) | (29,798 | ) | |||||||||||||||||||
|
Net
income (loss) (3)
|
(75,054 | ) | (8,784 | ) | (57,872 | ) | 57,950 | 118,976 | 137,279 | (11,793 | ) | (18,409 | ) | |||||||||||||||||||
|
Basic
net income (loss)
per
share (3)
|
(0.72 | ) | (0.08 | ) | (0.56 | ) | 0.56 | 1.15 | 1.33 | (0.11 | ) | (0.18 | ) | |||||||||||||||||||
|
Diluted
net income (loss)
per
share (3)
|
(0.72 | ) | (0.08 | ) | (0.56 | ) | 0.56 | 1.15 | 1.32 | (0.11 | ) | (0.18 | ) | |||||||||||||||||||
|
Refining
operations:
|
||||||||||||||||||||||||||||||||
|
Total
charges (bpd) (1)
|
138,673 | 177,741 | 181,152 | 182,475 | 185,599 | 173,954 | 161,380 | 126,018 | ||||||||||||||||||||||||
|
Gasoline
yields (bpd) (2)
|
69,493 | 84,913 | 83,723 | 82,768 | 88,680 | 78,755 | 73,203 | 65,498 | ||||||||||||||||||||||||
|
Diesel
and jet fuel
yields
(bpd) (2)
|
52,360 | 67,167 | 74,059 | 70,759 | 75,256 | 66,424 | 54,220 | 38,824 | ||||||||||||||||||||||||
|
Total
product sales (bpd)
|
152,672 | 178,163 | 191,106 | 179,413 | 191,952 | 177,219 | 158,766 | 137,148 | ||||||||||||||||||||||||
|
Average
gasoline crack
spread
(per bbl)
|
$ | 4.40 | $ | 7.92 | $ | 10.85 | $ | 7.04 | $ | (0.95 | ) | $ | 9.42 | $ | 5.85 | $ | 4.24 | |||||||||||||||
|
Average
diesel crack
spread
(per bbl)
|
7.03 | 7.94 | 6.28 | 11.69 | 21.81 | 26.76 | 28.70 | 20.92 | ||||||||||||||||||||||||
|
Cheyenne
average
light/heavy
crude oil
differential
(per bbl)
|
8.56 | 7.11 | 4.93 | 5.84 | 15.68 | 14.02 | 20.54 | 18.36 | ||||||||||||||||||||||||
|
El
Dorado average
light/heavy
crude oil
differential
(per bbl)
|
6.93 | 5.69 | 3.90 | 7.54 | 14.40 | 14.33 | 22.44 | 21.45 | ||||||||||||||||||||||||
|
Average
WTI/WTS crude
oil
differential (per bbl)
|
2.27 | 1.62 | 1.02 | 1.69 | 3.30 | 2.77 | 4.98 | 4.64 | ||||||||||||||||||||||||
|
(1)
Charges are the quantity of crude oil and other feedstock processed
through refinery units.
|
||||||||||||||||||||||||||||||||
|
(2)
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.
|
||||||||||||||||||||||||||||||||
|
(3)
Prior quarter and prior year amounts are adjusted from previously
disclosed amounts to reflect current year presentation under the LIFO
inventory method. The
following presents prior period presentation as previously disclosed and
the related change:
|
||||||||||||||||||||||||||||||||
|
2009
|
||||||||||||||||||||||||||||||
|
Third
Quarter
|
Second
Quarter
|
First
Quarter
|
||||||||||||||||||||||||||||
|
As
Reported
|
As
Adjusted
|
Change
|
As
Reported
|
As
Adjusted
|
Change
|
As
Reported
|
As
Adjusted
|
Change
|
||||||||||||||||||||||
|
(in
thousands, except per share amounts)
|
||||||||||||||||||||||||||||||
|
Operating
income (loss)
|
$ | (12,427 | ) | $ | (4,480 | ) | $ | 7,947 | $ | 84,305 | $ | (82,706 | ) | $ | (167,011 | ) | $ | 119,910 | $ | 96,181 | $ | (23,729 | ) | |||||||
|
Net
income (loss)
|
(15,127 | ) | (8,784 | ) | 6,343 | 49,841 | (57,872 | ) | (107,713 | ) | 73,459 | 57,950 | (15,509 | ) | ||||||||||||||||
|
Basic
net income (loss) per
share
|
(0.15 | ) | (0.08 | ) | 0.07 | 0.48 | (0.56 | ) | (1.04 | ) | 0.71 | 0.56 | (0.15 | ) | ||||||||||||||||
|
Diluted
net income (loss) per
share
|
(0.15 | ) | (0.08 | ) | 0.07 | 0.47 | (0.56 | ) | (1.03 | ) | 0.70 | 0.56 | (0.14 | ) | ||||||||||||||||
| 2008 | ||||||||||||||||||||||||||||||
|
Fourth
Quarter
|
Third
Quarter
|
Second
Quarter
|
||||||||||||||||||||||||||||
|
As
Reported
|
As
Adjusted
|
Change
|
As
Reported
|
As
Adjusted
|
Change
|
As
Reported
|
As
Adjusted
|
Change
|
||||||||||||||||||||||
|
(in
thousands, except per share amounts)
|
||||||||||||||||||||||||||||||
|
Operating
income (loss)
|
$ | (142,628 | ) | $ | 206,596 | $ | 349,224 | $ | 103,558 | $ | 208,295 | $ | 104,737 | $ | 81,986 | $ | (33,649 | ) | $ | (115,635 | ) | |||||||||
|
Net
income (loss)
|
(97,374 | ) | 118,976 | 216,350 | 72,323 | 137,279 | 64,956 | 59,316 | (11,793 | ) | (71,109 | ) | ||||||||||||||||||
|
Basic
net income (loss) per
share
|
(0.94 | ) | 1.15 | 2.09 | 0.70 | 1.33 | 0.63 | 0.58 | (0.11 | ) | (0.69 | ) | ||||||||||||||||||
|
Diluted
net income (loss) per
share
|
(0.94 | ) | 1.15 | 2.09 | 0.70 | 1.32 | 0.62 | 0.57 | (0.11 | ) | (0.68 | ) | ||||||||||||||||||
| 2008 | ||||||||||||||||||||||||||||||
|
First
Quarter
|
||||||||||||||||||||||||||||||
|
As
Reported
|
As
Adjusted
|
Change
|
||||||||||||||||||||||||||||
|
(in
thousands, except per share amounts)
|
||||||||||||||||||||||||||||||
|
Operating
income (loss)
|
$ | 73,837 | $ | (29,798 | ) | $ | (103,635 | ) | ||||||||||||||||||||||
|
Net
income (loss)
|
45,969 | (18,409 | ) | (64,378 | ) | |||||||||||||||||||||||||
|
Basic
net income (loss) per
share
|
0.45 | (0.18 | ) | (0.63 | ) | |||||||||||||||||||||||||
|
Diluted
net income (loss) per
share
|
0.44 | (0.18 | ) | (0.62 | ) | |||||||||||||||||||||||||
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, and that such information is accumulated and communicated
to management, including the Chief Executive Officer and Chief Financial
Officer, as appropriate, to allow timely decisions regarding required
disclosure. Management necessarily applies its judgment in assessing
the costs and benefits of such controls and procedures, which, by their nature,
can provide only reasonable assurance regarding management's control
objectives.
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 President and Chief
Executive Officer, our Executive Vice President and Chief Financial Officer and
our Vice-President and Chief Accounting Officer, the effectiveness of our
disclosure controls and procedures pursuant to Rule 13a-15 of the Exchange
Act. Based on that evaluation, our President and Chief Executive
Officer, our Executive Vice President and Chief Financial Officer and our
Vice-President and Chief Accounting 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.
Our
“Management’s Report on Internal Control Over Financial Reporting” and the
related “Report of Independent Registered Public Accounting Firm” on our report
are include on pages 24 and 26.
|
Item 9B.
|
Other
Information
|
None.
The
information required 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.
|
Item
15.
|
Exhibits
and Financial Statement Schedules
|
|
(a)1.
Financial Statements and Supplemental Data
|
|
(a)2.
Financial Statements Schedules
|
|
Other
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
|
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).
|
| 3.1 | Second Amended and Restated Articles of Incorporation of Frontier Oil Corporation dated May 1, 2009. | |
| * |
3.2
|
Fifth
Restated Bylaws of Wainoco Oil Corporation (now Frontier Oil Corporation),
effective November 12, 2008 (Exhibit 2.1 to Form 8-K, File Number 1-07627,
filed November 14, 2008).
|
|
*
|
4.1
|
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 6.625% Senior Notes due 2011 (Exhibit 4.1 to Form 8-K, File
Number 1-07627, filed October 4, 2004).
|
|
*
|
4.2
|
Indenture,
dated as of September 17, 2008, among Frontier Oil Corporation, the
guarantors named therein and Wells Fargo Bank, N.A., as trustee relating
to the Company’s 8.5% Senior Notes due 2016 (Exhibit 4.1 to Form 8-K, File
Number 1-07627, filed September 17, 2008).
|
|
*
|
4.3
|
First
Supplemental Indenture, dated as of September 17, 2008, among Frontier Oil
Corporation, the guarantors named therein and Wells Fargo Bank, N.A., as
trustee relating to the Company’s 8.5% Senior Notes due 2016 (Exhibit 4.2
to Form 8-K, File Number 1-07627, filed September 17,
2008).
|
|
*
|
4.4
|
Form
of the Company’s global note for 8.5% Senior Notes due 2016 (Exhibit 4.3
to Form 8-K, File Number1-07627, filed September 17,
2008).
|
|
*²
|
10.1
|
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
|
10.2
|
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).
|
|
*
|
10.3
|
Master
Crude Oil Purchase and Sale Contract, dated March 10, 2006, among Utexam
Limited, Frontier Oil and Refining Company and the Company (Exhibit 10.1
to Form 8-K, File Number 1-07627, filed March 14,
2006).
|
|
*
|
10.4
|
First
Amendment to Master Crude Oil Purchase and Sale Contract, dated April 2,
2006, among Utexam Limited, Frontier Oil and Refining Company and the
Company (Exhibit 10.4 to Form 10-K, File Number 1-07627, filed February
26, 2009).
|
|
*
|
10.5
|
Second
Amendment to Master Crude Oil Purchase and Sale Contract, dated March 12,
2008, among Utexam Limited, Frontier Oil and Refining Company and the
Company (Exhibit 10.1 to Form 8-K, File Number 1-07627, filed March 17,
2008).
|
|
*
|
10.6
|
Third
Amendment to Master Crude Oil Purchase and Sale Contract dated July 1,
2009, among Utexam Limited, Frontier Oil and Refining Company and the
Company (Exhibit 10.1 to Form 8-K, File Number 1-07627, filed July 1,
2009).
|
|
*
|
10.7
|
Guaranty,
dated March 10, 2006, by the Company in favor of Utexam Limited (Exhibit
10.2 to Form 8-K, File Number 1-07627, filed March 14,
2006).
|
|
*
|
10.8
|
Consent
of Frontier Oil and Refining Company to the Second Amendment to the
Revolving Credit Agreement (Uncommitted) dated as of March 8, 2007, among
Utexam Limited, as borrower, BNP Paribas, as administrative agent and the
lenders party thereto, and Consent of Frontier Oil and Refining Company to
the Third Amendment to the Revolving Credit Agreement (Uncommitted) dated
as of May 16, 2007, among Utexam Limited, as borrower, BNP Paribas, as
administrative agent and the lenders party thereto, and Consent of
Frontier Oil and Refining Company to the Sixth Amendment to the Revolving
Credit Agreement (Uncommitted) dated as of January 20, 2009, among Utexam
Limited, as borrower, BNP Paribas, as administrative agent and the lenders
party thereto Company (Exhibit 10.7 to Form 10-K, File Number 1-07627,
filed February 26, 2009).
|
|
*
|
10.9
|
Fourth
Amended and Restated Revolving Credit Agreement dated as of August 19,
2008, among Frontier Oil and Refining Company, Frontier Oil Corporation,
Union Bank of California, N.A., as administrative agent, and BNP Paribas,
as syndication agent and the other lenders specified therein (Exhibit 10.1
to Form 8-K, File Number 1-07627, filed August 20,
2008).
|
|
*
|
10.10
|
First
Amendment to Fourth Amended and Restated Revolving Credit Agreement dated
December 15, 2008, among Frontier Oil and Refining Company, Frontier Oil
Corporation, Union Bank of California, N.A., as administrative agent, and
BNP Paribas, as syndication agent and the other lenders specified therein
(Exhibit 10.1 to Form 8-K, File Number 1-07627, filed December 16,
2008).
|
| 10.11 | ||
| 10.12 | ||
|
*
|
10.13
|
Frontier
Products Offtake Agreement El Dorado Refinery, dated as of October 19,
1999 by and between Frontier Oil and Refining Company and Equiva Trading
Company (now Shell Oil Products US, assignee of Equiva Trading Company)
(“the Agreement”), and First Amendment to the Agreement dated September
18, 2000, Second Amendment to the Agreement dated September 21, 2000,
Third Amendment to the Agreement dated December 19, 2000, Fourth Amendment
to the Agreement dated February 22, 2001, Fifth Amendment to the Agreement
dated August 14, 2001, Sixth Amendment to the Agreement dated November 5,
2001, Seventh Amendment to the Agreement dated April 22, 2002, Eight
Amendment to the Agreement dated May 30, 2003, Ninth Amendment to the
Agreement dated May 25, 2004, Tenth Amendment to the Agreement dated May
3, 2005, Eleventh Amendment to the Agreement dated March 31, 2006, Twelfth
Amendment to the Agreement dated May 11, 2006, Thirteenth Amendment to the
Agreement dated September 30, 2007, Fourteenth Amendment to the Agreement
dated May 1, 2008 and Fifteenth Amendment to the Agreement dated May 28,
2008 (Exhibit 10.1 to Form 10-Q, File Number 1-07627, filed August 7,
2008).
|
| *² |
10.15
|
Frontier
Oil Corporation Omnibus Incentive Compensation Plan (Annex A to Proxy
Statement, File Number 1-07627, filed March 21, 2006).
|
|
*²
|
10.16
|
Form
of Frontier Oil Corporation Omnibus Incentive Compensation Plan Stock
Unit/Restricted Stock Agreement (Exhibit 4.8 to Form S-8, File Number
333-133595, filed April 27, 2006).
|
|
*²
|
10.17
|
Form
of Frontier Oil Corporation Omnibus Incentive Compensation Plan
Nonqualified Stock Option Agreement (Exhibit 4.9 to Form S-8, File Number
333-133595, filed April 27, 2006).
|
|
*²
|
10.18
|
Form
of Non-Employee Director Restricted Stock Unit Grant Agreement (Exhibit
10.1 to Form 8-K, File Number 1-07627, filed April 7,
2006).
|
|
*²
|
10.19
|
Form
of First Amendment to Restricted Stock Unit Grant (Exhibit 10.1 to Form
10-Q, File Number 1-07627, filed August 7, 2006).
|
|
*²
|
10.20
|
Form
of Restricted Stock Agreement (Exhibit 10.2 to Form 8-K, File Number
1-07627, filed April 7, 2006).
|
|
*²
|
10.21
|
Form
of Indemnification Agreement by and between the Company and each of its
officers and directors (Exhibit 10.41 to Form 10-K, File Number 1-07627,
filed February 28, 2007).
|
|
*²
|
10.22
|
Management
Incentive Compensation Plan for Fiscal 2008 (Exhibit 10.1 to Form 8-K,
File Number 1-07627, filed February 29, 2008).
|
|
*²
|
10.23
|
Management
Incentive Compensation Plan for Fiscal 2009 (Exhibit 10.1 to Form 8-K,
File Number 1-07627, filed February 27, 2009).
|
|
*²
|
10.24
|
Form
of 2007 Stock Unit / Restricted Stock Agreement (Exhibit 10.1 to Form
10-Q, File Number 1-07627, filed May 9, 2007).
|
|
*²
|
10.25
|
Form
of Stock Unit / Restricted Stock Agreement for James R. Gibbs (Exhibit
10.1 to Form 10-Q, File Number 1-07627, filed May 8,
2008).
|
|
*²
|
10.26
|
Form
of Stock Unit / Restricted Stock Agreement for other employees (Exhibit
10.2 to Form 10-Q, File Number 1-07627, filed May 8,
2008).
|
|
*²
|
10.27
|
Executive
Change in Control Severance Agreement, effective as of December 30, 2008
by and between Frontier Oil Corporation and James R. Gibbs (Exhibit 10.1
to Form 8-K, File Number 1-07627, filed January 2,
2009).
|
|
*²
|
10.28
|
Executive
Change in Control Severance Agreement, effective as of December 30, 2008
by and between Frontier Oil Corporation and Michael C. Jennings (Exhibit
10.2 to Form 8-K, File Number 1-07627, filed January 2,
2009).
|
|
*²
|
10.29
|
Amendment
to Executive and Change in Control Severance Agreement, dated April 28,
2009, between Frontier Oil Corporation and Michael C. Jennings (Exhibit
10.1 to Form 8-K, File Number 1-07627, filed May 01,
2009).
|
|
*²
|
10.30
|
Executive
Change in Control Severance Agreement, effective as of December 30, 2008
by and between Frontier Oil Corporation and W. Paul Eisman (Exhibit 10.3
to Form 8-K, File Number 1-07627, filed January 2,
2009).
|
|
*²
|
10.31
|
Executive
Change in Control Severance Agreement, effective as of December 30, 2008
by and between Frontier Oil Corporation and Doug S. Aron (Exhibit 10.4 to
Form 8-K, File Number 1-07627, filed January 2, 2009).
|
|
*²
|
10.32
|
Executive
Change in Control Severance Agreement, effective as of December 30, 2008
by and between Frontier Oil Corporation and J. Currie Bechtol (Exhibit
10.5 to Form 8-K, File Number 1-07627, filed January 2,
2009).
|
|
*²
|
10.33
|
Executive
Change in Control Severance Agreement, effective as of December 30, 2008
by and between Frontier Oil Corporation and Gerald B. Faudel (Exhibit 10.6
to Form 8-K, File Number 1-07627, filed January 2,
2009).
|
|
*²
|
10.34
|
Executive
Change in Control Severance Agreement, effective as of December 30, 2008
by and between Frontier Oil Corporation and Jon D. Galvin (Exhibit 10.7 to
Form 8-K, File Number 1-07627, filed January 2, 2009).
|
|
*²
|
10.35
|
Executive
Change in Control Severance Agreement, effective as of December 30, 2008
by and between Frontier Oil Corporation and Nancy J. Zupan (Exhibit 10.8
to Form 8-K, File Number 1-07627, filed January 2,
2009).
|
|
*²
|
10.36
|
Executive
Change in Control Severance Agreement, effective as of December 30, 2008
by and between Frontier Oil Corporation and Leo J. Hoonakker (Exhibit 10.9
to Form 8-K, File Number 1-07627, filed January 2,
2009).
|
|
*²
|
10.37
|
Executive
Change in Control Severance Agreement, effective as of December 30, 2008
by and between Frontier Oil Corporation and Penny S. Newmark (Exhibit
10.10 to Form 8-K, File Number 1-07627, filed January 2,
2009).
|
|
*²
|
10.38
|
Executive
Change in Control Severance Agreement, effective as of December 30, 2008
by and between Frontier Oil Corporation and Michael F. Milam (Exhibit
10.11 to Form 8-K, File Number 1-07627, filed January 2,
2009).
|
|
*²
|
10.39
|
Executive
Change in Control Severance Agreement, effective as of December 30, 2008
by and between Frontier Oil Corporation and Kent A. Olsen (Exhibit 10.12
to Form 8-K, File Number 1-07627, filed January 2,
2009).
|
|
*²
|
10.40
|
Executive
Change in Control Severance Agreement, effective as of December 30, 2008
by and between Frontier Oil Corporation and Joel W. Purdy (Exhibit 10.13
to Form 8-K, File Number 1-07627, filed January 2,
2009).
|
|
*²
|
10.41
|
Executive
Change in Control Severance Agreement, effective as of December 30, 2008
by and between Frontier Oil Corporation and Billy N. Rigby (Exhibit 10.14
to Form 8-K, File Number 1-07627, filed January 2,
2009).
|
|
*²
|
10.42
|
Executive
Change in Control Severance Agreement, effective as of December 30, 2008
by and between Frontier Oil Corporation and James M. Stump (Exhibit 10.15
to Form 8-K, File Number 1-07627, filed January 2,
2009).
|
|
*²
|
10.43
|
Executive
Change in Control Severance Agreement, dated April 28, 2009, between
Frontier Oil Corporation and Joshua Goodmanson (Exhibit 10.2 to Form 8-K,
File Number 1-07627, filed May 01, 2009).
|
|
*²
|
10.44
|
Executive
Change in Control Severance Agreement, dated September 9, 2009, between
Frontier Oil Corporation and Kevin D. Burke (Exhibit 10.1 to Form 8-K,
File Number 1-07627, filed September 09, 2009).
|
|
*²
|
10.45
|
Executive
Severance Agreement, effective as of December 30, 2008 by and between
Frontier Oil Corporation and Michael C. Jennings (Exhibit 10.16 to Form
8-K, File Number 1-07627, filed January 2, 2009).
|
|
*²
|
10.46
|
Executive
Severance Agreement, effective as of December 30, 2008 by and between
Frontier Oil Corporation and W. Paul Eisman (Exhibit 10.17 to Form 8-K,
File Number 1-07627, filed January 2, 2009).
|
|
*²
|
10.47
|
Executive
Severance Agreement, effective as of December 30, 2008 by and between
Frontier Oil Corporation and Doug S. Aron (Exhibit 10.18 to Form 8-K, File
Number 1-07627, filed January 2, 2009).
|
|
*²
|
10.48
|
Executive
Severance Agreement, effective as of December 30, 2008 by and between
Frontier Oil Corporation and J. Currie Bechtol (Exhibit 10.19 to Form 8-K,
File Number 1-07627, filed January 2, 2009).
|
|
*²
|
10.49
|
Executive
Severance Agreement, effective as of December 30, 2008 by and between
Frontier Oil Corporation and Gerald B. Faudel (Exhibit 10.20 to Form 8-K,
File Number 1-07627, filed January 2, 2009).
|
|
*²
|
10.50
|
Executive
Severance Agreement, effective as of December 30, 2008 by and between
Frontier Oil Corporation and Jon D. Galvin (Exhibit 10.21 to Form 8-K,
File Number 1-07627, filed January 2, 2009).
|
|
*²
|
10.51
|
Executive
Severance Agreement, effective as of December 30, 2008 by and between
Frontier Oil Corporation and Nancy J. Zupan (Exhibit 10.22 to Form 8-K,
File Number 1-07627, filed January 2, 2009).
|
|
*²
|
10.52
|
Executive
Severance Agreement, effective as of December 30, 2008 by and between
Frontier Oil Corporation and Leo J. Hoonakker (Exhibit 10.23 to Form 8-K,
File Number 1-07627, filed January 2, 2009).
|
|
*²
|
10.53
|
Executive
Severance Agreement, effective as of December 30, 2008 by and between
Frontier Oil Corporation and Penny S. Newmark (Exhibit 10.24 to Form 8-K,
File Number 1-07627, filed January 2, 2009).
|
|
*²
|
10.54
|
Executive
Severance Agreement, effective as of December 30, 2008 by and between
Frontier Oil Corporation and Michael F. Milam (Exhibit 10.25 to Form 8-K,
File Number 1-07627, filed January 2, 2009).
|
|
*²
|
10.55
|
Executive
Severance Agreement, effective as of December 30, 2008 by and between
Frontier Oil Corporation and Kent A. Olsen (Exhibit 10.26 to Form 8-K,
File Number 1-07627, filed January 2, 2009).
|
|
*²
|
10.56
|
Executive
Severance Agreement, effective as of December 30, 2008 by and between
Frontier Oil Corporation and Joel W. Purdy (Exhibit 10.27 to Form 8-K,
File Number 1-07627, filed January 2, 2009).
|
|
*²
|
10.57
|
Executive
Severance Agreement, effective as of December 30, 2008 by and between
Frontier Oil Corporation and Billy N. Rigby (Exhibit 10.28 to Form 8-K,
File Number 1-07627, filed January 2, 2009).
|
|
*²
|
10.58
|
Executive
Severance Agreement, effective as of December 30, 2008 by and between
Frontier Oil Corporation and James M. Stump (Exhibit 10.29 to Form 8-K,
File Number 1-07627, filed January 2, 2009).
|
|
*²
|
10.59
|
Executive
Severance Agreement, dated April 28, 2009, between Frontier Oil
Corporation and Joshua Goodmanson (Exhibit 10.3 to Form 8-K, File Number
1-07627, filed May 01, 2009).
|
|
*²
|
10.60
|
Executive
Severance Agreement, dated September 9, 2009, between Frontier Oil
Corporation and Kevin D. Burke (Exhibit 10.2 to Form 8-K, File Number
1-07627, filed September 09, 2009).
|
|
²
|
||
|
²
|
||
* Asterisk
indicates exhibits incorporated by reference as shown.
² Diamond
indicates management contract or compensatory plan or arrangement.
|
(b)
|
Exhibits
|
The
Company’s 2009 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
|
Frontier Oil Corporation
|
||||||||
|
Condensed
Financial Information of Registrant
|
||||||||
|
Balance
Sheets
|
||||||||
|
Schedule
I
|
||||||||
|
December
31,
|
||||||||
|
2009
|
2008
As
Adjusted
(Note
3)
|
|||||||
|
(in
thousands)
|
||||||||
|
ASSETS
|
||||||||
|
Current
assets:
|
||||||||
|
Cash
and cash equivalents
|
$ | 211,775 | $ | 254,548 | ||||
|
Trade
and other receivables
|
174,843 | 120,265 | ||||||
|
Deferred
income tax assets - current
|
26,373 | 16,301 | ||||||
|
Commutation
account
|
- | 6,319 | ||||||
|
Other
current assets
|
926 | 643 | ||||||
|
Total
current assets
|
413,917 | 398,076 | ||||||
|
Property,
plant and equipment, at cost:
|
||||||||
|
Furniture,
fixtures and other
|
1,298 | 1,248 | ||||||
|
Accumulated
depreciation
|
(924 | ) | (998 | ) | ||||
|
Property,
plant and equipment, net
|
374 | 250 | ||||||
|
Deferred
financing costs, net
|
2,857 | 3,642 | ||||||
|
Deferred
income tax assets - noncurrent
|
10,767 | - | ||||||
|
Other
assets
|
3,665 | 2,600 | ||||||
|
Receivable
from affiliated companies
|
- | 646 | ||||||
|
Investment
in subsidiaries
|
1,144,040 | 1,216,054 | ||||||
|
Total
assets
|
$ | 1,575,620 | $ | 1,621,268 | ||||
|
LIABILITIES
AND SHAREHOLDERS' EQUITY
|
||||||||
|
Current
liabilities:
|
||||||||
|
Accounts
payable
|
$ | 906 | $ | 1,168 | ||||
|
Accrued
liabilities and other
|
20,916 | 26,071 | ||||||
|
Total
current liabilities
|
21,822 | 27,239 | ||||||
|
Long-term
debt
|
347,485 | 347,220 | ||||||
|
Contingent
income tax liabilities
|
27,267 | 26,112 | ||||||
|
Other
long-term liabilities
|
3,578 | 2,507 | ||||||
|
Deferred
income tax liabilities
|
230,818 | 179,214 | ||||||
|
Payable
to affiliated companies
|
674 | - | ||||||
|
Commitments
and contingencies
|
||||||||
|
Shareholders'
equity
|
943,976 | 1,038,976 | ||||||
|
Total
liabilities and shareholders' equity
|
$ | 1,575,620 | $ | 1,621,268 | ||||
|
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 Operations
|
||||||||||||
|
Schedule
I
|
||||||||||||
|
December
31,
|
||||||||||||
|
2009
|
2008
As
Adjusted
(Note
3)
|
2007
As
Adjusted
(Note
3)
|
||||||||||
|
(in
thousands)
|
||||||||||||
|
Revenues
|
$ | (7 | ) | $ | (7 | ) | $ | 2 | ||||
|
Costs
and expenses:
|
||||||||||||
|
Selling
and general expenses, excluding depreciation
|
23,836 | 17,677 | 30,593 | |||||||||
|
Depreciation
|
70 | 55 | 61 | |||||||||
|
Loss
(gain) on sales of assets
|
- | (37 | ) | 2,028 | ||||||||
| 23,906 | 17,695 | 32,682 | ||||||||||
|
Operating
income (loss)
|
(23,913 | ) | (17,702 | ) | (32,680 | ) | ||||||
|
Interest
expense and other financing costs
|
29,278 | 15,939 | 12,723 | |||||||||
|
Interest
and investment income
|
(1,873 | ) | (2,868 | ) | (11,202 | ) | ||||||
|
Equity
in loss (earnings) of subsidiaries
|
79,986 | (371,830 | ) | (646,626 | ) | |||||||
| 107,391 | (358,759 | ) | (645,105 | ) | ||||||||
|
Income
(loss) before income taxes
|
(131,304 | ) | 341,057 | 612,425 | ||||||||
|
Provision
(benefit) for income taxes
|
(47,544 | ) | 115,004 | 210,093 | ||||||||
|
Net
income (loss)
|
$ | (83,760 | ) | $ | 226,053 | $ | 402,332 | |||||
|
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
|
||||||||||||
|
Schedule
I
|
||||||||||||
|
December
31,
|
||||||||||||
|
2009
|
2008
As
Adjusted
(Note
3)
|
2007
As
Adjusted
(Note
3)
|
||||||||||
|
(in
thousands)
|
||||||||||||
|
Cash
flows from operating activities:
|
||||||||||||
|
Net
income
|
$ | (83,760 | ) | $ | 226,053 | $ | 402,332 | |||||
|
Equity
in earnings of subsidiaries
|
79,986 | (371,830 | ) | (646,626 | ) | |||||||
|
Intercompany
transactions, net
|
1,321 | (3,261 | ) | 1,110 | ||||||||
|
Dividends
received from subsidiaries
|
21,200 | 10,000 | 212,150 | |||||||||
|
Income
taxes (paid to) received from subsidiaries
|
(30,000 | ) | (6,000 | ) | 317,500 | |||||||
|
Depreciation
|
70 | 55 | 61 | |||||||||
|
Deferred
income taxes
|
31,082 | 169,766 | (60,859 | ) | ||||||||
|
Stock-based
compensation expense
|
20,608 | 20,014 | 22,553 | |||||||||
|
Excess
income tax benefits of stock-based compensation
|
(244 | ) | (3,191 | ) | (6,962 | ) | ||||||
|
Amortization
of debt issuance costs
|
783 | 570 | 483 | |||||||||
|
Senior
notes discount amortization
|
264 | 60 | - | |||||||||
|
Allowance
for investment loss and bad debts
|
- | 41 | - | |||||||||
|
Loss
(gain) on sales of assets
|
- | (37 | ) | 2,028 | ||||||||
|
Decrease
in commutation account
|
- | - | 1,009 | |||||||||
|
Amortization
of long-term prepaid insurance
|
- | 909 | 1,211 | |||||||||
|
Increase
(decrease) in other long-term liabilities
|
2,633 | (3,716 | ) | 31,058 | ||||||||
|
Other
|
(1,065 | ) | 713 | (578 | ) | |||||||
|
Changes
in components of working capital from operations
|
(57,416 | ) | (80,054 | ) | (46,639 | ) | ||||||
|
Net
cash (used in) provided by operating activities
|
(14,538 | ) | (39,908 | ) | 229,831 | |||||||
|
Cash
flows from investing activities:
|
||||||||||||
|
Additions
to property, plant and equipment
|
(194 | ) | (129 | ) | (4,310 | ) | ||||||
|
Proceeds
from sale of assets
|
- | 37 | 2,290 | |||||||||
|
Net
cash used in investing activities
|
(194 | ) | (92 | ) | (2,020 | ) | ||||||
|
Cash
flows from financing activities:
|
||||||||||||
|
Proceeds
from issuance of 8.5% Senior Notes, net of
discount
|
- | 197,160 | - | |||||||||
|
Purchase
of treasury stock
|
(3,008 | ) | (67,030 | ) | (248,486 | ) | ||||||
|
Proceeds
from issuance of common stock
|
70 | 405 | 2,303 | |||||||||
|
Dividends
paid to shareholders
|
(25,349 | ) | (23,144 | ) | (17,271 | ) | ||||||
|
Excess
income tax benefits of stock-based compensation
|
244 | 3,191 | 6,962 | |||||||||
|
Debt
issuance costs and other
|
2 | (2,402 | ) | - | ||||||||
|
Net
cash provided by (used in) financing activities
|
(28,041 | ) | 108,180 | (256,492 | ) | |||||||
|
Increase
(decrease) in cash and cash equivalents
|
(42,773 | ) | 68,180 | (28,681 | ) | |||||||
|
Cash
and cash equivalents, beginning of period
|
254,548 | 186,368 | 215,049 | |||||||||
|
Cash
and cash equivalents, end of period
|
$ | 211,775 | $ | 254,548 | $ | 186,368 | ||||||
|
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 Statements
Incorporated
by reference are Frontier Oil Corporation and Subsidiaries Consolidated
Statements of Shareholder’s Equity for the three years ended December 31, 2009
in Part II, Item 8.
Basis of Presentation – The
condensed financial information of Frontier Oil Corporation’s (“FOC”)
investments in subsidiaries are presented under the equity method of
accounting. Under this method, the assets and liabilities of
subsidiaries are not consolidated. The investments in and advances to
subsidiaries are recorded in the Condensed Balance Sheets. The income
(losses) from operations of the subsidiaries are reported on an equity basis in
earnings of subsidiary companies in the Condensed Statements of
Operations.
See the
notes to the consolidated FOC financial statements in Part II, Item 8 for other
disclosures.
|
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)
|
||||||||||||||||
|
2009
|
||||||||||||||||
|
Allowance
for doubtful accounts
|
$ | 500 | $ | 698 | $ | 198 | $ | 1,000 | ||||||||
|
Allowance
for investment loss
|
499 | - | - | 499 | ||||||||||||
|
2008
|
||||||||||||||||
|
Allowance
for doubtful accounts
|
500 | - | - | 500 | ||||||||||||
|
Allowance
for investment loss
|
- | 499 | - | 499 | ||||||||||||
|
2007
|
||||||||||||||||
|
Allowance
for doubtful accounts
|
500 | 198 | 198 | 500 | ||||||||||||
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/ Michael C. Jennings | |
| Michael C. Jennings | |||
|
President
and Chief Executive Officer
(chief
executive officer) |
|||
Date:
February
25, 2010
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/ G. Clyde Buck |
| James R. Gibbs | G. Clyde Buck |
| Director and Chairman of the Board | Director |
| /s/ Michael C. Jennings | /s/ T. Michael Dossey |
| Michael C. Jennings | T. Michael Dossey |
| President and Chief Executive Officer | Director |
| and Director | |
| (principal executive officer) | |
| /s/ Doug S. Aron | /s/ James H. Lee |
| Doug S. Aron | James H. Lee |
| Executive Vice President and | Director |
| Chief Financial Officer | |
| (principal financial officer) | |
| /s/ Nancy J. Zupan | /s/ Paul B. Loyd, Jr |
| Nancy J. Zupan | Paul B. Loyd, Jr. |
| Vice President and | Director |
| Chief Accounting Officer | |
| (principal accounting officer) | |
| /s/ Douglas Y. Bech | s/ Michael E. Rose |
| Douglas Y. Bech | Michael E. Rose |
| Director | Director |
| /s/ Franklin Myers | |
| Franklin Myers | |
| Director |
Date: February
25, 2010