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) OF THE
SECURITIES EXCHANGE ACT OF 1934
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For the Fiscal
Year Ended December 31, 2010
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OR
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
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For the transition period from
to
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Commission File Number:
001-32721
WESTERN REFINING,
INC.
(Exact name of registrant as
specified in its charter)
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Delaware
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20-3472415
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(State or other jurisdiction of
incorporation or organization)
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(I.R.S. Employer Identification
No.)
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123 W. Mills Ave., Suite 200
El Paso, Texas
(Address of principal
executive offices)
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79901
(Zip Code)
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Registrants telephone number, including area code:
(915) 534-1400
Securities registered pursuant to Section 12(b) of the
Act:
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Title of Each Class
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Name of Each Exchange 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 o
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 o 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 o
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 o No o
Indicate by check mark if disclosure of delinquent filers
pursuant to rule 405 of
Regulation S-K
(§ 229.405 of this chapter) is not contained herein,
and will not be contained, to the best of registrants
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. þ
Indicate by check mark if 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
o Accelerated
Filer
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Non-Accelerated
Filer
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(Do not check if a smaller reporting company)
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Smaller
Reporting Company
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Indicate by check mark whether the registrant is a shell company
(as defined in
Rule 12b-2
of the Exchange
Act). Yes o No þ
The aggregate market value of the voting and non-voting common
equity held by non-affiliates of the registrant computed based
on the New York Stock Exchange closing price on June 30,
2010 (the last business day of the registrants most
recently completed second fiscal quarter) was $269,651,530.
As of February 25, 2011, there were 90,805,490 shares
outstanding, par value $0.01, of the registrants common
stock.
DOCUMENTS
INCORPORATED BY REFERENCE
Portions of the definitive proxy statement for the
registrants 2011 annual meeting of stockholders are
incorporated by reference into Part III of this report.
WESTERN
REFINING, INC. AND SUBSIDIARIES
INDEX
i
Forward-Looking
Statements
As provided by the safe harbor provisions of the Private
Securities Litigation Reform Act of 1995, certain statements
included throughout this Annual Report on
Form 10-K,
and in particular under the sections entitled Item 1.
Business, Item 3. Legal Proceedings, and
Item 7. Managements Discussion and Analysis of
Financial Condition and Results of Operations, relating to
matters that are not historical fact are forward-looking
statements that represent managements beliefs and
assumptions based on currently available information. These
forward-looking statements relate to matters such as our
industry, business strategy, goals and expectations concerning
our market position, future operations, including our expected
timeframe for restarting refining operations at our Yorktown
refinery, margins, profitability, deferred taxes, capital
expenditures, liquidity and capital resources, our working
capital requirements, our ability to improve our capital
structure through asset sales
and/or
through certain financings, and other financial and operating
information. Forward-looking statements also include those
regarding the recommencing of refining operations at our
Yorktown facility, the timing of completion of certain
operational improvements we are making at our refineries, future
operational or refinery efficiencies and cost savings, future
refining capacity, timing of future maintenance turnarounds, the
amount or sufficiency of future cash flows and earnings growth,
future expenditures and future contributions related to pension
and postretirement obligations, our ability to manage our
inventory price exposure through commodity derivative
instruments, the impact on our business of existing and future
state and federal regulatory requirements, environmental loss
contingency accruals, projected remediation costs or
requirements, and the expected outcomes of legal proceedings in
which we are involved. We have used the words
anticipate, assume, believe,
budget, continue, could,
estimate, expect, intend,
may, plan, potential,
predict, project, will,
future, and similar terms and phrases to identify
forward-looking statements in this report.
Forward-looking statements reflect our current expectations
regarding future events, results, or outcomes. These
expectations may or may not be realized. Some of these
expectations may be based upon assumptions or judgments that
prove to be incorrect. In addition, our business and operations
involve numerous risks and uncertainties, many of which are
beyond our control, which could result in our expectations not
being realized or otherwise materially affect our financial
condition, results of operations, and cash flows.
Actual events, results, and outcomes may differ materially from
our expectations due to a variety of factors. Although it is not
possible to identify all of these factors, they include, among
others, the following:
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worsening of the economic downturn and instability and
volatility in the financial markets;
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changes in the underlying demand for our refined products;
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availability, costs, and price volatility of crude oil, other
refinery feedstocks, and refined products;
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availability of renewable fuels for blending and Renewal
Identification Numbers, or RINs, to meet Renewable Fuel
Standards, or RFS, obligations;
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changes in crack spreads;
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changes in the spread between West Texas Intermediate, or WTI,
crude oil and West Texas Sour, or WTS, crude oil, also known as
the sweet/sour spread;
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changes in the spread between WTI crude oil and Maya crude oil,
also known as the light/heavy spread;
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changes in the spread between WTI crude oil and Dated Brent
crude oil;
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adverse changes in the credit ratings assigned to our debt
instruments;
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conditions in the capital markets;
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construction of new, or expansion of existing product pipelines
in the areas that we serve;
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actions of customers and competitors;
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changes in fuel and utility costs incurred by our refineries;
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the effect of weather-related problems on our operations;
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1
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disruptions due to equipment interruption, pipeline disruptions,
or failure at our or third-party facilities;
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execution of planned capital projects, cost overruns relating to
those projects, and failure to realize the expected benefits
from those projects;
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effects of, and costs relating to compliance with current and
future local, state, and federal environmental, economic,
climate change, safety, tax and other laws, policies and
regulations, and enforcement initiatives;
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rulings, judgments or settlements in litigation, or other legal
or regulatory matters, including unexpected environmental
remediation costs in excess of any reserves or insurance
coverage;
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the price, availability, and acceptance of alternative fuels and
alternative fuel vehicles;
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operating hazards, natural disasters, casualty losses, acts of
terrorism, and other matters beyond our control; and
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other factors discussed in more detail under
Part 1. Item 1A. Risk Factors of
this report, which are incorporated herein by this reference.
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Any one of these factors or a combination of these factors could
materially affect our results of operations and could influence
whether any forward-looking statements ultimately prove to be
accurate. You are urged to consider these factors carefully in
evaluating any forward-looking statements and are cautioned not
to place undue reliance on these forward-looking statements.
Although we believe that our plans, intentions, and expectations
reflected in or suggested by the forward-looking statements we
make in this report are reasonable, we can provide 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. The forward-looking statements
included herein are made only as of the date of this report, and
we are not required to update any information to reflect events
or circumstances that may occur after the date of this report,
except as required by applicable law.
2
PART I
In this Annual Report on
Form 10-K,
all references to Western Refining, the
Company, Western, we,
us, and our refer to Western Refining,
Inc., or WNR, and the entities that became its subsidiaries upon
closing of our initial public offering (including Western
Refining Company, L.P., or Western Refining LP), and Giant
Industries, Inc., or Giant, and its subsidiaries, which became
wholly-owned subsidiaries on May 31, 2007, unless the
context otherwise requires or where otherwise indicated. Any
references to the Company prior to this date exclude
the operations of Giant.
Overview
We are an independent crude oil refiner and marketer of refined
products and also operate service stations and convenience
stores. We own and operate two refineries with a total crude oil
throughput capacity of approximately 151,000 barrels per
day, or bpd. In addition to our 128,000 bpd refinery in
El Paso, Texas, we also own and operate a 23,000 bpd
refinery near Gallup, New Mexico. Until September 2010, we
operated a 70,000 bpd refinery near Yorktown, Virginia, and
until November 2009, we operated a 17,000 bpd refinery near
Bloomfield, New Mexico. We temporarily suspended refining
operations at our Yorktown facility in September 2010 and
indefinitely suspended refining operations at the Bloomfield
refinery in November 2009. We continue to operate Yorktown and
Bloomfield as product distribution terminals and supply our
refined products to those areas. Our primary operating areas
encompass West Texas, Arizona, New Mexico, Utah, Colorado, and
the Mid-Atlantic region. In addition to the refineries, we also
own and operate stand-alone refined product distribution
terminals in Albuquerque, New Mexico; Yorktown; and Bloomfield;
as well as asphalt terminals in Phoenix and Tucson, Arizona;
Albuquerque; and El Paso. At February 25, 2011, we
also own and operate 150 retail service stations and convenience
stores in Arizona, Colorado, and New Mexico; a fleet of crude
oil and refined product truck transports; and a wholesale
petroleum products distributor that operates in Arizona,
California, Colorado, Nevada, New Mexico, Texas, and Utah.
We were incorporated in September 2005 under Delaware law. In
January 2006, we completed an initial public offering and our
stock began trading on the New York Stock Exchange, or NYSE,
under the symbol WNR. Our principal offices are
located in El Paso, Texas.
On May 31, 2007, we completed the acquisition of Giant.
Under the terms of the merger agreement, we acquired 100% of
Giants 14,639,312 outstanding shares for $77.00 per share
in cash for a total purchase price of $1,149.2 million,
funded primarily through a $1,125.0 million secured term
loan. In connection with the acquisition, we borrowed an
additional $275.0 million in July 2007, when we paid off
and retired Giants 8% and 11% Senior Subordinated
Notes. Prior to the acquisition of Giant, we generated
substantially all of our revenues from our refining operations
in El Paso. With the acquisition of Giant, we also gained a
diverse mix of complementary retail and wholesale businesses.
Following the acquisition of Giant, we began reporting our
operating results in three business segments: the refining
group, the wholesale group, and the retail group. Our refining
group operates the two refineries and related refined product
distribution terminals and asphalt terminals. At the refineries,
we refine crude oil and other feedstocks into finished products
such as gasoline, diesel fuel, jet fuel, and asphalt. Our
refineries market finished products to a diverse customer base
including wholesale distributors and retail chains. Our
wholesale group distributes gasoline, diesel fuel, and lubricant
products. Our retail group operates service stations and
convenience stores and sells gasoline, diesel fuel, and
merchandise. See Note 3, Segment Information, in the
Notes to Consolidated Financial Statements included in this
annual report for detailed information on our operating results
by segment.
Refining
Segment
Our refining group currently operates two refineries: one in
El Paso, Texas (the El Paso refinery), and one near
Gallup, New Mexico (the Gallup refinery). Both of our refineries
have their own refined product distribution terminals. In
addition, we operate three stand-alone refined product
distribution terminals in Albuquerque, New
3
Mexico; Yorktown, Virginia; and Bloomfield, New Mexico. Our
refining group operates a crude oil gathering pipeline system in
the Four Corners region of New Mexico and a Company-owned
pipeline that runs from Southeast to Northwest New Mexico, or
Texas-New Mexico pipeline. The pipeline can transport crude oil
from Southeast New Mexico to the Four Corners region and south
from Lynch, New Mexico to Jal, New Mexico. We do not currently
transport crude via pipeline from Southeast New Mexico. We
presently use sections of the pipeline to deliver crude oil to
our Gallup refinery and to transport crude oil for unrelated
third parties. This pipeline provides us with an alternative
method of transportation within New Mexico and an alternative
supply of crude oil for our Gallup refinery. Our refining
operations also include an asphalt plant in El Paso and
four asphalt terminals in El Paso, Phoenix, Tucson, and
Albuquerque.
In September 2010, due to the continued effect of unfavorable
economic conditions in the refining market, especially in the
Mid-Atlantic region, and the resulting financial performance of
our Yorktown refinery, we temporarily suspended refining
operations at the Yorktown facility and will operate Yorktown as
a refined products distribution terminal to supply refined
products to the region in the near term. We anticipate
restarting refining operations in Yorktown during 2013. We will
continue to monitor our Yorktown long-lived assets, both
operating and idled, and capital projects for potential asset
impairments or project write-offs until conditions improve.
Changes in market conditions, as well as changes in assumptions
used to test for recoverability and to determine fair value,
could result in significant impairment charges or project
write-offs in the future, thus affecting our earnings. See
Item 7. Managements Discussion and Analysis of
Financial Condition and Results of Operations
Critical Accounting Policies and Estimates
Long-lived Assets.
Until November 2009, our operations in Bloomfield included both
crude oil refining and product distribution. During the fourth
quarter of 2009, we decided to consolidate the refining
operations of the Gallup and Bloomfield refineries into a single
operation at the Gallup refinery to eliminate certain operating
costs while maintaining the capability to process approximately
the same volumes of crude that we had previously processed
through the two refineries. We continue to supply refined
products to the Four Corners area through ongoing operations at
the Bloomfield product distribution terminal, and by utilizing a
recent pipeline connection and long-term exchange supply
agreement. Through the long-term exchange agreement, we supply
barrels to the Bloomfield product distribution terminal in
exchange for barrels produced at the El Paso refinery. In
the latter part of the fourth quarter of 2009, as a result of
the indefinite suspension of refining activities at the
Bloomfield refinery, we recorded a non-cash asset impairment
charge of $52.8 million and incurred approximately
$2.2 million in other costs primarily related to employee
severance programs for the Bloomfield refinery. During the
fourth quarter of 2010, we performed an analysis of specific
assets that we had previously planned to relocate from our
Bloomfield facility to our Gallup refinery. As a result of this
analysis, we recorded an additional non-cash impairment charge
of $9.1 million. See Item 7. Managements
Discussion and Analysis of Financial Condition and Results of
Operations Major Influences on Results of
Operations Long-lived Asset Impairment Loss.
Principal Products. Our refineries make
various grades of gasoline, diesel fuel, jet fuel, and other
products from crude oil, other feedstocks, and blending
components. We also acquire finished products through exchange
agreements and from various third-party suppliers. We sell these
products through our own wholesale group and service stations,
independent wholesalers and retailers, commercial accounts, and
sales and exchanges with major oil companies. See
Item 7. Managements Discussion and Analysis of
Financial Condition and Results of Operations for detail on
production by refinery. The following table summarizes sales
percentage by product for the years indicated:
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Year Ended December 31,
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2010
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2009
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2008
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Gasoline
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54.0
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%
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57.2
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%
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48.9
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%
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Diesel fuel
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32.3
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30.2
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38.6
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Jet fuel
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5.6
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4.6
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5.1
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Asphalt
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2.5
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2.7
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1.9
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Other
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5.6
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5.3
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5.5
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Total sales percentage by type
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100.0
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%
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100.0
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%
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100.0
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%
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4
Customers. We sell a variety of refined
products to our diverse customer base. No single customer
accounted for more than 10% of our consolidated net sales for
2010.
All of our refining sales were domestic sales in the United
States, except for sales of gasoline and diesel fuel for export
into Juarez, Mexico. The sales for export were to PMI Trading
Limited, an affiliate of Petroleos Mexicanos, the Mexican
state-owned oil company, and accounted for approximately 8.3%,
8.5%, and 8.3% of our consolidated net sales during the years
ended December 31, 2010, 2009, and 2008, respectively.
We also purchase additional refined products from third parties
to supplement supply to our customers. These products are
similar to the products that we currently manufacture.
Competition. We operate primarily in West
Texas, Arizona, New Mexico, Utah, Colorado, and the Mid-Atlantic
region. We supply refined products to these areas from our
refineries, from other refineries in these regions, and from
refineries located in other regions via interstate pipelines.
These areas have substantial refining capacity, and we also
compete with offshore refiners that deliver product by water
transport.
Petroleum refining and marketing is highly competitive. The
principal competitive factors affecting us are costs of crude
oil and other feedstocks, refinery efficiency, operating costs,
refinery product mix, and costs of product distribution and
transportation. Due to their geographic diversity, larger and
more complex refineries, integrated operations, and greater
resources, some of our competitors may be better able to
withstand volatile market conditions, compete on the basis of
price, obtain crude oil in times of shortage, and bear the
economic risk inherent in all phases of the refining industry.
In the Southwest, the El Paso and Gallup refineries
primarily compete with Valero Energy Corp., ConocoPhillips
Company, Alon USA Energy, Inc., Holly Corporation, Tesoro
Corporation, Chevron Products Company, or Chevron, and Suncor
Energy, Inc. as well as refineries in other regions of the
country that serve the regions we serve through pipelines.
The areas where we sell refined products are also supplied by
various refined product pipelines. Any expansions or additional
product supplied by these third-party pipelines could put
downward pressure on refined product prices in these areas.
When in operation as a refinery, our Yorktown facility in the
Mid-Atlantic region primarily competed with Sunoco, Inc., Valero
Energy Corp., ConocoPhillips Company, Hess Corporation, and
other refineries in the Gulf Coast via the Colonial Pipeline
that runs from the Gulf Coast area to New Jersey. We also
competed with offshore refiners that deliver product by water
transport to the region.
To the extent that climate change legislation is passed,
imposing greenhouse gas restrictions on domestic refiners, all
domestic refiners will be at a competitive disadvantage to
offshore refineries. In November 2010, the State of New Mexico
adopted regulations allowing New Mexico to participate in a
regional greenhouse
cap-and-trade
program through the Western Climate Initiative. The regulation
becomes effective in 2012 unless the current New Mexico
administration reverses the regulations or postpones the
effective date. Our Gallup refinery, along with other industrial
facilities in New Mexico, will be required to reduce their
greenhouse gas emissions by 2% per year between 2012 and 2020,
or obtain emission credits from other regulated facilities. The
program will not be initiated unless 100 million tons of
emissions are available regionally.
Southwest
El Paso
Refinery
Our El Paso refinery has a crude oil throughput capacity of
128,000 bpd with approximately 4.3 million barrels of
storage capacity, a finished product terminal, and an asphalt
plant and terminal.
This refinery is well situated to serve two separate geographic
areas, allowing us a diversified market pricing exposure. Tucson
and Phoenix typically reflect a West Coast market pricing
structure, while El Paso, Albuquerque, and Juarez, Mexico
typically reflect a Gulf Coast market pricing structure.
Process Summary. Our El Paso refinery is
a nominal 128,000 bpd crude oil throughput cracking
facility that has historically run a high percentage of WTI
crude oil to optimize the yields of higher value refined
products that
5
currently account for over 90% of our production output. With
the completion of our gasoline desulfurization project in May
2009 we have the flexibility to process up to 22% WTS crude oil,
which typically is less expensive than WTI crude oil.
Under a sulfuric acid regeneration and sulfur gas processing
agreement with E.I. du Pont de Nemours, or DuPont, Western
Refining LP has a long-term commitment to purchase services for
use by its El Paso refinery. In exchange for this
commitment, DuPont agreed to design, construct, and operate two
sulfuric acid regeneration plants on property we lease to DuPont
within our El Paso refinery. In November 2008, we began
processing all sulfur gas from the north side of the
El Paso refinery at the DuPont facility. In January 2009,
we began processing all sulfur gas from the south side of the
El Paso refinery at the DuPont facility.
Power Supply. Electricity is supplied to our
refinery by a regional electric company via two separate feeders
to both the north and south sides of our refinery. We have an
electrical power curtailment plan to conserve power in the event
of a partial outage.
Natural gas is supplied to our refinery via pipeline under two
transportation agreements. One transportation agreement is on an
interruptible basis while the other is on an uninterruptible
basis. We purchase our natural gas at market rates or under
fixed-price agreements.
Raw Material Supply. The primary inputs for
our refinery consist of crude oil, isobutane, and alkylate.
Operation of our gasoline desulfurization unit since startup in
May 2009 has allowed for higher sour rates. Currently, we have
the capability to process up to 22% of WTS crude oil at the
El Paso refinery. Smaller projects that we have deferred
will allow us to incrementally increase our WTS crude oil
processing capability at the El Paso refinery. The
following table summarizes the historical feedstocks used by our
El Paso refinery for the years indicated:
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Percentage For
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Year Ended
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Refinery Feedstocks
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Year Ended December 31,
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December 31,
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(bpd)
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2010
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2009
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2008
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2010
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Crude Oils:
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Sweet crude oil
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104,119
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99,680
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100,130
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81.9
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%
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Sour crude oil
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14,007
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17,601
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16,985
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11.0
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Total Crude Oils
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118,126
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117,281
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117,115
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92.9
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Other Feedstocks and Blendstocks:
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Intermediates and other
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4,359
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3,611
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4,302
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3.4
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Blendstocks
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4,692
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5,573
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5,152
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3.7
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Total Other Feedstocks and Blendstocks
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9,051
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9,184
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9,454
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7.1
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Total Crude Oils and Other Feedstocks and Blendstocks
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127,177
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126,465
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|
|
126,569
|
|
|
|
100.0
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil is delivered to our El Paso refinery via a
450-mile
crude oil pipeline owned and operated by Kinder Morgan under a
30-year
crude oil transportation agreement that began in 2004. The
system handles both WTI and WTS crude oil with its main
trunkline into El Paso used solely for the supply of crude
oil to us on a published tariff. The crude oil pipeline has
access to the majority of the producing fields in the Permian
Basin, which gives us access to a plentiful supply of WTI and
WTS crude oil from fields with long reserve lives. We generally
buy our crude oil under contracts with various crude oil
providers, including a contract with Kinder Morgan that expires
in 2020 and shorter term contracts with other suppliers, at
market-based rates.
We also have access to blendstocks and refined products from the
Gulf Coast through a pipeline that runs from the Gulf Coast to
El Paso.
Refined Products Transportation. Outside of
the El Paso area, which is supplied via our El Paso
refinery product distribution terminal, we provide refined
products to other areas, including Tucson, Phoenix, Albuquerque,
and Juarez, Mexico. Supply to these areas is achieved through
pipeline systems that are linked to our refinery. Our refined
products are delivered to Tucson and Phoenix through the Kinder
Morgan East Line, which was expanded to
6
over 200,000 bpd in the fourth quarter of 2007, and to
Albuquerque and Juarez, Mexico through pipelines owned by Plains
All American Pipeline L.P., or Plains. We also sell our refined
products at our product distribution terminal and rail loading
facilities in El Paso. Another pipeline owned by Kinder
Morgan provides diesel fuel to the Union Pacific railway in
El Paso.
Both Kinder Morgans East Line and the Plains pipeline to
Albuquerque are interstate pipelines regulated by the Federal
Energy Regulatory Commission, or FERC. The tariff provisions for
these pipelines include prorating policies that grant historical
shippers line space that is consistent with their prior
activities as well as a prorated portion of any expansions.
Four
Corners Refineries
Our refining group operates a refinery near Gallup, New Mexico.
Our Gallup refinery has a crude oil throughput capacity of
23,000 bpd. Until November 2009, we also operated a
refinery near Bloomfield, New Mexico. Our Bloomfield refinery
had a crude oil throughput capacity of 17,000 bpd. We
typically had not operated these refineries at full capacity,
and in November 2009, we indefinitely suspended refining
operations at Bloomfield. Our Bloomfield facility currently
operates as a product distribution terminal. See Item 7.
Managements Discussion and Analysis of Financial Condition
and Results of Operations Major Influences on
Results of Operations Long-lived Asset Impairment
Loss. We market refined products from the Gallup refinery
primarily in Arizona, Colorado, New Mexico, and Utah. Our
primary supply of crude oil and natural gas liquids comes from
Colorado, New Mexico, and Utah.
Process Summary. The Gallup refinery produces
a high percentage of high value products. Each barrel of raw
materials processed by our Gallup refinery has resulted in
approximately 90% of high value finished products, including
gasoline and diesel fuel during the past four years.
Power Supply. Electrical power is supplied to
the Gallup refinery by a regional electric cooperative. There
are several uninterruptible power supply units throughout the
plant to maintain computers and controls in the event of a power
outage. Natural gas is supplied to our refinery via two
different pipelines. We purchase our natural gas at market rates.
Raw Material Supply. The feedstock for our
Gallup refinery is Four Corners Sweet, which comes from the Four
Corners area and is delivered by pipelines, including pipelines
we own, connected to our refinery and product distribution
terminal, or delivered by our trucks to pipeline injection
points or refinery tankage. Our pipeline system reaches into the
San Juan Basin, located in the Four Corners area, and
connects with local common carrier pipelines. We currently own
approximately 250 miles of pipeline for delivering crude
oil to the refinery.
We supplement the crude oil used at our Gallup refinery with
other feedstocks. These other feedstocks currently include
locally produced natural gas liquids and condensate as well as
other feedstocks produced outside of the Four Corners area. Our
Gallup refinery is capable of processing approximately
6,000 bpd of natural gas liquids. An adequate supply of
natural gas liquids is available for delivery to our Gallup
refinery primarily through a
13-mile
pipeline we own that connects the refinery to a natural gas
liquids processing plant.
7
The following table summarizes the historical feedstocks used by
our Four Corners refineries for the years indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Percentage For
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended
|
|
Refinery Feedstocks
|
|
Year Ended December 31,
|
|
|
December 31,
|
|
(bpd)
|
|
2010
|
|
|
2009(1)
|
|
|
2008
|
|
|
2010
|
|
|
Crude Oil:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sweet crude oil
|
|
|
21,140
|
|
|
|
24,763
|
|
|
|
28,293
|
|
|
|
87.6
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Crude Oil
|
|
|
21,140
|
|
|
|
24,763
|
|
|
|
28,293
|
|
|
|
87.6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Feedstocks and Blendstocks:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Intermediates and other
|
|
|
1,822
|
|
|
|
1,425
|
|
|
|
1,077
|
|
|
|
7.6
|
|
Blendstocks
|
|
|
1,149
|
|
|
|
429
|
|
|
|
1,393
|
|
|
|
4.8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Other Feedstocks and Blendstocks
|
|
|
2,971
|
|
|
|
1,854
|
|
|
|
2,470
|
|
|
|
12.4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Crude Oil and Other Feedstocks and Blendstocks
|
|
|
24,111
|
|
|
|
26,617
|
|
|
|
30,763
|
|
|
|
100.0
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Includes barrels processed at our Bloomfield facility through
November 2009 when Bloomfield refining operations were
indefinitely suspended. We calculated total bpd feedstock
volumes by dividing by 365 days. |
We purchase crude oil from a number of sources, including major
oil companies and independent producers, under arrangements that
contain market responsive pricing provisions. Many of these
arrangements are subject to cancellation by either party or have
terms of one year or less. In addition, these arrangements are
subject to periodic renegotiation, which could result in our
paying higher or lower relative prices for crude oil.
Terminal Operations. Our Gallup refinery has
its own product distribution terminal. We own stand-alone
finished product terminals in Albuquerque and Bloomfield. The
Bloomfield refinery terminal is permitted to operate at
19,000 bpd. This terminal has approximately
251,000 barrels of finished product tankage and a truck
loading rack with three loading spots. We utilize a new pipeline
connection and a long-term exchange agreement to supply barrels
to the Bloomfield refinery terminal. Additionally, there are
approximately 470,000 barrels of crude oil and feedstock
tankage available for storage for the Gallup refinery. The
Albuquerque product distribution terminal is permitted to
operate at 27,500 bpd. This terminal has approximately
170,000 barrels of finished product tankage and a truck
loading rack with two loading spots. Product deliveries to this
terminal are made by truck or by pipeline, including deliveries
from our El Paso and Gallup refineries. In the third
quarter of 2010, we ceased operating our refined products
distribution terminal located in Flagstaff, Arizona. The
Flagstaff terminal was permitted to operate at 12,000 bpd.
This terminal had approximately 65,000 barrels of finished
product tankage and a truck loading rack with three loading
spots. Product deliveries to this terminal were made by truck
from our Gallup refinery.
Refined Products Transportation. Our Gallup
gasoline and diesel fuel production is distributed in Arizona,
Colorado, New Mexico, and Utah, primarily via a fleet of
finished product trucks operated by our wholesale group.
Mid-Atlantic
Yorktown
Facility
In September 2010, we temporarily suspended refining operations
at our Yorktown facility due primarily to the continued effect
of unfavorable economic conditions in the refining market,
especially in the Mid-Atlantic region. Through December 2010, we
have been making changes we believe are necessary to operate our
Yorktown facility as a stand-alone product distribution terminal
in the near term. We currently operate our Yorktown terminal in
connection with our sales of refined product in the Yorktown
area. We plan to expand our terminal operations at Yorktown to
provide terminalling and related services to third parties
during 2011.
Our Yorktown facility is on Goodwins Neck, located on the
York River in York County, Virginia. The Yorktown facility has
its own deep-water port on the York River, close to the Norfolk
military complex and the
8
Hampton Roads shipyards. The Yorktown refinery primarily served
Yorktown, Virginia; Salisbury, Maryland; Norfolk, Virginia;
North Carolina; and the New York Harbor. We anticipate that our
product distribution terminal will serve the Mid-Atlantic region.
Process Summary. When operating, our Yorktown
refinery is a nominal 70,000 bpd heavy crude oil coking
facility that can process a wide variety of crude oil, including
certain lower quality crude oils, into high value finished
products, including both conventional and reformulated gasoline,
ultra low sulfur diesel fuel, and heating oil. We can also
produce liquefied petroleum gases, or LPGs, fuel oil, and
petroleum coke.
Power Supply. The Yorktown facility electrical
power is supplied by the regional electric company via two
independent transformers. All process computers and controls are
protected by various uninterruptible power supply systems.
Natural gas is supplied to our facility via pipeline. The
natural gas was used as a
back-up to
refinery produced fuel gas.
Raw Material Supply. When operating, most of
the crude oil for our Yorktown refinery came from South America.
Our Yorktown refinerys strategic location on the York
River and its own deep water port access allowed it to receive
supply shipments from various regions of the world. The refinery
received all of its crude supply from crude oil tankers. Its
ability to process a wide range of crude oils allowed our
Yorktown refinery to vary its crude oil slate. Lower quality
crude oils are typically available at a lower cost compared to
higher quality crude oils. The Yorktown refinery also purchased
other feedstocks and blendstocks to optimize refinery operations
and blending operations.
Western Refining Yorktown, Inc., or Western Yorktown, settled a
lawsuit with Statoil Marketing & Trading (US) Inc., or
Statoil, related to its crude oil supply agreement in February
2010, when the parties mutually agreed to dismiss all claims and
counterclaims with prejudice.
The following table summarizes the historical feedstocks used by
our Yorktown refinery for the years indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Percentage For
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended
|
|
Refinery Feedstocks
|
|
Year Ended December 31,
|
|
|
December 31,
|
|
(bpd)
|
|
2010(1)
|
|
|
2009
|
|
|
2008
|
|
|
2010
|
|
|
Crude Oil:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sweet crude oil
|
|
|
7,713
|
|
|
|
1,885
|
|
|
|
15,291
|
|
|
|
13.4
|
%
|
Heavy crude oil
|
|
|
40,274
|
|
|
|
47,659
|
|
|
|
45,364
|
|
|
|
69.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Crude Oils
|
|
|
47,987
|
|
|
|
49,544
|
|
|
|
60,655
|
|
|
|
83.1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Feedstocks and Blendstocks:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Intermediates and other
|
|
|
4,522
|
|
|
|
5,398
|
|
|
|
3,416
|
|
|
|
7.8
|
|
Blendstocks
|
|
|
5,255
|
|
|
|
7,791
|
|
|
|
5,727
|
|
|
|
9.1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Other Feedstocks and Blendstocks
|
|
|
9,777
|
|
|
|
13,189
|
|
|
|
9,143
|
|
|
|
16.9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Crude Oils and Other Feedstocks and Blendstocks
|
|
|
57,764
|
|
|
|
62,733
|
|
|
|
69,798
|
|
|
|
100.0
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Feedstocks for the year ended December 31, 2010 include
usage through September 30, 2010. As a result of the
temporary suspension of refining operations, we calculated bpd
feedstock volumes by dividing total volumes processed by
273 days. |
Refined Products Transportation. Most of the
finished products sold by the refinery were shipped by barge,
with the remaining amount shipped by truck or rail. A rail
system that served the refinery transported shipments of mixed
butane and petroleum coke from the refinery to our customers.
9
Dock System and Storage. Our facilitys
dock system is capable of handling 150,000 ton deadweight
tankers and barges up to 200,000 barrels. The facility
includes 5.4 million barrels of storage capacity for crude
oil, gasoline, intermediates and blendstocks, and distillates,
including 500,000 barrels of leased storage capacity from
an adjacent landowner.
Wholesale
Segment
Our wholesale group includes several lubricant and bulk
petroleum distribution plants, unmanned fleet fueling
operations, a bulk lubricant terminal facility, and a fleet of
crude oil and finished product trucks and lubricant delivery
trucks. The wholesale group distributes commercial wholesale
petroleum products primarily in Arizona, California, Colorado,
Nevada, New Mexico, Texas, and Utah. Our wholesale group
purchases petroleum fuels and lubricants from our refining group
and from third-party suppliers.
Our principal customers are unbranded retail fuel distributors
and the mining, construction, utility, manufacturing,
transportation, aviation, and agricultural industries. We
compete with other wholesale petroleum products distributors in
the areas we serve such as Pro Petroleum, Inc., Southern
Counties Fuels, Union Distributing, Brown Evans Distributing
Co., and Maxum Petroleum, Inc.
Retail
Segment
Our retail group operates service stations that include
convenience stores or kiosks. Our service stations sell various
grades of gasoline, diesel fuel, general merchandise, and
beverage and food products to the general public. Our wholesale
group supplies substantially all the gasoline and diesel fuel
that our retail group sells. We purchase general merchandise as
well as beverage and food products from various suppliers. At
February 25, 2011, our retail group operated 150 service
stations with convenience stores or kiosks located in Arizona,
New Mexico, and Colorado.
The main competitive factors affecting our retail segment are
the location of the stores, brand identification, and product
price and quality. Our service stations compete with Valero
Energy Corp., Alon USA Energy, K&G Markets (formerly
ConocoPhillips), Murphy Oil, Maverik, Circle K, Brewer Oil
Company, Quick-Trip, am/pm, and 7-2-11 food stores. Large chains
of retailers like Costco Wholesale Corp., Wal-Mart Stores Inc.,
and large grocery retailers compete in the motor fuel retail
business. Many of these competitors are substantially larger
than we are and because of their integrated operations, may be
better able to withstand volatile conditions in the fuel market
and lower profitability in merchandise sales.
At February 25, 2011, our retail group had 123 convenience
stores branded Giant, one branded Western, and two branded
Western Express. In addition, 14 units were branded Mustang
and 10 were branded Sundial. Gasoline brands sold at these
stores include Western, Giant, Mustang, Phillips 66, Conoco, and
Shell.
|
|
|
|
|
|
|
|
|
|
|
|
|
Location
|
|
Owned
|
|
|
Leased
|
|
|
Total
|
|
|
Arizona
|
|
|
24
|
|
|
|
18
|
|
|
|
42
|
|
New Mexico
|
|
|
72
|
|
|
|
24
|
|
|
|
96
|
|
Colorado
|
|
|
10
|
|
|
|
2
|
|
|
|
12
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
106
|
|
|
|
44
|
|
|
|
150
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Governmental
Regulation
All of our operations and properties are subject to extensive
federal, state, and local environmental, health, and safety
regulations governing, among other things, the generation,
storage, handling, use, and transportation of petroleum and
hazardous substances; the emission and discharge of materials
into the environment; waste management; characteristics and
composition of gasoline, diesel, and other fuels; and the
monitoring and reporting of greenhouse gas emissions. Our
operations also require numerous permits and authorizations
under various environmental, health, and safety laws and
regulations. Failure to comply with these permits or
environmental, health, or safety laws generally could result in
fines, penalties, or other sanctions, or a revocation of our
permits. We
10
have made significant capital and other expenditures to comply
with these environmental, health, and safety laws. We anticipate
significant capital and other expenditures with respect to
continuing compliance with these environmental, health, and
safety laws. For additional details on our capital expenditures
related to regulatory requirements and our refinery capacity
expansion and upgrade, see Item 7. Managements
Discussion and Analysis of Financial Condition and Results of
Operations Liquidity and Capital
Resources Capital Spending.
Periodically, we receive communications from various federal,
state, and local governmental authorities asserting violation(s)
of environmental laws
and/or
regulations. These governmental entities may also propose or
assess fines or require corrective action for these asserted
violations. We intend to respond in a timely manner to all such
communications and to take appropriate corrective action. We do
not anticipate that any such matters currently asserted will
have a material adverse impact on our financial condition,
results of operations, or cash flows.
El Paso
Refinery
The groundwater and certain solid waste management units and
other areas at and adjacent to our El Paso refinery have
been impacted by prior spills, releases, and discharges of
petroleum or hazardous substances and are currently undergoing
remediation by us and Chevron pursuant to certain agreed
administrative orders with the Texas Commission on Environmental
Quality, or TCEQ. Pursuant to our purchase of the north side of
the El Paso refinery from Chevron, Chevron retained
responsibility to remediate their solid waste management units
in accordance with its Resource Conservation Recovery Act, or
RCRA, permit, which Chevron has fulfilled. Chevron also retained
liability for, and control of, certain groundwater remediation
responsibilities, which are ongoing.
In May 2000, we entered into an Agreed Order with the Texas
Natural Resources Conservation Commission, now known as the
TCEQ, for remediation of the south side of our El Paso
refinery property. In August 2000, we purchased a Pollution and
Legal Liability and
Clean-Up
Cost Cap Insurance policy at a cost of $10.3 million, which
was expensed in 2000. The policy is non-cancelable and covers
environmental
clean-up
costs related to contamination that occurred prior to
December 31, 1999, including the costs of the Agreed Order
activities. The insurance provider assumed responsibility for
all environmental
clean-up
costs related to the Agreed Order up to $20 million. In
addition, under a settlement agreement with us, a subsidiary of
Chevron is obligated to pay 60% of any Agreed Order
environmental
clean-up
costs that would otherwise have been covered under the policy
but that exceed the $20 million threshold. Under the
policy, environmental costs outside the scope of the Agreed
Order are covered up to $20 million and require payment by
us of a deductible of $0.1 million per incident as well as
any costs that exceed the covered limits of the insurance policy.
The U.S. Environmental Protection Agency, or EPA, has
embarked on a Petroleum Refinery Enforcement Initiative, or EPA
Initiative, whereby it is investigating industry-wide
noncompliance with certain Clean Air Act rules. The EPA
Initiative has resulted in many refiners entering into consent
decrees typically requiring penalties and substantial capital
expenditures for additional air pollution control equipment.
Since December 2003, we have been voluntarily discussing a
settlement pursuant to the EPA Initiative related to the
El Paso refinery. Negotiations with the EPA regarding this
Initiative have focused exclusively on air emission programs. We
do not expect these negotiations to result in any soil or
groundwater remediation or
clean-up
requirements. In May 2008, we and the EPA agreed on the basic
EPA Initiative requirements related to the Fluid Catalytic
Cracking Unit, or FCCU, and heaters and boilers that we expect
will ultimately be incorporated into a final settlement
agreement between us and the EPA. Based on current negotiations
and information, we estimate the total capital expenditures
necessary to address the EPA Initiative issues would be
approximately $60 million, of which $38.8 million has
already been expended, $15.2 million for the installation
of a flare gas recovery system that was completed in 2007; and
$23.6 million for nitrogen oxides, or NOx, emission
controls on heaters and boilers was expended through 2010. We
estimate remaining expenditures of approximately
$21.2 million for the NOx emission controls on heaters and
boilers from 2011 through 2013. This estimate may change
depending upon the actual final settlement reached. We
anticipate meeting the EPA Initiative NOx requirements for the
FCCU using catalyst additives and therefore do not expect
additional capital expenditures related to the EPA Initiative
NOx requirements for the FCCU.
We received a proposed draft settlement agreement from the EPA
in September 2009 demanding penalties of $1.5 million. We
have accrued $1.5 million related to this matter. As of
February 25, 2011, a final settlement between us and the
EPA relating to this matter is still pending.
11
In March 2008, the TCEQ had notified us that it would be
presenting us with a proposed Agreed Order regarding six excess
air emission incidents that occurred at the El Paso
refinery during 2007 and early 2008. While at this time it is
not known precisely how or when the Agreed Order may affect us,
we may be required to implement corrective action under the
Agreed Order and we may be assessed penalties. We do not expect
any penalties or corrective action requested to have a material
adverse effect on our business, financial condition, or results
of operations or that any penalties assessed or increased costs
associated with the corrective action will be material.
In 2004 and 2005, the El Paso refinery applied for and was
issued a Texas Flexible Permit by the TCEQ Flexible Permits
program, under which the refinery continues to operate.
Established in 1994 under the Texas Clean Air Act, the program
grants operational flexibility to industrial facilities and
permits the allocation of emissions on a facility-wide basis in
exchange for emissions reduction and controlling previously
unregulated grandfathered emission sources. The TCEQ
submitted its Flexible Permits Program rules to the EPA for
approval in 1994 and has administered the program for
16 years with the EPAs full knowledge. In May 2010,
the El Paso refinery received a request from the EPA,
pursuant to Section 114 of the Clean Air Act, seeking
information about the refinerys air permits. We responded
to the EPAs request in June 2010. Also in June 2010, the
EPA disapproved the TCEQ Flexible Permits Program. In July 2010,
the Texas Attorney General filed a legal challenge to the
EPAs disapproval in a federal appeals court asking for
reconsideration. Although we believe our Texas Flexible Permit
is federally enforceable, we agreed in December 2010 to submit
within one year an application to TCEQ for a permit amendment to
obtain an approved Texas State Implementation Plan, or SIP, air
quality permit to address concerns raised by the EPA about all
flexible permits. Sufficient time has not elapsed for us to
reasonably estimate any potential impact of these regulatory
developments in the Texas air permits program.
In September 2010, we received a notice of intent to sue under
the Clean Air Act from several environmental groups. While not
entirely clear, the notice apparently contends that our
El Paso refinery is not operating under a valid permit or
permits because the EPA has disapproved the TCEQ Flexible
Permits program and that our El Paso refinery may have
exceeded certain emission limitations under these same permits.
We dispute these claims and maintain our El Paso refinery
is properly operating, and has not exceeded emissions
limitations, under the validly issued TCEQ permits. We intend to
defend our refinery accordingly.
Four
Corners Refineries
Four Corners 2005 Consent Agreements. In July
2005, as part of the EPA Initiative, Giant reached an
administrative settlement with the New Mexico Environment
Department, or NMED, and the EPA in the form of consent
agreements that resolved certain alleged violations of air
quality regulations at the Gallup and Bloomfield refineries in
the Four Corners area of New Mexico, or the 2005 NMED Agreement.
In January 2009, we and the NMED agreed to an amendment of the
2005 administrative settlement with the NMED, or the 2009 NMED
Amendment, which altered certain deadlines and allowed for
alternative air pollution controls.
In November 2009, we indefinitely suspended refining operations
at our Bloomfield refinery. We currently operate the site as a
products distribution terminal and crude oil storage facility.
We continue to operate certain Bloomfield refinery equipment to
support the terminal and to store crude for our Gallup refinery.
We are currently negotiating with the NMED to revise the 2009
NMED Amendment to reflect the indefinite suspension.
Based on current information and the 2009 NMED Amendment and
favorably negotiating a revision to reflect the indefinite
suspension of refining operations at our Bloomfield facility, we
estimate $17.6 million total remaining capital expenditures
will be required pursuant to the 2009 NMED Amendment. Through
2010, we have expended $5.9 million and expect to spend the
remaining $11.7 million during 2011 and 2012. These capital
expenditures will primarily be for installation of emission
controls on the heaters, boilers, and FCCU, and for reducing
sulfur in fuel gas to reduce emissions of sulfur dioxide and NOx
and particulate matter from our Gallup refinery. The 2009 NMED
Amendment also provided for a $2.4 million penalty. Payment
of the penalty was completed between November 2009 and September
2010 to fund a Supplemental Environmental Project, or SEP. We do
not expect implementation of the requirements in the 2005 NMED
Agreement and the associated 2009 NMED Amendment will result in
any soil or groundwater remediation or
clean-up
costs.
Bloomfield 2007 NMED Remediation Order. In
July 2007, we received a final administrative compliance order
from the NMED alleging that releases of contaminants and
hazardous substances that have occurred at the
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Bloomfield refinery over the course of its operation prior to
June 1, 2007, have resulted in soil and groundwater
contamination. Among other things, the order requires us to:
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investigate and determine the nature and extent of such releases
of contaminants and hazardous substances;
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perform interim remediation measures, or continue interim
measures already begun, to mitigate any potential threats to
human health or the environment from such releases;
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identify and evaluate alternatives for corrective measures to
clean up any contaminants and hazardous substances released at
the refinery and prevent or mitigate their migration at or from
the site;
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implement any corrective measures that may be approved by the
NMED;
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develop investigation work plans over a period of approximately
four years; and
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implement corrective measures pursuant to the investigation.
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The order recognizes that prior work satisfactorily completed
may fulfill some of the foregoing requirements. In that regard,
we have already put in place some remediation measures with the
approval of the NMED and New Mexico Oil Conservation Division.
Based on current information, we estimate a remaining
undiscounted cost of $3.3 million for implementing the
investigation and interim measures of the order. As of
December 31, 2010, we had a liability of $2.5 million
relating to the investigation and interim measures of the order
implementation costs. As of December 31, 2010, we had
expended $2.3 million to implement the order.
Gallup 2007 Resource Conservation and Recovery Act, or RCRA,
Inspection. In September 2007, our Gallup
refinery was inspected jointly by the EPA and the NMED, or the
Gallup 2007 RCRA Inspection, to determine compliance with the
EPAs hazardous waste regulations promulgated pursuant to
the RCRA. We reached a final settlement with the agencies in
August 2009 and paid a penalty of $0.7 million in October
2009. We do not expect implementation of the requirements in the
final settlement will result in any soil or groundwater
remediation or
clean-up
costs. We currently estimate $15.4 million in capital
expenditures to upgrade the wastewater treatment plant at the
Gallup refinery pursuant to the requirements of the final
settlement. Through 2010, we have expended $4.2 million on
the upgrade of the wastewater treatment plant and expect to
spend the remaining $11.2 million during 2011 and 2012. In
April 2010, we submitted a plan with the design and construction
schedule to upgrade the wastewater treatment plant to the NMED
for approval. We negotiated with the NMED and the EPA regarding
modifications to the plan issued by the NMED in its May 2010
approval letter, which resulted in a September 2010 modification
to the August 2009 final settlement establishing a May 2012
deadline for
start-up of
the upgraded wastewater treatment plant.
Gallup 2010 NMED Compliance Order. In late
October 2010, the NMED issued a proposed compliance order to us
alleging violations of air quality regulations and permits
related to certain emission limits at our Gallup refinery. The
violations are alleged to have occurred at various times between
March 2009 and October 2010. Under this compliance order, we
have been assessed a penalty of $0.6 million. We are
currently evaluating the merits of the alleged violations
described in the compliance order. As the outcome of ongoing
discussions or negotiations with the NMED is uncertain, we
cannot reasonably estimate the liability under the order at this
time. No amounts have been accrued at December 31, 2010 for
this matter.
Yorktown
Refinery
Yorktown 1991 and 2006 Orders. Giant and a
subsidiary company assumed certain liabilities and obligations
in connection with the 2002 purchase of the Yorktown refinery
from BP Corporation North America Inc. and BP Products North
America Inc., or collectively BP, and BP agreed to indemnify
Giant for certain costs. During 2007, BP disputed
indemnification for certain costs. In the related lawsuit styled
Western Refining Yorktown, Inc. f/k/a Giant Yorktown,
Inc. v. BP Corporation North America, Inc. and BP Products
North America, Inc., all claims and counterclaims were
voluntarily dismissed with prejudice in 2009 by mutual agreement
of the parties.
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In August 2006, Giant agreed to the terms of the final
administrative consent order pursuant to which Giant would
implement a
clean-up
plan for the refinery. Following the acquisition of Giant, we
completed the first phase of the soil
clean-up
plan and negotiated revisions with the EPA for the remainder of
the soil
clean-up
plan. We anticipate completing the requirements of the soil
clean-up in
2011.
We currently estimate total remediation expenditures of
$39.1 million associated with the EPA order. Through
December 2010, we have expended $22.7 million related to
the EPA order. We anticipate further expenditures of
$16.0 million primarily during 2011 with the remainder over
the next 29 years, ending in 2040. The EPA issued an
approval in January 2010 that allowed us to begin implementing
our revised soil
clean-up
plan during the second quarter of 2010. The January 2010 EPA
approval and a prior EPA approval in 2008 allowed adjustments to
the cost estimates for the groundwater monitoring plan and
reductions to our estimate of total remediation expenditures.
Yorktown 2002 Amended Consent Decree. In May
2002, Giant acquired the Yorktown refinery and assumed certain
environmental obligations including responsibilities under a
consent decree, or Consent Decree, among various parties
covering many locations entered into August 2001 under the EPA
Initiative. Parties to the Consent Decree include the United
States, BP Exploration and Oil Co., Amoco Oil Company, and
Atlantic Richfield Company. As applicable to our Yorktown
refinery, the Consent Decree required, among other things, a
reduction of NOx, sulfur dioxide, and particulate matter
emissions and upgrades to the refinerys leak detection and
repair program. We do not expect implementation of the Consent
Decree requirements will require any soil or groundwater
remediation or
clean-up.
Pursuant to the Consent Decree and prior to May 31, 2007,
Giant had installed a new sour water stripper and sulfur
recovery unit with a tail gas treating unit and an electrostatic
precipitator on the FCCU and had begun using sulfur dioxide
emissions reducing catalyst additives in the FCCU. We
temporarily suspended refining operations at our Yorktown
facility in September 2010. Until such time that local market
economics can support sustained profitable refining operations,
we intend to operate our Yorktown facility as a product
distribution terminal only. We expect additional capital
expenditures to complete implementation of the Consent Decree
requirements when refining operations are resumed. Our current
estimate for these capital expenditures is $5.0 million and
could differ significantly from what is required when refining
operations are resumed. We do not expect that completing the
requirements of the Consent Decree will result in material
increased operating costs, nor do we expect the completion of
these requirements to have a material adverse effect on our
business, financial condition, or results of operations.
In March 2010, the EPA demanded stipulated penalties in the
amount of $0.5 million, pursuant to the Consent Decree, for
a flaring event that occurred at our Yorktown refinery in
October 2009. In April 2010, we met with the EPA and provided
additional written clarifying information in anticipation that
the EPA will consider the information as the basis for reducing
the agencys demand for stipulated penalties. We continue
to communicate with the EPA regarding the additional information
provided. To allow discussions to continue, the EPA clarified
its position in May 2010, stating that the March 2010 letter did
not constitute a demand pursuant to the Consent Decree. We do
not expect any penalties, corrective action, or other associated
settlement costs related to this issue to have a material
adverse effect on our business, financial condition, or results
of operations.
Yorktown EPA EPCRA Potential Enforcement
Notice. In January 2010, the EPA issued our
Yorktown refinery a notice to show cause why the EPA
should not bring an enforcement action pursuant to the
notification requirements under the Emergency Planning and
Community
Right-to-Know
Act related to two separate flaring events that occurred in 2007
prior to our acquisition of Giant. We reached a settlement of
this enforcement notice with the EPA in June 2010 for
$0.2 million. As of December 31, 2010, the entire
penalty has been paid to the EPA.
Regulation
of Fuel Quality
The EPA adopted regulations under the Clean Air Act that require
significant reductions in the sulfur content in gasoline,
on-road diesel fuel, and off-road diesel fuel. These regulations
required most refineries to begin reducing sulfur content in
gasoline to 30 parts per million, or ppm, on January 1,
2004, with full compliance by January 1, 2006, and require
reductions in sulfur content in on-road diesel to 15 ppm
beginning on June 1, 2006, with full compliance by
January 1, 2010. Qualified small refiners or
refiners seeking and receiving hardship waivers with compliance
plans from the EPA were allowed additional time under these
regulations to comply.
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Under the EPAs regulations, all on-road and off-road
diesel, with the exception of off-road diesel for locomotive and
marine use, must meet a 15 ppm sulfur standard as of June
2010. Off-road diesel produced for locomotive and marine use is
allowed to meet the 500 ppm sulfur standard through May
2012. Our El Paso refinery implemented the 15 ppm
sulfur standard for on-road diesel by April 2006 and the interim
500 ppm standard for off-road diesel by December 2009. Our
Yorktown refinery implemented the 15 ppm sulfur standard
for on-road and off-road diesel by February 2007 under a
modified compliance plan. Our Gallup refinery implemented the
15 ppm sulfur standard for on-road diesel by June 2006, and
was allowed to produce, under the flexibility of the regulation,
up to 20% by volume of its on-road diesel at 500 ppm sulfur
through May 2010. Our Gallup refinery implemented the interim
500 ppm standard for off-road diesel by June 2007 and was
allowed to produce off-road diesel at this standard through May
2010. Our Gallup refinery currently relies on operational and
marketing changes to meet the on-road and off-road diesel
15 ppm sulfur standard.
By June 2012, all locomotive and marine diesel must also meet
the 15 ppm sulfur standard. EPA regulations allow the
one-time use of credits to extend the June 2012 deadline by up
to 24 months. Low sulfur credits purchased in 2010 will
allow our El Paso refinery to continue producing
500 ppm sulfur locomotive fuel until late 2013. Our
Yorktown refinery met this requirement before refining
operations were suspended in 2010. We are evaluating the need
for capital expenditures to produce 15 ppm sulfur
locomotive fuel.
Our Yorktown refinery was producing 30 ppm gasoline by
May 1, 2008, as required by its EPA compliance plan. Our
El Paso refinery began producing low sulfur gasoline by
August 1, 2009, as required by the EPA compliance plan for
Yorktown and following our loss of small refiner
status after the 2007 Giant acquisition. All of our refineries
meet the requirements of the EPAs low sulfur gasoline
regulations. For additional details, see Item 7.
Managements Discussion and Analysis of Financial Condition
and Results of Operations Liquidity and Capital
Resources Capital Spending.
Pursuant to the Energy Acts of 2005 and 2007, the EPA has issued
Renewable Fuels Standards, or RFS, implementing mandates to
blend renewable fuels into the petroleum fuels produced at our
refineries. The standards have been enforced at our El Paso
refinery since September 2007. Our Gallup refinery became
subject to RFS in January 2011 and will remain so unless the EPA
grants a further extension to small refineries based on a
U.S. Department of Energy study. Our Yorktown refinery will
be subject to RFS when we restart refinery operations unless the
EPA grants a further extension. Annually, the EPA establishes a
volume of renewable fuels that obligated refineries must blend
into their finished petroleum fuels. The obligated volume
increases over time until 2022. Blending renewable fuels into
their finished petroleum fuels will displace an increasing
volume of a refinerys product pool. In 2010, the RFS
obligation for ethanol and biodiesel for our El Paso
refinery was met by blending at El Paso and also by
transferring credits from blending at our Yorktown and Gallup
refineries, the product distribution terminals in Albuquerque
and Bloomfield, and the purchase of third-party credits.
Our El Paso and Gallup refineries are required to meet the
new Mobile Source Air Toxics, or MSAT II, regulations to reduce
the benzene content of gasoline. Under the MSAT II regulations,
benzene in the finished gasoline pool must be reduced to an
annual average of 0.62 volume percent by 2011. Beginning on
July 1, 2012, each refinery must also average 1.30 volume
percent benzene without the use of credits. As of
December 31, 2010, we have expended $62.0 million to
comply with MSAT II regulations at our El Paso refinery by
completing construction of a benzene saturation unit in 2010,
which is scheduled for
start-up in
March 2011. Early credits generated in 2009 and 2010 from the
operation of our Yorktown refinery will be used by our Gallup
refinery to comply with the 0.62 volume percent requirement. We
anticipate $2.0 million or less in capital expenditures
during 2011 and 2012 for our Gallup refinery to meet the 1.30
volume percent requirement. Our Yorktown refinery met the
1.30 volume percent benzene requirement prior to our
temporarily suspending Yorktown refining activity and had
planned to rely on credits to comply with the 0.62 volume
percent requirement.
Several northeast states have proposed legislation to reduce the
sulfur content of home heating oil. New Jersey has published a
rule change that would require 500 ppm sulfur home heating
oil beginning July 2014 and 15 ppm sulfur home heating oil
beginning July 2016. New York has passed legislation to
implement the 15 ppm sulfur level
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in July 2012. Before refining operations were suspended at our
Yorktown refinery during 2010, it produced home heating oil that
complied with the 3,000 ppm sulfur specification, but
lacked the processing capability to produce heating oil that
would comply with the revised standards. Implementation of these
new standards will potentially reduce the market for
3.000 ppm sulfur home heating oil resulting in changes to
our product slate and profitability when we restart refining
operations at our Yorktown refinery.
Environmental
Remediation
Certain environmental laws hold current or previous owners or
operators of real property liable for the costs of cleaning up
spills, releases, and discharges of petroleum or hazardous
substances, even if these owners or operators did not know of
and were not responsible for such spills, releases, and
discharges. These environmental laws also assess liability on
any person who arranges for the disposal or treatment of
hazardous substances, regardless of whether the affected site is
owned or operated by such person. We may face currently unknown
liabilities for
clean-up
costs pursuant to these laws.
In addition to
clean-up
costs, we may face liability for personal injury or property
damage due to exposure to chemicals or other hazardous
substances that we may have manufactured, used, handled,
disposed of, or that are located at or released from our
refineries or otherwise related to our current or former
operations. We may also face liability for personal injury,
property damage, natural resource damage, or for
clean-up
costs for the alleged migration of petroleum or hazardous
substances from our refineries to adjacent and other nearby
properties.
Employees
As of February 25, 2011, we employed approximately
2,950 people, approximately 380 of whom were covered by
collective bargaining agreements. Subject to a Memorandum of
Understanding dated August 23, 2010, between Western
Refining Yorktown, Inc. and the local union representing the
covered Yorktown refinery employees, the collective bargaining
agreement at our Yorktown refinery was terminated in connection
with the temporary suspension of refining activities at our
Yorktown facility. If we restart refining operations at our
Yorktown facility prior to March 15, 2012, the collective
bargaining agreement for covered Yorktown employees will be
reinstated. All separated covered employees have recall rights
if we restart Yorktown refining operations prior to
March 16, 2012. In 2008, we successfully negotiated
collective bargaining agreements covering employees at our
Gallup and Bloomfield refineries that expire in 2011 and 2012,
respectively. Although the collective bargaining agreement
remains in force, the covered employees at our Bloomfield
refinery were terminated in connection with the indefinite
suspension of refining operations at our Bloomfield facility
during November 2009. We also successfully negotiated a new
collective bargaining agreement covering employees at our
El Paso refinery, renewing the collective bargaining
agreement that expired in April 2009. The collective bargaining
agreement covering the El Paso refinery employees expires
in April 2012. While all of our collective bargaining agreements
contain no strike provisions, those provisions are
not effective in the event that an agreement expires.
Accordingly, we may not be able to prevent a strike or work
stoppage in the future, and any such work stoppage could have a
material adverse affect on our business, financial condition,
and results of operations.
Available
Information
We file reports with the Securities and Exchange Commission, or
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 SECs
Public Reference Room at 100 F Street, N.E.,
Room 1580, Washington, D.C. 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 SECs Internet site at
http://www.sec.gov
contains the reports, proxy, and information statements, and
other information filed electronically.
As required by Section 406 of the Sarbanes-Oxley Act of
2002, we have adopted a code of ethics that applies specifically
to our Chief Executive Officer, Chief Financial Officer, and
Principal Accounting Officer. We have also adopted a Code of
Business Conduct and Ethics applicable to all our directors,
officers, and employees. Those codes of ethics are posted on our
website. Within the time period required by the SEC and the New
York Stock Exchange,
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or NYSE, we will post on our website any amendment to our code
of ethics and any waiver applicable to any of our Chief
Executive Officer, Chief Financial Officer, and Principal
Accounting Officer. Our website address is:
http://www.wnr.com.
We make our website 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 website 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 simultaneously to the electronic
filings of those materials with, or furnishing of those
materials to, the SEC. We also make available to shareholders
hard copies of our complete audited financial statements free of
charge upon request.
On June 24, 2010, the Companys Chief Executive
Officer certified to the NYSE that he was not aware of any
violation by the Company of the NYSEs corporate governance
listing standards. In addition, attached as Exhibits 31.1
and 31.2 to this
Form 10-K
are the certifications required by Section 302 of the
Sarbanes-Oxley Act of 2002.
An investment in our common shares involves risk. In addition to
the other information in this report and our other filings with
the SEC, you should carefully consider the following risk
factors in evaluating us and our business.
The
price volatility of crude oil, other feedstocks, refined
products, and fuel and utility services has had and may continue
to have a material adverse effect on our earnings and cash
flows.
Our earnings and cash flows from operations depend on the margin
above fixed and variable expenses (including the cost of
refinery feedstocks, such as crude oil) at which we are able to
sell refined products. Refining margins historically have been
volatile, and are likely to continue to be volatile, as a result
of a variety of factors, including fluctuations in the prices of
crude oil, other feedstocks, refined products, and fuel and
utility services. In particular, our refining margins were
significantly lower in 2010 and 2009 compared to 2008 and 2007
due to decreased demand for refined products, substantial
increases in feedstock costs, and lower increases in product
prices throughout much of 2009 and 2010.
In recent years, the prices of crude oil, other feedstocks, and
refined products have fluctuated substantially. The NYMEX WTI
postings of crude oil for 2010 ranged from $68.01 to $91.51 per
barrel. Prices of crude oil, other feedstocks, and refined
products depend on numerous factors beyond our control,
including the supply of and demand for crude oil, other
feedstocks, gasoline, and other refined products. Such supply
and demand are affected by, among other things:
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changes in global and local economic conditions;
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demand for crude oil and refined products, especially in the
U.S., China, and India;
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worldwide political conditions, particularly in significant oil
producing regions such as the Middle East, West Africa, and
Latin America;
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the level of foreign and domestic production of crude oil and
refined products and the level of crude oil, feedstocks, and
refined products imported into the U.S., which can be impacted
by accidents, interruptions in transportation, inclement
weather, or other events affecting producers and suppliers;
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U.S. government regulations;
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utilization rates of U.S. refineries;
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changes in fuel specifications required by environmental and
other laws;
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the ability of the members of the Organization of Petroleum
Exporting Countries, or OPEC, to maintain oil price and
production controls;
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development and marketing of alternative and competing fuels;
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pricing and other actions taken by competitors that impact the
market;
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product pipeline capacity, including the Magellan Southwest
System pipeline, as well as Kinder Morgans expansion of
its East Line, both of which could increase supply in certain of
our service areas and therefore reduce our margins;
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accidents, interruptions in transportation, inclement weather or
other events that can cause unscheduled shutdowns or otherwise
adversely affect our plants, machinery or equipment, or those of
our suppliers or customers; and
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local factors, including market conditions, weather conditions,
and the level of operations of other refineries and pipelines in
our service areas.
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Volatility has had, and may continue to further have, a negative
effect on our results of operations to the extent that the
margin between refined product prices and feedstock prices
narrows further, as was the case throughout much of 2009 and
2010.
The nature of our business requires us to maintain substantial
quantities of crude oil and refined product inventories. Crude
oil and refined products are commodities. As a result, we have
no control over the changing market value of these inventories.
Because our inventory of crude oil and refined product is valued
at the lower of cost or market value under the
last-in,
first-out, or LIFO, inventory valuation methodology, if
the market value of our inventory were to decline to an amount
less than our LIFO cost, we would record a write-down of
inventory and a non-cash charge to cost of products sold. The
estimated fair value of the Giant inventory recorded as a result
of the acquisition of Giant increased the likelihood of a lower
of cost or market, or LCM, inventory write-down to occur in the
future. As a result of increasing market prices of crude oil,
blendstocks, and refined products, we had a net change in the
lower of cost or market reserve from December 31, 2008 to
December 31, 2009 of $61.0 million to value our
Yorktown inventories to net realizable market values, which
decreased cost of products sold and increased refinery gross
margin for the year ended December 31, 2009. In addition,
due to the volatility in the price of crude oil and other
blendstocks, we experienced fluctuations in our LIFO reserves
during the three years ended December 31, 2010. We also
experienced LIFO liquidations based on decreased levels in our
inventories. These LIFO liquidations resulted in decreases in
cost of products sold of $16.9 million and
$9.4 million for the years ended December 31, 2010 and
2009, and an increase in cost of products sold of
$66.9 million for the year ended December 31, 2008.
In addition, the volatility in costs of fuel, principally
natural gas, and other utility services, principally
electricity, used by our refineries affects operating costs.
Fuel and utility prices have been, and will continue to be,
affected by factors outside our control, such as supply and
demand for fuel and utility services in both local and regional
markets. Natural gas prices have historically been volatile.
Typically, electricity prices fluctuate with natural gas prices.
Future increases in fuel and utility prices may have a negative
effect on our results of operations.
If the
price of crude oil increases significantly or our credit profile
changes, or if we are unable to access our Revolving Credit
Agreement for borrowings or for letters of credit, our liquidity
and our ability to purchase enough crude oil to operate our
refineries at full capacity could be materially and adversely
affected.
We rely on borrowings and letters of credit under our Revolving
Credit Agreement to purchase crude oil for our refineries.
Changes in our credit profile could affect the way crude oil
suppliers view our ability to make payments and induce them to
shorten the payment terms of their invoices with us or require
additional support such as letters of credit. Due to the large
dollar amounts and volume of our crude oil and other feedstock
purchases, any imposition by our creditors of more burdensome
payment terms on us, or our inability to access our Revolving
Credit Agreement, may have a material adverse effect on our
liquidity and our ability to make payments to our suppliers,
which could hinder our ability to purchase sufficient quantities
of crude oil to operate our refineries at planned rates. In
addition, if the price of crude oil increases significantly, we
may not have sufficient capacity under our Revolving Credit
Agreement, or sufficient cash on hand, to purchase enough crude
oil to operate our refineries at planned rates. A failure to
operate our refineries at planned rates could have a material
adverse effect on our earnings and cash flows.
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We
have a significant amount of indebtedness.
As of December 31, 2010, our total debt was
$1,069.5 million and our stockholders equity was
$675.6 million. On December 23, 2010, we completed an
amendment of our Revolving Credit Agreement, resulting in total
commitments of $800.0 million composed of a
$145.0 million tranche maturing on May 31, 2012 and a
$655.0 million tranche maturing on January 1, 2015. As
of December 31, 2010, the gross availability under the
Revolving Credit Agreement was $624.0 million pursuant to
the borrowing base. As of December 31, 2010, we had net
availability under the Revolving Credit Agreement of
$335.6 million due to $288.4 million in letters of
credit outstanding and no direct borrowings. On
February 25, 2011, the gross availability under the
Revolving Credit Agreement was $650.3 million pursuant to
the borrowing base. On February 25, 2011, we had net
availability under the Revolving Credit Agreement of
$192.3 million due to $273.0 million in letters of
credit outstanding and $185.0 million in direct borrowings.
Our level of debt may have important consequences to you. Among
other things, it may:
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limit our ability to use our cash flow, or obtain additional
financing, for future working capital, capital expenditures,
acquisitions, or other general corporate purposes;
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restrict our ability to pay dividends;
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require a substantial portion of our cash flow from operations
to make debt service payments;
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limit our flexibility to plan for, or react to, changes in our
business and industry conditions;
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place us at a competitive disadvantage compared to our less
leveraged competitors; and
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increase our vulnerability to the impact of adverse economic and
industry conditions and, to the extent of our outstanding debt
under our floating rate debt facilities, the impact of increases
in interest rates.
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We cannot assure you that we will continue to generate
sufficient cash flows or that we will be able to borrow funds
under our Revolving Credit Agreement in amounts sufficient to
enable us to service our debt or meet our working capital and
capital expenditure requirements. Our ability to generate
sufficient cash flows from our operating activities will
continue to be primarily dependent on producing or purchasing,
and selling, sufficient quantities of refined products at
margins sufficient to cover fixed and variable expenses. If our
margins were to deteriorate significantly, or if our earnings
and cash flow were to suffer for any other reason, we may be
unable to comply with the financial covenants set forth in our
credit facilities. If we fail to satisfy these covenants, we
could be prohibited from borrowing for our working capital needs
and issuing letters of credit, which would hinder our ability to
purchase sufficient quantities of crude oil to operate our
refineries at planned rates. To the extent that we are unable to
generate sufficient cash flows from operations, or if we are
unable to borrow or issue letters of credit under the Revolving
Credit Agreement, we may be required to sell assets, reduce
capital expenditures, refinance all or a portion of our existing
debt, or obtain additional financing through equity or debt
financings. If additional funds are obtained by issuing equity
securities or if holders of our outstanding
5.75% Convertible Senior Notes convert those notes into
shares of our common stock, our existing stockholders could be
diluted. We cannot assure you that we will be able to refinance
our debt, sell assets, or obtain additional financing on terms
acceptable to us, if at all. In addition, our ability to incur
additional debt will be restricted under the covenants contained
in our Revolving Credit Agreement, Term Loan Credit Agreement,
and Senior Secured Notes. See Item 7. Managements
Discussion and Analysis of Financial Condition and Results of
Operations Liquidity and Capital
Resources Working Capital and Item 7.
Managements Discussion and Analysis of Financial Condition
and Results of Operations Liquidity and Capital
Resources Indebtedness.
Covenants
and events of default in our debt instruments could limit our
ability to undertake certain types of transactions and adversely
affect our liquidity.
Our Revolving Credit Agreement, Term Loan Credit Agreement, or
Term Loan, and the indenture governing our Senior Secured Notes
contain covenants and events of default that may limit our
financial flexibility and ability to undertake certain types of
transactions. For instance, we are subject to covenants that
restrict our activities, including restrictions on:
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engaging in mergers, consolidations, and sales of assets;
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incurring additional indebtedness;
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providing guarantees;
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engaging in different businesses;
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making investments;
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making certain dividend, debt, and other restricted payments;
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engaging in certain transactions with affiliates; and
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entering into certain contractual obligations.
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We are also subject to financial covenants that require us to
maintain, in the case of the Revolving Credit Agreement, a
minimum fixed charge coverage ratio (as defined therein),
contingent on the level of availability thereunder, and in the
case of the Term Loan Credit Agreement, a minimum consolidated
interest coverage ratio (as defined therein), and a maximum
consolidated leverage ratio (as defined therein). Our ability to
comply with these covenants will depend on factors outside our
control, including refined product margins. We cannot assure you
that we will satisfy these covenants. If we fail to satisfy the
covenants set forth in these facilities or an event of default
occurs under these facilities, the maturity of the loans, our
Senior Secured Notes and our Convertible Senior Notes could be
accelerated or we could be prohibited from borrowing for our
working capital needs and issuing letters of credit. If the
loans, our Senior Secured Notes, or our Convertible Senior Notes
are accelerated and we do not have sufficient cash on hand to
pay all amounts due, we could be required to sell assets, to
refinance all or a portion of our indebtedness, or to obtain
additional financing through equity or debt financings.
Refinancing may not be possible and additional financing may not
be available on commercially acceptable terms, or at all. If we
cannot borrow or issue letters of credit under the Revolving
Credit Agreement, we would need to seek additional financing, if
available, or curtail our operations.
We
have capital needs for which our internally generated cash flows
and other sources of liquidity may not be
adequate.
If we cannot generate cash flow or otherwise secure sufficient
liquidity to support our short-term and long-term capital
requirements, we may not be able to comply with certain
environmental standards by the current EPA mandated deadlines or
pursue our business strategies, in which case our operations may
not perform as well as we currently expect. We have substantial
short-term and long-term capital needs, including those for
capital expenditures that we will make to comply with various
regulatory requirements. Our short-term working capital needs
are primarily crude oil purchase requirements, which fluctuate
with the pricing and sourcing of crude oil. We also have
significant long-term needs for cash, including those to support
ongoing capital expenditures and other regulatory compliance.
The
dangers inherent in our operations could cause disruptions and
could expose us to potentially significant losses, costs, or
liabilities. Any significant interruptions in the operations of
any of our refineries could materially and adversely affect our
business, financial condition, and results of
operations.
Our operations are subject to significant hazards and risks
inherent in refining operations and in transporting and storing
crude oil, intermediate products, and refined products. These
hazards and risks include, but are not limited to, the following:
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natural disasters;
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weather-related disruptions;
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fires;
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explosions;
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pipeline ruptures and spills;
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third-party interference;
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disruption of natural gas deliveries;
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disruptions of electricity deliveries;
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disruption of sulfur gas processing by E.I. du Pont de Nemours
at our El Paso refinery; and
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mechanical failure of equipment at our refineries or third-party
facilities.
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Any of the foregoing could result in production and distribution
difficulties and disruptions, environmental pollution, personal
injury or wrongful death claims, and other damage to our
properties and the properties of others. There is also risk of
mechanical failure and equipment shutdowns both in general and
following unforeseen events. For example, in February 2011, we
experienced several days of unplanned downtime at our
El Paso refinery due to weather related causes and
interruptions to our electrical supply. Furthermore, in any of
those situations, undamaged refinery processing units may be
dependent on or interact with damaged process units and,
accordingly, are also subject to being shut down.
Our refineries consist of many processing units, several of
which have been in operation for a long time. One or more of the
units may require unscheduled downtime for unanticipated
maintenance or repairs, or our planned turnarounds may last
longer than anticipated. Scheduled and unscheduled maintenance
could reduce our revenues and increase our costs during the
period of time that our units are not operating.
Our refining activities are conducted at our El Paso
refinery in Texas, the Yorktown refinery in Virginia, and our
Gallup refinery in New Mexico. The refineries constitute a
significant portion of our operating assets, and our refineries
supply a significant portion of our fuel to our retail
operations. Prior to our acquisition of Giant in 2007, there was
one fire incident at the Yorktown refinery and two fire
incidents at the Gallup refinery in late 2006. Because of the
significance to us of our refining operations, the occurrence of
any of the events described above could significantly disrupt
our production and distribution of refined products, and any
sustained disruption could have a material adverse effect on our
business, financial condition, and results of operations.
Crude oil supplies for the El Paso refinery come from the
Permian Basin in Texas and New Mexico and therefore are
generally not subject to interruption from severe weather, such
as hurricanes. We, however, obtain certain of our feedstocks for
the El Paso refinery, such as alkylate, and some refined
products we purchase for resale, by pipeline from Gulf Coast
refineries. Alkylate is used to produce a portion of our Phoenix
Clean Burning Gasoline, or CBG, and other refined products. If
our supply of feedstocks is interrupted for the El Paso
refinery, our business, financial condition, and results of
operations could be adversely impacted.
Our
operations involve environmental risks that could give rise to
material liabilities.
Our operations, and those of prior owners or operators of our
properties, have previously resulted in spills, discharges, or
other releases of petroleum or hazardous substances into the
environment, and such spills, discharges, or releases could also
happen in the future. Past or future spills related to any of
our operations, including our refineries, product terminals, or
transportation of refined products or hazardous substances from
those facilities, may give rise to liability (including strict
liability, or liability without fault, and
clean-up
responsibility) to governmental entities or private parties
under federal, state, or local environmental laws, as well as
under common law. For example, we could be held strictly liable
under the Comprehensive Environmental Responsibility,
Compensation, and Liability Act, or CERCLA, for contamination of
properties that we currently own or operate and facilities to
which we transported or arranged for the transportation of
wastes or by-products for use, treatment, storage or disposal,
without regard to fault or whether our actions were in
compliance with law at the time. Our liability could also
increase if other responsible parties, including prior owners or
operators of our facilities, fail to complete their
clean-up
obligations. Based on current information, we do not believe
these liabilities are likely to have a material adverse effect
on our business, financial condition, or results of operations.
In the event that new spills, discharges, or other releases of
petroleum or hazardous substances occur or are discovered or
there are other changes in facts or in the level of
contributions being made by other responsible parties, there
could be a material adverse effect on our business, financial
condition, and results of operations.
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In addition, we may face liability for alleged personal injury
or property damage due to exposure to chemicals or other
hazardous substances located at or released from our refineries
or otherwise related to our current or former operations. We may
also face liability for personal injury, property damage,
natural resource damage, or for
clean-up
costs for the alleged migration of contamination or other
hazardous substances from our refineries to adjacent and other
nearby properties.
We may
incur significant costs to comply with environmental and health
and safety laws and regulations.
Our operations and properties are subject to extensive federal,
state, and local environmental, health, and safety regulations
governing, among other things, the generation, storage,
handling, use, and transportation of petroleum and hazardous
substances, the emission and discharge of materials into the
environment, waste management, characteristics, composition of
gasoline, diesel, and other fuels and the monitoring and
reporting of greenhouse gas emissions. If we fail to comply with
these regulations, we may be subject to administrative, civil,
and criminal proceedings by governmental authorities, as well as
civil proceedings by environmental groups and other entities and
individuals. A failure to comply, and any related proceedings,
including lawsuits, could result in significant costs and
liabilities, penalties, judgments against us, or governmental or
court orders that could alter, limit, or stop our operations.
In addition, new environmental laws and regulations, including
new regulations relating to alternative energy sources, new
state regulations relating to fuel quality, and the risk of
global climate change, as well as new interpretations of
existing laws and regulations, increased governmental
enforcement, or other developments could require us to make
additional unforeseen expenditures. Many of these laws and
regulations are becoming increasingly stringent, and the cost of
compliance with these requirements can be expected to increase
over time. We are not able to predict the impact of new or
changed laws or regulations or changes in the ways that such
laws or regulations are administered, interpreted, or enforced.
The requirements to be met, as well as the technology and length
of time available to meet those requirements, continue to
develop and change. To the extent that the costs associated with
meeting any or all of these requirements are substantial and not
adequately provided for, there could be a material adverse
effect on our business, financial condition, and results of
operations.
The EPA has issued rules pursuant to the Clean Air Act that
require refiners to reduce the sulfur content of gasoline and
diesel fuel and reduce the benzene content of gasoline by
various specified dates. We are incurring substantial costs to
comply with the EPAs low sulfur and low benzene rules. Our
strategy for complying with low sulfur gasoline regulations at
our El Paso refinery and our strategy for complying with
low sulfur gasoline regulations at our El Paso and Gallup
refineries relies partially on purchasing credits. If credits
are not available or are too costly, we may not be able to meet
the EPAs deadlines using a credit strategy. Failure to
meet the EPAs clean fuels mandates could have a material
adverse effect on our business, financial condition, and results
of operations.
Pursuant to the Energy Acts of 2005 and 2007, the EPA has issued
Renewable Fuels Standards, or RFS, implementing mandates to
blend renewable fuels into the petroleum fuels produced at our
refineries. Currently, the standards are enforced at our
El Paso refinery only. Our Gallup refinery became subject
to RFS in 2011 and will remain subject unless the EPA grants
further extensions to small refineries. Annually, the EPA
establishes a volume of renewable fuels that obligated
refineries must blend into their finished petroleum fuels. The
obligated volume increases over time until 2022. Blending
renewable fuels into their finished petroleum fuels will
displace an increasing volume of a refinerys product pool.
Alternatively, refineries can meet their RFS obligations by
purchasing renewable identification numbers, or RINs. If
sufficient RINs are unavailable for purchase, or if we are
otherwise unable to meet the EPAs RFS mandates, our
business, financial condition and results of operations could be
materially adversely affected.
We
could incur significant costs to comply with greenhouse gas
emissions regulation or legislation.
In November 2010, the State of New Mexico adopted regulations
regarding greenhouse gas emissions. The regulations will become
effective in 2012 unless reversed by the current New Mexico
administration, or unless a certain amount of emissions are not
available within New Mexico and other participating states. Our
Gallup refinery will be required to reduce its greenhouse gas
emissions by 2% per year between 2012 and 2020 or obtain
emission credits from other regulated facilities. The EPA has
recently adopted and implemented regulations to restrict
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emissions of greenhouse gases under certain provisions of the
Clean Air Act. One of the rules adopted by the EPA requires a
reduction in certain emissions of greenhouse gases from large
stationary sources, such as refineries, effective
January 2, 2011. A number of legal challenges have been
presented regarding these proposed greenhouse gas regulations
but no legal limitation on the EPA implementing these rules has
occurred to date. The EPA has also adopted rules requiring
refiners to report greenhouse gas emissions on an annual basis
beginning in 2011 for emissions occurring after January 1,
2010. Further, the United States Congress has recently discussed
legislation related to the reduction of greenhouse gases through
cap and trade programs. To the extent these EPA
rules and regulations continue to be implemented or cap and
trade legislation is enacted by federal or state governments,
our operating costs will increase and such increase could have
an adverse effect on our business, financial condition, and
results of operations.
Our
business, financial condition, and results of operations may be
materially adversely affected by a continued economic
downturn.
The recent turmoil in the global financial markets and the
scarcity of credit has led to lack of consumer confidence,
increased market volatility, and widespread reduction of
business activity generally in the United States and abroad. The
economic downturn has materially adversely affected and may
continue to affect the liquidity, businesses,
and/or
financial conditions of our customers, which has resulted, and
may continue to result, not only in decreased demand for our
products, but also increased delinquencies in our accounts
receivable. The disruptions in the financial markets could also
lead to a reduction in available trade credit due to
counterparties liquidity concerns. If we are unable to
obtain borrowings or letters of credit under our Revolving
Credit Agreement, our business, financial condition, and results
of operations could be materially adversely affected.
We
could experience business interruptions caused by pipeline
shutdown.
Our El Paso refinery, which is our largest refinery, is
dependent on a pipeline owned by Kinder Morgan Energy Partners,
LP, or Kinder Morgan, for the delivery of all of its crude oil.
Because our crude oil refining capacity at the El Paso
refinery is approaching the delivery capacity of the pipeline,
our ability to offset lost production due to disruptions in
supply with increased future production is limited due to this
crude oil supply constraint. In addition, we will be unable to
take advantage of further expansion of the El Paso
refinerys production without securing additional crude oil
supplies or pipeline expansion. We also deliver a substantial
percentage of the refined products produced at the El Paso
refinery through three principal product pipelines. Any
extended, non-excused downtime of our El Paso refinery
could cause us to lose line space on these refined products
pipelines if we cannot otherwise utilize our pipeline
allocations. We could experience an interruption of supply or
delivery, or an increased cost of receiving crude oil and
delivering refined products to market, if the ability of these
pipelines to transport crude oil or refined products is
disrupted because of accidents, governmental regulation,
terrorism, other third-party action, or any other events beyond
our control. A prolonged inability to receive crude oil or
transport refined products on pipelines that we currently
utilize could have a material adverse effect on our business,
financial condition, and results of operations.
We also have a pipeline system that delivers crude oil and
natural gas liquids to our Gallup refinery. The Gallup refinery
is dependent on the crude oil pipeline system for the delivery
of the crude oil necessary to run the refinery. If the operation
of the pipeline system is disrupted, we may not receive the
crude oil necessary to run the refinery. A prolonged inability
to transport crude oil on the pipeline system could have a
material adverse effect on our business, financial condition,
and results of operations.
Certain
rights-of-way
necessary for our crude oil pipeline system to deliver crude oil
to our Gallup refinery must be renewed periodically. A prolonged
inability to use these pipelines to transport crude oil to our
Gallup refinery could have a material adverse effect on our
business, financial condition, and results of operations.
We may
not have sufficient crude oil to be able to run our Gallup
refinery at full capacity.
Our Gallup refinery purchases crude oil from the local regions
around the refinery. To the extent sufficient local crude oil
cannot be purchased and we are unable to transport sufficient
crude oil on our
16-inch
pipeline to supply the Gallup refinery, we may not have
sufficient crude oil to run the Gallup refinery at the
historical levels of
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our Four Corners refineries, which could have a material adverse
impact on our business, financial condition, and results of
operations.
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. This includes our El Paso
refinerys Texas Flexible Permit. See Note 21,
Contingencies El Paso Refinery. 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 modifications 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.
Competition
in the refining and marketing industry is intense, and an
increase in competition in the areas in which we sell our
refined products could adversely affect our sales and
profitability.
We compete with a broad range of refining and marketing
companies, including certain multinational oil companies.
Because of their geographic diversity, larger and more complex
refineries, integrated operations, and greater resources, some
of our competitors may be better able to withstand volatile
market conditions, to compete on the basis of price, to obtain
crude oil in times of shortage, and to bear the economic risks
inherent in all phases of the refining industry.
We are not engaged in the petroleum exploration and production
business and therefore do not produce any of our crude oil
feedstocks. Certain of our competitors, however, obtain a
portion of their feedstocks from company-owned production.
Competitors that have their own production are at times able to
offset losses from refining operations with profits from
production, and may be better positioned to withstand periods of
depressed refining margins or feedstock shortages. In addition,
we compete with other industries 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 of our industry, there could be a material adverse
effect on our business, financial condition, and results of
operations.
The areas where we sell refined products are also supplied by
various refined product pipelines. Any expansions or additional
product supplied by these third-party pipelines could put
downward pressure on refined product prices in these areas.
Portions of our operations in the areas we operate may be
impacted by competitors plans, as well as plans of our
own, for expansion projects and refinery improvements that could
increase the production of refined products in the Southwest
region. In addition, we anticipate that lower quality crude
oils, which are typically less expensive to acquire, can and
will be processed by our competitors as a result of refinery
improvements. These developments could result in increased
competition in the areas in which we operate.
Our
insurance policies do not cover all losses, costs, or
liabilities that we may experience.
Our insurance coverage does not cover all potential losses,
costs, or liabilities. We could suffer losses for uninsurable or
uninsured risks or in amounts in excess of our existing
insurance coverage. Our ability to obtain and maintain adequate
insurance may be affected by conditions in the insurance market
over which we have no control. In addition, if we experience any
more insurable events, our annual premiums could increase
further or insurance may not be available at all. The occurrence
of an event that is not fully covered by insurance or the loss
of insurance coverage could have a material adverse effect on
our business, financial condition, and results of operations.
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A
substantial portion of our refining workforce is unionized, and
we may face labor disruptions that would interfere with our
operations.
As of February 25, 2011, we employed approximately
2,950 people, approximately 380 of whom were covered by
collective bargaining agreements. Subject to a Memorandum of
Understanding dated August 23, 2010 between Western
Refining Yorktown, Inc. and the local union representing the
covered Yorktown refinery employees, the collective bargaining
agreement at our Yorktown refinery was terminated in connection
with the temporary suspension of refining activities at our
Yorktown facility. If we restart refining operations at our
Yorktown facility prior to March 15, 2012, the collective
bargaining agreement for covered Yorktown employees will be
reinstated. All separated covered employees have recall rights
if we restart Yorktown refining operations prior to
March 16, 2012. In 2008, we successfully negotiated
collective bargaining agreements covering employees at our
Gallup and Bloomfield refineries that expire in 2011 and 2012,
respectively. Although the collective bargaining agreement
remains in force, the covered employees at our Bloomfield
refinery were terminated in connection with the indefinite
suspension of refining operations at our Bloomfield facility
during November 2009. We also successfully negotiated a new
collective bargaining agreement covering employees at our
El Paso refinery, renewing the collective bargaining
agreement that expired in April 2009. The collective bargaining
agreement covering the El Paso refinery employees expires
in April 2012. While all of our collective bargaining agreements
contain no strike provisions, those provisions are
not effective in the event that an agreement expires.
Accordingly, we may not be able to prevent a strike or work
stoppage in the future, and any such work stoppage could have a
material adverse affect on our business, financial condition,
and results of operations.
Terrorist
attacks, threats of war, or actual war may negatively affect our
operations, financial condition, results of operations and
prospects.
Terrorist attacks in the U.S. as well as events occurring
in response to or in connection with them, may adversely affect
our operations, financial condition, results of operations and
prospects. Energy related assets (which could include refineries
and terminals such as ours or pipelines such as the ones on
which we depend for our crude oil supply and refined product
distribution) may be at greater risk of future terrorist attacks
than other possible targets. A direct attack on our assets or
assets used by us could have a material adverse effect on our
operations, financial condition, results of operations and
prospects. 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. In addition,
disruption or significant increases in energy prices could
result in government imposed price controls.
While we currently maintain some insurance that provides
coverage against terrorist attacks, such insurance has become
increasingly expensive and difficult to obtain. As a result,
insurance providers may not continue to offer this coverage to
us on terms that we consider affordable, or at all.
Long-lived
and intangible assets comprise a significant portion of our
total assets.
Long-lived assets and both amortizable intangible assets and
intangible assets with indefinite lives must be tested for
recoverability whenever events or changes in circumstances
indicate that the carrying amount of those assets may not be
recoverable. We evaluate the remaining useful lives of our
intangible assets with indefinite lives each reporting period.
If events or circumstances no longer support an indefinite life,
the intangible asset is tested for impairment and prospectively
amortized over its remaining useful life. Long-lived and
amortizable intangible assets are not recoverable if their
carrying amount exceeds the sum of the undiscounted cash flows
expected to result from their use and eventual disposition. If a
long-lived or amortizable intangible asset is not recoverable,
an impairment loss is recognized in an amount by which its
carrying amount exceeds its fair value, with fair value
determined generally based on discounted estimated net cash
flows.
In order to test long-lived and amortizable intangible assets
for recoverability, management must make estimates of projected
cash flows related to the asset being evaluated, which include,
but are not limited to, assumptions about the use or disposition
of the asset, its estimated remaining life, and future
expenditures necessary to maintain its existing service
potential. In order to determine fair value, management must
make certain estimates and assumptions including, among other
things, an assessment of market conditions, projected volumes,
margins,
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cash flows, investment rates, interest/equity rates, and growth
rates, that could significantly impact the fair value of the
asset being tested for impairment.
Due to the effect of the current unfavorable economic conditions
on the refining industry, and our expectations of a continuation
of such conditions for the near term, we will continue to
monitor both our operating assets and our capital projects for
potential asset impairments or project write-offs until
conditions improve. Due to continuing losses resulting from
narrow heavy light crude differentials, poor coking economics,
and changes in our Yorktown crude oil purchase contracts, we
have recently suspended refining operations at our Yorktown
refinery. As such, our current evaluations are primarily focused
on our Yorktown refinery long-lived assets, which had a carrying
value of $678.5 million as of December 31, 2010.
Changes in market conditions, as well as changes in assumptions
used to test for recoverability and to determine fair value,
could result in significant impairment charges or project
write-offs in the future, thus negatively affecting our
earnings. See Item 7. Managements
Discussion and Analysis of Financial Condition and Results of
Operations Critical Accounting Policies and
Estimates Long-lived Assets.
Our
operating results are seasonal and generally lower in the first
and fourth quarters of the year.
Demand for gasoline is generally higher during the summer months
than during the winter months. In addition, ethanol is added to
the gasoline in our service areas during the winter months,
thereby increasing the supply of gasoline. This combination of
decreased demand and increased supply during the winter months
can lower gasoline prices. As a result, our operating results
for the first and fourth calendar quarters are generally lower
than those for the second and third calendar quarters of each
year. The effects of seasonal demand for gasoline are partially
offset by increased demand during the winter months for diesel
fuel in the Southwest and heating oil in the Northeast.
Our
ability to pay dividends in the future is limited by contractual
restrictions and cash generated by operations.
We are a holding company and all of our operations are conducted
through our subsidiaries. Consequently, we will rely on
dividends or advances from our subsidiaries to fund any
dividends. The ability of our operating subsidiaries to pay
dividends and our ability to receive distributions from those
entities are subject to applicable local law. In addition, our
ability to pay dividends to our shareholders is subject to
certain restrictions in our Revolving Credit Agreement, our Term
Loan Credit Agreement, and the indenture governing our Senior
Secured Notes, including pro forma compliance with a fixed
charge coverage ratio test and an excess availability test under
our Revolving Credit Agreement, pro forma compliance with our
minimum consolidated interest coverage ratio and maximum
leverage ratio covenants and a fixed cap under our Term Loan
Credit Agreement and compliance with an incurrence-based test
and a formula-based maximum under the indenture governing our
Senior Secured Notes. These factors could restrict our ability
to pay dividends in the future. In addition, our payment of
dividends will depend upon our ability to generate sufficient
cash flows. Our board of directors will review our dividend
policy periodically in light of the factors referred to above,
and we cannot assure you of the amount of dividends, if any,
that may be paid in the future.
Our
controlling stockholders may have conflicts of interest with
other stockholders in the future.
Mr. Paul Foster, our Executive Chairman, and
Messrs. Jeff Stevens (our Chief Executive Officer and
President and a current director), Ralph Schmidt (our former
Chief Operating Officer and a current director) and Scott Weaver
(our Vice President, Assistant Secretary and a current director)
own approximately 41% of our common stock. As a result,
Mr. Foster and the other members of this group will
strongly influence or effectively control the election of our
directors, our corporate and management policies and determine,
without the consent of our other stockholders, the outcome of
any corporate transaction or other matter submitted to our
stockholders for approval, including potential mergers or
acquisitions, asset sales, and other significant corporate
transactions. The interests of Mr. Foster and the other
members of this group may not coincide with the interests of
other holders of our common stock.
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If we
lose any of our key personnel, our ability to manage our
business and continue our growth could be negatively
impacted.
Our future performance depends to a significant degree upon the
continued contributions of our senior management team, including
our Executive Chairman, Chief Executive Officer and President,
Chief Financial Officer, Vice President and Assistant Secretary,
President-Refining and Marketing, Senior Vice President-Legal,
General Counsel and Secretary, Chief Accounting Officer, and
Senior Vice President-Treasurer. We do not currently maintain
key man life insurance with respect to any member of our senior
management team. The loss or unavailability to us of any member
of our senior management team or a key technical employee could
significantly harm us. We face competition for these
professionals from our competitors, our customers, and other
companies operating in our industry. To the extent that the
services of members of our senior management team would be
unavailable to us for any reason, we would be required to hire
other personnel to manage and operate our company. We may not be
able to locate or employ such qualified personnel on acceptable
terms, or at all.
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Item 1B.
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Unresolved
Staff Comments
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None.
Our principal properties are described under Item 1.
Business and the information is incorporated herein by
reference. As of December 31, 2010, we were a party to a
number of cancelable and non-cancelable leases for certain
properties, including our corporate headquarters in El Paso
and administrative offices in Tempe, Arizona. See
Note 23, Operating Leases and Other Commitments, in
the Notes to Consolidated Financial Statements included
elsewhere in this annual report.
|
|
Item 3.
|
Legal
Proceedings
|
In the ordinary conduct of our business, we are subject to
periodic lawsuits, investigations and claims, including
environmental claims and employee related matters. Although we
cannot predict with certainty the ultimate resolution of
lawsuits, investigations and claims asserted against us, we do
not believe that any currently pending legal proceeding or
proceedings to which we are a party will have a material adverse
effect on our business, financial condition or results of
operations.
PART II
|
|
Item 5.
|
Market
for Registrants Common Equity, Related Stockholder
Matters, and Issuer Purchases of Equity Securities
|
Market
Information
Our common stock began trading on the NYSE, on January 19,
2006 under the symbol WNR. As of February 25,
2011, we had 142 holders of record of our common stock. The
following table summarizes the high
27
and low sales prices of our common stock as reported on the NYSE
Composite Tape for the quarterly periods in the past two fiscal
years and dividends declared on our common stock for the same
periods:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dividends per
|
|
|
|
High
|
|
|
Low
|
|
|
Common Share
|
|
|
2010:
|
|
|
|
|
|
|
|
|
|
|
|
|
First quarter
|
|
$
|
5.84
|
|
|
$
|
4.03
|
|
|
$
|
|
|
Second quarter
|
|
|
5.90
|
|
|
|
4.30
|
|
|
|
|
|
Third quarter
|
|
|
5.42
|
|
|
|
4.01
|
|
|
|
|
|
Fourth quarter
|
|
|
10.78
|
|
|
|
5.09
|
|
|
|
|
|
2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
First quarter
|
|
$
|
14.00
|
|
|
$
|
7.83
|
|
|
$
|
|
|
Second quarter
|
|
|
16.30
|
|
|
|
6.65
|
|
|
|
|
|
Third quarter
|
|
|
8.13
|
|
|
|
5.45
|
|
|
|
|
|
Fourth quarter
|
|
|
7.00
|
|
|
|
4.45
|
|
|
|
|
|
Our payment of dividends is limited under the terms of our
Revolving Credit Agreement, our Term Loan Credit Agreement, and
our Senior Secured Notes, and in part, depends on our ability to
satisfy certain financial covenants.
Securities
Authorized for Issuance Under Equity Compensation
Plans
See Item 12. Security Ownership of Certain Beneficial
Owners and Management and Related Stockholder Matters.
28
Performance
Graph
The following performance graph and related information shall
not be deemed soliciting material or
filed with the SEC, nor shall such information be
incorporated by reference into any further filings under the
Securities Act of 1933 or the Securities Exchange Act of 1934,
each as amended, except to the extent we specifically
incorporate it by reference into such filing.
The following graph compares the cumulative
59-month
total stockholder return on the Companys common stock
relative to the cumulative total stockholder returns of the
Standard & Poors, or S&P, 500 index, and a
customized peer group of seven companies that includes: Alon USA
Energy, Inc., Delek US Holdings Inc., Frontier Oil Corp., Holly
Corp., Sunoco Inc., Tesoro Corp., and Valero Energy Corp. An
investment of $100 (with reinvestment of all dividends) is
assumed to have been made in our common stock and peer group on
January 19, 2006. The index on December 31, 2010, and
its relative performance are tracked through this date. The
stock price performance included in this graph is not
necessarily indicative of future stock price performance.
COMPARISON
OF 59-MONTH
CUMULATIVE TOTAL RETURN
COMPARISON
OF 59-MONTH
CUMULATIVE TOTAL RETURN
(Tabular
representation of data in graph above)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Jan
|
|
Mar
|
|
Jun
|
|
Sep
|
|
Dec
|
|
Mar
|
|
Jun
|
|
Sep
|
|
Dec
|
|
Mar
|
|
Jun
|
|
Sep
|
|
Dec
|
2006-2008
|
|
2006
|
|
2006
|
|
2006
|
|
2006
|
|
2006
|
|
2007
|
|
2007
|
|
2007
|
|
2007
|
|
2008
|
|
2008
|
|
2008
|
|
2008
|
|
Western Refining, Inc.
|
|
$
|
100.00
|
|
|
$
|
116.51
|
|
|
$
|
116.51
|
|
|
$
|
125.69
|
|
|
$
|
137.92
|
|
|
$
|
211.59
|
|
|
$
|
313.75
|
|
|
$
|
220.60
|
|
|
$
|
131.94
|
|
|
$
|
73.41
|
|
|
$
|
64.91
|
|
|
$
|
55.43
|
|
|
$
|
42.54
|
|
S&P 500
|
|
|
100.00
|
|
|
|
101.15
|
|
|
|
99.69
|
|
|
|
105.34
|
|
|
|
112.40
|
|
|
|
113.12
|
|
|
|
120.22
|
|
|
|
122.66
|
|
|
|
118.58
|
|
|
|
107.38
|
|
|
|
104.45
|
|
|
|
95.71
|
|
|
|
74.70
|
|
Peer Group
|
|
|
100.00
|
|
|
|
98.70
|
|
|
|
106.90
|
|
|
|
86.68
|
|
|
|
88.23
|
|
|
|
110.65
|
|
|
|
129.14
|
|
|
|
114.97
|
|
|
|
116.78
|
|
|
|
81.67
|
|
|
|
66.61
|
|
|
|
52.05
|
|
|
|
41.46
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mar
|
|
|
Jun
|
|
|
Sep
|
|
|
Dec
|
|
|
Mar
|
|
|
Jun
|
|
|
Sep
|
|
|
Dec
|
|
2009-2010
|
|
2009
|
|
|
2009
|
|
|
2009
|
|
|
2009
|
|
|
2010
|
|
|
2010
|
|
|
2010
|
|
|
2010
|
|
|
Western Refining, Inc.
|
|
$
|
65.46
|
|
|
$
|
38.71
|
|
|
$
|
35.36
|
|
|
$
|
25.82
|
|
|
$
|
30.15
|
|
|
$
|
27.58
|
|
|
$
|
28.73
|
|
|
$
|
58.00
|
|
S&P 500
|
|
|
66.48
|
|
|
|
77.07
|
|
|
|
89.09
|
|
|
|
94.47
|
|
|
|
99.56
|
|
|
|
88.19
|
|
|
|
98.15
|
|
|
|
108.70
|
|
Peer Group
|
|
|
35.35
|
|
|
|
32.81
|
|
|
|
38.44
|
|
|
|
34.12
|
|
|
|
38.98
|
|
|
|
37.57
|
|
|
|
38.13
|
|
|
|
48.90
|
|
Purchases
of Equity Securities by the Issuer and Affiliated
Purchasers
There were no purchases of equity securities by us or any of our
affiliates during the quarter ended December 31, 2010. In
addition, we currently do not have any share repurchase plans or
programs.
29
|
|
Item 6.
|
Selected
Financial Data
|
The following tables set forth our summary of historical
financial and operating data for the periods indicated below.
The summary results of operations and financial position data
for 2010, 2009, 2008, 2007, and 2006 have been derived from the
consolidated financial statements of Western Refining, Inc. and
its subsidiaries including Western Refining Company LP. On
May 31, 2007, we completed the acquisition of Giant. The
summary results of operations and financial position data for
2007 include the results of operations for Giant beginning
June 1, 2007. The first full fiscal year in which we owned
Giant was 2008, and therefore, the summary results of operations
and financial position data for 2010, 2009, and 2008 are not
comparable to periods prior to 2008.
The information presented below should be read in conjunction
with Item 7. Managements Discussion and Analysis
of Financial Condition and Results of Operations and the
financial statements and the notes thereto included in
Item 8. Financial Statements and Supplementary Data.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
2007(1)
|
|
|
2006
|
|
|
|
(In thousands, except per share data)
|
|
|
Statement of Operations Data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net sales
|
|
$
|
7,965,053
|
|
|
$
|
6,807,368
|
|
|
$
|
10,725,581
|
|
|
$
|
7,305,032
|
|
|
$
|
4,199,383
|
|
Operating costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of products sold (exclusive of depreciation and
amortization)(2)
|
|
|
7,155,967
|
|
|
|
5,944,128
|
|
|
|
9,735,500
|
|
|
|
6,385,623
|
|
|
|
3,644,391
|
|
Direct operating expenses (exclusive of depreciation and
amortization)
|
|
|
444,531
|
|
|
|
486,164
|
|
|
|
532,325
|
|
|
|
382,690
|
|
|
|
171,729
|
|
Selling, general, and administrative expenses
|
|
|
84,175
|
|
|
|
109,697
|
|
|
|
115,913
|
|
|
|
77,350
|
|
|
|
37,043
|
|
Goodwill and other impairment losses
|
|
|
13,038
|
|
|
|
352,340
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Maintenance turnaround expense
|
|
|
23,286
|
|
|
|
8,088
|
|
|
|
28,936
|
|
|
|
15,947
|
|
|
|
22,196
|
|
Depreciation and amortization
|
|
|
138,621
|
|
|
|
145,981
|
|
|
|
113,611
|
|
|
|
64,193
|
|
|
|
13,624
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating costs and expenses
|
|
|
7,859,618
|
|
|
|
7,046,398
|
|
|
|
10,526,285
|
|
|
|
6,925,803
|
|
|
|
3,888,983
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss)
|
|
|
105,435
|
|
|
|
(239,030
|
)
|
|
|
199,296
|
|
|
|
379,229
|
|
|
|
310,400
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest income
|
|
|
441
|
|
|
|
248
|
|
|
|
1,830
|
|
|
|
18,852
|
|
|
|
10,820
|
|
Interest expense and other financing costs
|
|
|
(146,549
|
)
|
|
|
(121,321
|
)
|
|
|
(102,202
|
)
|
|
|
(53,843
|
)
|
|
|
(2,167
|
)
|
Amortization of loan fees
|
|
|
(9,739
|
)
|
|
|
(6,870
|
)
|
|
|
(4,789
|
)
|
|
|
(1,912
|
)
|
|
|
(500
|
)
|
Write-off of unamortized loan fees
|
|
|
|
|
|
|
(9,047
|
)
|
|
|
(10,890
|
)
|
|
|
|
|
|
|
(1,961
|
)
|
Loss on early extinguishment of debt
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(774
|
)
|
|
|
|
|
Other income (expense), net
|
|
|
7,286
|
|
|
|
(15,184
|
)
|
|
|
1,176
|
|
|
|
(1,049
|
)
|
|
|
561
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before income taxes
|
|
|
(43,126
|
)
|
|
|
(391,204
|
)
|
|
|
84,421
|
|
|
|
340,503
|
|
|
|
317,153
|
|
Provision for income taxes
|
|
|
26,077
|
|
|
|
40,583
|
|
|
|
(20,224
|
)
|
|
|
(101,892
|
)
|
|
|
(112,373
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
(17,049
|
)
|
|
$
|
(350,621
|
)
|
|
$
|
64,197
|
|
|
$
|
238,611
|
|
|
$
|
204,780
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic earnings (loss) per share
|
|
$
|
(0.19
|
)
|
|
$
|
(4.43
|
)
|
|
$
|
0.94
|
|
|
$
|
3.50
|
|
|
$
|
3.05
|
|
Diluted earnings (loss) per share
|
|
|
(0.19
|
)
|
|
|
(4.43
|
)
|
|
|
0.94
|
|
|
|
3.50
|
|
|
|
3.05
|
|
Dividends declared per common share
|
|
$
|
|
|
|
$
|
|
|
|
$
|
0.06
|
|
|
$
|
0.22
|
|
|
$
|
0.16
|
|
Weighted average basic shares outstanding
|
|
|
88,204
|
|
|
|
79,163
|
|
|
|
67,715
|
|
|
|
67,180
|
|
|
|
65,387
|
|
Weighted average dilutive shares outstanding
|
|
|
88,204
|
|
|
|
79,163
|
|
|
|
67,715
|
|
|
|
67,180
|
|
|
|
65,387
|
|
30
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
2007(1)
|
|
|
2006
|
|
|
|
(In thousands, except per share data)
|
|
|
Cash Flow Data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating activities
|
|
$
|
134,456
|
|
|
$
|
140,841
|
|
|
$
|
285,575
|
|
|
$
|
113,237
|
|
|
$
|
245,004
|
|
Investing activities
|
|
|
(73,777
|
)
|
|
|
(115,361
|
)
|
|
|
(220,554
|
)
|
|
|
(1,334,028
|
)
|
|
|
(149,555
|
)
|
Financing activities
|
|
|
(75,657
|
)
|
|
|
(30,407
|
)
|
|
|
(274,769
|
)
|
|
|
1,247,191
|
|
|
|
(13,115
|
)
|
Other Data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA(3)
|
|
$
|
288,107
|
|
|
$
|
191,438
|
|
|
$
|
405,854
|
|
|
$
|
477,172
|
|
|
$
|
357,601
|
|
Capital expenditures
|
|
|
78,095
|
|
|
|
115,854
|
|
|
|
222,288
|
|
|
|
277,073
|
|
|
|
120,211
|
|
Cash paid for Giant acquisition, net of cash acquired
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,056,955
|
|
|
|
|
|
Balance Sheet Data (at end of period)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
59,912
|
|
|
$
|
74,890
|
|
|
$
|
79,817
|
|
|
$
|
289,565
|
|
|
$
|
263,165
|
|
Working capital
|
|
|
272,750
|
|
|
|
311,254
|
|
|
|
314,521
|
|
|
|
621,362
|
|
|
|
276,609
|
|
Total assets
|
|
|
2,628,146
|
|
|
|
2,824,654
|
|
|
|
3,076,792
|
|
|
|
3,559,716
|
|
|
|
908,523
|
|
Total debt
|
|
|
1,069,531
|
|
|
|
1,116,664
|
|
|
|
1,340,500
|
|
|
|
1,583,500
|
|
|
|
|
|
Stockholders equity
|
|
|
675,593
|
|
|
|
688,452
|
|
|
|
811,489
|
|
|
|
756,485
|
|
|
|
521,601
|
|
|
|
|
(1) |
|
Includes the results of operations and cash flows for Giant
beginning June 1, 2007, the date of acquisition. |
|
(2) |
|
Cost of products sold includes $21.7 million and
$9.9 million, respectively, in economic hedging losses, for
the years ended December 31, 2009 and 2007, and
$11.4 million and $8.6 million, respectively, in
economic hedging gains for the years ended December 31,
2008 and 2006. We previously reported economic hedging gains and
losses as gain (loss) from derivative activities under other
income (expense) in our Consolidated Statements of Operations
for each of the periods indicated above. These prior year
reclassifications were made to conform to the current
presentation. Cost of products sold for the year ended
December 31, 2010 includes $9.4 million in economic
hedging losses. |
|
(3) |
|
Adjusted EBITDA represents earnings before interest expense,
income tax expense, amortization of loan fees, write-off of
unamortized loan fees, loss on early extinguishment of debt,
depreciation, amortization, goodwill and other impairment
losses, maintenance turnaround expense, and Lower of Cost or
Market, or LCM, inventory reserve adjustments. Adjusted EBITDA
is not, however, a recognized measurement under United States
generally accepted accounting principles, or GAAP. Our
management believes that the presentation of Adjusted EBITDA is
useful to investors because it is frequently used by securities
analysts, investors, and other interested parties in the
evaluation of companies in our industry. In addition, our
management believes that Adjusted EBITDA is useful in evaluating
our operating performance compared to that of other companies in
our industry because the calculation of Adjusted EBITDA
generally eliminates the effects of financings, income taxes,
the accounting effects of significant turnaround activities
(that many of our competitors capitalize and thereby exclude
from their measures of EBITDA), acquisitions, and other items
that may vary for different companies for reasons unrelated to
overall operating performance. |
|
|
|
Adjusted EBITDA has limitations as an analytical tool, and you
should not consider it in isolation, or as a substitute for
analysis of our results as reported under GAAP. Some of these
limitations are: |
|
|
|
Adjusted EBITDA does not reflect our cash
expenditures or future requirements for significant turnaround
activities, capital expenditures, or contractual commitments;
|
|
|
|
Adjusted EBITDA does not reflect the interest
expense or the cash requirements necessary to service interest
or principal payments on our debt;
|
|
|
|
Adjusted EBITDA does not reflect changes in, or cash
requirements for, our working capital needs; and
|
|
|
|
Our calculation of Adjusted EBITDA may differ from
the Adjusted EBITDA calculations of other companies in our
industry, limiting its usefulness as a comparative measure.
|
31
|
|
|
|
|
Because of these limitations, Adjusted EBITDA should not be
considered a measure of discretionary cash available to us to
invest in the growth of our business. We compensate for these
limitations by relying primarily on our GAAP results and using
Adjusted EBITDA only supplementally. The following table
reconciles net income (loss) to Adjusted EBITDA for the periods
presented: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
2007(1)
|
|
|
2006
|
|
|
|
(In thousands)
|
|
|
Net income (loss)
|
|
$
|
(17,049
|
)
|
|
$
|
(350,621
|
)
|
|
$
|
64,197
|
|
|
$
|
238,611
|
|
|
$
|
204,780
|
|
Interest expense and other financing costs
|
|
|
146,549
|
|
|
|
121,321
|
|
|
|
102,202
|
|
|
|
53,843
|
|
|
|
2,167
|
|
Provision for income taxes
|
|
|
(26,077
|
)
|
|
|
(40,583
|
)
|
|
|
20,224
|
|
|
|
101,892
|
|
|
|
112,373
|
|
Amortization of loan fees
|
|
|
9,739
|
|
|
|
6,870
|
|
|
|
4,789
|
|
|
|
1,912
|
|
|
|
500
|
|
Write-off of unamortized loan fees
|
|
|
|
|
|
|
9,047
|
|
|
|
10,890
|
|
|
|
|
|
|
|
1,961
|
|
Loss on early extinguishment of debt
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
774
|
|
|
|
|
|
Depreciation and amortization
|
|
|
138,621
|
|
|
|
145,981
|
|
|
|
113,611
|
|
|
|
64,193
|
|
|
|
13,624
|
|
Maintenance turnaround expense
|
|
|
23,286
|
|
|
|
8,088
|
|
|
|
28,936
|
|
|
|
15,947
|
|
|
|
22,196
|
|
Goodwill and other impairment losses
|
|
|
13,038
|
|
|
|
352,340
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net change in LCM inventory reserve
|
|
|
|
|
|
|
(61,005
|
)
|
|
|
61,005
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA
|
|
$
|
288,107
|
|
|
$
|
191,438
|
|
|
$
|
405,854
|
|
|
$
|
477,172
|
|
|
$
|
357,601
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
32
|
|
Item 7.
|
Managements
Discussion and Analysis of Financial Condition and Results of
Operations
|
You should read the following discussion together with the
financial statements and the notes thereto included elsewhere in
this annual report. This discussion contains forward-looking
statements that are based on managements current
expectations, estimates and projections about our business and
operations. The cautionary statements made in this report should
be read as applying to all related forward-looking statements
wherever they appear in this report. Our actual results may
differ materially from those currently anticipated and expressed
in such forward-looking statements as a result of a number of
factors, including those we discuss under
Part I Item 1A. Risk Factors and elsewhere
in this report. You should read such Risk Factors and
Forward-Looking Statements. In this Item 7, all
references to Western Refining, the
Company, Western, we,
us, and our refer to Western Refining,
Inc., or WNR, and the entities that became its subsidiaries upon
closing of our initial public offering (including Western
Refining Company, L.P., or Western Refining LP), and Giant
Industries, Inc., or Giant, and its subsidiaries, which became
wholly-owned subsidiaries on May 31, 2007, unless the
context otherwise requires or where otherwise indicated.
Company
Overview
We are an independent crude oil refiner and marketer of refined
products and also operate service stations and convenience
stores. We own and operate two refineries with a total crude oil
throughput capacity of approximately 151,000 barrels per
day, or bpd. In addition to our 128,000 bpd refinery in
El Paso, Texas, we own and operate a refinery near Gallup,
New Mexico with a throughput capacity of approximately
23,000 bpd. Until September 2010, we operated a
70,000 bpd refinery on the East Coast of the United States
near Yorktown, Virginia, and until November 2009, we also
operated a 17,000 bpd refinery near Bloomfield, New Mexico.
We temporarily suspended refining operations at our Yorktown
facility in September 2010 and we indefinitely suspended
refining operations at the Bloomfield refinery in November 2009.
We continue to operate Yorktown and Bloomfield as product
distribution terminals and supply refined products to those
areas. Our primary operating areas encompass West Texas,
Arizona, New Mexico, Utah, Colorado, and the Mid-Atlantic
region. In addition to the refineries, we also own and operate
stand-alone refined product distribution terminals in
Albuquerque, New Mexico; Yorktown; and Bloomfield; as well as
asphalt terminals in Phoenix and Tucson, Arizona; Albuquerque;
and El Paso. As of December 31, 2010, we also own and
operate 150 retail service stations and convenience stores in
Arizona, Colorado, and New Mexico; a fleet of crude oil and
finished product truck transports; and a wholesale petroleum
products distributor, that operates in Arizona, California,
Colorado, Nevada, New Mexico, Texas, and Utah.
On May 31, 2007, we completed the acquisition of Giant.
Under the terms of the merger agreement, we acquired 100% of
Giants 14,639,312 outstanding shares for $77.00 per share
in cash for a total purchase price of $1,149.2 million,
funded primarily through a $1,125.0 million secured term
loan. In connection with the acquisition, we borrowed an
additional $275.0 million in July 2007, when we paid off
and retired Giants 8% and 11% Senior Subordinated
Notes. Prior to the acquisition of Giant, we generated
substantially all of our revenues from our refining operations
in El Paso. With the acquisition of Giant, we also gained a
diverse mix of complementary retail and wholesale businesses.
Following the acquisition of Giant, we began reporting our
operating results in three business segments: the refining
group, the wholesale group, and the retail group. Our refining
group currently operates the two refineries and related refined
product distribution terminals and asphalt terminals. At the
refineries, we refine crude oil and other feedstocks into
finished products such as gasoline, diesel fuel, jet fuel, and
asphalt. Our refineries market finished products to a diverse
customer base including wholesale distributors and retail
chains. Our wholesale group distributes gasoline, diesel fuel,
and lubricant products. Our retail group operates service
stations and convenience stores and sells gasoline, diesel fuel,
and merchandise. See Note 3, Segment Information, in
the Notes to Consolidated Financial Statements included
elsewhere in this annual report for detailed information on our
operating results by segment.
33
Major
Influences on Results of Operations
Refining. Our net sales fluctuate
significantly with movements in refined product prices and the
cost of crude oil and other feedstocks, all of which are
commodities. The spread between crude oil and refined product
prices is the primary factor affecting our earnings and cash
flows from operations. The cost to acquire feedstocks and the
price of the refined products that we ultimately sell depends on
numerous factors beyond our control. These factors include the
supply of and demand for crude oil, gasoline, and other refined
products. Supply and demand for these products depend on changes
in domestic and foreign economies; weather conditions; domestic
and foreign political affairs; production levels; availability
of imports; marketing of competitive fuels; price differentials
between heavy and sour crude oils and light sweet crude oils,
known as the heavy light crude oil differential; and government
regulation. Refining margins experienced extreme volatility
throughout 2008 and 2009. Refining margins were somewhat less
volatile in 2010. Gasoline margin averages have improved each
year since 2008 and average diesel margins for 2010 showed
improvement over 2009 levels. Another factor impacting our
margins in recent years is the narrowing of the heavy light
crude oil differential. Since the second quarter of 2009, the
heavy light crude oil differential has narrowed significantly,
particularly impacting our Yorktown refinery which, when
operating, can process up to 100% of heavy crude oil. Narrowing
of the heavy light crude oil differential can have significant
negative impact on our Yorktown refining margins, as was the
case during 2009 and 2010. In addition, we had changes in our
LCM reserve of $61.0 million related to our Yorktown
inventories that increased our cost of products sold for the
year ended December 31, 2008 and decreased our cost of
products sold for the year ended December 31, 2009. There
were no such LCM reserve changes in the year ended
December 31, 2010.
Other factors that impact our overall refinery gross margins are
the sale of lower value products such as residuum and propane,
particularly when crude costs are higher. In addition, our
refinery gross margin is further reduced because our refinery
product yield is less than our total refinery throughput volume.
Our results of operations are also significantly affected by our
refineries direct operating expenses, especially the cost
of natural gas used for fuel and the cost of electricity.
Natural gas prices have historically been volatile. Typically,
electricity prices fluctuate with natural gas prices.
Demand for gasoline is generally higher during the summer months
than during the winter months. In addition, higher volumes of
ethanol are blended with gasoline produced in the Southwest
region during the winter months, thereby increasing the supply
of gasoline. This combination of decreased demand and increased
supply during the winter months can lower gasoline prices. As a
result, our operating results for the first and fourth calendar
quarters are generally lower than those for the second and third
calendar quarters of each year. The effects of seasonal demand
for gasoline are partially offset by increased demand during the
winter months for diesel fuel in the Southwest and heating oil
in the Northeast. Refining margins remain volatile and our
results of operations may not reflect these historical seasonal
trends.
Safety, reliability, and the environmental performance of our
refineries operations are critical to our financial
performance. Unplanned downtime of our refineries, such as the
unplanned weather-related outage our El Paso refinery
experienced during February 2011, generally results in lost
refinery gross margin opportunity, increased maintenance costs,
and a temporary increase in working capital investment and
inventory. We attempt to mitigate the financial impact of
planned downtime, such as a turnaround or a major maintenance
project, through a planning process that considers product
availability, margin environment, and the availability of
resources to perform the required maintenance.
Periodically we have planned maintenance turnarounds at our
refineries, which are expensed as incurred. We shut down the
south crude unit for 13 days at the El Paso refinery
in the second quarter of 2009 and we performed a crude unit
inspection outage for 20 days at the Yorktown refinery in
October 2009. We completed a scheduled turnaround at the south
side of the El Paso refinery during the first quarter of 2010.
Our next scheduled maintenance turnarounds are during the first
quarter of 2013 for El Paso and the fourth quarter of 2012
for Gallup.
The nature of our business requires us to maintain substantial
quantities of crude oil and refined product inventories. Because
crude oil and refined products are commodities, we have no
control over the changing market value of these inventories. Our
inventory of crude oil and the majority of our refined products
are valued at the lower of cost or market value under the
last-in,
first-out, or LIFO, inventory valuation methodology. If the
market values of our inventories decline below our cost basis,
we would record a write-down of our inventories resulting in a
non-
34
cash charge to our cost of products sold. Market value declines
during the year ended December 31, 2008 resulted in
non-cash charges to our cost of products sold of
$61.0 million. Under the LIFO inventory valuation method,
this write-down is subject to recovery in future periods to the
extent the market values of our inventories equal our cost basis
relative to any LIFO inventory valuation write-downs previously
recorded. Based on 2009 market conditions, we recorded non-cash
recoveries of $61.0 million related to the 2008 LCM
charges. In addition, due to the volatility in the price of
crude oil and other blendstocks, we experienced fluctuations in
our LIFO reserves between 2008 and 2009. We also experienced
LIFO liquidations based on decreased levels in our inventories.
These LIFO liquidations resulted in decreases in cost of
products sold of $16.9 million and $9.4 million for
the years ended December 31, 2010 and 2009, respectively,
and an increase of $66.9 million in cost of products sold
for the year ended December 31, 2008. See Note 5,
Inventories, in the Notes to Consolidated Financial
Statements included in this annual report for detailed
information on the impact of LIFO inventory accounting.
Wholesale. Our earnings and cash flows from
our wholesale business segment are primarily affected by the
sales volumes and margins of gasoline, diesel fuel, and
lubricants sold. Margins for gasoline, diesel fuel, and
lubricant sales are equal to the sales price less cost of sales.
Margins are impacted by local supply, demand, and competition.
Retail. Our earnings and cash flows from our
retail business segment are primarily affected by the sales
volumes and margins of gasoline and diesel fuel sold, and by the
sales and margins of merchandise sold at our service stations
and convenience stores. Margins for gasoline and diesel fuel
sales are equal to the sales price less the delivered cost of
the fuel and motor fuel taxes, and are measured on a cents per
gallon, or cpg, basis. Fuel margins are impacted by local
supply, demand, and competition. Margins for retail merchandise
sold are equal to retail merchandise sales less the delivered
cost of the merchandise, net of supplier discounts and inventory
shrinkage, and are measured as a percentage of merchandise
sales. Merchandise sales are impacted by convenience or
location, branding, and competition. Our retail sales are
seasonal. Our retail business segment operating results for the
first and fourth calendar quarters are generally lower than
those for the second and third calendar quarters of each year.
Goodwill Impairment Loss. Under our policy we
test goodwill for impairment annually or more frequently if
indications of impairment exist. Various indications of possible
goodwill impairment prompted us to perform goodwill impairment
analyses at December 31, 2008 and March 31, 2009. We
determined that no such impairment existed as of those dates.
Our annual 2009 impairment test was performed as of
June 30, 2009. The performance of the test is a two-step
process. Step 1 of the impairment test involves comparing the
fair values of the applicable reporting units with their
aggregate carrying values, including goodwill. If the carrying
amount of a reporting unit exceeds the reporting units
fair value, we perform Step 2 of the goodwill impairment test to
determine the amount of impairment loss. Step 2 of the goodwill
impairment test involves comparing the implied fair value of the
affected reporting units goodwill against the carrying
value of that goodwill.
From the first to the second quarter of 2009, there was a
decline in margins within the refining industry as well as a
downward change in industry analysts forecasts for the
remainder of 2009 and 2010. This, along with other negative
financial forecasts released by independent refiners during the
latter part of the second quarter of 2009, contributed to
declines in common stock trading prices within the independent
refining sector, including declines in our common stock trading
price. As a result, our equity market capitalization fell below
the net book value of our assets. Through the filing date of our
second quarter of 2009
Form 10-Q
and through the end of the fourth quarter of 2009, the trading
price of our stock had experienced further reductions.
We completed Step 1 of the impairment test during the second
quarter of 2009 and concluded that impairment existed.
Consistent with the preliminary Step 2 analysis completed during
the second quarter of 2009, we concluded that our entire
goodwill balance was impaired. The resulting non-cash charge of
$299.6 million was reported in our second quarter of 2009
results of operations. We finalized our Step 2 analysis during
the third quarter of 2009. There were no such impairment charges
in previous years.
Long-lived Asset Impairment Loss. We review
the carrying values of our long-lived assets for possible
impairment whenever events or changes in circumstances indicate
that the carrying amount of assets to be held and used may not
be recoverable. A long-lived asset is not recoverable if its
carrying amount exceeds the sum of the undiscounted cash flows
expected to result from its use and eventual disposition. If a
long-lived asset is not recoverable, an impairment loss is
recognized in an amount by which its carrying amount exceeds its
fair value.
35
In order to test long-lived assets for recoverability, we must
make estimates of projected cash flows related to the asset
being evaluated, which include, but are not limited to,
assumptions about the use or disposition of the asset, its
estimated remaining life, and future expenditures necessary to
maintain its existing service potential. In order to determine
fair value, we must make certain estimates and assumptions
including, among other things, an assessment of market
conditions, projected volumes, margins, cash flows, investment
rates, interest/equity rates, and growth rates that could
significantly impact the fair value of the asset being tested
for impairment.
In the fourth quarter of 2009, we announced our plans to
indefinitely suspend the refining operations at our Bloomfield
refinery and operate the site as a product distribution terminal
and crude oil storage facility. Accordingly, we tested our
Bloomfield refinery long-lived assets and certain intangible
assets for recoverability and determined that $41.8 million
and $11.0 million of certain refinery related long-lived
and intangible assets, respectively, were impaired. During the
fourth quarter of 2010, we recorded an additional impairment
charge of $9.1 million resulting from our fourth quarter
2010 analysis of specific assets that we had previously planned
to relocate from our Bloomfield facility to our Gallup refinery.
Based on the sustainable operational improvements of our Gallup
refinery during 2010 that were beyond what we had anticipated at
the time of the Bloomfield refinery idling, we determined that
one of the three assets set aside for relocation to Gallup was
no longer required to attain our desired levels of production.
Non-cash impairment losses of $9.1 million and
$52.8 million related to the long-lived assets and certain
intangible assets are included under other impairment losses in
the Consolidated Statements of Operations for the years ended
December 31, 2010 and 2009, respectively.
Factors
Impacting Comparability of Our Financial Results
Our historical results of operations for the periods presented
may not be comparable with prior periods or to our results of
operations in the future for the reasons discussed below.
Senior
Secured Notes, Convertible Senior Notes, and Equity
Offering
During the second and third quarters of 2009, we issued
$600.0 million in Senior Secured Notes and
$215.5 million in Convertible Senior Notes. The Senior
Secured Notes consist of two tranches; the first consisting of
$325.0 million in 11.25% fixed rate aggregate principal
amount notes and the second consisting of $275.0 million
floating rate aggregate principal amount notes. The interest
rate on the floating rate notes was 10.75% at issuance in June
2009. Proceeds from the issuance of the Senior Secured Notes,
net of original issue and underwriting discounts were
$538.2 million. The Convertible Senior Notes consist of
$215.5 million in 5.75% aggregate principal amount notes.
The Convertible Senior Notes are unsecured and were issued with
an initial conversion rate of 92.5926 shares of common
stock per $1,000 principal amount of Convertible Senior Notes
(equivalent to an initial conversion price of approximately
$10.80 per share of common stock). Proceeds from the issuance of
the Convertible Senior Notes were $209.0 million, net of
underwriting discounts.
During the second quarter of 2009, we issued an additional
20,000,000 shares of our common stock for an aggregate
amount of $180.0 million. The proceeds of this issuance
were $171.0 million, net of $9.0 million in
underwriting discounts.
The combined proceeds from the issuance and sale of the Senior
Secured Notes, the Convertible Senior Notes, and our common
stock were used to retire $912.7 million of our outstanding
indebtedness under our Term Loan Credit Agreement. See
Note 13, Long-Term Debt, and Note 18,
Stockholders Equity, in the Consolidated Financial
Statements included in this annual report for detailed
information on the issuance and composition of these notes.
Asset
Impairments
In the fourth quarter of 2009, we announced our plans to
indefinitely suspend the refining operations at our Bloomfield
refinery and maintain the site as a product distribution
terminal and crude oil storage facility. Accordingly, we tested
the Bloomfield refinery long-lived assets and certain intangible
assets for recoverability and determined that $41.8 million
and $11.0 million of certain Bloomfield refinery related
long-lived and intangible assets, respectively, were impaired.
During the fourth quarter of 2010, we recorded an additional
impairment charge of $9.1 million resulting from our fourth
quarter 2010 analysis of specific assets that we had previously
planned to
36
relocate from our Bloomfield facility to our Gallup refinery.
Based on the current operations of the Gallup refinery, we have
determined that one of the three assets set aside for relocation
to Gallup is no longer required. Non-cash impairment losses of
$9.1 million and $52.8 million related to the
long-lived assets and certain intangible assets are included
under other impairment losses in our Consolidated Statements of
Operations for the years ended December 31, 2010 and 2009,
respectively.
We completed an impairment analysis of the long-lived assets at
our Flagstaff, Arizona product distribution terminal following
our permanent closure of the facility in the third quarter of
2010. The analysis determined that impairment existed, and we
accordingly recorded a third quarter 2010 non-cash impairment
charge of $3.8 million related to Flagstaff terminal
long-lived assets. This charge is included under other
impairment losses in our Consolidated Statement of Operations
for the year ended December 31, 2010.
During the second quarter of 2009, we performed our annual
impairment test and as a result concluded that all of our
goodwill was impaired. The resulting non-cash charge of
$299.6 million was reported in our second quarter 2009
results of operations. This charge is included under goodwill
impairment loss in our Consolidated Statements of Operations for
the year ended December 31, 2009.
Employee
Benefit Plans
We terminated our defined benefit plan covering certain
El Paso refinery employees during 2009. The termination
resulted in a reduction to our related pension obligation of
$24.3 million with a corresponding reduction of
$25.1 million before the effect of income taxes to other
comprehensive loss. During 2010, in connection with the
temporary idling of our Yorktown refinery and resultant
termination of participants of the Yorktown cash balance plan,
we had distributed $12.8 million from plan assets to plan
participants. As of December 31, 2010, the plan had not
been terminated. The curtailment resulted in increases to the
related pension obligation of $1.4 million and to other
comprehensive loss (before income taxes) of $1.1 million.
Subject to a Memorandum of Understanding between Western
Refining Yorktown, Inc. and the local union representing the
Yorktown refinery employees, eligible terminated employees, both
bargained for and non-bargained for, were given the option of
receiving severance pay or coverage under the Yorktown retiree
medical plan, but not both. The resulting choices made by the
terminated employees reduced our benefits obligation by
$5.7 million as of December 31, 2010. Currently, we do
not plan to terminate the Yorktown retiree medical plan.
Write-off
of Unamortized Loan Fees
During the second and third quarters of 2009, we made principal
payments on our Term Loan of $925.7 million primarily from
the net proceeds of our debt and common stock offerings.
Accordingly, we expensed $9.0 million during the second
quarter of 2009 to write-off a portion of the unamortized loan
fees related to the Term Loan. In June 2008, we amended our
Revolving Credit Agreement and Term Loan. As a result of such
amendment, we recorded an expense of $10.9 million related
to the write-off of deferred loan fees incurred in May 2007. We
completed an additional amendment to our Revolving Credit
Agreement in December 2010. We will amortize all fees incurred
as a result of this amendment, along with all unamortized loan
fees related to the Revolving Credit Agreement prior to this
amendment, ratably through the amended maturity date of January
2015. See Note 13, Long-Term Debt, in the
Consolidated Financial Statements included in this annual report
for detailed information on our long-term debt.
Environmental
Cost Recoveries, Property Tax Refunds, and Other
During the latter part of March 2010, we reversed
$14.7 million related to our accrued bonus for 2009. This
revision of our 2009 bonus estimate reduced direct operating
expenses and selling, general, and administrative expenses for
2010 by $8.5 million and $6.2 million, respectively.
During 2009, we recovered $10.6 million from various third
parties related to environmental costs recorded during 2009 and
prior years. These recoveries are included in direct operating
expenses reported for the year ended December 31, 2009.
Additionally, during 2009, we decreased our property tax expense
estimate by $5.5 million resulting from revised
El Paso property appraisal rolls for 2006 through 2008. The
revision to the property appraisal rolls also resulted in a
refund of $2.9 million from
37
various taxing authorities, further reducing our property tax
expense for a total decrease of $8.4 million for the year
ended December 31, 2009. We also recorded a fourth quarter
2009 legal settlement charge of $20.0 million.
Planned
Maintenance Turnaround
During 2010 and 2009, we incurred costs of $23.3 million
and $8.1 million, respectively for maintenance turnarounds.
Primarily during the third and fourth quarters of 2009, we
incurred costs of $2.9 million in a crude unit shutdown and
$4.0 million in connection with the planned turnaround in
the first quarter of 2010 at the El Paso refinery; and
$1.2 million in connection with the planned turnaround in
the third quarter of 2010 at the Yorktown refinery, which was
subsequently cancelled. The 2008 maintenance turnaround was
performed during the fourth quarter at the north side of the
El Paso refinery. Our next scheduled maintenance
turnarounds are during the first quarter of 2013 for
El Paso and the fourth quarter of 2012 for Gallup. We
expense the cost of maintenance turnarounds when the expense is
incurred. Most of our competitors, however, capitalize and
amortize maintenance turnarounds.
Critical
Accounting Policies and Estimates
We prepare our financial statements in conformity with
U.S. GAAP. In order to apply these principles, we must make
judgments, assumptions, and estimates based on the best
available information at the time. Actual results may differ
based on the accuracy of the information utilized and subsequent
events, some of which we may have little or no control over. Our
critical accounting policies, which are discussed below, could
materially affect the amounts recorded in our financial
statements.
Inventories. Crude oil, refined product, and
other feedstock and blendstock inventories are carried at the
lower of cost or market. Cost is determined principally under
the LIFO valuation method to reflect a better matching of costs
and revenues. Ending inventory costs in excess of market value
are written down to net realizable market values and charged to
cost of products sold in the period recorded. In subsequent
periods, a new lower of cost or market determination is made
based upon current circumstances. We determine market value
inventory adjustments by evaluating crude oil, refined products,
and other inventories on an aggregate basis by geographic
region. Aggregated LIFO costs were less than the current cost of
our crude oil, refined product, and other feedstock and
blendstock inventories by $173.5 million at
December 31, 2010.
Retail refined product (fuel) inventory values are determined
using the
first-in,
first-out, or FIFO, inventory valuation method. Retail
merchandise inventory value is determined under the retail
inventory method. Wholesale finished product, lubricant, and
related inventories are determined using the FIFO inventory
valuation method. Finished product inventories originate from
either our refineries or from third-party purchases.
Maintenance Turnaround Expense. The units at
our refineries require periodic maintenance and repairs commonly
referred to as turnarounds. The required frequency
of the maintenance varies by unit but generally is every two to
six years depending on the processing unit involved. We expense
the cost of maintenance turnarounds when the expense is
incurred. These costs are identified as a separate line item in
our Consolidated Statements of Operations.
Long-lived Assets. We calculate depreciation
and amortization on a straight-line basis over the estimated
useful lives of the various classes of depreciable assets. When
assets are placed in service, we make estimates of what we
believe are their reasonable useful lives. For assets to be
disposed of, we report long-lived assets at the lower of
carrying amount or fair value less cost of disposal.
We review the carrying values of our long-lived assets for
possible impairment whenever events or changes in circumstances
indicate that the carrying amount of assets to be held and used
may not be recoverable. A long-lived asset is not recoverable if
its carrying amount exceeds the sum of the undiscounted cash
flows expected to result from its use and eventual disposition.
If a long-lived asset is not recoverable, an impairment loss is
recognized in an amount by which its carrying amount exceeds its
fair value.
In order to test our long-lived assets for recoverability, we
must make estimates of projected cash flows related to the asset
being evaluated, which include, but are not limited to,
assumptions about the use or disposition of the
38
asset, its estimated remaining life, and future expenditures
necessary to maintain its existing service potential. In order
to determine fair value, we must make certain estimates and
assumptions including, among other things, an assessment of
market conditions, projected cash flows, investment rates,
interest/equity rates, and growth rates that could significantly
impact the fair value of the asset being tested for impairment.
The economic slowdown that began in 2008 and continued into 2010
has reduced demand for refined products, thereby putting
significant pressure on refined product margins. Beginning in
the second quarter of 2009, heavy light crude oil differentials
have narrowed significantly. Narrow heavy light crude oil
differential has negatively impacted the results of operations
of our Yorktown refinery. Due to these economic conditions, at
December 31, 2009, we performed an impairment analysis of
our Yorktown long-lived and intangible assets. This analysis
indicated that the December 31, 2009 carrying value of our
Yorktown long-lived assets was recoverable. Continuing losses
due to narrow heavy light crude oil differentials, poor coking
economics, changes in Yorktown crude oil purchase contract
terms, and potentially significant regulatory capital spending
requirements caused us to temporarily suspend our Yorktown
refining operations during the third quarter of 2010.
Accordingly, we revised our cash flow forecasts used in our
analysis for long-lived asset impairment at our Yorktown
refinery to reflect these changes in operations at the Yorktown
facility as of June 30, 2010. The revised cash flows used
in our June 30, 2010 impairment analysis assumes that
refining operations will be temporarily suspended; that our
Yorktown facility will be operated as a refined product terminal
in the near term; and that restart activities will begin no
later than the middle of 2013. Our revised forecast includes
estimates and assumptions that require considerable judgment and
are based on our historical production volumes and throughputs,
industry analysts margin forecasts, financial forecasts,
and industry trends and conditions. Based on our analysis, we
determined that the undiscounted forecasted cash flows exceeded
the carrying amount of our Yorktown long-lived and intangible
assets as of June 30, 2010. No significant changes have
occurred since we performed our analysis that would require us
to revise our June 30, 2010 analysis. The carrying value of
the long-lived assets related to refining operations that were
temporarily idled could be subject to impairment. We currently
anticipate a six to nine month pre-restart maintenance period
will be required before our Yorktown refinery can be restarted,
at an estimated cost of at least $50.0 million, which
includes a maintenance turnaround. If our current plans to
restart refining operations at our Yorktown facility within the
next two to three years change, the likelihood of impairment of
the long-lived assets and certain intangible assets related to
the refinery operations will increase. Impairments related to
Yorktown could have a material impact on our results of
operations. The carrying value of total long-lived and
intangible assets at Yorktown as of December 31, 2010 was
$678.5 million, of which $472.4 million related to our
Yorktown refining assets.
In the fourth quarter of 2009, we announced our plans to
indefinitely suspend the refining operations at our Bloomfield
refinery and maintain the site as a product distribution
terminal and crude oil storage facility. Accordingly, we tested
the Bloomfield refinery long-lived assets and certain intangible
assets for recoverability and determined that $41.8 million
and $11.0 million, respectively, of impairment losses
existed in certain Bloomfield refinery related long-lived and
intangible assets. During the fourth quarter of 2010, we
recorded an additional impairment charge of $9.1 million
resulting from our fourth quarter 2010 analysis of specific
assets that we had previously planned to relocate from our
Bloomfield facility to our Gallup refinery. Based on sustainable
operational improvements at our Gallup refinery during 2010 that
were beyond what we had anticipated at the time of the
Bloomfield refinery idling, we determined that one of the three
assets set aside for relocation to Gallup was no longer required
to attain our desired levels of production. Non-cash impairment
losses of $9.1 million and $52.8 million related to
the long-lived assets and certain intangible assets are included
under other impairment losses in our Consolidated Statements of
Operations for the years ended December 31, 2010 and 2009,
respectively. We currently plan to relocate and place the
remaining Bloomfield refining assets with a net book value of
$12.4 million at December 31, 2010 into service at the
Gallup refinery during the maintenance turnaround scheduled for
2012.
During the third quarter of 2010, we permanently closed our
product distribution terminal in Flagstaff, Arizona. We
completed an impairment analysis of our Flagstaff terminal
long-lived assets and determined from this analysis that the
assets were fully impaired. Accordingly, an impairment charge of
$3.8 million related to our Flagstaff long-lived assets is
included in other impairment losses in the Consolidated
Statements of Operations for the year ended December 31,
2010.
39
Goodwill and Other Intangible Assets. Goodwill
represents the excess of the purchase price (cost) over the fair
value of the net assets acquired and is carried at cost. We test
goodwill for impairment at the reporting unit level annually. In
addition, goodwill of a reporting unit is tested for impairment
if any events and circumstances arise during a quarter that
indicates goodwill of a reporting unit might be impaired. The
reporting unit or units used to evaluate and measure goodwill
for impairment are determined primarily from the manner in which
the business is managed. A reporting unit is an operating
segment or a component that is one level below an operating
segment. Within our refining segment, we have determined that we
have three reporting units for purposes of assigning goodwill
and testing for impairment. Our wholesale and retail segments
are considered reporting units for purposes of assigning
goodwill and testing for impairment. Our goodwill was assigned
to two of our three refining reporting units and to our
wholesale and retail reporting units. We do not amortize
goodwill for financial reporting purposes.
Various indications of possible goodwill impairment prompted us
to perform goodwill impairment analyses at December 31,
2008 and March 31, 2009. We determined that no such
impairment existed as of those dates. Our 2009 annual impairment
test was performed as of June 30, 2009. The performance of
the test is a two-step process. Step 1 of the impairment test
involves comparing the fair values of the applicable reporting
units with their aggregate carrying values, including goodwill.
If the carrying amount of a reporting unit exceeds the reporting
units fair value, we perform Step 2 of the goodwill
impairment test to determine the amount of impairment loss. Step
2 of the goodwill impairment test involves comparing the implied
fair value of the affected reporting units goodwill
against the carrying value of that goodwill.
From the first to the second quarter of 2009, there was a
decline in margins within the refining industry as well as a
downward change in industry analysts forecasts for the
remainder of 2009 and 2010. This, along with other negative
financial forecasts released by independent refiners during the
latter part of the second quarter of 2009, contributed to
declines in common stock trading prices within the independent
refining sector, including declines in our common stock trading
price. As a result, our equity market capitalization fell below
the net book value of our assets. Through the filing date of our
second quarter 2009
Form 10-Q
and through the end of the fourth quarter of 2009, the trading
price of our stock had experienced further reductions.
We completed Step 1 of the impairment test during the second
quarter of 2009 and concluded that impairment existed. We
finalized our Step 2 analysis during the third quarter of 2009.
Consistent with the preliminary Step 2 analysis completed during
the second quarter of 2009, we concluded that all of our
goodwill was impaired. The resulting non-cash charge of
$299.6 million was reported in our second quarter of 2009
results of operations. We had no such impairment charges during
2010 or 2008.
We amortize intangible assets, such as
rights-of-way,
licenses, and permits over their economic useful lives, unless
the economic useful lives of the assets are indefinite. If an
intangible assets economic useful life is determined to be
indefinite, then that asset is not amortized. We consider
factors such as the assets history, our plans for that
asset, and the market for products associated with the asset
when the intangible asset is acquired. We consider these same
factors when reviewing the economic useful lives of our existing
intangible assets as well. We review the economic useful lives
of our intangible assets at least annually.
Environmental and Other Loss Contingencies. We
record liabilities for loss contingencies, including
environmental remediation costs, when such losses are probable
and can be reasonably estimated. Environmental costs are
expensed if they relate to an existing condition caused by past
operations with no future economic benefit. Estimates of
projected environmental costs are made based upon internal and
third-party assessments of contamination, available remediation
technology, and environmental regulations. Loss contingency
accruals, including those for environmental remediation, are
subject to revision as further information develops or
circumstances change and such accruals can take into account the
legal liability of other parties.
As a result of purchase accounting related to the Giant
acquisition, the majority of our environmental obligations
assumed in the acquisition of Giant are recorded on a discounted
basis. Where the available information is sufficient to estimate
the amount of liability, that estimate is used. Where the
information is only sufficient to establish a range of probable
liability and no point within the range is more likely than
other, the lower end of the range is used. Possible recoveries
of some of these costs from other parties are not recognized in
the financial statements until they become probable. Legal costs
associated with environmental remediation are included as part
of the estimated liability. We have $18.3 million accrued
at December 31, 2010 for environmental obligations.
40
Asset Retirement Obligations
(ARO). The estimated fair value of an
ARO is based on the estimated current cost escalated by an
inflation rate and discounted at a credit adjusted risk free
rate. This liability is capitalized as part of the cost of the
related asset and amortized using the straight-line method. The
liability accretes until we settle the liability. Legally
restricted assets have been set aside for purposes of settling
certain of the ARO liabilities.
Financial Instruments and Fair Value. We are
exposed to various market risks, including changes in commodity
prices. We use commodity future contracts, price swaps, and
options to reduce price volatility, to fix margins for refined
products, and to protect against price declines associated with
our crude oil and blendstock inventories. All derivatives
entered into by us are recognized as either assets or
liabilities in the Consolidated Balance Sheets and those
instruments are measured at fair value. We elected not to pursue
hedge accounting treatment for these instruments for financial
accounting purposes. Therefore, changes in the fair value of
these derivative instruments are included in income in the
period of change. Net gains or losses associated with these
transactions are recognized within cost of products sold using
mark-to-market
accounting.
Pension and Other Postretirement
Obligations. Pension and other postretirement
plan expenses and liabilities are determined based on actuarial
valuations. Inherent in these valuations are key assumptions
including discount rates, future compensation increases,
expected return on plan assets, health care cost trends, and
demographic data. Changes in our actuarial assumptions are
primarily influenced by factors outside of our control and can
have a significant effect on our pension and other
postretirement liabilities and costs. A defined benefit
postretirement plan sponsor must (a) recognize in its
statement of financial position an asset for a plans
overfunded status or liability for the plans underfunded
status, (b) measure the plans assets and obligations
that determine its funded status as of the end of the
employers fiscal year, and (c) recognize, as a
component of other comprehensive income, the changes in the
funded status of the plan that arise during the year but are not
recognized as components of net periodic benefit cost.
Stock-Based Compensation. The cost of the
employee services received in exchange for an award of equity
instruments awarded under the Western Refining Long-Term
Incentive Plan is measured based on the grant date fair value of
the award. The fair value of each share of restricted stock
awarded is measured based on the market price at closing as of
the measurement date and is amortized on a straight-line basis
over the respective vesting periods.
Recent
Accounting Pronouncements
From time to time, new accounting pronouncements are issued by
the Financial Accounting Standards Board or other standard
setting bodies that may have an impact on our accounting and
reporting. We believe that such recently issued accounting
pronouncements and other authoritative guidance for which the
effective date is in the future either will not have an impact
on our accounting or reporting or that such impact will not be
material to our financial position, results of operations, and
cash flows when implemented.
41
Results
of Operations
The following tables summarize our consolidated and operating
segment financial data and key operating statistics for the
three years ended December 31, 2010:
Consolidated
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands)
|
|
|
Net sales(1)
|
|
$
|
7,965,053
|
|
|
$
|
6,807,368
|
|
|
$
|
10,725,581
|
|
Operating costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of products sold (exclusive of depreciation and
amortization)(1)
|
|
|
7,155,967
|
|
|
|
5,944,128
|
|
|
|
9,735,500
|
|
Direct operating expenses (exclusive of depreciation and
amortization)(1)
|
|
|
444,531
|
|
|
|
486,164
|
|
|
|
532,325
|
|
Selling, general, and administrative expenses
|
|
|
84,175
|
|
|
|
109,697
|
|
|
|
115,913
|
|
Goodwill and other impairment losses
|
|
|
13,038
|
|
|
|
352,340
|
|
|
|
|
|
Maintenance turnaround expense
|
|
|
23,286
|
|
|
|
8,088
|
|
|
|
28,936
|
|
Depreciation and amortization
|
|
|
138,621
|
|
|
|
145,981
|
|
|
|
113,611
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating costs and expenses
|
|
|
7,859,618
|
|
|
|
7,046,398
|
|
|
|
10,526,285
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss)
|
|
$
|
105,435
|
|
|
$
|
(239,030
|
)
|
|
$
|
199,296
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Excludes $3,294.0 million, $2,095.0 million, and
$2,847.8 million of intercompany sales;
$3,287.5 million, $2,088.8 million, and
$2,831.6 million of intercompany cost of products sold; and
$6.5 million, $6.2 million, and $16.2 million of
intercompany direct operating expenses for the years ended
December 31, 2010, 2009, and 2008, respectively. |
Fiscal
Year Ended December 31, 2010 Compared to Fiscal Year Ended
December 31, 2009
Net Sales. Net sales primarily consist of
gross sales of refined products, lubricants, and merchandise,
net of customer rebates or discounts, and excise taxes. Net
sales for the year ended December 31, 2010 were
$7,965.1 million, compared to $6,807.4 million for the
year ended December 31, 2009, an increase of
$1,157.7 million, or 17.0%. This increase was the result of
increased sales from our refining, wholesale, and retail groups
of $570.7 million, $502.0 million, and
$85.0 million, respectively, net of intercompany
transactions that eliminate in consolidation. The average sales
price per barrel of refined products for all operating segments
increased from $71.99 in 2009 to $93.18 million in 2010.
This increase was partially offset by decreased sales volumes
from 118.8 million barrels in 2009 to 117.1 million
barrels in 2010, a decrease of 1.7 million barrels, or 1.4%.
Cost of Products Sold (exclusive of depreciation and
amortization). Cost of products sold primarily
includes cost of crude oil, other feedstocks and blendstocks,
purchased refined products, lubricants and merchandise for
resale, and transportation and distribution costs. Cost of
products sold was $7,156.0 million for the year ended
December 31, 2010, compared to $5,944.1 million for
the year ended December 31, 2009, an increase of
$1,211.9 million, or 20.4%. This increase was primarily the
result of increased cost of products sold from our refining,
wholesale, and retail groups of $629.3 million,
$499.9 million, and $82.7 million, respectively, net
of intercompany transactions that eliminate in consolidation.
Cost of products sold for the year ended December 31, 2009
included a non-cash LCM inventory recovery of
$61.0 million. No such recovery occurred in 2010. The
average cost per barrel of crude oil, feedstocks, and refined
products for all operating segments increased from $65.60 in
2009 to $86.94 in 2010. Cost of products sold for the year ended
December 31, 2009 includes $21.7 million in economic
hedging losses previously reported as loss from derivative
activities under other income (expense). We reclassified the
prior year amount to conform to the current presentation. Cost
of products sold for the year ended December 31, 2010
includes $9.4 million in economic hedging losses.
42
Direct Operating Expenses (exclusive of depreciation and
amortization). Direct operating expenses include
direct costs of labor, maintenance materials and services,
transportation expenses, chemicals and catalysts, natural gas,
utilities, insurance expense, property taxes, and other direct
operating expenses. Direct operating expenses were
$444.5 million for the year ended December 31, 2010,
compared to $486.2 million for the year ended
December 31, 2009, a decrease of $41.7 million, or
8.6%. Included in this decrease was $8.5 million related to
the reversal of our December 2009 incentive bonus accrual. This
decrease in direct operating expenses resulted from decreases of
$40.1 million and $3.6 million partially offset by an
increase of $2.0 million, in direct operating expenses of
our refining, wholesale, and retail groups, respectively, net of
intercompany transactions that eliminate in consolidation.
Included within the decrease of $40.1 million in our
refining group was a decrease of $23.4 million in direct
operating expenses primarily resulting from cost-saving
initiatives related to the fourth quarter 2009 consolidation of
our Four Corners refining operations. This decrease was
partially offset by certain costs associated with terminal
operations at our Bloomfield facility. Accrued incentive bonus
of $4.7 million was included in consolidated direct
operating expenses for the year ended December 31, 2010.
In total, we reversed $14.7 million related to our December
2009 incentive bonus accrual including the $6.2 million
reversal discussed below under selling, general, and
administrative expenses for the year ended December 31,
2010. We consider the awarding of a bonus for any period to be
discretionary and subject to not only the earnings during the
bonus period, but also to the economic conditions and refining
industry environment at the time the bonus is to be paid. Our
first quarter 2010 results, coupled with our near-term forecasts
of operating results and our expectations for the economy were
such that we did not deem the pay-out of the previously accrued
2009 bonus prudent as such payment would not be in the best
interests of the Company or our shareholders. On March 29,
2010, we determined that 2009 bonuses would not be paid. Accrued
incentive bonus of $8.3 million was included in
consolidated direct operating costs and selling, general, and
administrative expenses for the year ended December 31,
2010 which had been substantially paid out by March 4, 2011.
Selling, General, and Administrative
Expenses. Selling, general, and administrative
expenses consist primarily of corporate overhead, marketing
expenses, public company costs, and stock-based compensation.
Selling, general, and administrative expenses were
$84.2 million for the year ended December 31, 2010,
compared to $109.7 million for the year ended
December 31, 2009, a decrease of $25.5 million, or
23.2%. Included in this decrease was $6.2 million related
to the reversal of our December 2009 incentive bonus accrual.
See direct operating expenses (exclusive of depreciation and
amortization) for the year ended December 31, 2010 for
additional discussion of the bonus accrual reversal. This
decrease resulted from decreased expenses in our refining,
wholesale, and retail groups of $15.8 million,
$4.0 million, and $1.1 million respectively, and a
$4.6 million decrease in corporate overhead.
The decrease of $4.6 million in corporate overhead was
primarily caused by decreased professional and legal fees
($4.2 million). Accrued incentive bonus of
$3.6 million was included in consolidated selling, general,
and administrative expenses for the year ended December 31,
2010.
Goodwill and Other Impairment Losses. As a
result of our decision to permanently close our product
distribution terminal in Flagstaff, Arizona during the third
quarter of 2010, we completed an impairment analysis of the
related long-lived assets and determined from this analysis that
impairment existed. Accordingly, we recorded an impairment
charge of $4.0 million primarily related to the Flagstaff
long-lived and other assets. Also during 2010, we determined the
existence of additional impairment related to certain of
Bloomfields refinery assets and recorded a resulting
non-cash charge of $9.1 million.
During 2009, we determined that our entire goodwill balance,
which was previously reported under four of our six reporting
units, was impaired. The total impact of this impairment was a
non-cash charge of $299.6 million. Also during 2009,
following our decision to indefinitely suspend the refining
operations of our Bloomfield refinery, we completed an
impairment analysis of the related long-lived and intangible
assets and determined that impairment of certain of the
Bloomfield refinery related assets existed and accordingly
recorded a non-cash impairment charge of $52.8 million.
Maintenance Turnaround Expense. Maintenance
turnaround expense includes periodic maintenance and repairs
generally performed every two to six years, depending on the
processing unit involved. During 2010, we incurred costs of
$23.3 million in connection with a maintenance turnaround
at the El Paso refinery. Primarily
43
during the third and fourth quarters of 2009, we incurred costs
of $2.9 million in a crude unit shutdown and
$4.0 million in connection with the planned turnaround in
the first quarter of 2010 at the El Paso refinery, and
$1.2 million in connection with the anticipated 2010
turnaround at the Yorktown refinery, which was subsequently
canceled.
Depreciation and Amortization. Depreciation
and amortization for the year ended December 31, 2010 was
$138.6 million compared to $146.0 million for the year
ended December 31, 2009, a decrease of $7.4 million,
or 5.1%. The majority of the decrease was due to differences in
the timing of various assets reaching the end of their estimated
useful lives.
Operating Income (Loss). Operating income was
$105.4 million for the year ended December 31, 2010,
compared to an operating loss of $239.0 million for the
year ended December 31, 2009, an increase of
$344.4 million. This increase was primarily attributable to
non-cash impairment losses of $352.3 million recorded in
2009 compared to $13.0 million in 2010, and decreased
direct operating and selling, general, and administrative
expenses along with decreased depreciation expense. The increase
was partially offset by increased maintenance turnaround costs
due to the maintenance turnaround completed in the first quarter
of 2010.
Interest Income. Interest income for the years
ended December 31, 2010 and 2009 was $0.4 million and
$0.2 million, respectively.
Interest Expense and Other Financing
Costs. Interest expense was $146.5 million
(net of capitalized interest of $4.2 million) for the year
ended December 31, 2010, compared to $121.3 million
(net of capitalized interest of $6.4 million) for the year
ended December 31, 2009, an increase of $25.2 million,
or 20.8%. This increase was primarily attributable to a full
year of interest expense and discount amortization on the Senior
Secured and Convertible Senior Notes in 2010 compared to six
months in 2009. This increase was partially offset by lower 2010
Term Loan interest expense resulting from the early retirement
of a portion of our Term Loan in 2009.
Amortization of Loan Fees. Amortization of
loan fees for 2010 was $9.7 million compared to
$6.9 million for 2009, an increase of $2.8 million, or
40.6%. This increase is primarily the result of additional
deferred loan fees incurred during 2009 of $30.7 million
for new debt and amendments to our Term Loan and our Revolving
Credit Agreement. This increase was partially offset by the
reduction in amortization expense resulting from the write-off
of $9.0 million in unamortized loan fees in 2009 related to
the early retirement of a portion of our Term Loan.
Write-off of Unamortized Loan Fees. We made
unscheduled principal payments on our Term Loan credit agreement
primarily from the net proceeds of our 2009 debt and common
stock offerings. As a result of the early retirement of a
portion of our Term Loan, we wrote off $9.0 million in 2009
related to the portion of deferred financing costs associated
with that portion of the Term Loan.
Provision for Income Taxes. Our effective tax
rate can be affected by any estimated tax credits that we plan
to utilize for the years estimated tax provision.
Generally, such tax credits will lower our tax expense and
effective rate when we have positive earnings and increase our
tax benefit and effective rate when we have losses. We recorded
an income tax benefit of $26.1 million for the year ended
December 31, 2010, using an estimated effective tax rate of
60.5%, as compared to the federal statutory rate of 35%. The
effective tax rate was higher primarily due to the federal
income tax credit available to small business refiners related
to the production of ultra low sulfur diesel fuel.
We recorded an income tax benefit of $40.6 million for the
year ended December 31, 2009, using an estimated effective
tax rate of 44.3%, as compared to the federal statutory rate of
35%. The effective tax rate was higher primarily due to the
federal income tax credit available to small business refiners
related to the production of ultra low sulfur diesel fuel and
the non-deductible goodwill impairment for federal tax reporting
purposes.
Net Income (Loss). We reported a net loss of
$17.0 million for the year ended December 31, 2010,
representing $0.19 net loss per share on weighted average
diluted shares outstanding of 88.2 million. We reported a
net loss of $350.6 million for the year ended
December 31, 2009, representing $4.43 net loss per
share on weighted average dilutive shares outstanding of
79.2 million. Our net loss for the year ended
December 31, 2009 included a non-cash goodwill impairment
charge of $299.6 million and a before-tax
$20.0 million legal settlement charge. Similar charges were
not included in our net loss for the year ended
December 31, 2010.
See additional analysis under the Refining Segment, Wholesale
Segment, and Retail Segment.
44
Fiscal
Year Ended December 31, 2009 Compared to Fiscal Year Ended
December 31, 2008
Net Sales. Net sales primarily consist of
gross sales of refined products, lubricants, and merchandise,
net of customer rebates or discounts, and excise taxes. Net
sales for the year ended December 31, 2009 were
$6,807.4 million, compared to $10,725.6 million for
the year ended December 31, 2008, a decrease of
$3,918.2 million, or 36.5%. This decrease was the result of
decreased sales from our refining, wholesale, and retail groups
of $3,231.8 million, $502.9 million, and
$183.5 million, respectively, net of intercompany
transactions that eliminate in consolidation. The average sales
price per barrel of refined products for all operating segments
decreased from $113.20 in 2008 to $71.99 in 2009. This decrease
was partially offset by an increase in sales volumes. Our sales
volume increased by 2.5 million barrels, or 2.1%, to
118.8 million barrels for 2009 compared to
116.3 million barrels for 2008.
Cost of Products Sold (exclusive of depreciation and
amortization). Cost of products sold primarily
includes cost of crude oil, other feedstocks and blendstocks,
purchased refined products, lubricants and merchandise for
resale, and transportation and distribution costs. Cost of
products sold was $5,944.1 million for the year ended
December 31, 2009, compared to $9,735.5 million for
the year ended December 31, 2008, a decrease of
$3,791.4 million, or 38.9%. This decrease primarily was the
result of decreased cost of products sold from our refining,
wholesale, and retail groups of $3,128.4 million,
$476.6 million, and $186.4 million, respectively, net
of intercompany transactions that eliminate in consolidation. A
non-cash LCM inventory write-down of $61.0 million was
included in cost of products sold in 2008 versus a non-cash LCM
inventory recovery of $61.0 million in 2009. The average
cost per barrel of crude oil, feedstocks, and refined products
for all operating segments decreased from $105.44 in 2008, to
$65.60 in 2009. Cost of products sold for the year ended
December 31, 2009 and 2008 includes $21.7 million in
economic hedging losses and $11.4 million in economic
hedging gains, respectively, previously reported as gain (loss)
from derivative activities under other income (expense) in our
Consolidated Statements of Operations. These prior year amounts
were reclassified to conform to current presentation.
Direct Operating Expenses (exclusive of depreciation and
amortization). Direct operating expenses include
direct costs of labor, maintenance materials and services,
transportation expenses, chemicals and catalysts, natural gas,
utilities, insurance expense, property taxes, and other direct
operating expenses. Direct operating expenses were
$486.2 million for the year ended December 31, 2009,
compared to $532.3 million for the year ended
December 31, 2008, a decrease of $46.1 million, or
8.7%. This decrease resulted from decreases of
$33.0 million, $12.5 million, and $0.6 million in
direct operating expenses of our refining, wholesale, and retail
groups, respectively, net of intercompany transactions that
eliminate in consolidation.
Selling, General, and Administrative
Expenses. Selling, general, and administrative
expenses consist primarily of corporate overhead, marketing
expenses, public company costs, and stock-based compensation.
Selling, general, and administrative expenses were
$109.7 million for the year ended December 31, 2009,
compared to $115.9 million for the year ended
December 31, 2008, a decrease of $6.2 million, or
5.3%. This decrease resulted from decreased expenses in our
refining and wholesale groups of $1.5 million and
$2.3 million, respectively, and a $3.2 million
decrease in corporate overhead. These decreases were offset by
increases of $0.9 million in our retail group.
The decrease of $3.2 million in corporate overhead was
primarily caused by decreased personnel costs mainly related to
decreased 401(k) contribution expense resulting from the
allocation to the other operating segments ($4.4 million),
incentive compensation ($3.2 million), decreased
stock-based compensation ($2.6 million), and vacation
expense ($1.8 million). These decreases were partially
offset by increased professional and legal fees
($5.6 million) and increased information technology
expenses ($2.6 million).
Goodwill and Other Impairment Losses. During
2009, we determined that all of our goodwill was impaired. The
total impact of this goodwill impairment was a non-cash charge
of $299.6 million. Also during 2009, as a result of our
decision to indefinitely suspend the refining operations of our
Bloomfield refinery, we completed an impairment analysis of the
related long-lived assets. We determined that impairment of
certain of the Bloomfield refinery related long-lived and
intangible assets existed and accordingly recorded a non-cash
charge of $52.8 million related to this impairment. No
impairment losses were recorded in 2008.
45
Maintenance Turnaround Expense. Maintenance
turnaround expense includes periodic maintenance and repairs
generally performed every two to six years, depending on the
processing unit involved. Primarily during the third and fourth
quarters of 2009, we incurred costs of $2.9 million in a
crude unit shutdown and $4.0 million in connection with the
planned turnaround in the first quarter of 2010 at the
El Paso refinery, and $1.2 million in connection with
the planned turnaround in the third quarter of 2010 at the
Yorktown refinery. During the year ended December 31, 2008,
we performed a maintenance turnaround at the north side of the
El Paso refinery at a cost of $28.9 million.
Depreciation and Amortization. Depreciation
and amortization for the year ended December 31, 2009 was
$146.0 million, compared to $113.6 million for the
year ended December 31, 2008, an increase of
$32.4 million, or 28.5%. The increase was due to the
completion of various capital projects during the latter part of
2008 and 2009.
Operating Income (Loss). Operating loss was
$239.0 million for the year ended December 31, 2009,
compared to operating income of $199.3 million for the year
ended December 31, 2008, a decrease of $438.3 million.
This decrease was primarily attributable to non-cash impairment
losses of $352.3 million recorded in 2009 and decreased
gross margins resulting from lower sales prices per barrel
during 2009 without a corresponding decrease in the cost per
barrel of crude.
Interest Income. Interest income for the years
ended December 31, 2009 and 2008, was $0.2 million and
$1.8 million, respectively. The decrease was attributable
to decreased balances of cash for investment as well as lower
interest rates in 2009 compared to 2008.
Interest Expense and Other Financing
Costs. Interest expense was $121.3 million
(net of capitalized interest of $6.4 million) for the year
ended December 31, 2009, compared to $102.2 million
(net of capitalized interest of $9.9 million) for the year
ended December 31, 2008, an increase of $19.1 million
or 18.7%. The increase is primarily attributable to higher
effective interest rates in the latter half of 2009 versus 2008
offset by lower levels of outstanding debt.
Amortization of Loan Fees. Amortization of
loan fees for 2009 was $6.9 million, compared to
$4.8 million for 2008. The increase is primarily the result
of additional deferred loan fees incurred during 2009 of
$30.7 million for new debt and amendments to our term and
revolving loan agreements. This increase was partially offset by
the reduction in amortization expense resulting from the
write-off of $9.0 million in unamortized loan fees related
to our Term Loan. On June 30, 2008, we entered into an
amendment to our Term Loan Credit Agreement and incurred
$22.4 million in loan fees. This increase was partially
offset by the write-off of $10.9 million in unamortized
loan fees incurred in May 2007.
Write-off of Unamortized Loan Fees. During
2009, we expensed $9.0 million in deferred loan fees when
we retired $912.7 million of our term debt earlier than
scheduled with proceeds from our debt and stock offering. On
June 30, 2008, we entered into an amendment to our Term
Loan Credit Agreement and as a result, we recorded an expense of
$10.9 million related to the write-off of deferred loan
fees incurred in May 2007.
Provision for Income Taxes. We recorded an
income tax benefit of $40.6 million for the year ended
December 31, 2009, using an estimated effective tax rate of
44.3%, as compared to the federal statutory rate of 35%. The
effective tax rate was higher primarily due to the federal
income tax credit available to small business refiners related
to the production of ultra low sulfur diesel fuel and the
non-deductible goodwill impairment for federal tax reporting
purposes.
We recorded an income tax expense of $20.2 million for the
year ended December 31, 2008, using an estimated effective
tax rate of 24.0%, as compared to the federal statutory rate of
35%. The effective tax rate was lower primarily due to the
federal income tax credit available to small business refiners
related to the production of ultra low sulfur diesel fuel.
Net Income (Loss). We reported a net loss of
$350.6 million for the year ended December 31, 2009,
representing $4.43 net loss per share on weighted average
dilutive shares outstanding of 79.2 million. Our net loss
for the year ended December 31, 2009 included a before tax
$20.0 million legal settlement charge. Similar charges were
not included in net income for the year ended December 31,
2008. For the year ended December 31, 2008, we
46
reported net income of $64.2 million representing
$0.94 net income per share on weighted average dilutive
shares outstanding of 67.7 million.
The following tables set forth our summary and individual
refining throughput and production data. All Refineries
summary tables include summary throughput and production
data for all of our refineries for the periods presented.
Southwest Refineries summary tables present current and
prior year operating and production results of our refining
facilities operational as of December 31, 2010 for the
periods presented. We do not allocate selling, general, and
administrative expenses to the individual refineries or other
related refinery operations.
Refining
Segment (All Refineries and Related Operations)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands, except per barrel data)
|
|
|
Net sales (including intersegment sales)
|
|
$
|
8,070,119
|
|
|
$
|
6,608,075
|
|
|
$
|
10,455,602
|
|
Operating costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of products sold (exclusive of depreciation and
amortization)(1)
|
|
|
7,439,826
|
|
|
|
5,919,499
|
|
|
|
9,653,681
|
|
Direct operating expenses (exclusive of depreciation and
amortization)
|
|
|
335,869
|
|
|
|
375,690
|
|
|
|
418,628
|
|
Selling, general, and administrative expenses
|
|
|
20,155
|
|
|
|
36,021
|
|
|
|
37,561
|
|
Goodwill and other impairment losses
|
|
|
12,832
|
|
|
|
283,500
|
|
|
|
|
|
Maintenance turnaround expense
|
|
|
23,286
|
|
|
|
8,088
|
|
|
|
28,936
|
|
Depreciation and amortization
|
|
|
118,661
|
|
|
|
125,537
|
|
|
|
95,713
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating costs and expenses
|
|
|
7,950,629
|
|
|
|
6,748,335
|
|
|
|
10,234,519
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss)
|
|
$
|
119,490
|
|
|
$
|
(140,260
|
)
|
|
$
|
221,083
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Key Operating Statistics
|
|
|
|
|
|
|
|
|
|
|
|
|
Total sales volume (bpd)(2)(7)
|
|
|
248,785
|
|
|
|
258,259
|
|
|
|
258,013
|
|
Total refinery production (bpd)(7)
|
|
|
192,997
|
|
|
|
213,833
|
|
|
|
225,740
|
|
Total refinery throughput (bpd)(3)(7)
|
|
|
194,492
|
|
|
|
215,815
|
|
|
|
227,130
|
|
Per barrel of throughput:
|
|
|
|
|
|
|
|
|
|
|
|
|
Refinery gross margin(1)(4)
|
|
$
|
8.88
|
|
|
$
|
8.74
|
|
|
$
|
9.65
|
|
Gross profit(4)
|
|
|
7.21
|
|
|
|
7.15
|
|
|
|
8.50
|
|
Direct operating expenses(5)
|
|
|
4.73
|
|
|
|
4.77
|
|
|
|
5.04
|
|
47
Southwest
Refineries (El Paso and Four Corners and Related
Operations)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands, except per barrel data)
|
|
|
Net sales (including intersegment sales)
|
|
$
|
6,321,322
|
|
|
$
|
4,877,985
|
|
|
|
7,565,295
|
|
Operating costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of products sold (exclusive of depreciation and
amortization)
|
|
|
5,745,996
|
|
|
|
4,326,182
|
|
|
|
6,927,609
|
|
Direct operating expenses (exclusive of depreciation and
amortization)
|
|
|
242,422
|
|
|
|
262,259
|
|
|
|
297,228
|
|
Selling, general, and administrative expenses
|
|
|
20,155
|
|
|
|
36,021
|
|
|
|
27,843
|
|
Goodwill and other impairment losses
|
|
|
12,832
|
|
|
|
125,936
|
|
|
|
|
|
Maintenance turnaround expense
|
|
|
23,286
|
|
|
|
6,898
|
|
|
|
28,936
|
|
Depreciation and amortization
|
|
|
72,886
|
|
|
|
78,732
|
|
|
|
53,905
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating costs and expenses
|
|
|
6,117,577
|
|
|
|
4,836,028
|
|
|
|
7,335,521
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
$
|
203,745
|
|
|
$
|
41,957
|
|
|
$
|
229,774
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Key Operating Statistics
|
|
|
|
|
|
|
|
|
|
|
|
|
Total sales volume (bpd)(2)
|
|
|
189,613
|
|
|
|
184,108
|
|
|
|
180,940
|
|
Total refinery production (bpd)
|
|
|
149,007
|
|
|
|
150,411
|
|
|
|
154,295
|
|
Total refinery throughput (bpd)(3)
|
|
|
151,288
|
|
|
|
153,082
|
|
|
|
157,332
|
|
Per barrel of throughput:
|
|
|
|
|
|
|
|
|
|
|
|
|
Refinery gross margin(4)
|
|
$
|
10.42
|
|
|
$
|
9.88
|
|
|
$
|
11.07
|
|
Gross profit(4)
|
|
|
9.10
|
|
|
|
8.47
|
|
|
|
10.14
|
|
Direct operating expenses(5)
|
|
|
4.39
|
|
|
|
4.69
|
|
|
|
5.16
|
|
All
Refineries
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2010(7)
|
|
|
2009
|
|
|
2008
|
|
|
Refinery Product Yields (bpd)
|
|
|
|
|
|
|
|
|
|
|
|
|
Gasoline
|
|
|
102,927
|
|
|
|
113,364
|
|
|
|
114,876
|
|
Diesel and jet fuel
|
|
|
73,774
|
|
|
|
80,157
|
|
|
|
88,695
|
|
Residuum
|
|
|
4,899
|
|
|
|
5,504
|
|
|
|
5,711
|
|
Other
|
|
|
7,174
|
|
|
|
9,349
|
|
|
|
9,649
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liquid by-products
|
|
|
188,774
|
|
|
|
208,374
|
|
|
|
218,931
|
|
By-products (coke)
|
|
|
4,223
|
|
|
|
5,459
|
|
|
|
6,809
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
192,997
|
|
|
|
213,833
|
|
|
|
225,740
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Refinery Throughput (bpd)
|
|
|
|
|
|
|
|
|
|
|
|
|
Sweet crude oil
|
|
|
131,028
|
|
|
|
126,328
|
|
|
|
143,714
|
|
Sour or heavy crude oil
|
|
|
44,129
|
|
|
|
65,260
|
|
|
|
62,349
|
|
Other feedstocks and blendstocks
|
|
|
19,335
|
|
|
|
24,227
|
|
|
|
21,067
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total refinery throughput (bpd)
|
|
|
194,492
|
|
|
|
215,815
|
|
|
|
227,130
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
48
Southwest
Refineries (El Paso and Four Corners)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2010
|
|
|
2009(6)
|
|
|
2008
|
|
|
Refinery Product Yields (bpd)
|
|
|
|
|
|
|
|
|
|
|
|
|
Gasoline
|
|
|
81,953
|
|
|
|
82,540
|
|
|
|
82,279
|
|
Diesel and jet fuel
|
|
|
58,122
|
|
|
|
57,976
|
|
|
|
61,552
|
|
Residuum
|
|
|
4,899
|
|
|
|
5,504
|
|
|
|
5,711
|
|
Other
|
|
|
4,033
|
|
|
|
4,391
|
|
|
|
4,753
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
149,007
|
|
|
|
150,411
|
|
|
|
154,295
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Refinery Throughput (bpd)
|
|
|
|
|
|
|
|
|
|
|
|
|
Sweet crude oil
|
|
|
125,259
|
|
|
|
124,443
|
|
|
|
128,423
|
|
Sour crude oil
|
|
|
14,007
|
|
|
|
17,601
|
|
|
|
16,985
|
|
Other feedstocks and blendstocks
|
|
|
12,022
|
|
|
|
11,038
|
|
|
|
11,924
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total refinery throughput (bpd)
|
|
|
151,288
|
|
|
|
153,082
|
|
|
|
157,332
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
El Paso Refinery
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
Key Operating Statistics
|
|
|
|
|
|
|
|
|
|
|
|
|
Refinery product yields (bpd):
|
|
|
|
|
|
|
|
|
|
|
|
|
Gasoline
|
|
|
65,740
|
|
|
|
65,160
|
|
|
|
62,557
|
|
Diesel and jet fuel
|
|
|
51,571
|
|
|
|
50,524
|
|
|
|
52,754
|
|
Residuum
|
|
|
4,899
|
|
|
|
5,504
|
|
|
|
5,711
|
|
Other
|
|
|
3,245
|
|
|
|
3,341
|
|
|
|
3,612
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total refinery production (bpd)
|
|
|
125,455
|
|
|
|
124,529
|
|
|
|
124,634
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Refinery throughput (bpd):
|
|
|
|
|
|
|
|
|
|
|
|
|
Sweet crude oil
|
|
|
104,119
|
|
|
|
99,680
|
|
|
|
100,130
|
|
Sour crude oil
|
|
|
14,007
|
|
|
|
17,601
|
|
|
|
16,985
|
|
Other feedstocks and blendstocks
|
|
|
9,051
|
|
|
|
9,184
|
|
|
|
9,454
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total refinery throughput (bpd)
|
|
|
127,177
|
|
|
|
126,465
|
|
|
|
126,569
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total sales volume (bpd)(2)
|
|
|
153,398
|
|
|
|
147,854
|
|
|
|
138,775
|
|
Per barrel of throughput:
|
|
|
|
|
|
|
|
|
|
|
|
|
Refinery gross margin(4)
|
|
$
|
9.37
|
|
|
$
|
9.20
|
|
|
$
|
9.45
|
|
Direct operating expenses(5)
|
|
|
3.50
|
|
|
|
3.60
|
|
|
|
4.07
|
|
49
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
Four Corners
Refineries
|
|
2010
|
|
|
2009(6)
|
|
|
2008
|
|
|
Key Operating Statistics
|
|
|
|
|
|
|
|
|
|
|
|
|
Refinery product yields (bpd):
|
|
|
|
|
|
|
|
|
|
|
|
|
Gasoline
|
|
|
16,213
|
|
|
|
17,380
|
|
|
|
19,722
|
|
Diesel and jet fuel
|
|
|
6,551
|
|
|
|
7,452
|
|
|
|
8,798
|
|
Other
|
|
|
788
|
|
|
|
1,050
|
|
|
|
1,141
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total refinery production (bpd)
|
|
|
23,552
|
|
|
|
25,882
|
|
|
|
29,661
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Refinery throughput (bpd):
|
|
|
|
|
|
|
|
|
|
|
|
|
Sweet crude oil
|
|
|
21,140
|
|
|
|
24,763
|
|
|
|
28,293
|
|
Other feedstocks and blendstocks
|
|
|
2,971
|
|
|
|
1,854
|
|
|
|
2,470
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total refinery throughput (bpd)
|
|
|
24,111
|
|
|
|
26,617
|
|
|
|
30,763
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total sales volume (bpd)(2)
|
|
|
36,215
|
|
|
|
36,254
|
|
|
|
42,165
|
|
Per barrel of throughput:
|
|
|
|
|
|
|
|
|
|
|
|
|
Refinery gross margin(4)
|
|
$
|
16.82
|
|
|
$
|
15.17
|
|
|
$
|
15.49
|
|
Direct operating expenses(5)
|
|
|
6.68
|
|
|
|
8.79
|
|
|
|
8.35
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
Yorktown Refinery
|
|
2010(7)
|
|
|
2009
|
|
|
2008
|
|
|
Key Operating Statistics
|
|
|
|
|
|
|
|
|
|
|
|
|
Refinery Product Yields (bpd):
|
|
|
|
|
|
|
|
|
|
|
|
|
Gasoline
|
|
|
28,043
|
|
|
|
30,824
|
|
|
|
32,597
|
|
Diesel and jet fuel
|
|
|
20,926
|
|
|
|
22,181
|
|
|
|
27,143
|
|
Other
|
|
|
4,199
|
|
|
|
4,958
|
|
|
|
4,896
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liquid by-products
|
|
|
53,168
|
|
|
|
57,963
|
|
|
|
64,636
|
|
By-products (coke)
|
|
|
5,647
|
|
|
|
5,459
|
|
|
|
6,809
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total refinery production (bpd)
|
|
|
58,815
|
|
|
|
63,422
|
|
|
|
71,445
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Refinery throughput (bpd):
|
|
|
|
|
|
|
|
|
|
|
|
|
Sweet crude oil
|
|
|
7,713
|
|
|
|
1,885
|
|
|
|
15,291
|
|
Heavy crude oil
|
|
|
40,274
|
|
|
|
47,659
|
|
|
|
45,364
|
|
Other feedstocks and blendstocks
|
|
|
9,777
|
|
|
|
13,189
|
|
|
|
9,143
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total refinery throughput (bpd)
|
|
|
57,764
|
|
|
|
62,733
|
|
|
|
69,798
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total sales volume (bpd)(2)(7)
|
|
|
59,172
|
|
|
|
74,151
|
|
|
|
77,073
|
|
Per barrel of throughput:
|
|
|
|
|
|
|
|
|
|
|
|
|
Refinery gross margin(1)(4)
|
|
$
|
3.49
|
|
|
$
|
5.97
|
|
|
$
|
6.43
|
|
Direct operating expenses(5)
|
|
|
5.93
|
|
|
|
4.95
|
|
|
|
4.75
|
|
|
|
|
(1) |
|
Cost of products sold includes non-cash LCM adjustments of
$(61.0) million and $61.0 million for 2009 and 2008,
respectively, related to valuation of our Yorktown inventories
to net realizable market values. These non-cash adjustments
resulted in a corresponding increase of $0.78 and decrease of
$0.73 in combined refinery gross margins for the years ended
December 31, 2009 and 2008, respectively. These non-cash
adjustments resulted in a corresponding increase of $2.66 and
decrease of $2.39 in Yorktowns refinery gross margins for
the years ended December 31, 2009 and 2008, respectively. |
|
(2) |
|
Includes sales of refined products sourced from our refinery
production as well as refined products purchased from third
parties. |
50
|
|
|
(3) |
|
Total refinery throughput includes crude oil, other feedstocks,
and blendstocks. |
|
(4) |
|
Refinery gross margin is a per barrel measurement calculated by
dividing the difference between net sales and cost of products
sold by our refineries total throughput volumes for the
respective periods presented. Economic hedging gains and losses
included in the combined refining segment gross margin are not
allocated to the individual refineries. Cost of products sold
does not include any depreciation or amortization. Refinery
gross margin is a non-GAAP performance measure that we believe
is important to investors in evaluating our refinery performance
as a general indication of the amount above our cost of products
that we are able to sell refined products. Each of the
components used in this calculation (net sales and cost of
products sold) can be reconciled directly to our statement of
operations. Our calculation of refinery gross margin may differ
from similar calculations of other companies in our industry,
thereby limiting its usefulness as a comparative measure. |
|
|
|
The following table reconciles combined gross profit for all
refineries to combined gross margin for all refineries for the
periods presented: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands, except per barrel data)
|
|
|
Net sales (including intersegment sales)
|
|
$
|
8,070,119
|
|
|
$
|
6,608,075
|
|
|
$
|
10,455,602
|
|
Cost of products sold (exclusive of depreciation and
amortization)
|
|
|
7,439,826
|
|
|
|
5,919,499
|
|
|
|
9,653,681
|
|
Depreciation and amortization
|
|
|
118,661
|
|
|
|
125,537
|
|
|
|
95,713
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross profit
|
|
|
511,632
|
|
|
|
563,039
|
|
|
|
706,208
|
|
Plus depreciation and amortization
|
|
|
118,661
|
|
|
|
125,537
|
|
|
|
95,713
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Refinery gross margin
|
|
$
|
630,293
|
|
|
$
|
688,576
|
|
|
$
|
801,921
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Refinery gross margin per refinery throughput barrel(4)
|
|
$
|
8.88
|
|
|
$
|
8.74
|
|
|
$
|
9.65
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross profit per refinery throughput barrel(4)
|
|
$
|
7.21
|
|
|
$
|
7.15
|
|
|
$
|
8.50
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following table reconciles gross profit for our Southwest
refineries to combined gross margin for our Southwest refineries
for the periods presented: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands, except per barrel data)
|
|
|
Net sales (including intersegment sales)
|
|
$
|
6,321,322
|
|
|
$
|
4,877,985
|
|
|
$
|
7,565,295
|
|
Cost of products sold (exclusive of depreciation and
amortization)
|
|
|
5,745,996
|
|
|
|
4,326,182
|
|
|
|
6,927,609
|
|
Depreciation and amortization
|
|
|
72,886
|
|
|
|
78,732
|
|
|
|
53,905
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross profit
|
|
|
502,440
|
|
|
|
473,071
|
|
|
|
583,781
|
|
Plus depreciation and amortization
|
|
|
72,886
|
|
|
|
78,732
|
|
|
|
53,905
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Refinery gross margin
|
|
$
|
575,326
|
|
|
$
|
551,803
|
|
|
$
|
637,686
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Refinery gross margin per refinery throughput barrel(4)
|
|
$
|
10.42
|
|
|
$
|
9.88
|
|
|
$
|
11.07
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross profit per refinery throughput barrel(4)
|
|
$
|
9.10
|
|
|
$
|
8.47
|
|
|
$
|
10.14
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(5) |
|
Refinery direct operating expenses per throughput barrel is
calculated by dividing direct operating expenses by total
throughput volumes for the respective periods presented. Direct
operating expenses do not include any depreciation or
amortization, and combined refinery direct operating expenses
include transportation and other related expenses not specific
to a particular refinery. |
|
(6) |
|
Until November 2009, Four Corners refining was comprised of two
separate facilities; the Bloomfield refinery and the Gallup
refinery. In late November 2009, we consolidated refining
operations into the Gallup facility and indefinitely suspended
refining operations at the Bloomfield refinery. We calculated
total bpd refinery |
51
|
|
|
|
|
production, refinery throughput, and sales volume related to the
Four Corners refineries by dividing by 365 days. |
|
(7) |
|
In September 2010, we temporarily suspended refining operations
at our Yorktown refinery. We calculated Yorktown total bpd
refinery production and refinery throughput by dividing total
volumes by 273 days. Total Yorktown sales volume includes
refined product sales, following the temporary suspension,
through December 31, 2010. We calculated Yorktowns
bpd sales volume by dividing total refinery sales volume by
365 days. |
|
|
|
For our combined refining operating statistics, we calculated
total bpd refinery sales volume, refinery production, refinery
throughput, and refinery product yields by dividing all
refineries operations by 365 days. |
Fiscal
Year Ended December 31, 2010, Compared to Fiscal Year Ended
December 31, 2009
Net Sales. Net sales primarily consist of
gross sales of refined petroleum products, net of customer
rebates, discounts, and excise taxes. Net sales for the year
ended December 31, 2010 were $8,070.1 million,
compared to $6,608.1 million for the year ended
December 31, 2009, an increase of $1,462.0 million, or
22.1%. This increase primarily resulted from an increase in the
average per barrel sales price. The average sales price per
barrel increased from $70.09 in 2009 to $88.87 in 2010. This
increase was partially offset by a decrease in sales volume of
3.5 million barrels, or 3.7%, from 94.3 million
barrels in 2009 to 90.8 million barrels in 2010.
Cost of Products Sold (exclusive of depreciation and
amortization). Cost of products sold primarily
includes cost of crude oil, other feedstocks and blendstocks,
purchased products for resale, and transportation and
distribution costs. Cost of products sold for the year ended
December 31, 2010 was $7,439.8 million, compared to
$5,919.5 million for the year ended December 31, 2009,
an increase of $1,520.3 million, or 25.7%. This increase
was primarily the result of increased average costs of crude
oil. The average cost per barrel increased from $58.49 in 2009
to $77.31 in 2010, an increase of 32.2%. Also contributing to
this increase were increased finished product and blendstock
purchases. Partially offsetting this increase were decreased
crude purchase volumes. During 2010, we purchased
63.4 million barrels of crude oil compared to
69.5 million barrels in 2009, a decrease of 8.8% primarily
related to the temporary suspension of refining operations at
our Yorktown refinery. Refinery gross margin per throughput
barrel increased from $8.74 in 2009 to $8.88 in 2010. Gross
profit per barrel, based on the closest comparable GAAP measure
to refinery gross margin, was $7.21 in 2010 compared to $7.15 in
2009. Cost of products sold for the year ended December 31,
2009 includes $21.7 million in economic hedging losses
previously reported as loss from derivative activities under
other income (expense). The prior year amount was reclassified
to conform to current presentation. Cost of products sold for
the year ended December 31, 2010 includes $9.4 million
in economic hedging losses.
Direct Operating Expenses (exclusive of depreciation and
amortization). Direct operating expenses include
costs associated with the operations of our refineries, such as
energy and utility costs, catalyst and chemical costs, periodic
maintenance, labor, insurance, property taxes, and environmental
compliance costs. Direct operating expenses were
$335.9 million for the year ended December 31, 2010,
compared to $375.7 million for the year ended
December 31, 2009, a decrease of $39.8 million, or
10.6%. This decrease primarily resulted from decreased personnel
costs ($24.9 million), including the reversal of our 2009
incentive bonus accrual in the first quarter of 2010. See
consolidated direct operating expenses (exclusive of
depreciation and amortization) for the fiscal year ended
December 31, 2010 for additional discussion of the bonus
accrual reversal. Also contributing to the decrease were
decreased maintenance expenses ($7.1 million), decreased
chemicals and catalyst purchases ($7.0 million), decreased
electricity expense ($5.7 million), decreased insurance
expense ($3.4 million), decreased outside support services
($2.5 million), and decreased professional, legal, and
other expenses ($2.7 million). Partially offsetting these
decreases were increased environmental expenses
($5.7 million), increased natural gas expense
($5.3 million), and increased property taxes
($4.0 million).
Selling, General, and Administrative
Expenses. Selling, general, and administrative
expenses consist primarily of segment overhead, marketing
expenses, and stock-based compensation. Selling, general, and
administrative expenses were $20.2 million for the year
ended December 31, 2010 compared to $36.0 million for
the year ended December 31, 2009, a decrease of
$15.8 million, or 43.9%. This decrease primarily resulted
from decreases in personnel costs ($6.9 million), including
the reversal of the 2009 incentive bonus accrual in the first
quarter of 2010. See consolidated direct operating expenses
(exclusive of depreciation and amortization) for the fiscal year
52
ended December 31, 2010 for additional discussion of the
bonus accrual reversal. Also contributing to the decrease were
decreased marketing expenses ($2.5 million), decreased
information technology expenses ($1.7 million), decreased
professional, legal, and other expenses ($1.7 million),
decreased bad debt expense ($1.5 million), and decreased
environmental fines and penalties ($1.5 million).
Goodwill and Other Impairment Losses. As a
result of our decision to permanently close our product
distribution terminal in Flagstaff, Arizona during the third
quarter of 2010, we completed an impairment analysis of the
related long-lived assets and determined from this analysis that
impairment existed. Accordingly, we recorded an impairment
charge of $3.8 million primarily related to the Flagstaff
long-lived assets. Also during 2010, we determined the existence
of additional impairment to certain of Bloomfields
refinery assets and recorded a non-cash impairment charge of
$9.1 million. During 2009, we determined that all of the
goodwill in two of our three refining reporting units was fully
impaired. The total impact of this impairment was a non-cash
charge of $230.7 million. Also during 2009, as a result of
our decision to indefinitely suspend the refining operations of
our Bloomfield refinery, we completed an impairment analysis of
the related long-lived and intangible assets and determined that
impairment of certain of the Bloomfield refinery related assets
existed and accordingly recorded a non-cash charge of
$52.8 million related to this impairment.
Maintenance Turnaround Expense. Maintenance
turnaround expense includes planned periodic maintenance and
repairs generally performed every two to six years, depending on
the processing unit involved. During the year ended
December 31, 2010, we incurred costs of $23.3 million
in connection with a turnaround in the first quarter of 2010 at
the El Paso refinery. During the year ended
December 31, 2009, we incurred costs of $2.9 million
in a crude unit shutdown and $4.0 million in connection
with the planned turnaround in the first quarter 2010 at the
El Paso refinery, and $1.2 million related to the
anticipated 2010 turnaround at the Yorktown refinery, which was
subsequently canceled.
Depreciation and Amortization. Depreciation
and amortization for the year ended December 31, 2010 was
$118.7 million, compared to $125.5 million for the
year ended December 31, 2009. The decrease was primarily
due to differences in the timing of various assets reaching the
end of their estimated useful lives.
Operating Income (Loss). Operating income was
$119.5 million for the year ended December 31, 2010,
compared to an operating loss of $140.3 million for the
year ended December 31, 2009, an increase of
$259.8 million. This increase is primarily attributable to
the 2009 goodwill impairment loss and higher 2009 asset
impairment losses compared to 2010, decreased direct operating
and selling, general, and administrative expenses, and decreased
depreciation and amortization expense. These decreases were
partially offset by increased maintenance turnaround expense in
2010 compared to 2009.
Fiscal
Year Ended December 31, 2009, Compared to Fiscal Year Ended
December 31, 2008
Net Sales. Net sales primarily consist of
gross sales of refined petroleum products, net of customer
rebates, discounts, and excise taxes. Net sales for the year
ended December 31, 2009 were $6,608.1 million,
compared to $10,455.6 million for the year ended
December 31, 2008, a decrease of $3,847.5 million, or
36.8%. This decrease primarily resulted from a decrease in the
average price and sales volume of refined products. The average
sales price per barrel decreased from $110.46 in 2008 compared
to $70.09 in 2009. Our sales volume decreased by
0.2 million barrels, or 0.2%, to 94.3 million barrels
for 2009 compared to 94.5 million barrels for 2008. Also
contributing to this decrease was decreased production in the
Four Corners refineries as a result of running less crude oil
($16.1 million).
Cost of Products Sold (exclusive of depreciation and
amortization). Cost of products sold primarily
includes cost of crude oil, other feedstocks and blendstocks,
purchased products for resale, and transportation and
distribution costs. Cost of products sold was
$5,919.5 million for the year ended December 31, 2009,
compared to $9,653.7 million for the year ended
December 31, 2008, a decrease of $3,734.2 million, or
38.7%. This decrease was primarily the result of lower average
costs and volume purchased of crude oil. The average cost per
barrel decreased from $98.86 in 2008 to $58.49 in 2009. During
2009, we purchased 69.5 million barrels of crude oil
compared to 74.6 million barrels in 2008, a decrease of
6.8%. Also contributing to this decrease were decreased finished
product and blendstock purchases and economic hedging losses.
LCM inventory reserve recoveries of $61.0 million decreased
cost of products sold in 2009 compared to 2008 LCM inventory
charges of $61.0 million
53
that increased cost of products sold. These decreases were
partially offset by an increase in the change in our LIFO
reserve. Refinery gross margin per throughput barrel decreased
from $9.65 in 2008 to $8.74 in 2009, reflecting lower refining
margins. Gross profit per barrel, based on the closest
comparable GAAP measure to refinery gross margin, was $7.15 in
2009 compared to $8.50 in 2008. Cost of products sold for the
year ended December 31, 2008 and 2009 includes
$11.4 million in economic hedging gains and
$21.7 million in economic hedging losses, respectively,
previously reported as gain (loss) from derivative activities
under other income (expense). These prior year amounts were
reclassified to conform to the current presentation.
Direct Operating Expenses (exclusive of depreciation and
amortization). Direct operating expenses include
costs associated with the operations of our refineries, such as
energy and utility costs, catalyst and chemical costs, periodic
maintenance, labor, insurance, property taxes, and environmental
compliance costs. Direct operating expenses were
$375.7 million for the year ended December 31, 2009,
compared to $418.6 million for the year ended
December 31, 2008, a decrease of $42.9 million, or
10.2%. This decrease primarily resulted from decreases in
natural gas expense ($18.4 million), environmental expense
primarily resulting from cost recoveries received during 2009
($14.8 million), general maintenance ($9.8 million),
property taxes primarily resulting from tax refunds from prior
years taxes and revisions in property tax appraisal rolls
($6.0 million), outside support services
($2.8 million), insurance expense ($2.5 million),
facilities leases ($1.7 million), and equipment rental
($1.5 million). These decreases were partially offset by
increased chemicals and catalyst ($4.4 million), personnel
costs ($4.3 million), electricity expenses
($3.3 million), and increased professional fees
($1.4 million).
Selling, General, and Administrative
Expenses. Selling, general, and administrative
expenses consist primarily of segment overhead, marketing
expenses, and stock-based compensation. Selling, general, and
administrative expenses were $36.0 million for the year
ended December 31, 2009, compared to $37.6 million for
the year ended December 31, 2008, a decrease of
$1.6 million, or 4.3%. This decrease resulted from
decreased professional and legal fees ($7.1 million). This
decrease was partially offset by increases in marketing expenses
($2.1 million), environmental penalties
($1.5 million), and bad debt expense ($1.6 million).
Goodwill and Other Impairment Losses. During
2009, we determined that all of the goodwill in two of our three
refining reporting units was fully impaired. The total impact of
this impairment was a non-cash charge of $230.7 million.
Also during 2009, as a result of our decision to indefinitely
suspend the refining operations of our Bloomfield refinery, we
completed an impairment analysis of the related long-lived and
intangible assets. We determined that impairment of certain of
the Bloomfield refinery related assets existed and accordingly
recorded a non-cash charge of $52.8 million related to this
impairment. No impairment losses were recorded in 2008.
Maintenance Turnaround Expense. Maintenance
turnaround expense includes periodic maintenance and repairs
generally performed every two to six years, depending on the
processing unit involved. During the year ended
December 31, 2009, we incurred costs of $2.9 million
in a crude unit shutdown and $4.0 million in connection
with the planned turnaround in the first quarter of 2010 at the
El Paso refinery, and $1.2 million in anticipation of
a turnaround previously scheduled for the fall of 2010 at the
Yorktown refinery. During the year ended December 31, 2008,
we performed a maintenance turnaround at the north side of the
El Paso refinery at a cost of $28.9 million.
Depreciation and Amortization. Depreciation
and amortization for the year ended December 31, 2009 was
$125.5 million, compared to $95.7 million for the year
ended December 31, 2008. The increase was primarily due to
the completion of several projects including the FCC
hydrotreater, the sour water stripper, and a new laboratory at
the El Paso refinery; the gasoline desulfurization project
at the Yorktown refinery; and various other capital projects at
our refineries.
Operating Income (Loss). Operating loss was
$140.3 million for the year ended December 31, 2009,
compared to operating income of $221.1 million for the year
ended December 31, 2008, a decrease of $361.4 million.
This decrease primarily is attributable to an asset impairment
loss recorded in the fourth quarter of 2009 related to the
suspension of refining activities at the Bloomfield refinery and
a goodwill impairment loss recorded in the second quarter of
2009, increased depreciation and amortization expense, and
decreased refinery gross margins in 2009 compared to 2008.
54
Wholesale
Segment
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands, except per gallon data)
|
|
|
Statement of Operations Data
|
|
|
|
|
|
|
|
|
|
|
|
|
Net sales (including intersegment sales)
|
|
$
|
2,470,586
|
|
|
$
|
1,664,397
|
|
|
$
|
2,279,541
|
|
Operating costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of products sold (exclusive of depreciation amortization)
|
|
|
2,383,931
|
|
|
|
1,579,910
|
|
|
|
2,168,707
|
|
Direct operating expenses (exclusive of depreciation and
amortization)
|
|
|
48,222
|
|
|
|
51,775
|
|
|
|
64,273
|
|
Selling, general, and administrative expenses
|
|
|
12,638
|
|
|
|
16,566
|
|
|
|
18,915
|
|
Goodwill impairment loss
|
|
|
|
|
|
|
41,230
|
|
|
|
|
|
Depreciation and amortization
|
|
|
5,069
|
|
|
|
5,616
|
|
|
|
5,551
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating costs and expenses
|
|
|
2,449,860
|
|
|
|
1,695,097
|
|
|
|
2,257,446
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss)
|
|
$
|
20,726
|
|
|
$
|
(30,700
|
)
|
|
$
|
22,095
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Data
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel gallons sold (in thousands)
|
|
|
1,009,786
|
|
|
|
823,207
|
|
|
|
706,864
|
|
Fuel margin per gallon(1)
|
|
$
|
0.07
|
|
|
$
|
0.07
|
|
|
$
|
0.09
|
|
Lubricant sales
|
|
$
|
102,200
|
|
|
$
|
111,193
|
|
|
$
|
163,679
|
|
Lubricant margin(2)
|
|
|
11.5
|
%
|
|
|
9.6
|
%
|
|
|
12.4
|
%
|
|
|
|
(1) |
|
Fuel margin per gallon is a measurement calculated by dividing
the difference between fuel sales and cost of fuel sales for our
wholesale segment by the number of gallons sold. Fuel margin per
gallon is a measure frequently used in the petroleum products
wholesale industry to measure operating results related to fuel
sales. |
|
(2) |
|
Lubricant margin is a measurement calculated by dividing the
difference between lubricant sales and lubricant cost of
products sold by lubricant sales. Lubricant margin is a measure
frequently used in the petroleum products wholesale industry to
measure operating results related to lubricant sales. |
The following table reconciles fuel sales and cost of fuel sales
to net sales and cost of products sold:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands, except per gallon data)
|
|
|
Net sales:
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel sales (including intersegment sales)
|
|
$
|
2,588,628
|
|
|
$
|
1,749,431
|
|
|
$
|
2,269,203
|
|
Excise taxes included in fuel sales
|
|
|
(250,550
|
)
|
|
|
(224,771
|
)
|
|
|
(193,634
|
)
|
Lubricant sales
|
|
|
102,200
|
|
|
|
111,193
|
|
|
|
163,679
|
|
Other sales (including intersegment sales)
|
|
|
30,308
|
|
|
|
28,544
|
|
|
|
40,293
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net sales
|
|
$
|
2,470,586
|
|
|
$
|
1,664,397
|
|
|
$
|
2,279,541
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of products sold:
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel cost of products sold
|
|
$
|
2,527,758
|
|
|
$
|
1,692,177
|
|
|
$
|
2,205,548
|
|
Excise taxes included in fuel sales
|
|
|
(250,550
|
)
|
|
|
(224,771
|
)
|
|
|
(193,634
|
)
|
Lubricant cost of products sold
|
|
|
90,411
|
|
|
|
100,567
|
|
|
|
143,317
|
|
Other cost of products sold
|
|
|
16,312
|
|
|
|
11,937
|
|
|
|
13,476
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of products sold
|
|
$
|
2,383,931
|
|
|
$
|
1,579,910
|
|
|
$
|
2,168,707
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel margin per gallon
|
|
$
|
0.07
|
|
|
$
|
0.07
|
|
|
$
|
0.09
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
55
Fiscal
Year Ended December 31, 2010, Compared to Fiscal Year Ended
December 31, 2009
Net Sales. Net sales consist primarily of
sales of refined products net of excise taxes, lubricants, and
freight. Net sales for the year ended December 31, 2010
were $2,470.6 million compared to $1,664.4 million for
the year ended December 31, 2009, an increase of
$806.2 million, or 48.4%. This increase was primarily due
to an increase in the sales price of refined products, increased
fuel sales volume, and increased freight billed. The average
sales price per gallon of refined products increased from $2.13
in 2009 to $2.56 in 2010. Fuel sales volume increased from
823.2 million gallons in 2009 to 1,009.8 million
gallons in 2010. Fuel sales volume for the year ended
December 31, 2010 included 113.0 million gallons sold
to our Retail group without comparable wholesale sales for the
same period during 2009. During 2009, such sales of fuel were
reported under our Refining group. This increase was partially
offset by a decrease in lubricant sales volume. Lubricant sales
volume decreased from 11.8 million gallons in 2009 to
10.7 million gallons in 2010.
Cost of Products Sold (exclusive of depreciation and
amortization). Cost of products sold includes
costs of refined products net of excise taxes, lubricants, and
delivery freight. Cost of products sold was
$2,383.9 million for the year ended December 31, 2010,
compared to $1,579.9 million for the year ended
December 31, 2009, an increase of $804.0 million, or
50.9%. This increase was primarily due to increased delivery
freight expenses and costs of refined products and purchased
fuel volume. The average cost per gallon increased from $2.06 in
2009 to $2.50 in 2010. This increase was partially offset by a
decrease in the purchased volume of lubricants.
Direct Operating Expenses (exclusive of depreciation and
amortization). Direct operating expenses include
costs associated with the operations of our wholesale division
such as labor, repairs and maintenance, rentals and leases,
insurance, property taxes, and environmental compliance costs.
Direct operating expenses were $48.2 million for the year
ended December 31, 2010, compared to $51.8 million for
the year ended December 31, 2009, a decrease of
$3.6 million, or 6.9%. This decrease primarily resulted
from decreases in personnel costs ($6.1 million). This
decrease was partially offset by increased vehicle fuel costs
($1.8 million) and repairs and maintenance
($0.7 million).
Selling, General, and Administrative
Expenses. Selling, general, and administrative
expenses consist primarily of overhead and marketing expenses.
Selling, general, and administrative expenses were
$12.6 million in December 31, 2010, compared to
$16.6 million for the year ended December 31, 2009, a
decrease of $4.0 million, or 24.1%. This decrease primarily
resulted from decreases in personnel costs ($2.6 million),
taxes, licenses, and fees ($0.3 million), outside services
($0.2 million), and bank fees ($0.2 million).
Goodwill Impairment Loss. During 2009, we
determined that all of the goodwill in our wholesale reporting
unit was fully impaired. The total impact of the goodwill
impairment for the year ended December 31, 2009 was a
non-cash charge of $41.2 million. No impairment losses were
recorded in 2010.
Depreciation and Amortization. Depreciation
and amortization was $5.1 million for the year ended
December 31, 2010, compared to $5.6 million for the
year ended December 31, 2009, a decrease of
$0.5 million, or 8.9%.
Operating Income (Loss). Operating income for
the year ended December 31, 2010 was $20.7 million
compared to an operating loss of $30.7 million for the year
ended December 31, 2009, an increase of $51.4 million.
This increase primarily resulted from a goodwill impairment loss
in 2009, decreased direct operating expenses, decreased selling,
general, and administrative expenses, and increased fuel and
lubricant margins for the year ended December 31, 2010
compared to the same period in 2009.
Fiscal
Year Ended December 31, 2009, Compared to Fiscal Year Ended
December 31, 2008
Net Sales. Net sales consist primarily of
sales of refined products net of excise taxes, lubricants, and
freight. Net sales for the year ended December 31, 2009,
were $1,664.4 million, compared to $2,279.5 million
for the year ended December 31, 2008, a decrease of
$615.1 million, or 27.0%. This decrease was primarily due
to a decrease in the sales price of refined products and
decreased sales volume of lubricants. The average sales price
per gallon of refined products decreased from $3.21 in 2008 to
$2.13 in 2009. Lubricant sales volume decreased from
17.0 million gallons in 2008 to 11.8 million gallons
for the same period in 2009. This decrease was partially offset
by increased fuel volumes sold.
56
Cost of Products Sold (exclusive of depreciation and
amortization). Cost of products sold includes
costs of refined products net of excise taxes, lubricants, and
delivery freight. Cost of products sold was
$1,579.9 million for the year ended December 31, 2009,
compared to $2,168.7 million for the year ended
December 31, 2008, a decrease of $588.8 million, or
27.2%. This decrease was primarily due to decreased costs of
refined products and decreased purchased volume of lubricants.
The average cost per gallon decreased from $3.12 in 2008 to
$2.06 in 2009. This decrease was partially offset by increased
fuel volumes purchased.
Direct Operating Expenses (exclusive of depreciation and
amortization). Direct operating expenses include
costs associated with the operations of our wholesale division
such as labor, repairs and maintenance, rentals and leases,
insurance, property taxes, and environmental compliance costs.
Direct operating expenses were $51.8 million for the year
ended December 31, 2009, compared to $64.3 million for
the year ended December 31, 2008, a decrease of
$12.5 million, or 19.4%. This decrease primarily resulted
from decreases in fuel expense ($6.7 million), repairs and
maintenance ($2.7 million), vehicle licenses and permits
($0.7 million), outside maintenance services
($0.7 million), trailer leases ($0.6 million), and
utilities ($0.6 million).
Selling, General, and Administrative
Expenses. Selling, general, and administrative
expenses consist primarily of overhead and marketing expenses.
Selling, general, and administrative expenses were
$16.6 million for the year ended December 31, 2009,
compared to $18.9 million for the year ended
December 31, 2008, a decrease of $2.3 million, or
12.2%. This decrease primarily resulted from decreases in
personnel costs ($1.2 million), outside services
($0.5 million), utilities ($0.4 million), repairs and
maintenance ($0.3 million), administration supplies
($0.3 million), and bank fees ($0.3 million). These
decreases were partially offset by an increase in bad debt
expense ($0.8 million).
Goodwill Impairment Loss. During 2009, we
determined that all of the goodwill in our wholesale reporting
unit was fully impaired. The total impact of the goodwill
impairment for the year ended December 31, 2009 was a
non-cash charge of $41.2 million. No impairment losses were
recorded in 2008.
Depreciation and Amortization. Depreciation
and amortization was $5.6 million for the years ended
December 31, 2009 and 2008.
Operating Income (Loss). Operating loss for
the year ended December 31, 2009, was $30.7 million,
compared to operating income of $22.1 million for the year
ended December 31, 2008, a decrease of $52.8 million.
This decrease primarily resulted from a goodwill impairment loss
and decreased lubricant and fuel margins for the year ended
December 31, 2009 compared to the same period in 2008.
These decreases were partially offset by decreased direct
operating expenses and decreased selling, general, and
administrative expenses.
57
Retail
Segment
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands, except per gallon data)
|
|
|
Statement of Operations Data
|
|
|
|
|
|
|
|
|
|
|
|
|
Net sales (including intersegment sales)
|
|
$
|
718,369
|
|
|
$
|
629,938
|
|
|
$
|
838,197
|
|
Operating costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of products sold (exclusive of depreciation and
amortization)
|
|
|
619,674
|
|
|
|
533,481
|
|
|
|
744,691
|
|
Direct operating expenses (exclusive of depreciation and
amortization)
|
|
|
66,997
|
|
|
|
64,979
|
|
|
|
65,604
|
|
Selling, general, and administrative expenses
|
|
|
5,095
|
|
|
|
6,216
|
|
|
|
5,301
|
|
Goodwill impairment loss
|
|
|
|
|
|
|
27,610
|
|
|
|
|
|
Depreciation and amortization
|
|
|
10,245
|
|
|
|
9,820
|
|
|
|
8,479
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating costs and expenses
|
|
|
702,011
|
|
|
|
642,106
|
|
|
|
824,075
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss)
|
|
$
|
16,358
|
|
|
$
|
(12,168
|
)
|
|
$
|
14,122
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Data
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel gallons sold (in thousands)
|
|
|
207,303
|
|
|
|
205,532
|
|
|
|
210,401
|
|
Fuel margin per gallon(1)
|
|
$
|
0.19
|
|
|
$
|
0.18
|
|
|
$
|
0.18
|
|
Merchandise sales
|
|
$
|
191,324
|
|
|
$
|
189,096
|
|
|
$
|
185,712
|
|
Merchandise margin(2)
|
|
|
28.5
|
%
|
|
|
28.4
|
%
|
|
|
27.4
|
%
|
Operating retail outlets at period end
|
|
|
150
|
|
|
|
149
|
|
|
|
155
|
|
|
|
|
(1) |
|
Fuel margin per gallon is a measurement calculated by dividing
the difference between fuel sales and cost of fuel sales for our
retail segment by the number of gallons sold. Fuel margin per
gallon is a measure frequently used in the retail industry to
measure operating results related to fuel sales. |
|
(2) |
|
Merchandise margin is a measurement calculated by dividing the
difference between merchandise sales and merchandise cost of
products sold by merchandise sales. Merchandise margin is a
measure frequently used in the convenience store industry to
measure operating results related to merchandise sales. |
|
|
|
The following table reconciles fuel sales and cost of fuel sales
to net sales and cost of products sold: |
58
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands, except per gallon data)
|
|
|
Net sales:
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel sales (including intersegment sales)
|
|
$
|
582,688
|
|
|
$
|
489,033
|
|
|
$
|
694,891
|
|
Excise taxes included in fuel revenues
|
|
|
(79,639
|
)
|
|
|
(71,998
|
)
|
|
|
(66,736
|
)
|
Merchandise sales
|
|
|
191,324
|
|
|
|
189,096
|
|
|
|
185,712
|
|
Other sales
|
|
|
23,996
|
|
|
|
23,807
|
|
|
|
24,330
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net sales
|
|
$
|
718,369
|
|
|
$
|
629,938
|
|
|
$
|
838,197
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of products sold:
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel cost of products sold
|
|
$
|
543,916
|
|
|
$
|
451,485
|
|
|
$
|
657,537
|
|
Excise taxes included in fuel cost of products sold
|
|
|
(79,639
|
)
|
|
|
(71,998
|
)
|
|
|
(66,736
|
)
|
Merchandise cost of products sold
|
|
|
136,855
|
|
|
|
135,459
|
|
|
|
134,821
|
|
Other cost of products sold
|
|
|
18,542
|
|
|
|
18,535
|
|
|
|
19,069
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of products sold
|
|
|
619,674
|
|
|
|
533,481
|
|
|
|
744,691
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel margin per gallon
|
|
$
|
0.19
|
|
|
$
|
0.18
|
|
|
$
|
0.18
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fiscal
Year Ended December 31, 2010, Compared to Fiscal Year Ended
December 31, 2009
Net Sales. Net sales consist primarily of
gross sales of gasoline and diesel fuel net of excise taxes,
general merchandise, and beverage and food products. Net sales
for the year ended December 31, 2010 were
$718.4 million, compared to $629.9 million for the
year ended December 31, 2009, an increase of
$88.5 million, or 14.0%. This increase was primarily due to
an increase in the sales price of gasoline and diesel fuel. The
average sales price per gallon, including excise taxes,
increased from $2.38 in 2009 to $2.81 in 2010.
Cost of Products Sold (exclusive of depreciation and
amortization). Cost of products sold includes
costs of gasoline and diesel fuel net of excise taxes, general
merchandise, and beverage and food products. Cost of products
sold was $619.7 million for the year ended
December 31, 2010, compared to $533.5 million for the
year ended December 31, 2009, an increase of
$86.2 million, or 16.2%. This increase was primarily due to
increased costs of gasoline and diesel fuel. Average fuel cost
per gallon, including excise taxes, increased from $2.20 in 2009
to $2.62 in 2010.
Direct Operating Expenses (exclusive of depreciation and
amortization). Direct operating expenses include
costs associated with the operations of our retail division such
as labor, repairs and maintenance, rentals and leases,
insurance, property taxes, and environmental compliance costs.
Direct operating expenses were $67.0 million for the year
ended December 31, 2010, compared to $65.0 million for
the year ended December 31, 2009, an increase of
$2.0 million, or 3.1%. This increase was primarily due to
increased bank fees primarily related to credit card sales
($1.8 million).
Selling, General, and Administrative
Expenses. Selling, general, and administrative
expenses consist primarily of overhead and marketing expenses.
Selling, general, and administrative expenses were
$5.1 million for the year ended December 31, 2010,
compared to $6.2 million for the year ended
December 31, 2009, a decrease of $1.1 million, or
17.7%. This decrease was primarily due to decreased personnel
costs ($0.6 million), insurance expense
($0.3 million), and environmental expense
($0.2 million).
Goodwill Impairment Loss. During 2009, we
determined that all of the goodwill in our retail reporting unit
was fully impaired. The total impact of the goodwill impairment
for the year ended December 31, 2009 was a non-cash charge
of $27.6 million. No impairment losses were recorded in
2010.
Depreciation and Amortization. Depreciation
and amortization for the year ended December 31, 2010 was
$10.2 million compared to $9.8 million for the year
ended December 31, 2009, an increase of $0.4 million,
or 4.1%.
59
Operating Income (Loss). Operating income for
the year ended December 31, 2010 was $16.4 million
compared to an operating loss of $12.2 million for the year
ended December 31, 2009, an increase of $28.6 million.
This increase was primarily due to a goodwill impairment charge
in 2009.
Fiscal
Year Ended December 31, 2009, Compared to Fiscal Year Ended
December 31, 2008
Net Sales. Net sales consist primarily of
gross sales of gasoline and diesel fuel net of excise taxes,
general merchandise, and beverage and food products. Net sales
for the year ended December 31, 2009, were
$629.9 million, compared to $838.2 million for the
year ended December 31, 2008, a decrease of
$208.3 million, or 24.9%. This decrease was primarily due
to a decrease in the sales price of gasoline and diesel fuel.
The average sales price per gallon decreased from $3.30 in 2008
to $2.38 in 2009. This decrease was partially offset by
increased merchandise sales.
Cost of Products Sold (exclusive of depreciation and
amortization). Cost of products sold includes
costs of gasoline and diesel fuel net of excise taxes, general
merchandise, and beverage and food products. Cost of products
sold was $533.5 million for the year ended
December 31, 2009, compared to $744.7 million for the
year ended December 31, 2008, a decrease of
$211.2 million, or 28.4%. This decrease was primarily due
to decreased costs of gasoline and diesel fuel. Average fuel
cost per gallon decreased from $3.13 in 2008 to $2.20 in 2009.
Direct Operating Expenses (exclusive of depreciation and
amortization). Direct operating expenses include
costs associated with the operations of our retail division such
as labor, repairs and maintenance, rentals and leases,
insurance, property taxes, and environmental compliance costs.
Direct operating expenses were $65.0 million for the year
ended December 31, 2009, compared to $65.6 million for
the year ended December 31, 2008, a decrease of
$0.6 million, or 0.9%.
Selling, General, and Administrative
Expenses. Selling, general, and administrative
expenses consist primarily of overhead and marketing expenses.
Selling, general, and administrative expenses were
$6.2 million for the year ended December 31, 2009,
compared to $5.3 million for the year ended
December 31, 2008, an increase of $0.9 million, or
17.0%.
Goodwill Impairment Loss. During 2009, we
determined that all of the goodwill in our retail reporting unit
was impaired. The total impact of the goodwill impairment for
the year ended December 31, 2009 was a non-cash charge of
$27.6 million. No impairment losses were recorded in 2008.
Depreciation and Amortization. Depreciation
and amortization for the year ended December 31, 2009, was
$9.8 million, compared to $8.5 million for the year
ended December 31, 2008, an increase of $1.3 million,
or 15.3%.
Operating Income (Loss). Operating loss for
the year ended December 31, 2009, was $12.2 million,
compared to operating income of $14.1 million for the year
ended December 31, 2008, a decrease of $26.3 million.
This decrease was primarily due to a goodwill impairment loss.
This decrease was partially offset by higher merchandise and
fuel margins for the year ended December 31, 2009, compared
to the same period in 2008.
Outlook
The weak global economy over the past two years has resulted in
decreased demand for refined products. The decreased demand
along with narrowing differentials between light and heavy crude
oil prices negatively impacted our refining margins through the
first quarter of 2010 and all of 2009. Beginning in the second
quarter of 2010, our refining margins improved due to increased
demand, primarily for diesel fuel. During the early part of
2011, our refining margins have continued to strengthen,
partially due to increased gasoline crack spreads as we approach
the spring 2011 driving season, continued strong diesel demand,
and a supply/demand imbalance of WTI crude oil in the
Mid-Continent, resulting in historically low prices for WTI
crude oil relative to Brent crude oil. This is a positive
development for us as all of our crude oil purchases are based
on pricing tied to WTI.
60
Liquidity
and Capital Resources
Cash
Flows
The following table sets forth our cash flows for the periods
indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands)
|
|
|
Cash flows provided by operating activities
|
|
$
|
134,456
|
|
|
$
|
140,841
|
|
|
$
|
285,575
|
|
Cash flows used in investing activities
|
|
|
(73,777
|
)
|
|
|
(115,361
|
)
|
|
|
(220,554
|
)
|
Cash flows used in financing activities
|
|
|
(75,657
|
)
|
|
|
(30,407
|
)
|
|
|
(274,769
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net decrease in cash and cash equivalents
|
|
$
|
(14,978
|
)
|
|
$
|
(4,927
|
)
|
|
$
|
(209,748
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
Flows Provided By Operating Activities
Net cash provided by operating activities for the year ended
December 31, 2010 was $134.5 million. The most
significant providers of cash were adjustments to net loss for
non-cash items such as depreciation and amortization
($138.6 million), amortization of original issue discount
($15.9 million), impairment losses ($13.0 million),
amortization of loan fees ($9.7 million), and stock-based
compensation ($5.9 million). The most significant users of
cash were a net cash outflow from a change in operating assets
and liabilities ($14.8 million), deferred income taxes
($16.8 million), and our net loss ($17.0 million).
Net cash provided by operating activities for the year ended
December 31, 2009 was $140.8 million. The most
significant providers of cash were adjustments to net loss for
non-cash items such as goodwill and other impairment losses
($352.3 million), depreciation and amortization
($146.0 million), deferred income taxes
($9.4 million), the write-off of unamortized loan fees
($9.0 million), amortization of original issue discount
($7.1 million), amortization of loan fees
($6.9 million), and stock-based compensation
($4.7 million). The most significant users of cash were our
net loss ($350.6 million), and a net cash outflow from a
change in operating assets and liabilities ($44.0 million).
Net cash provided by operating activities for the year ended
December 31, 2008 was $285.6 million. The most
significant providers of cash were our net income
($64.2 million), adjustments to net income for non-cash
items such as depreciation and amortization
($113.6 million), the write-off of unamortized loan fees
($10.9 million), deferred income taxes
($14.1 million), stock-based compensation
($7.7 million), and amortization of loan fees
($4.8 million). Also contributing to our cash flows from
operating activities was a net cash inflow from a change in
operating assets and liabilities ($70.3 million).
Cash
Flows Used In Investing Activities
Net cash used in investing activities for the year ended
December 31, 2010 was $73.8 million, mainly relating
to capital expenditures of $78.1 million, including
capitalized interest of $4.2 million. Total capital
spending for 2010, excluding capitalized interest, included
spending on the Mobile Source Air Toxics II, or MSAT II, project
($42.5 million), other improvement projects at our
El Paso refinery ($5.7 million), and several other
improvement and regulatory projects primarily at our Gallup and
Yorktown refineries ($19.4 million). In addition, our
capital spending included projects for our retail group
($4.9 million), our wholesale group ($0.7 million),
and general corporate spending ($0.7 million).
Net cash used in investing activities for the year ended
December 31, 2009 was $115.4 million, mainly relating
to capital expenditures, including capitalized interest of
$6.4 million. Capital spending for 2009, excluding
capitalized interest, included spending on the low sulfur
gasoline project ($41.3 million), the MSAT project
($19.5 million), improvement projects in conjunction with
the 2010 maintenance turnaround ($6.4 million), the diesel
hydrotreater unit revamp project ($3.9 million), and amine
unit upgrade ($3.3 million) at our El Paso refinery;
coker unit upgrades ($5.9 million), the MSAT project
($4.5 million), and the crude unit yield improvement
project ($1.5 million) at our Yorktown refinery; and
several other improvement and regulatory projects for our
refining
61
group ($17.6 million). In addition, our total capital
spending included projects for our retail group
($3.4 million), our corporate group ($1.4 million),
and our wholesale group ($0.9 million).
Net cash used in investing activities for the year ended
December 31, 2008 was $220.6 million, mainly relating
to capital expenditures, including capitalized interest of
$9.9 million. Capital spending for 2008, excluding
capitalized interest, included spending on the low sulfur
gasoline project ($99.4 million), improvement projects in
conjunction with the 2008 maintenance turnaround
($22.7 million), the naphtha hydrotreating unit
($8.6 million), the construction of a new laboratory
($5.1 million), and the acid and sulfur gas facilities
($1.2 million) at our El Paso refinery; the low sulfur
gasoline project ($23.4 million), improvements to the
laboratory and fire station ($2.4 million), the ultraformer
blowdown stack ($2.3 million), and coker unit electrical
infrastructure ($1.9 million) at our Yorktown refinery; and
several other improvement and regulatory projects for our
refining group ($25.0 million). In addition, our total
capital spending included projects for our retail group
($7.9 million), our corporate group ($6.8 million),
and our wholesale group ($5.7 million).
Cash
Flows Used In Financing Activities
Net cash used in financing activities for the year ended
December 31, 2010 was $75.7 million. Cash used in
financing activities for 2010 included a net decrease to our
Revolving Credit Agreement ($50.0 million), principal
payments on our Term Loan ($13.0 million), and deferred
financing costs ($12.7 million).
Net cash used in financing activities for the year ended
December 31, 2009 was $30.4 million. Cash used in
financing activities for 2009 included principal payments on our
Term Loan ($925.7 million), deferred financing costs
($11.7 million), a net decrease to our Revolving Credit
Agreement ($10.0 million), and the repurchases of common
stock ($0.6 million) to cover payroll withholding taxes for
certain employees in connection with the vesting of restricted
shares awarded under the Western Refining Long-Term Incentive
Plan. These decreases in cash were significantly offset by the
net proceeds from the issuance of our Senior Secured Notes
($538.2 million), our Convertible Senior Notes
($209.0 million), and common stock ($170.4 million).
Net cash used in financing activities for the year ended
December 31, 2008 was $274.8 million. Cash used in
financing activities for 2008 included a net decrease to our
Revolving Credit Agreement ($230.0 million), deferred
financing costs ($22.4 million), principal payments on our
Term Loan ($13.0 million), dividends paid
($8.2 million), and the repurchases of common stock
($1.2 million) to cover payroll withholding taxes for
certain employees in connection with the vesting of restricted
shares awarded under the Western Refining Long-Term Incentive
Plan.
Working
Capital
Our primary sources of liquidity are cash generated from our
operating activities, existing cash balances, and our Revolving
Credit Agreement. Our ability to generate sufficient cash flows
from our operating activities will continue to be primarily
dependent on producing or purchasing, and selling, sufficient
quantities of refined products at margins sufficient to cover
fixed and variable expenses. The improved refining margin
environment during 2010, compared to the fourth quarter of 2009,
positively impacted our earnings and cash flows. Our refining
gross margin increased from $5.35 per throughput barrel in the
fourth quarter of 2009 to $8.88 per throughput barrel for the
year ended December 31, 2010. Refining margins were
extremely volatile throughout 2009. For example, our refining
margin per throughput barrel decreased from $13.59 in the first
quarter of 2009 to $9.47, $7.28, and $5.35 in the second, third,
and fourth quarters of 2009, respectively. These changes in
refining margins are attributable to the spread between crude
oil and refined product prices. If our margins deteriorate
significantly, or if our earnings and cash flows suffer for any
other reason, we could be unable to comply with the financial
covenants set forth in our credit facilities (described below).
If we fail to satisfy these covenants, we could be prohibited
from borrowing for our working capital needs and issuing letters
of credit, which would hinder our ability to purchase sufficient
quantities of crude oil to operate our refineries at planned
rates. To the extent that we are unable to generate sufficient
cash flows from operations, or if we are unable to borrow or
issue letters of credit under the revolving credit facility, we
would need to seek additional financing, if available, in order
to operate our business.
We continually evaluate additional alternatives to further
improve our capital structure by increasing our cash balances
and/or
reducing or refinancing a portion of the remaining balance on
our Term Loan. These alternatives include various strategic
initiatives and potential asset sales as well as potential
public or private equity or debt
62
financings. If additional funds are obtained by issuing equity
securities, our existing stockholders could be diluted. We can
give no assurances that we will be able to sell any of our
assets or to obtain additional financing on terms acceptable to
us, or at all.
In addition, our future capital expenditures and other cash
requirements could be higher than we currently expect as a
result of various factors described in
Part I. Item 1A. Risk Factors
elsewhere in this report.
Working capital at December 31, 2010 was
$272.7 million, consisting of $825.7 million in
current assets and $553.0 million in current liabilities.
Working capital at December 31, 2009 was
$311.3 million consisting of $944.2 million in current
assets and $632.9 million in current liabilities. In
addition, at December 31, 2010, the gross availability
under the Revolving Credit Agreement was $624.0 million
determined based on an advance rate formula tied to our accounts
receivable and inventory levels. As of December 31, 2010,
we had net availability under the Revolving Credit Agreement of
$335.6 million due to $288.4 million in letters of
credit outstanding and no outstanding borrowings. On
February 25, 2011, the gross availability under the
Revolving Credit Agreement was $650.3 million pursuant to
the borrowing base. On February 25, 2011, we had net
availability under the Revolving Credit Agreement of
$192.3 million due to $273.0 million in letters of
credit outstanding and $185.0 million in direct borrowings.
Our available cash balance as of February 25, 2011 was
$39.1 million.
Indebtedness
Senior Secured Notes. In June 2009, we issued
two tranches of Senior Secured Notes under an indenture dated
June 12, 2009. The first tranche consisted of
$325.0 million in aggregate principal amount of
11.25% Senior Secured Notes (the Fixed Rate
Notes). The second tranche consisted of
$275.0 million Senior Secured Floating Rate Notes (the
Floating Rate Notes, and together with the Fixed
Rate Notes, the Senior Secured Notes). The Fixed
Rate Notes pay interest semi-annually in cash in arrears on June
15 and December 15 of each year at a rate of 11.25% per annum
and will mature on June 15, 2017. We may redeem the Fixed
Rate Notes at our option beginning on June 15, 2013 through
June 14, 2014 at a premium of 5.625%; from June 15,
2014 through June 14, 2015 at a premium of 2.813%; and at
par thereafter. As of December 31, 2010, the fair value of
the Fixed Rate Notes was $347.8 million.
The Floating Rate Notes pay interest quarterly at a per annum
rate, reset quarterly, equal to three-month LIBOR (subject to a
LIBOR floor of 3.25%) plus 7.50% and will mature on
June 15, 2014. The interest rate on the Floating Rate Notes
as of December 31, 2010 was 10.75%. We may redeem the
Floating Rate Notes at our option beginning on December 15,
2011 through June 14, 2012 at a premium of 5.0%; from
June 15, 2012 through June 14, 2013 at a premium of
3.0%; and at a premium of 1.0% thereafter. The fair value of the
Floating Rate Notes was $291.5 million at December 31,
2010. We are amortizing the original issue discounts using the
effective interest rate method over the life of the notes. We
used the combined proceeds from the issuance and sale of the
Senior Secured Notes to repay a portion of the outstanding
indebtedness under the Term Loan Credit Agreement (Term
Loan). Proceeds from the issuance of the Fixed Rate Notes
were $290.7 million, net of an original issue discount of
$27.8 million and underwriting discounts of
$6.5 million. Proceeds from the issuance of the Floating
Rate Notes were $247.5 million, net of original issue
discount of $22.0 million and underwriting discounts of
$5.5 million. We paid $2.1 million in other financing
costs related to the Senior Secured Notes in 2009.
The Senior Secured Notes are guaranteed by all of our domestic
restricted subsidiaries in existence on the date the Senior
Secured Notes were issued. The Senior Secured Notes will also be
guaranteed by all future wholly-owned domestic restricted
subsidiaries and by any restricted subsidiary that guarantees
any of our indebtedness under credit facilities that are secured
by a lien on the collateral securing the Senior Secured Notes.
The Senior Secured Notes are also secured on a first priority
basis, equally and ratably with our Term Loan and any future
other pari passu secured obligation, by the collateral securing
the Term Loan, which consists of our fixed assets, and on a
second priority basis, equally and ratably with the Term Loan
and any future other pari passu secured obligation, by the
collateral securing the Revolving Credit Agreement, which
consists of our cash and cash equivalents, trade accounts
receivables, and inventory.
The indenture governing the Senior Secured Notes contains
covenants that limit our (and most of our subsidiaries)
ability to, among other things: (i) pay dividends or make
other distributions in respect of our capital stock or make
other restricted payments; (ii) make certain investments;
(iii) sell certain assets; (iv) incur additional
63
debt or issue certain preferred shares; (v) create liens on
certain assets to secure debt; (vi) consolidate, merge,
sell or otherwise dispose of all or substantially all of our
assets; (vii) restrict dividends or other payments from
restricted subsidiaries; and (viii) enter into certain
transactions with our affiliates. These covenants are subject to
a number of important limitations and exceptions. The indenture
governing the Senior Secured Notes also provides for events of
default, which, if any of them occur, would permit or require
the principal, premium, if any, and interest on all then
outstanding Senior Secured Notes to be due and payable
immediately.
We may issue additional notes from time to time pursuant to the
indenture governing the Senior Secured Notes.
Convertible Senior Notes. We issued and sold
$215.5 million in aggregate principal amount of our
5.75% Senior Convertible Notes due 2014 (the
Convertible Senior Notes) during June and July 2009.
The Convertible Senior Notes are unsecured and pay interest
semi-annually in arrears at a rate of 5.75% per year beginning
on December 15, 2009. The Convertible Senior Notes will
mature on June 15, 2014. The initial conversion rate for
the Convertible Senior Notes is 92.5926 shares of common
stock per $1,000 principal amount of Convertible Senior Notes
(equivalent to an initial conversion price of approximately
$10.80 per share of common stock). In lieu of delivery of shares
of common stock in satisfaction of our obligation upon
conversion of the Convertible Senior Notes, we may elect to
settle conversions entirely in cash or by net share settlement.
Proceeds from the issuance of the Convertible Senior Notes of
$209.0 million, net of underwriting discounts of
$6.5 million, were used to repay a portion of outstanding
indebtedness under the Term Loan. Issuers of convertible debt
instruments that may be settled in cash upon conversion
(including partial cash settlement) are required to separately
account for the liability and equity (conversion feature)
components of the instruments in a manner reflective of the
issuers nonconvertible debt borrowing rate. The borrowing
rate that we used to determine the liability and equity
components of the Convertible Senior Notes was 13.75%. We paid
$0.5 million in other financing costs related to the
Convertible Senior Notes. We valued the conversion feature at
June 30, 2009 at $60.9 million and recorded additional
paid-in capital of $36.3 million, net of deferred income
taxes of $22.6 million and transaction costs of
$2.0 million, related to the equity portion of this
convertible debt in 2009. The discount on the Convertible Senior
Notes is amortized using the effective interest method through
maturity on June 15, 2014. As of December 31, 2010,
the fair value of the Convertible Senior Notes was
$275.5 million and the if-converted value is less than the
principal amount.
Term Loan Credit Agreement. The Term Loan has
a maturity date of May 30, 2014. The Term Loan is secured
on a first priority basis, together with the Senior Secured
Notes and any future other pari passu secured obligations, by
our fixed assets, and on a second priority basis, together with
the Senior Secured Notes and any future other pari passu secured
obligations, by the collateral securing the Revolving Credit
Agreement, which consists of our cash and cash equivalents,
trade accounts receivable, and inventory. The Term Loan provides
for principal payments on a quarterly basis of
$13.0 million annually until March 31, 2014, with the
remaining balance due on the maturity date. We made principal
payments on the Term Loan of $13.0 million in 2010,
$925.7 million in 2009, primarily from the net proceeds of
the debt and common stock offerings in June and July 2009, and
$13.0 million during 2008. Since 2009, interest rates under
the Term Loan are equal to LIBOR (subject to a floor of 3.25%)
plus 7.50%. The average interest rates under the Term Loan for
2010 and 2009 were 10.75% and 8.67%, respectively. As of
December 31, 2010, the interest rate under the Term Loan
was 10.75%. We amended the Term Loan during the second and
fourth quarters of 2009 in connection with the new debt
offerings and to modify certain financial covenants. To effect
these amendments, we paid $3.4 million in amendment fees.
As a result of the partial paydown of the Term Loan in June
2009, we expensed $9.0 million during the second quarter of
2009 to write-off a portion of the unamortized loan fees related
to the Term Loan. At December 31, 2010, the fair value of
the Term Loan was $346.9 million.
Revolving Credit Agreement. On
December 23, 2010, we completed an amendment to the
Revolving Credit Agreement resulting in, among other items, the
extension of the maturity of a portion of the commitments
thereunder to January 1, 2015. The amended Revolving Credit
Agreement included commitments of $800.0 million composed
of a $145.0 million tranche that matures on May 31,
2012 and a $655.0 million tranche that matures on
January 1, 2015. The Revolving Credit Agreement is secured
on a first priority basis by certain cash and cash equivalents,
trade accounts receivable, and inventory, and on a second
priority basis by the collateral securing the Term Loan, the
Senior Secured Notes, and any future other pari passu secured
obligations, which consist of the Companys fixed assets.
The Revolving Credit Agreement can be used to finance working
capital and capital
64
expenditures, refinance our existing indebtedness and that of
our subsidiaries, and for other general corporate purposes; and
also provides for letters of credit and swing line loans. The
Revolving Credit Agreement is an asset-based facility with the
borrowing base capacity primarily dependent on our eligible
receivables and inventory. Interest rates for the
$145.0 million tranche vary based on our consolidated
leverage ratio and range from 3.75% to 4.50% over LIBOR or 2.75%
to 3.50% over the Base Rate (as defined in the Revolving Credit
Agreement). Interest rates for the $655.0 million tranche
vary based on our excess borrowing base capacity under the
Revolving Credit Agreement and range from 3.00% to 3.75% over
LIBOR or 2.00% to 2.75% over the Base Rate. As of
December 31, 2010, the gross availability under the
Revolving Credit Agreement was $624.0 million. As of
December 31, 2010, we had net availability under the
Revolving Credit Agreement of $335.6 million due to
$288.4 million in letters of credit outstanding. The
average interest rates under the Revolving Credit Agreement for
2010 and 2009 were 6.15% and 5.20%, respectively. At
December 31, 2010, there were no outstanding borrowings
under the Revolving Credit Agreement. Among other amendments,
the 2010 amendment replaced financial maintenance covenants with
a fixed charge coverage ratio covenant that applies only when
unused availability falls below a specified level. We incurred
$12.7 million in fees related to the Revolving Credit
Agreement amendment in 2010. We also amended the Revolving
Credit Agreement during the second and fourth quarters of 2009
in connection with the new debt offerings and to modify certain
of the financial covenants. We incurred $5.6 million in
fees related to these amendments.
As a result of the 2009 amendment, our Revolving Credit
Agreement required a structure mandating that all receipts be
swept daily to reduce borrowings outstanding under the Revolving
Credit Agreement. This arrangement, combined with the existence
of a material adverse change clause in the Revolving Credit
Agreement, required outstanding borrowings under the Revolving
Credit Agreement to be classified as a current liability. As a
result of the 2010 amendment, going forward, the cash dominion
requirement will only be in effect if the excess availability
under the Revolving Credit Agreement falls below a certain
threshold.
Guarantors of the Term Loan and the Revolving Credit
Agreement. The Term Loan and the Revolving Credit
Agreement (together, the Agreements) are guaranteed,
on a joint and several basis, by subsidiaries of Western
Refining, Inc. No amounts have been recorded for these
guarantees.
Certain Covenants. The Agreements contain
certain covenants, including limitations on debt, investments,
and dividends. The Term Loan contains financial covenants
relating to minimum interest coverage and maximum leverage and,
for certain periods in 2010 through September 30, 2010,
minimum EBITDA. We were in compliance with all applicable
covenants set forth in the Term Loan at December 31, 2010.
The following table sets forth the financial covenant
requirements for minimum consolidated interest coverage (as
defined therein), and maximum consolidated leverage (as defined
therein) under the Term Loan by quarter:
|
|
|
|
|
|
|
Minimum
|
|
|
|
|
Consolidated
|
|
Maximum
|
|
|
Interest Coverage
|
|
Consolidated
|
|
|
Ratio
|
|
Leverage Ratio
|
|
December 31, 2010 and March 31, 2011
|
|
1.50 to 1.00
|
|
5.25 to 1.00
|
June 30, 2011 and thereafter
|
|
2.00 to 1.00
|
|
4.50 to 1.00
|
Letters
of Credit
The Revolving Credit Agreement provides for the issuance of
letters of credit. We issue and cancel letters of credit on a
periodic basis depending upon our needs. At December 31,
2010, there were $288.4 million of irrevocable letters of
credit outstanding, primarily issued to crude oil suppliers
under the Revolving Credit Agreement.
Capital
Spending
Capital expenditures totaled $78.1 million for the year
ended December 31, 2010, and included the MSAT II project
at El Paso and several other improvement and regulatory
projects for our refining group. In addition, our total capital
spending included several smaller projects for our wholesale
group, our retail group, and our corporate group. Capital
expenditures also included $4.2 million of capitalized
interest for 2010.
65
Our capital expenditure budget for 2011 is $62.2 million,
of which $52.5 million is for our refining group,
$1.4 million is for our wholesale group, $6.3 million
is for our retail group, and $2.0 million is for other
general projects. The following table summarizes the spending
allocation between sustaining, discretionary, and regulatory
projects for 2011:
|
|
|
|
|
|
|
2011
|
|
|
|
(In thousands)
|
|
|
Sustaining
|
|
$
|
20,575
|
|
Discretionary
|
|
|
10,550
|
|
Regulatory
|
|
|
31,118
|
|
|
|
|
|
|
Total
|
|
$
|
62,243
|
|
|
|
|
|
|
Sustaining Projects. Sustaining maintenance
capital expenditures are those related to minor replacement of
assets, refurbishing and replacement of components, fire
protection, process safety management, and other recurring and
safety related capital expenditures.
Discretionary Projects. Discretionary project
capital expenditures are those driven primarily by the economic
returns that such projects can generate for us.
Regulatory Projects. Regulatory projects are
undertaken to comply with various regulatory requirements,
including those related to environmental, health, and safety
matters. Our low sulfur fuel and low benzene gasoline projects
are regulatory investments, driven primarily by fuels
regulations. We completed our capital project to comply with the
EPAs low sulfur gasoline regulations during 2010. Our
Gallup and Yorktown refineries require no further regulatory
spending to meet the EPAs ultra low sulfur diesel
standards. The deadline for compliance with the final phase of
the ultra low sulfur diesel regulations to reduce sulfur in
locomotive and marine diesel is June 2012 and affects our
El Paso refinery only. EPA regulations allow the one-time
use of credits to extend the June 2012 deadline by up to
24 months. Low sulfur credits purchased in 2010 will allow
our El Paso refinery to continue producing 500 ppm
sulfur locomotive diesel until early 2014. We are evaluating the
need for a capital project to produce 15 ppm locomotive
diesel after early 2014.
All of our refineries are required to meet the new Mobile Source
Air Toxics, or MSAT II, regulations to reduce the benzene
content of gasoline. Under the MSAT II regulations, benzene in
the finished gasoline pool must be reduced to an annual average
of 0.62 volume percent by 2011 with or without the purchase of
credits. Beginning on July 1, 2012, each refinery must also
average 1.30 volume percent benzene without the use of credits.
As of December 31, 2010, we have expended
$62.0 million to comply with MSAT II regulations at our
El Paso refinery. A capital project for $2.0 million
or less at our Gallup refinery is currently anticipated to meet
the 1.30 volume percent requirement. Our Yorktown refinery
currently meets the 1.30 volume percent benzene requirement
and intends to rely on credits to comply with the
0.62 volume percent requirement.
Based on current information, we estimate the total remaining
capital expenditures necessary to address the EPA Initiative
issues at El Paso would be approximately $21.2 million
for NOx emission controls on heaters and boilers and will occur
from 2011 through 2013. Based on current information and the
2009 NMED Amendment and favorably negotiating a revision to
reflect the indefinite suspension of refining operations at our
Bloomfield facility, we estimate the total remaining capital
expenditures that may be required pursuant to the 2009 NMED
Amendment to address the EPA Initiative issues at Gallup would
be $17.6 million and will occur in 2011 and 2012. These
capital expenditures will primarily be for installation of
emission controls on the heaters, boilers, and fluid catalytic
cracking unit, and for reducing sulfur in fuel gas to reduce
emissions of sulfur dioxide and NOx and particulate matter from
our Gallup refinery. See Item 1. Business
Governmental Regulation.
66
The actual capital expenditures for the regulatory projects
described above for the past three years are summarized in the
table below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
(In millions)
|
|
|
MSAT II gasoline
|
|
$
|
43
|
|
|
$
|
20
|
|
|
$
|
|
|
EPA Initiative Projects
|
|
|
|
|
|
|
|
|
|
|
23
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
43
|
|
|
$
|
20
|
|
|
$
|
23
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The estimated capital expenditures for the regulatory projects
described above and for other regulatory requirements for the
next three years are summarized in the table below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2011
|
|
|
2012
|
|
|
2013
|
|
|
|
(In millions)
|
|
|
MSAT II gasoline
|
|
$
|
3
|
|
|
$
|
1
|
|
|
$
|
|
|
EPA Initiative Projects
|
|
|
12
|
|
|
|
21
|
|
|
|
|
|
Ultra low sulfur non-road diesel
|
|
|
|
|
|
|
5
|
|
|
|
20
|
|
Various other projects
|
|
|
16
|
|
|
|
7
|
|
|
|
8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
31
|
|
|
$
|
34
|
|
|
$
|
28
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contractual
Obligations and Commercial Commitments
Information regarding our contractual obligations of the types
described below as of December 31, 2010, is set forth in
the following table:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments Due by Period
|
|
Contractual Obligations
|
|
Totals
|
|
|
2011
|
|
|
2012 and 2013
|
|
|
2014 and 2015
|
|
|
2016 and Beyond
|
|
|
|
(In thousands)
|
|
|
Long-term debt obligations(1)
|
|
$
|
1,639,436
|
|
|
$
|
173,705
|
|
|
$
|
240,531
|
|
|
$
|
846,878
|
|
|
$
|
378,322
|
|
Capital lease obligations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating lease obligations
|
|
|
94,505
|
|
|
|
16,059
|
|
|
|
23,718
|
|
|
|
16,315
|
|
|
|
38,413
|
|
Purchase obligations(2)
|
|
|
4,774,194
|
|
|
|
631,589
|
|
|
|
1,097,611
|
|
|
|
1,014,998
|
|
|
|
2,029,996
|
|
Environmental reserves(3)
|
|
|
23,288
|
|
|
|
11,095
|
|
|
|
1,601
|
|
|
|
1,265
|
|
|
|
9,327
|
|
Other obligations(4)(5)
|
|
|
310,557
|
|
|
|
34,192
|
|
|
|
44,636
|
|
|
|
33,718
|
|
|
|
198,011
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total obligations(6)
|
|
$
|
6,841,980
|
|
|
$
|
866,640
|
|
|
$
|
1,408,097
|
|
|
$
|
1,913,174
|
|
|
$
|
2,654,069
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Includes minimum principal payments and interest calculated
using interest rates at December 31, 2010. |
|
(2) |
|
Purchase obligations include agreements to buy crude oil and
other raw materials. Amounts included in the table were
calculated using the pricing at December 31, 2010,
multiplied by the contract volumes. |
|
(3) |
|
As of December 31, 2010, the discounted environmental
reserve related to these liabilities totaled $18.3 million.
Our environmental liabilities are discussed in Note 21,
Contingencies, in the Notes to Consolidated Financial
Statements elsewhere in this annual report. |
67
|
|
|
(4) |
|
Other commitments include agreements for sulfuric acid
regeneration and sulfur gas processing, throughput and
distribution, storage services, barges, and professional
consulting. The minimum payment commitments are included in the
table. |
|
(5) |
|
We are obligated to make future expenditures related to our
pension and postretirement obligations. These payments are not
fixed and cannot be reasonably determined beyond 2018. As a
result, our obligations beyond 2018 related to these plans are
not included in the table. Our pension and postretirement
obligations are discussed in Note 15, Retirement Plans,
in the Notes to Consolidated Financial Statements elsewhere
in this annual report. |
|
(6) |
|
As of December 31, 2010, we have no uncertain tax positions
or related liabilities recorded. |
Off-Balance
Sheet Arrangements
We have no off-balance sheet arrangements.
68
|
|
Item 7A.
|
Quantitative
and Qualitative Disclosure About Market Risk
|
Changes in commodity prices and interest rates are our primary
sources of market risk.
Commodity
Price Risk
We are exposed to market risks related to the volatility of
crude oil and refined product prices, as well as volatility in
the price of natural gas used in our refinery operations. Our
financial results can be affected significantly by fluctuations
in these prices, which depend on many factors, including demand
for crude oil, gasoline, and other refined products, changes in
the economy, worldwide production levels, worldwide inventory
levels, and governmental regulatory initiatives. Our risk
management strategy identifies circumstances in which we may
utilize the commodity futures market to manage risk associated
with these price fluctuations.
In order to manage the uncertainty relating to inventory price
volatility, we have generally applied a policy of maintaining
inventories at or below a targeted operating level. In the past,
circumstances have occurred, such as turnaround schedules or
shifts in market demand that have resulted in variances between
our actual inventory level and our desired target level. We may
utilize the commodity futures market to manage these anticipated
inventory variances.
We maintain inventories of crude oil, other feedstocks and
blendstocks, and refined products, the values of which are
subject to wide fluctuations in market prices driven by
worldwide economic conditions, regional and global inventory
levels, and seasonal conditions. At December 31, 2010, we
held approximately 5.7 million barrels of crude oil,
refined product, and other inventories valued under the LIFO
valuation method with an average cost of $58.39 per barrel. At
December 31, 2010, aggregated LIFO costs exceeded the
current cost of our crude oil, refined product, and other
feedstock and blendstock inventories by $173.5 million. At
December 31, 2009, we held approximately 6.3 million
barrels of crude oil, refined product, and other inventories
valued under the LIFO valuation method with an average cost of
$56.32 per barrel. At December 31, 2009, aggregated LIFO
costs exceeded the current cost of our crude oil, refined
product, and other feedstock and blendstock inventories by
$126.4 million.
All commodity futures contracts, price swaps, and options are
recorded at fair value and any changes in fair value between
periods are recorded under cost of products sold in our
Consolidated Statements of Operations.
We selectively utilize commodity derivatives to manage our price
exposure to inventory positions or to fix margins on certain
future sales volumes. The commodity derivative instruments may
take the form of futures contracts, price swaps, or options and
are entered into with counterparties that we believe to be
creditworthy. We elected not to pursue hedge accounting
treatment for these instruments for financial accounting
purposes. Therefore, changes in the fair value of these
derivative instruments are included in income in the period of
change. Net gains or losses associated with these transactions
are reflected within cost of products sold at the end of each
period. For the years ended December 31, 2010 and 2009, we
had $9.4 million and $21.7 million, respectively, in
net losses settled or accounted for using
mark-to-market
accounting. For the year ended December 31, 2008, we had
$11.4 million in net gains settled or accounted for using
mark-to-market
accounting.
At December 31, 2010, we had open commodity derivative
instruments consisting of crude oil futures and finished product
price swaps on a net 1,023,000 barrels to protect the value
of certain crude oil, finished product, and blendstock
inventories for the first quarter of 2011. These open
instruments had total unrealized net losses at December 31,
2010 of approximately $1.2 million. At December 31,
2009, we had open commodity derivative instruments consisting of
crude oil futures and finished product price swaps on a net
268,000 barrels to protect the value of certain crude oil,
finished product, and blendstock inventories for the first
quarter of 2010. These open instruments had total unrealized net
losses at December 31, 2009 of approximately
$1.5 million. At December 31, 2008, we had open
commodity derivative instruments consisting of finished product
price swaps on a net 20,000 barrels to protect the value of
certain gasoline blendstock inventories for the first quarter of
2009. We did not record an unrealized gain or loss on these open
positions since the fair value equaled the trade price on these
swaps at December 31, 2008.
During the three years ended December 31, 2010, we did not
have any commodity derivative instruments that were designated
or accounted for as hedges.
69
Interest
Rate Risk
As of December 31, 2010, $616.8 million of our
outstanding debt, excluding unamortized discount, was at
floating interest rates based on LIBOR and prime rates. An
increase in these base rates of 1% would increase our interest
expense by $6.2 million per year.
70
Managements
Report on Internal Control Over Financial Reporting
The Companys management is responsible for establishing
and maintaining adequate internal control over financial
reporting. Internal control over financial reporting is defined
in
Rule 13a-15(f)
or 15d-15(f)
promulgated under the Securities Exchange Act of 1934 as a
process designed by, or under the supervision of, the
Companys principal executive and principal financial
officers and effected by the Companys 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 and
includes those policies and procedures that:
|
|
|
|
|
Pertain to the maintenance of records that in reasonable detail
accurately and fairly reflect the transactions and dispositions
of the assets of the Company;
|
|
|
|
Provide reasonable assurance that transactions are recorded as
necessary to permit preparation of financial statements in
accordance with generally accepted accounting principles, and
the receipts and expenditures of the Company are being made only
in accordance with authorizations of management and directors of
the Company; and
|
|
|
|
Provide reasonable assurance regarding prevention or timely
detection of unauthorized acquisition, use, or disposition of
the Companys assets that could have a material effect on
the financial statements.
|
Because of its inherent limitations, internal control over
financial reporting may not prevent or detect misstatements.
Projections of any evaluation of effectiveness to future periods
are subject to the risk that controls may become inadequate
because of changes in conditions, or that the degree of
compliance with the policies or procedures may deteriorate.
The Companys management assessed the effectiveness of the
Companys internal control over financial reporting as of
December 31, 2010. In making this assessment, the
Companys management used the criteria set forth by the
Committee of Sponsoring Organizations of the Treadway Commission
(COSO) in Internal Control-Integrated Framework.
Based on its assessment, the Companys management believes
that, as of December 31, 2010, the Companys internal
control over financial reporting is effective based on those
criteria.
The Companys independent registered public accounting
firm, Deloitte & Touche LLP, has issued an audit
report on the Companys internal control over financial
reporting. This report appears on page 72 of this annual
report.
71
Report of
Independent Registered Public Accounting Firm
The Board of Directors and Stockholders of
Western Refining, Inc.
El Paso, Texas
We have audited the internal control over financial reporting of
Western Refining, Inc. as of December 31, 2010, based on
criteria established in Internal Control
Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission. The Companys
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 Report on Internal
Control Over Financial Reporting. Our responsibility is to
express an opinion on the Companys 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 companys internal control over financial reporting is a
process designed by, or under the supervision of, the
companys principal executive and principal financial
officers, or persons performing similar functions, and effected
by the companys 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 companys
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
companys 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
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, 2010, 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 as of and for the year ended
December 31, 2010 of the Company and our report dated
March 7, 2011 expressed an unqualified opinion on those
financial statements.
/s/ Deloitte &
Touche LLP
Phoenix, AZ
March 7, 2011
72
|
|
Item 8.
|
Financial
Statements and Supplementary Data
|
INDEX TO
FINANCIAL STATEMENTS
|
|
|
|
|
|
|
Page
|
|
|
|
74
|
|
|
|
|
75
|
|
|
|
|
76
|
|
|
|
|
77
|
|
|
|
|
78
|
|
|
|
|
79
|
|
|
|
|
80
|
|
73
Report of
Independent Registered Public Accounting Firm
The Board of Directors and Stockholders of
Western Refining, Inc.
El Paso, Texas
We have audited the accompanying consolidated balance sheets of
Western Refining, Inc. and subsidiaries (the
Company) as of December 31, 2010 and 2009, and
the related consolidated statements of operations, comprehensive
income (loss), stockholders equity, and cash flows for
each of the three years in the period ended December 31,
2010. These consolidated financial statements are the
responsibility of the Companys management. Our
responsibility is to express an opinion on the consolidated
financial statements 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 the
Company at December 31, 2010 and 2009, and the results of
its operations and its cash flows for each of the three years in
the period ended December 31, 2010, in conformity with
accounting principles generally accepted in the United States of
America.
We have also audited, in accordance with the standards of the
Public Company Accounting Oversight Board (United States), the
Companys internal control over financial reporting as of
December 31, 2010, based on criteria established in
Internal Control-Integrated Framework issued by the
Committee of Sponsoring Organizations of the Treadway
Commission, and our report dated March 7, 2011 expressed an
unqualified opinion on the Companys internal control over
financial reporting.
/s/ Deloitte &
Touche LLP
Phoenix, AZ
March 7, 2011
74
WESTERN
REFINING, INC. AND SUBSIDIARIES
CONSOLIDATED
BALANCE SHEETS
(In thousands, except share data)
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
ASSETS
|
Current assets:
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
59,912
|
|
|
$
|
74,890
|
|
Accounts receivable, principally trade, net of a reserve for
doubtful accounts of $3,896 and $1,571, respectively
|
|
|
283,897
|
|
|
|
337,559
|
|
Inventories
|
|
|
365,673
|
|
|
|
422,753
|
|
Prepaid expenses
|
|
|
71,935
|
|
|
|
29,216
|
|
Other current assets
|
|
|
44,286
|
|
|
|
79,740
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
825,703
|
|
|
|
944,158
|
|
Property, plant, and equipment, net
|
|
|
1,688,154
|
|
|
|
1,767,900
|
|
Intangible assets, net
|
|
|
59,945
|
|
|
|
61,693
|
|
Other assets, net
|
|
|
54,344
|
|
|
|
50,903
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
2,628,146
|
|
|
$
|
2,824,654
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND STOCKHOLDERS EQUITY
|
Current liabilities:
|
|
|
|
|
|
|
|
|
Accounts payable
|
|
$
|
308,646
|
|
|
$
|
405,684
|
|
Accrued liabilities
|
|
|
122,378
|
|
|
|
118,569
|
|
Current deferred income tax liability, net
|
|
|
58,929
|
|
|
|
45,651
|
|
Current portion of long-term debt
|
|
|
63,000
|
|
|
|
63,000
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
552,953
|
|
|
|
632,904
|
|
|
|
|
|
|
|
|
|
|
Long-term liabilities:
|
|
|
|
|
|
|
|
|
Long-term debt, less current portion
|
|
|
1,006,531
|
|
|
|
1,053,664
|
|
Deferred income tax liability, net
|
|
|
361,292
|
|
|
|
391,348
|
|
Environmental, postretirement, and other liabilities
|
|
|
31,777
|
|
|
|
58,286
|
|
|
|
|
|
|
|
|
|
|
Total long-term liabilities
|
|
|
1,399,600
|
|
|
|
1,503,298
|
|
|
|
|
|
|
|
|
|
|
Commitments and contingencies (Note 21)
|
|
|
|
|
|
|
|
|
Stockholders equity:
|
|
|
|
|
|
|
|
|
Common stock, par value $0.01, 240,000,000 shares
authorized; 89,025,010 and 88,688,717 shares issued,
respectively
|
|
|
890
|
|
|
|
887
|
|
Preferred stock, par value $0.01, 10,000,000 shares
authorized; no shares issued and outstanding
|
|
|
|
|
|
|
|
|
Additional paid-in capital
|
|
|
588,215
|
|
|
|
583,458
|
|
Retained earnings
|
|
|
109,871
|
|
|
|
126,920
|
|
Accumulated other comprehensive loss, net of tax
|
|
|
(1,940
|
)
|
|
|
(1,370
|
)
|
Treasury stock, 698,006 shares, respectively, at cost
|
|
|
(21,443
|
)
|
|
|
(21,443
|
)
|
|
|
|
|
|
|
|
|
|
Total stockholders equity
|
|
|
675,593
|
|
|
|
688,452
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and stockholders equity
|
|
$
|
2,628,146
|
|
|
$
|
2,824,654
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these financial
statements.
75
WESTERN
REFINING, INC. AND SUBSIDIARIES
CONSOLIDATED
STATEMENTS OF OPERATIONS
(In thousands, except per share
data)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
Net sales
|
|
$
|
7,965,053
|
|
|
$
|
6,807,368
|
|
|
$
|
10,725,581
|
|
Operating costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of products sold (exclusive of depreciation and
amortization)
|
|
|
7,155,967
|
|
|
|
5,944,128
|
|
|
|
9,735,500
|
|
Direct operating expenses (exclusive of depreciation and
amortization)
|
|
|
444,531
|
|
|
|
486,164
|
|
|
|
532,325
|
|
Selling, general, and administrative expenses
|
|
|
84,175
|
|
|
|
109,697
|
|
|
|
115,913
|
|
Goodwill impairment losses
|
|
|
|
|
|
|
299,552
|
|
|
|
|
|
Other impairment losses
|
|
|
13,038
|
|
|
|
52,788
|
|
|
|
|
|
Maintenance turnaround expense
|
|
|
23,286
|
|
|
|
8,088
|
|
|
|
28,936
|
|
Depreciation and amortization
|
|
|
138,621
|
|
|
|
145,981
|
|
|
|
113,611
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating costs and expenses
|
|
|
7,859,618
|
|
|
|
7,046,398
|
|
|
|
10,526,285
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss)
|
|
|
105,435
|
|
|
|
(239,030
|
)
|
|
|
199,296
|
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest income
|
|
|
441
|
|
|
|
248
|
|
|
|
1,830
|
|
Interest expense and other financing costs
|
|
|
(146,549
|
)
|
|
|
(121,321
|
)
|
|
|
(102,202
|
)
|
Amortization of loan fees
|
|
|
(9,739
|
)
|
|
|
(6,870
|
)
|
|
|
(4,789
|
)
|
Write-off of unamortized loan fees
|
|
|
|
|
|
|
(9,047
|
)
|
|
|
(10,890
|
)
|
Other income (expense), net
|
|
|
7,286
|
|
|
|
(15,184
|
)
|
|
|
1,176
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before income taxes
|
|
|
(43,126
|
)
|
|
|
(391,204
|
)
|
|
|
84,421
|
|
Provision for income taxes
|
|
|
26,077
|
|
|
|
40,583
|
|
|
|
(20,224
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
(17,049
|
)
|
|
$
|
(350,621
|
)
|
|
$
|
64,197
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings (loss) per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
(0.19
|
)
|
|
$
|
(4.43
|
)
|
|
$
|
0.94
|
|
Diluted
|
|
$
|
(0.19
|
)
|
|
$
|
(4.43
|
)
|
|
$
|
0.94
|
|
Weighted average common shares outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
88,204
|
|
|
|
79,163
|
|
|
|
67,715
|
|
Diluted
|
|
|
88,204
|
|
|
|
79,163
|
|
|
|
67,715
|
|
The accompanying notes are an integral part of these
consolidated financial statements.
76
WESTERN
REFINING, INC. AND SUBSIDIARIES
CONSOLIDATED
STATEMENTS OF CHANGES IN
STOCKHOLDERS EQUITY
(In thousands, except share data)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated
|
|
|
|
|
|
|
|
|
|
|
|
|
Common Stock
|
|
|
|
|
|
Other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additional
|
|
|
|
|
|
Comprehensive
|
|
|
|
|
|
|
|
|
|
|
|
|
Shares
|
|
|
Par
|
|
|
Paid-In
|
|
|
Retained
|
|
|
Loss,
|
|
|
Treasury Stock
|
|
|
|
|
|
|
Issued
|
|
|
Value
|
|
|
Capital
|
|
|
Earnings
|
|
|
Net of Tax
|
|
|
Shares
|
|
|
Cost
|
|
|
Total
|
|
|
Balance at December 31, 2007
|
|
|
68,105,132
|
|
|
$
|
679
|
|
|
$
|
366,071
|
|
|
$
|
417,439
|
|
|
$
|
(8,056
|
)
|
|
|
(566,235
|
)
|
|
$
|
(19,648
|
)
|
|
$
|
756,485
|
|
Stock-based compensation
|
|
|
|
|
|
|
|
|
|
|
7,711
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7,711
|
|
Restricted stock vesting
|
|
|
321,862
|
|
|
|
5
|
|
|
|
(5
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Tax deficiency from stock-based compensation
|
|
|
|
|
|
|
|
|
|
|
(659
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(659
|
)
|
Cash dividend declared
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(4,099
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(4,099
|
)
|
Net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
64,197
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
64,197
|
|
Other comprehensive loss, net of tax benefit of $6,910
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(10,950
|
)
|
|
|
|
|
|
|
|
|
|
|
(10,950
|
)
|
Treasury stock, at cost
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(80,668
|
)
|
|
|
(1,196
|
)
|
|
|
(1,196
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2008
|
|
|
68,426,994
|
|
|
|
684
|
|
|
|
373,118
|
|
|
|
477,537
|
|
|
|
(19,006
|
)
|
|
|
(646,903
|
)
|
|
|
(20,844
|
)
|
|
|
811,489
|
|
Public offering of common stock
|
|
|
20,000,000
|
|
|
|
200
|
|
|
|
170,242
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
170,442
|
|
Equity component of convertible notes issuance
|
|
|
|
|
|
|
|
|
|
|
36,281
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
36,281
|
|
Stock-based compensation
|
|
|
|
|
|
|
|
|
|
|
4,697
|
|
|
|
4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,701
|
|
Restricted stock vesting
|
|
|
261,723
|
|
|
|
3
|
|
|
|
(3
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Tax deficiency from stock-based compensation
|
|
|
|
|
|
|
|
|
|
|
(877
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(877
|
)
|
Net loss
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(350,621
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(350,621
|
)
|
Other comprehensive income, net of tax expense of $10,372
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
17,636
|
|
|
|
|
|
|
|
|
|
|
|
17,636
|
|
Treasury stock, at cost
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(51,103
|
)
|
|
|
(599
|
)
|
|
|
(599
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2009
|
|
|
88,688,717
|
|
|
|
887
|
|
|
|
583,458
|
|
|
|
126,920
|
|
|
|
(1,370
|
)
|
|
|
(698,006
|
)
|
|
|
(21,443
|
)
|
|
|
688,452
|
|
Stock-based compensation
|
|
|
|
|
|
|
|
|
|
|
5,857
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5,857
|
|
Restricted stock vesting
|
|
|
336,293
|
|
|
|
3
|
|
|
|
(3
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Tax deficiency from stock-based compensation
|
|
|
|
|
|
|
|
|
|
|
(1,097
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,097
|
)
|
Net loss
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(17,049
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(17,049
|
)
|
Other comprehensive loss, net of tax benefit of $396
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(570
|
)
|
|
|
|
|
|
|
|
|
|
|
(570
|
)
|
Treasury stock, at cost
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2010
|
|
|
89,025,010
|
|
|
$
|
890
|
|
|
$
|
588,215
|
|
|
$
|
109,871
|
|
|
$
|
(1,940
|
)
|
|
|
(698,006
|
)
|
|
$
|
(21,443
|
)
|
|
$
|
675,593
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these
consolidated financial statements.
77
WESTERN
REFINING, INC. AND SUBSIDIARIES
CONSOLIDATED
STATEMENTS OF CASH FLOWS
(In thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
Cash flows from operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
(17,049
|
)
|
|
$
|
(350,621
|
)
|
|
$
|
64,197
|
|
Adjustments to reconcile net income (loss) to net cash provided
by operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Goodwill impairment losses
|
|
|
|
|
|
|
299,552
|
|
|
|
|
|
Other impairment losses
|
|
|
13,038
|
|
|
|
52,788
|
|
|
|
|
|
Depreciation and amortization
|
|
|
138,621
|
|
|
|
145,981
|
|
|
|
113,611
|
|
Reserve for doubtful accounts
|
|
|
3,260
|
|
|
|
6,119
|
|
|
|
9,340
|
|
Amortization of loan fees
|
|
|
9,739
|
|
|
|
6,870
|
|
|
|
4,789
|
|
Amortization of original issue discount
|
|
|
15,867
|
|
|
|
7,091
|
|
|
|
|
|
Write-off of unamortized loan fees
|
|
|
|
|
|
|
9,047
|
|
|
|
10,890
|
|
Stock-based compensation expense
|
|
|
5,857
|
|
|
|
4,701
|
|
|
|
7,711
|
|
Deferred income taxes
|
|
|
(16,778
|
)
|
|
|
9,410
|
|
|
|
14,115
|
|
(Gain) loss from the disposal of assets
|
|
|
(1,484
|
)
|
|
|
343
|
|
|
|
1,308
|
|
Changes in operating assets and liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
|
50,402
|
|
|
|
(128,403
|
)
|
|
|
194,277
|
|
Inventories
|
|
|
57,080
|
|
|
|
2,784
|
|
|
|
173,136
|
|
Prepaid expenses
|
|
|
(42,719
|
)
|
|
|
24,281
|
|
|
|
(21,915
|
)
|
Other assets
|
|
|
39,972
|
|
|
|
(41,896
|
)
|
|
|
45,020
|
|
Accounts payable
|
|
|
(96,706
|
)
|
|
|
97,325
|
|
|
|
(336,964
|
)
|
Accrued liabilities
|
|
|
2,712
|
|
|
|
(4,269
|
)
|
|
|
13,547
|
|
Postretirement and other non-current liabilities
|
|
|
(27,356
|
)
|
|
|
(262
|
)
|
|
|
(7,487
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
|
134,456
|
|
|
|
140,841
|
|
|
|
285,575
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from investing activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures
|
|
|
(78,095
|
)
|
|
|
(115,854
|
)
|
|
|
(222,288
|
)
|
Proceeds from the sale of assets
|
|
|
4,318
|
|
|
|
493
|
|
|
|
1,734
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used in investing activities
|
|
|
(73,777
|
)
|
|
|
(115,361
|
)
|
|
|
(220,554
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from financing activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Additions to long-term debt
|
|
|
|
|
|
|
747,183
|
|
|
|
|
|
Payments on long-term debt
|
|
|
(13,000
|
)
|
|
|
(925,693
|
)
|
|
|
(13,000
|
)
|
Common stock offering
|
|
|
|
|
|
|
170,442
|
|
|
|
|
|
Revolving credit facility, net
|
|
|
(50,000
|
)
|
|
|
(10,000
|
)
|
|
|
(230,000
|
)
|
Deferred financing costs
|
|
|
(12,657
|
)
|
|
|
(11,740
|
)
|
|
|
(22,391
|
)
|
Dividends paid
|
|
|
|
|
|
|
|
|
|
|
(8,182
|
)
|
Repurchases of common stock
|
|
|
|
|
|
|
(599
|
)
|
|
|
(1,196
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used in financing activities
|
|
|
(75,657
|
)
|
|
|
(30,407
|
)
|
|
|
(274,769
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net decrease in cash and cash equivalents
|
|
|
(14,978
|
)
|
|
|
(4,927
|
)
|
|
|
(209,748
|
)
|
Cash and cash equivalents at beginning of year
|
|
|
74,890
|
|
|
|
79,817
|
|
|
|
289,565
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of year
|
|
$
|
59,912
|
|
|
$
|
74,890
|
|
|
$
|
79,817
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Supplemental disclosures of cash flow information:
|
|
|
|
|
|
|
|
|
|
|
|
|
Income taxes refunded
|
|
$
|
(49,827
|
)
|
|
$
|
(7,201
|
)
|
|
$
|
(51,134
|
)
|
Interest paid, excluding amounts capitalized
|
|
|
135,063
|
|
|
|
129,812
|
|
|
|
96,499
|
|
Non-cash investing and financing activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Reduction of long-term debt for original issue discounts and
deferred financing costs
|
|
$
|
|
|
|
$
|
68,267
|
|
|
$
|
|
|
Equity component of convertible notes, net of deferred taxes of
$22.6 million and issuance costs of $2.0 million
|
|
|
|
|
|
|
36,281
|
|
|
|
|
|
Accrued capital expenditures
|
|
|
|
|
|
|
332
|
|
|
|
13,673
|
|
The accompanying notes are an integral part of these
consolidated financial statements.
78
WESTERN
REFINING, INC. AND SUBSIDIARIES
CONSOLIDATED
STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(In thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
Net income (loss)
|
|
$
|
(17,049
|
)
|
|
$
|
(350,621
|
)
|
|
$
|
64,197
|
|
Other comprehensive income (loss) items:
|
|
|
|
|
|
|
|
|
|
|
|
|
Benefit plans:
|
|
|
|
|
|
|
|
|
|
|
|
|
Actuarial gain (loss)
|
|
|
(4,272
|
)
|
|
|
2,793
|
|
|
|
(18,673
|
)
|
Reclassification of (gain) loss to income
|
|
|
(15
|
)
|
|
|
144
|
|
|
|
813
|
|
Pension plan termination adjustment
|
|
|
3,321
|
|
|
|
25,071
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other comprehensive income (loss) before tax
|
|
|
(966
|
)
|
|
|
28,008
|
|
|
|
(17,860
|
)
|
Income tax
|
|
|
396
|
|
|
|
(10,372
|
)
|
|
|
6,910
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other comprehensive income (loss), net of tax
|
|
|
(570
|
)
|
|
|
17,636
|
|
|
|
(10,950
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive income (loss)
|
|
$
|
(17,619
|
)
|
|
$
|
(332,985
|
)
|
|
$
|
53,247
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these
consolidated financial statements.
79
WESTERN
REFINING, INC. AND SUBSIDIARIES
|
|
1.
|
Organization
and Basis of Presentation
|
The Company or Western may be used to
refer to Western Refining, Inc. and, unless the context
otherwise requires, its subsidiaries. Any references to the
Company as of a date prior to September 16,
2005 (the date of Western Refining, Inc.s formation) are
to Western Refining Company, L.P. (Western Refining
LP). On May 31, 2007, the Company completed the
acquisition of Giant Industries, Inc. (Giant). Any
references to the Company prior to this date exclude
the operations of Giant.
The Company is an independent crude oil refiner and marketer of
refined products and also operates service stations and
convenience stores. The Company owns and currently operates two
refineries. In addition to the refinery in El Paso, Texas,
the Company also owns and operates a refinery near Gallup, in
the Four Corners region of Northern New Mexico. Prior to
September 2010, the Company operated a refinery near Yorktown,
Virginia and until November 2009, the Company also operated a
refinery near Bloomfield, New Mexico. The Company temporarily
suspended refining operations at the Yorktown facility in
September 2010 and indefinitely suspended refining operations at
the Bloomfield refinery in November 2009. The Company continues
to operate both facilities as product distribution terminals.
The Companys primary operating areas encompass West Texas,
Arizona, New Mexico, Utah, Colorado, and the Mid-Atlantic
region. In addition to the refineries, the Company also owns and
operates stand-alone refined product distribution terminals in
Bloomfield, New Mexico; Albuquerque, New Mexico; and Yorktown,
Virginia; as well as asphalt terminals in Phoenix and Tucson,
Arizona; Albuquerque; and El Paso. As of December 31,
2010, the Company also owned and operated 150 retail service
stations and convenience stores in Arizona, Colorado, and New
Mexico; a fleet of crude oil and finished product truck
transports; and a wholesale petroleum products distributor that
operates in Arizona, California, Colorado, Nevada, New Mexico,
Texas, and Utah.
The Companys operations include three business segments:
the refining group, the wholesale group, and the retail group.
Prior to the Giant acquisition, the Company operated as one
business segment. See Note 3, Segment Information,
for further discussion of the Companys business segments.
Demand for gasoline is generally higher during the summer months
than during the winter months. In addition, higher volumes of
ethanol are blended to the gasoline produced in the Southwest
region during the winter months, thereby increasing the supply
of gasoline. This combination of decreased demand and increased
supply during the winter months can lower gasoline prices. As a
result, the Companys operating results for the first and
fourth calendar quarters are generally lower than those for the
second and third calendar quarters of each year. The effects of
seasonal demand for gasoline are partially offset by increased
demand during the winter months for diesel fuel in the Southwest
and heating oil in the Northeast. Throughout 2009, however,
refining margins were extremely volatile and the Companys
results of operations do not reflect these seasonal trends.
The accompanying consolidated financial statements have been
prepared in accordance with U.S. generally accepted
accounting principles (GAAP) for financial
information and with the instructions to
Form 10-K
and Article 10 of
Regulation S-X.
|
|
2.
|
Summary
of Accounting Policies
|
Principles
of Consolidation
Western Refining, Inc. was formed on September 16, 2005, as
a holding company prior to its initial public offering. On
May 31, 2007, the Company acquired 100% of Giants
outstanding shares. The accompanying consolidated financial
statements reflect the operations of Giant and its subsidiaries.
In connection with the Companys initial public offering in
January 2006, pursuant to a contribution agreement, a
reorganization of entities under common control was consummated
whereby the Company became the indirect owner of Western
Refining LP and all of its refinery assets. All intercompany
balances and transactions have been eliminated for all periods
presented.
80
WESTERN
REFINING, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Cash
Equivalents
Cash equivalents consist of investments in money market
accounts. The Company considers all highly liquid investments
purchased with an original maturity of three months or less to
be cash equivalents. There were no cash equivalents as of
December 31, 2010 and $5.4 million in cash equivalents
as of December 31, 2009 included in the Companys
Consolidated Balance Sheets.
Accounts
Receivable
Accounts receivable are due from a diverse customer base
including companies in the petroleum industry, railroads,
airlines, and the federal government and is stated net of an
allowance for uncollectible accounts as determined by historical
experience and adjusted for economic uncertainties or known
trends. Credit is extended based on an evaluation of the
customers financial condition. In addition, a portion of
the sales at the Companys service stations are on credit
terms generally through major credit card companies. Past due or
delinquency status of the Companys trade accounts
receivable are generally based on contractual arrangements with
the Companys customers.
Uncollectible accounts receivable are charged against the
allowance for doubtful accounts when all reasonable efforts to
collect the amounts due have been exhausted. Reserves for
doubtful accounts related to trade receivables were
$3.9 million, $1.6 million, and $2.5 million for
the years ended December 31, 2010, 2009, and 2008,
respectively. The remaining reserves for doubtful accounts at
December 31, 2008 of $10.0 million related to various
notes receivable and other non-trade receivables. Additions,
deductions, and balances for allowances for doubtful accounts
for the three years ended December 31, 2010 are presented
below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands)
|
|
|
Trade receivables:
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at January 1
|
|
$
|
1,571
|
|
|
$
|
2,516
|
|
|
$
|
1,079
|
|
Additions
|
|
|
3,260
|
|
|
|
4,400
|
|
|
|
2,015
|
|
Reductions
|
|
|
(935
|
)
|
|
|
(5,345
|
)
|
|
|
(578
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31
|
|
|
3,896
|
|
|
|
1,571
|
|
|
|
2,516
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other receivables:
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at January 1
|
|
|
|
|
|
|
9,971
|
|
|
|
2,646
|
|
Additions
|
|
|
|
|
|
|
1,719
|
|
|
|
7,325
|
|
Reductions
|
|
|
|
|
|
|
(11,690
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31
|
|
|
|
|
|
|
|
|
|
|
9,971
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total allowance for uncollectible accounts
|
|
$
|
3,896
|
|
|
$
|
1,571
|
|
|
$
|
12,487
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Inventories
Crude oil, refined product, and other feedstock and blendstock
inventories are carried at the lower of cost or market. Cost is
determined principally under the
last-in,
first-out (LIFO) valuation method to reflect a
better matching of costs and revenues. Costs include both direct
and indirect expenditures incurred in bringing an item or
product to its existing condition and location but not
unusual/non-recurring costs or research and development costs.
Ending inventory costs in excess of market value are written
down to net realizable market values and charged to cost of
products sold in the period recorded. In subsequent periods, a
new lower of cost or market determination is made based upon
current circumstances. The Company determines market value
inventory adjustments by evaluating crude oil, refined products,
and other inventories on an aggregate basis by geographic region.
81
WESTERN
REFINING, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Retail refined product (fuel) inventory values are determined
using the
first-in,
first-out (FIFO) inventory valuation method. Retail
merchandise inventory value is determined under the retail
inventory method. Wholesale finished product, lubricants, and
related inventories are determined using the FIFO inventory
valuation method. Finished product inventories originate from
either the Companys refineries or from third-party
purchases.
Other
Current Assets
Other current assets primarily consist of materials and
chemicals inventories, income taxes receivable and prepaid,
futures margin deposits, and spare parts inventories.
Property,
Plant, and Equipment
Property, plant, and equipment are stated at cost. The Company
capitalizes interest on expenditures for capital projects in
process greater than one year and greater than $5 million
until such projects are ready for their intended use.
Depreciation is provided on the straight-line method at rates
based upon the estimated useful lives of the various classes of
depreciable assets. The lives used in computing depreciation for
such assets are as follows:
|
|
|
|
|
Refinery facilities and related equipment
|
|
|
3 25 years
|
|
Pipelines, terminals, and transportation equipment
|
|
|
5 20 years
|
|
Wholesale facilities and related equipment
|
|
|
3 20 years
|
|
Retail facilities and related equipment
|
|
|
3 30 years
|
|
Other
|
|
|
3 10 years
|
|
Leasehold improvements are depreciated on the straight-line
method over the shorter of the lease term or the
improvements estimated useful life.
Expenditures for periodic maintenance and repair costs,
including major turnaround expenses, are expensed when incurred.
Such expenses are reported in direct operating expenses in the
Companys Consolidated Statements of Operations.
Goodwill
and Other Intangible Assets
Goodwill represents the excess of the purchase price (cost) over
the fair value of the net assets acquired and is carried at
cost. The Company tests goodwill for impairment at the reporting
unit level annually. In addition, goodwill of that reporting
unit is tested for impairment if any events or circumstances
arise during a quarter that indicates goodwill of a reporting
unit might be impaired. The reporting unit or units used to
evaluate and measure goodwill for impairment are determined
primarily from the manner in which the business is managed. A
reporting unit is an operating segment or a component that is
one level below an operating segment. Within its refining
segment, the Company has determined that it has three reporting
units for purposes of assigning goodwill and testing for
impairment. The Companys wholesale and retail segments are
considered reporting units for purposes of assigning goodwill
and testing for impairment. The Companys goodwill was
assigned to two of the three refining reporting units and to the
Companys wholesale and retail reporting units. The Company
did not amortize goodwill for financial reporting purposes.
Intangible assets, net, consist of both amortizable intangible
assets, net of accumulated amortization, and intangible assets
with indefinite lives. These intangible assets are primarily
comprised of licenses, permits, and
rights-of-way
related to the Companys refining operations. The Company
amortizes its intangible assets, such as
rights-of-way,
licenses, and permits over their estimated economic useful
lives, unless the economic useful lives of the assets are
indefinite. If an intangible assets economic useful life
is determined to be indefinite, then that asset is not
amortized. The Company considers factors such as the
assets history, its plans for that asset, and the market
for products associated with the asset when the intangible asset
is acquired. The Company considers these same factors
82
WESTERN
REFINING, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
when reviewing the economic useful lives of its existing
intangible assets as well. The Company evaluates the remaining
useful lives of its intangible assets with indefinite lives at
least annually. If events or circumstances no longer support an
indefinite useful life, the intangible asset is tested for
impairment and prospectively amortized over its remaining useful
life.
Both amortizable intangible assets and intangible assets with
indefinite lives must be tested for recoverability whenever
events or changes in circumstances indicate that the carrying
amount of those assets may not be recoverable. Amortizable
intangible assets are not recoverable if their carrying amount
exceeds the sum of the undiscounted cash flows expected to
result from their use and eventual disposition. If an
amortizable intangible asset is not recoverable, an impairment
loss is recognized in an amount by which its carrying amount
exceeds its fair value generally based on discounted estimated
net cash flows.
In order to test amortizable intangible assets for
recoverability, management must make estimates of projected cash
flows related to the asset being evaluated, which include, but
are not limited to, assumptions about the use or disposition of
the asset, its estimated remaining life, and future expenditures
necessary to maintain its existing service potential. In order
to determine fair value, management must make certain estimates
and assumptions including, among other things, an assessment of
market conditions, projected volumes, margins, cash flows,
investment rates, interest/equity rates, and growth rates, that
could significantly impact the fair value of the asset being
tested for impairment.
The risk of other intangible asset impairment losses may
increase to the extent the Companys results of operations
or cash flows decline. Impairment losses may result in a
material, non-cash write-down of other intangible assets.
Furthermore, impairment losses could have a material adverse
effect on the Companys results of operations and
shareholders equity.
Other
Assets
Other assets consist primarily of loan origination fees and
various other assets that are related to the general operation
of the Company and are stated at cost. Amortization is provided
on a straight-line basis over the term of the agreement, which
approximates the effective interest method.
Impairment
of Long-Lived Assets
The Company reviews the carrying values of its long-lived assets
for possible impairment whenever events or changes in
circumstances indicate that the carrying amount of assets to be
held and used may not be recoverable. A long-lived asset is not
recoverable if its carrying amount exceeds the sum of the
undiscounted cash flows expected to result from its use and
eventual disposition. If a long-lived asset is not recoverable,
an impairment loss is recognized in an amount by which its
carrying amount exceeds its fair value.
In order to test long-lived assets for recoverability,
management must make estimates of projected cash flows related
to the asset being evaluated, which include, but are not limited
to, assumptions about the use or disposition of the asset, its
estimated remaining life, and future expenditures necessary to
maintain its existing service potential. In order to determine
fair value, management must make certain estimates and
assumptions including, among other things, an assessment of
market conditions, projected volumes, margins, cash flows,
investment rates, interest/equity rates, and growth rates, that
could significantly impact the fair value of the asset being
tested for impairment.
The risk of long-lived asset impairment losses may increase to
the extent the Companys results of operations or cash
flows decline. Impairment losses may result in a material,
non-cash write-down of long-lived assets or intangible assets.
Furthermore, impairment losses could have a material effect on
the Companys results of operations and shareholders
equity.
For assets to be disposed of, the Company reports long-lived
assets at the lower of carrying amount or fair value less cost
to sell.
83
WESTERN
REFINING, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Revenue
Recognition
Revenues for products sold are recorded upon delivery of the
products to customers, which is the point at which title is
transferred, the customer has the assumed risk of loss, and when
payment has been received or collection is reasonably assured.
Transportation, shipping, and handling costs incurred are
included in cost of products sold. Excise and other taxes
collected from customers and remitted to governmental
authorities are not included in revenues.
Cost
Classifications
Refining cost of products sold includes cost of crude oil, other
feedstocks, blendstocks, the costs of purchased finished
products, and transportation and distribution costs. Wholesale
cost of products sold includes the cost of fuel and lubricants,
transportation and distribution costs, and service parts and
labor. Retail cost of products sold includes costs for motor
fuels and for merchandise. Motor fuel cost of products sold
represents net cost for purchased fuel. Net cost of purchased
fuel excludes transportation and motor fuel taxes. Merchandise
cost of products sold includes merchandise purchases, net of
merchandise rebates and inventory shrinkage.
Refining direct operating expenses include direct costs of
labor, maintenance materials and services, chemicals and
catalysts, natural gas, utilities, and other direct operating
expenses. Wholesale direct operating expenses include direct
costs of labor, transportation expense, maintenance materials
and services, utilities, and other direct operating expenses.
Retail direct operating expenses include direct costs of labor,
maintenance materials and services, outside services, bank
charges, rent expense, utilities, and other direct operating
expenses. Direct operating expenses also include insurance
expense and property taxes.
Maintenance
Turnaround Expense
Refinery process units require periodic maintenance and repairs
that are commonly referred to as turnarounds. The
required frequency of the maintenance varies by unit, but
generally is every two to six years depending on the processing
unit involved. Turnaround costs are expensed as incurred.
Stock-Based
Compensation
The cost of employee services received in exchange for an award
of equity instruments granted under the Western Refining
Long-Term Incentive Plan and 2010 Incentive Plan of Western
Refining, Inc. is measured based on the grant date fair value of
the award. The fair value of each share of restricted stock
awarded was measured based on the market price at closing as of
the measurement date and is amortized on a straight-line basis
over the respective vesting periods.
As of December 31, 2010, there were 2,438,147 shares
of restricted stock outstanding. Although ownership of the
shares does not transfer to the recipients until the shares have
vested, recipients have voting and dividend rights on these
shares from the date of grant. See Note 17, Stock-Based
Compensation.
Financial
Instruments and Fair Value
Financial instruments that potentially subject the Company to
concentrations of credit risk primarily consist of accounts
receivable. Credit risk is minimized as a result of the credit
quality of the Companys customer base. No customer
accounted for more than 10% of the Companys consolidated
net sales in 2010. The carrying amounts of cash equivalents,
accounts receivable, accounts payable, accrued liabilities, and
amounts outstanding under the Companys Revolving Credit
Agreement approximate their fair values due to their short-term
maturities.
The Company enters into crude oil forward contracts to
facilitate the supply of crude oil to the refinery. These
contracts qualify for the normal purchases and normal sales
exception because the Company physically receives and delivers
the crude oil under the contracts and when the Company enters
into these contracts, the quantities are
84
WESTERN
REFINING, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
expected to be used or sold over a reasonable period of time in
the normal course of business. These transactions are reflected
in cost of products sold in the period in which delivery of the
crude oil takes place.
In addition, the Company maintains a refined products pricing
strategy, which includes the use of refined product futures,
swap contracts, or options to minimize fluctuations in earnings
caused by the volatility of refined product prices. The
estimated fair values of refined product futures, swap
contracts, and options are based on quoted market prices and
generally have maturities of three months or less. These
transactions historically have not qualified for hedge
accounting and, accordingly, these instruments are marked to
market at each period end and are included in other current
assets or other current liabilities. Gains and losses related to
these instruments are included in the Consolidated Statements of
Operations within cost of products sold.
The Company does not believe that there is a significant credit
risk associated with the Companys derivative instruments,
which are transacted through counterparties meeting established
collateral and credit criteria. Generally, the Company does not
require collateral from counterparties.
See Note 4, Fair Value Measurement; Note 13,
Long-Term Debt; Note 15, Retirement Plans; and
Note 16, Crude Oil and Refined Product Risk Management
for further fair value disclosures.
Pension
and Other Postretirement Obligations
Pension and other postretirement plan expenses and liabilities
are determined on an actuarial basis and are affected by the
market value of plan assets, estimates of the expected return on
plan assets, and assumed discount rates and demographic data.
Pension and other postretirement plan expenses and liabilities
are determined based on actuarial valuations. Inherent in these
valuations are key assumptions including discount rates, future
compensation increases, expected return on plan assets, health
care cost trends, and demographic data. Changes in our actuarial
assumptions are primarily influenced by factors outside of our
control and can have a significant effect on our pension and
other postretirement liabilities and costs. A defined benefit
postretirement plan sponsor must (a) recognize in its
statement of financial position an asset for a plans
overfunded status or liability for the plans underfunded
status, (b) measure the plans assets and obligations
that determine its funded status as of the end of the
employers fiscal year, and (c) recognize, as a
component of other comprehensive income, the changes in the
funded status of the plan that arise during the year but are not
recognized as components of net periodic benefit cost. See
Note 15, Retirement Plans.
Asset
Retirement Obligations
The Company recognizes the fair value of a liability for an
asset retirement obligation (ARO) in the period in
which it is incurred if a reasonable estimate of fair value can
be made. The associated asset retirement costs are capitalized
as part of the carrying amount of the long-lived asset. The
increase in the ARO due to the passage of time is recorded as an
operating expense (accretion expense). See Note 12,
Asset Retirement Obligations.
Environmental
and Other Loss Contingencies
The Company records liabilities for loss contingencies,
including environmental remediation costs when such losses are
probable and can be reasonably estimated. Environmental costs
are expensed if they relate to an existing condition caused by
past operations with no future economic benefit. Estimates of
projected environmental costs are made based upon internal and
third-party assessments of contamination, available remediation
technology, and environmental regulations. Legal costs
associated with environmental remediation are included as part
of the estimated liability. Loss contingency accruals, including
those for environmental remediation are subject to revision as
further information develops or circumstances change and such
accruals can take into account the legal liability of other
parties. Recoveries of environmental remediation costs from
other parties are recorded as assets when the Company deems
their receipt probable. See Note 21, Contingencies.
85
WESTERN
REFINING, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
As a result of purchase accounting related to the Giant
acquisition, the majority of the Companys environmental
obligations are recorded on a discounted basis. Where the
available information is sufficient to estimate the amount of
liability, that estimate is used. Where the information is only
sufficient to establish a range of probable liability and no
point within the range is more likely than another, the lower
end of the range is used.
Income
Taxes
Income taxes are accounted for under the asset and liability
method. Deferred tax assets and liabilities are recognized to
reflect temporary differences between the basis of assets and
liabilities for financial reporting purposes and income tax
purposes. Deferred tax assets and liabilities are measured using
enacted tax rates expected to apply to taxable income in the
years in which those temporary differences are expected to be
recovered or settled. The effect on deferred tax assets and
liabilities of a change in tax rates is recognized in income in
the period that includes the enactment date. The Company
classifies interest to be paid on an underpayment of income
taxes and any related penalties as income tax expense.
Use of
Estimates
The preparation of financial statements in conformity with
U.S. GAAP requires management to make estimates and
assumptions that affect the reported amounts of assets and
liabilities and disclosure 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.
Reclassifications
Cost of products sold for the years ended December 31, 2009
and 2008 includes $21.7 million in economic hedging losses
and $11.4 million in economic hedging gains, respectively,
previously reported as gain (loss) from derivative activities
under other income (expense) in the 2009 and 2008 Consolidated
Statements of Operations. These prior year reclassifications
were made to conform to the current presentation. Inclusion of
these amounts in cost of products sold for the period provides a
better matching of costs to revenues than the Companys
previous presentation as all related derivative trading activity
is for the purpose of reducing the Companys exposure to
crude oil, other feedstock, and refined product price risk. Cost
of products sold for the year ended December 31, 2010
includes $9.4 million in economic hedging losses.
Recent
Accounting Pronouncements
From time to time, new accounting pronouncements are issued by
the Financial Accounting Standards Board or other standard
setting bodies that may have an impact on the Companys
accounting and reporting. The Company believes that such
recently issued accounting pronouncements and other
authoritative guidance for which the effective date is in the
future either will not have an impact on its accounting or
reporting or that such impact will not be material to its
financial position, results of operations, and cash flows when
implemented.
The Company is organized into three operating segments based on
manufacturing and marketing criteria and the nature of their
products and services, their production processes, and their
types of customers. These segments are the refining group, the
wholesale group, and the retail group. See Note 22,
Concentration of Risk, for a discussion on significant
customers. A description of each segment and its principal
products follows:
Refining Group. The Companys refining
group currently operates two refineries: one in El Paso,
Texas (the El Paso refinery) and one near
Gallup, New Mexico (the Gallup refinery). The
refining group also operates a crude oil transportation and
gathering pipeline system in New Mexico, an asphalt plant in
El Paso, three stand-alone refined product distribution
terminals, and four asphalt terminals. The two refineries make
various grades of
86
WESTERN
REFINING, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
gasoline, diesel fuel, and other products from crude oil, other
feedstocks, and blending components. The Company purchases crude
oil, other feedstocks, and blending components from various
suppliers. The Company also acquires refined products through
exchange agreements and from various third-party suppliers. The
Company sells these products through its own service stations,
its own wholesale group, independent wholesalers and retailers,
commercial accounts, and sales and exchanges with major oil
companies.
The economic slowdown that began in 2008 and continued into 2010
has reduced demand for refined products, thereby putting
significant pressure on refined product margins. Beginning in
the second quarter of 2009, price differentials between sour and
heavy crude oil and light sweet crude oil narrowed
significantly. Narrow heavy sour crude oil differentials
negatively impacted the results of operations for the Yorktown
refinery. Due to these economic conditions at December 31,
2009, the Company performed an impairment analysis of its
Yorktown long-lived and intangible assets. This analysis
indicated that the December 31, 2009 carrying value of the
Yorktown long-lived assets was recoverable. Continuing losses
due to narrow heavy light crude oil differentials, poor coking
economics, changes in Yorktown crude oil purchase contract
terms, and potentially significant regulatory capital spending
requirements caused the Company to temporarily suspend its
Yorktown refining operations during the third quarter of 2010.
Accordingly, the Company revised its cash flow forecasts used in
its analysis for long-lived asset impairment at the Yorktown
refinery to reflect these changes in operations at the Yorktown
facility as of June 30, 2010. The revised cash flows used
in the Companys June 30, 2010 impairment analysis
assumes that refining operations will be temporarily suspended
and that the Yorktown facility will be operated as a refined
product terminal in the near term and that restart activities
will begin no later than the middle of 2013. The Companys
revised forecast includes estimates and assumptions that require
considerable judgment and are based on the Companys
historical production volumes and throughputs, industry
analysts forecasts of refining margins and heavy light
crude oil differentials, financial forecasts, and industry
trends and conditions. The cash flow model assumes an $86.00
average cost per barrel of crude oil and that the heavy light
crude oil differentials realized at Yorktown will return to
historical levels of between $6.50 and $7.00 per barrel within
the next two to three years. Increases in the average cost per
barrel of crude oil without a corresponding increase in the
heavy light crude oil differential could negatively impact the
forecasted cash flows. The Companys forecast also assumes
sustained gross refining margins and throughputs similar to
historical levels achieved at the Yorktown refinery in 2008 with
an average per barrel margin of $8.70 and an annual average
throughput of 69,800 barrels per day. Based on the
analysis, the Company determined that the undiscounted
forecasted cash flows exceeded the carrying amount of its
Yorktown long-lived and intangible assets as of June 30,
2010. No significant changes have occurred since the Company
performed its analysis that would require it to revise its
June 30, 2010 impairment analysis.
Due to the uncertainty of various assumptions used the potential
for future impairment remains. The longer the period of dormancy
of the refining equipment, the more problematic a restart of
reliable refining operations can become. The Company currently
anticipates a six to nine month pre-restart maintenance period
will be required before the Yorktown refinery can be restarted,
at an estimated cost of at least $50.0 million, which
includes the cost of a maintenance turnaround. If it becomes
apparent to management in the future that the Company will not
restart the refining operations, or if its future cash flow
forecasts change significantly, an indication of potential
impairment could exist at that time. Impairments related to
Yorktown could have a material impact on the Companys
results of operations. The carrying value of the long-lived
assets related to refining operations that were temporarily
idled could be subject to impairment upon a change in
managements plans to restart refinery operations within
three years. The carrying value of total long-lived and
intangible assets at Yorktown as of December 31, 2010 was
$678.5 million, of which $472.4 million are related to
Yorktown refining assets.
In the fourth quarter of 2009, the Company announced its plans
to indefinitely suspend the refining operations at its
Bloomfield refinery and maintain the site as a product
distribution terminal and crude oil storage facility.
Accordingly, the Company tested the Bloomfield refinery
long-lived assets and certain intangible assets for
recoverability and determined that $41.8 million and
$11.0 million in related refinery fixed and intangible
assets, respectively, were impaired. During the fourth quarter
of 2010, the Company recorded an additional impairment charge of
$9.1 million resulting from its fourth quarter 2010
analysis of specific assets that the Company had
87
WESTERN
REFINING, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
previously planned to relocate from the Bloomfield facility to
the Gallup refinery. Based on sustainable operational
improvements at the Gallup refinery during 2010 that were beyond
what management had anticipated at the time of the Bloomfield
refinery idling, the Company has determined that one of the
three assets set aside for relocation to Gallup was no longer
required to attain the Companys desired levels of
production. Impairment losses of $9.1 million and
$52.8 million related to Bloomfield long-lived assets and
certain intangible assets are included under other impairment
losses in the Consolidated Statements of Operations for the
years ended December 31, 2010 and 2009, respectively. The
Company currently plans to relocate and place the remaining
Bloomfield refining assets with a net book value of
$12.4 million at December 31, 2010 into service at the
Gallup refinery during the maintenance turnaround scheduled for
2012.
During the third quarter of 2010, the Company permanently closed
its product distribution terminal in Flagstaff, Arizona. The
Company completed an impairment analysis of the Flagstaff
terminal long-lived assets and determined from this analysis
that the assets were fully impaired. Accordingly, an impairment
charge of $3.8 million related to the Flagstaff long-lived
assets is included in other impairment losses in the
Consolidated Statements of Operations for the year ended
December 31, 2010.
Wholesale Group. The Companys wholesale
group includes several lubricant and bulk petroleum distribution
plants, unmanned fleet fueling operations, a bulk lubricant
terminal facility, and a fleet of refined product and lubricant
delivery trucks. The wholesale group distributes commercial
wholesale petroleum products primarily in Arizona, California,
Colorado, Nevada, New Mexico, Texas, and Utah. The
Companys wholesale group purchases petroleum fuels and
lubricants from suppliers and from the refining group.
Retail Group. The Companys retail group
operates service stations that include convenience stores or
kiosks. The service stations sell various grades of gasoline,
diesel fuel, general merchandise, and beverage and food products
to the general public. The Companys wholesale group
supplies the gasoline and diesel fuel that the retail group
sells. The Company purchases general merchandise and beverage
and food products from various suppliers. At December 31,
2010, the Companys retail group operated 150 service
stations, including one non-fuel convenience store in Arizona,
New Mexico, and Colorado.
Segment Accounting Principles. Operating
income for each segment consists of net revenues less cost of
products sold; direct operating expenses; selling, general, and
administrative expenses; maintenance turnaround expense; and
depreciation and amortization. Cost of products sold reflects
current costs adjusted, where appropriate, for LIFO and lower of
cost or market (LCM) inventory adjustments.
Intersegment revenues are reported at prices that approximate
market.
Operations that are not included in any of the three segments
mentioned above are included in the category Other. These
operations consist primarily of corporate staff operations and
other items not considered to be related to the normal business
operations of the other segments. Other items of income and
expense not specifically related to the other segments,
including income taxes, are not allocated to operating segments.
The total assets of each segment consist primarily of cash and
cash equivalents; net property, plant, and equipment;
inventories; net accounts receivable; and other assets directly
associated with the individual segments operations.
Included in the total assets of the corporate operations are
cash and cash equivalents; various accounts receivable, net of
reserve for doubtful accounts; property, plant, and equipment;
and other long-term assets.
The Company temporarily suspended its Yorktown refinery
operations in September 2010. No impairment charges resulted
from the suspension of refinery operations. Severance and other
costs of $7.0 million were incurred related to this
temporary suspension of operations. There were no significant
terminated contract costs incurred. All costs have either been
paid or accrued at December 31, 2010. These severance and
other costs have been included in direct operating expenses and
selling, general, and administrative expenses in the
Consolidated Statement of Operations for the year ended
December 31, 2010. The Company also ceased operating its
refined product distribution terminal located in Flagstaff,
Arizona. The Companys impairment analysis resulted in
impairment
88
WESTERN
REFINING, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
charges that have been included in other impairment losses in
the accompanying Consolidated Statement of Operations for the
year ended December 31, 2010.
During the second quarter of 2009, in performing its annual
impairment analysis, the Company determined that the entire
balance of its goodwill of $299.6 million that was reported
under four of its six reporting units was impaired. Related
impairment charges have been reported under goodwill impairment
loss in the accompanying Consolidated Statement of Operations
for the year ended December 31, 2009.
Disclosures regarding the Companys reportable segments
with reconciliations to consolidated totals for the three years
ended December 31, 2010 are presented below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2010
|
|
|
|
Refining Group(3)
|
|
|
Wholesale Group(2)
|
|
|
Retail Group
|
|
|
Other
|
|
|
Consolidated
|
|
|
|
(In thousands)
|
|
|
Net sales to external customers
|
|
$
|
5,327,570
|
|
|
$
|
1,942,527
|
|
|
$
|
694,956
|
|
|
$
|
|
|
|
$
|
7,965,053
|
|
Intersegment revenues(1)
|
|
|
2,742,549
|
|
|
|
528,059
|
|
|
|
23,413
|
|
|
|
|
|
|
|
|
|
Operating income (loss) before impairment losses
|
|
|
132,322
|
|
|
|
20,726
|
|
|
|
16,358
|
|
|
|
(50,933
|
)
|
|
|
118,473
|
|
Other impairment losses
|
|
|
(12,832
|
)
|
|
|
|
|
|
|
|
|
|
|
(206
|
)
|
|
|
(13,038
|
)
|
Operating income (loss) after impairment losses
|
|
$
|
119,490
|
|
|
$
|
20,726
|
|
|
$
|
16,358
|
|
|
$
|
(51,139
|
)
|
|
$
|
105,435
|
|
Other income (expense), net
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(148,561
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss before income taxes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
(43,126
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization
|
|
$
|
118,661
|
|
|
$
|
5,069
|
|
|
$
|
10,245
|
|
|
$
|
4,646
|
|
|
$
|
138,621
|
|
Capital expenditures
|
|
|
71,751
|
|
|
|
726
|
|
|
|
4,940
|
|
|
|
678
|
|
|
|
78,095
|
|
Total assets at December 31, 2010
|
|
|
2,253,882
|
|
|
|
163,929
|
|
|
|
155,999
|
|
|
|
54,336
|
|
|
|
2,628,146
|
|
|
|
|
(1) |
|
Intersegment revenues of $3,294.0 million have been
eliminated in consolidation. |
|
(2) |
|
Wholesale group fuel sales volumes included 113.0 million
gallons sold to the Retail group that in prior years were sold
to the Retail group by the Refining group. The average sales
price for these gallons was $2.64 per gallon. |
|
(3) |
|
Included in refining assets are $12.4 million in long-lived
assets currently located at the Bloomfield facility that the
Company intends to relocate and place into service at the Gallup
refinery. The Company currently plans to place these assets in
service during the scheduled 2012 maintenance turnaround. Also
included in refining assets are $472.4 million in
long-lived and intangible assets that the Company has
temporarily idled at the Yorktown facility. See related
discussion above. Unforeseen circumstances could alter the
Companys planned time lines or prevent full utilization of
these assets in the future. As such, risk of partial or full
impairment exists. |
89
WESTERN
REFINING, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2009
|
|
|
|
Refining Group
|
|
|
Wholesale Group
|
|
|
Retail Group
|
|
|
Other
|
|
|
Consolidated
|
|
|
|
(In thousands)
|
|
|
Net sales to external customers
|
|
$
|
4,756,868
|
|
|
$
|
1,440,493
|
|
|
$
|
610,007
|
|
|
$
|
|
|
|
$
|
6,807,368
|
|
Intersegment revenues(1)
|
|
|
1,851,207
|
|
|
|
223,904
|
|
|
|
19,931
|
|
|
|
|
|
|
|
|
|
Operating income (loss) before impairment losses
|
|
$
|
143,240
|
|
|
$
|
10,530
|
|
|
$
|
15,442
|
|
|
$
|
(55,902
|
)
|
|
$
|
113,310
|
|
Goodwill impairment losses
|
|
|
(230,712
|
)
|
|
|
(41,230
|
)
|
|
|
(27,610
|
)
|
|
|
|
|
|
|
(299,552
|
)
|
Other impairment losses(2)
|
|
|
(52,788
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(52,788
|
)
|
Operating loss after impairment losses
|
|
$
|
(140,260
|
)
|
|
$
|
(30,700
|
)
|
|
$
|
(12,168
|
)
|
|
$
|
(55,902
|
)
|
|
$
|
(239,030
|
)
|
Other income (expense), net
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(152,174
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss before income taxes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
(391,204
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization
|
|
$
|
125,537
|
|
|
$
|
5,616
|
|
|
$
|
9,820
|
|
|
$
|
5,008
|
|
|
$
|
145,981
|
|
Capital expenditures
|
|
|
110,172
|
|
|
|
864
|
|
|
|
3,411
|
|
|
|
1,407
|
|
|
|
115,854
|
|
Total assets at December 31, 2009
|
|
|
2,386,751
|
|
|
|
154,518
|
|
|
|
158,987
|
|
|
|
124,398
|
|
|
|
2,824,654
|
|
|
|
|
(1) |
|
Intersegment revenues of $2,095.0 million have been
eliminated in consolidation. |
|
(2) |
|
During the fourth quarter of 2009, as a result of the indefinite
suspension of refining operations at the Bloomfield refinery,
the Company determined that $52.8 million of long-lived
assets were impaired. |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2008
|
|
|
|
Refining Group
|
|
|
Wholesale Group
|
|
|
Retail Group
|
|
|
Other
|
|
|
Consolidated
|
|
|
|
(In thousands)
|
|
|
Net sales to external customers
|
|
$
|
7,988,657
|
|
|
$
|
1,943,458
|
|
|
$
|
793,466
|
|
|
$
|
|
|
|
$
|
10,725,581
|
|
Intersegment revenues(1)
|
|
|
2,466,945
|
|
|
|
336,083
|
|
|
|
44,731
|
|
|
|
|
|
|
|
|
|
Operating income (loss)
|
|
$
|
221,083
|
|
|
$
|
22,095
|
|
|
$
|
14,122
|
|
|
$
|
(58,004
|
)
|
|
$
|
199,296
|
|
Other income (expense), net
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(114,875
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
84,421
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization
|
|
$
|
95,713
|
|
|
$
|
5,551
|
|
|
$
|
8,479
|
|
|
$
|
3,868
|
|
|
$
|
113,611
|
|
Capital expenditures
|
|
|
201,931
|
|
|
|
5,702
|
|
|
|
7,865
|
|
|
|
6,790
|
|
|
|
222,288
|
|
Total assets, excluding goodwill, at December 31, 2008
|
|
$
|
2,354,105
|
|
|
$
|
142,879
|
|
|
$
|
165,950
|
|
|
$
|
114,306
|
|
|
$
|
2,777,240
|
|
Goodwill
|
|
|
230,712
|
|
|
|
41,230
|
|
|
|
27,610
|
|
|
|
|
|
|
|
299,552
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets at December 31, 2008
|
|
$
|
2,584,817
|
|
|
$
|
184,109
|
|
|
$
|
193,560
|
|
|
$
|
114,306
|
|
|
$
|
3,076,792
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Intersegment revenues of $2,847.8 million have been
eliminated in consolidation. |
90
WESTERN
REFINING, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The changes in the carrying amounts of goodwill for the years
ended December 31, 2009 and 2008 are presented below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Refining Group
|
|
|
Wholesale Group
|
|
|
Retail Group
|
|
|
Total
|
|
|
|
(In thousands)
|
|
|
Balances at January 1, 2008
|
|
$
|
248,343
|
|
|
$
|
23,599
|
|
|
$
|
27,610
|
|
|
$
|
299,552
|
|
Transfers between groups
|
|
|
(17,631
|
)
|
|
|
17,631
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balances at December 31, 2008
|
|
|
230,712
|
|
|
|
41,230
|
|
|
|
27,610
|
|
|
|
299,552
|
|
Impairment losses
|
|
|
(230,712
|
)
|
|
|
(41,230
|
)
|
|
|
(27,610
|
)
|
|
|
(299,552
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balances at December 31, 2009
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The assets and results of operations of a fleet of trucks
previously reported under the refining group were transferred to
the wholesale group during the second quarter of 2008. In
connection with this transfer, $17.6 million of goodwill
was transferred from the refining group to the wholesale group.
The Company believes these operations are more consistent with
the functions of the wholesale group. The results of operations
for this fleet of trucks for all years presented were reported
in the results of the wholesale segment.
|
|
4.
|
Fair
Value Measurement
|
On January 1, 2008, the Company adopted the accounting and
reporting provisions for its financial assets and liabilities
that require enhanced disclosures about assets and liabilities
measured at fair value. On January 1, 2009, the Company
adopted these provisions for its nonfinancial assets and
liabilities. The adoption of these standards did not have a
material effect on the Companys financial condition or
results of operations, and had no impact on methodologies used
by the Company in measuring the fair value of its assets and
liabilities.
The Company utilizes the market approach to measure fair value
for its financial assets and liabilities. The market approach
uses prices and other relevant information generated by market
transactions involving identical or comparable assets or
liabilities.
The Company uses a fair value hierarchy that is intended to
increase consistency and comparability in fair value
measurements and related disclosures. The fair value hierarchy
is based on inputs to valuation techniques that are used to
measure fair value that are either observable or unobservable.
Observable inputs reflect market participants assumptions
for use in pricing an asset or liability based on market data
obtained from independent sources while unobservable inputs
reflect a reporting entitys pricing based upon their own
market assumptions. The fair value hierarchy consists of the
following three levels:
|
|
|
|
|
|
Level 1
|
|
Inputs are quoted prices (unadjusted) in active markets for
identical assets or liabilities.
|
|
|
|
Level 2
|
|
Inputs are quoted prices for similar assets or liabilities in an
active market, quoted prices for identical or similar assets or
liabilities in markets that are not active, inputs other than
quoted prices that are observable, and market corroborated
inputs, which are derived principally from or corroborated by
observable market data.
|
|
|
|
Level 3
|
|
Inputs are derived from valuation techniques in which one or
more significant inputs or value drivers are unobservable and
cannot be corroborated by market data or other entity specific
inputs.
|
91
WESTERN
REFINING, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
For cash, trade receivables, and accounts payable, the fair
value approximated carrying value at December 31, 2010. The
following table represents the Companys assets measured at
fair value on a recurring basis as of December 31, 2010,
and the basis for that measurement:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurement at
|
|
|
|
|
December 31, 2010 Using
|
|
|
|
|
Quoted Prices
|
|
|
|
|
|
|
|
|
in Active
|
|
Significant
|
|
|
|
|
|
|
Markets for
|
|
Other
|
|
Significant
|
|
|
|
|
Identical Assets
|
|
Observable
|
|
Unobservable
|
|
|
Carrying Value at
|
|
or Liabilities
|
|
Inputs
|
|
Inputs
|
|
|
December 31, 2010
|
|
(Level 1)
|
|
(Level 2)
|
|
(Level 3)
|
|
|
(In thousands)
|
|
Financial liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative contracts
|
|
$
|
1,173
|
|
|
$
|
|
|
|
$
|
1,173
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurement at
|
|
|
|
|
December 31, 2009 Using
|
|
|
|
|
Quoted Prices
|
|
|
|
|
|
|
|
|
in Active
|
|
Significant
|
|
|
|
|
|
|
Markets for
|
|
Other
|
|
Significant
|
|
|
|
|
Identical Assets
|
|
Observable
|
|
Unobservable
|
|
|
Carrying Value at
|
|
or Liabilities
|
|
Inputs
|
|
Inputs
|
|
|
December 31, 2009
|
|
(Level 1)
|
|
(Level 2)
|
|
(Level 3)
|
|
|
(In thousands)
|
|
Financial assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Money market accounts
|
|
$
|
5,408
|
|
|
$
|
5,408
|
|
|
$
|
|
|
|
$
|
|
|
Financial liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative contracts
|
|
|
1,510
|
|
|
|
|
|
|
|
1,510
|
|
|
|
|
|
There have been no transfers between assets or liabilities whose
fair value is determined through the use of quoted prices in
active markets (Level 1) and those determined through
the use of significant other observable inputs (Level 2).
During the third and fourth quarters of 2010 and the fourth
quarter of 2009, the Company impaired certain long-lived assets
from its Bloomfield refinery and Flagstaff terminal. The
impairment was determined as the excess of the carrying values
of the respective assets over fair value. Fair value was
determined using unobservable inputs (Level 3). The
carrying value of the assets impaired during 2010 prior to
impairment was $14.2 million and $1.2 million after
impairment. The carrying value of the assets impaired during
2009 was $73.9 million prior to impairment and
$22.1 million after impairment.
Inventories were as follows:
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
|
(In thousands)
|
|
|
Refined products(1)
|
|
$
|
189,994
|
|
|
$
|
145,813
|
|
Crude oil and other raw materials
|
|
|
152,155
|
|
|
|
252,860
|
|
Lubricants
|
|
|
11,456
|
|
|
|
12,738
|
|
Convenience store merchandise
|
|
|
12,068
|
|
|
|
11,342
|
|
|
|
|
|
|
|
|
|
|
Inventories
|
|
$
|
365,673
|
|
|
$
|
422,753
|
|
|
|
|
|
|
|
|
|
|
92
WESTERN
REFINING, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
(1) |
|
Includes $10.0 million and $10.7 million of inventory
valued using the FIFO valuation method at December 31, 2010
and 2009, respectively. |
The Company values its crude oil, other raw materials, and
asphalt inventories at the lower of cost or market under the
LIFO valuation method. Other than refined products inventories
held by the Companys retail and wholesale groups, refined
products inventories are valued under the LIFO valuation method.
Lubricants and convenience store merchandise are valued under
the FIFO valuation method.
As of December 31, 2010 and 2009, refined products valued
under the LIFO method and crude oil and other raw materials
totaled 5.7 million barrels and 6.3 million barrels,
respectively. At December 31, 2010, the excess of the
current cost of these crude oil, refined product, and other
feedstock and blendstock inventories over LIFO cost was
$173.5 million. At December 31, 2009, the excess of
the current cost of these crude oil, refined product, and other
feedstock and blendstock inventories over LIFO cost was
$126.4 million.
The net effect of the change in the LCM reserve to value the
Companys Yorktown inventories to net realizable market
values on the Companys Consolidated Statements of
Operations and the net effect of inventory reductions that
resulted in the liquidation of applicable LIFO inventory levels
are summarized in the table below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
2010
|
|
2009
|
|
2008
|
|
|
(In thousands, except
|
|
|
per share amount)
|
|
Change in LCM reserve:
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss)
|
|
$
|
|
|
|
$
|
61,005
|
|
|
$
|
(61,005
|
)
|
Net income (loss)
|
|
|
|
|
|
|
33,992
|
|
|
|
(46,388
|
)
|
Earnings (loss) per diluted share
|
|
$
|
|
|
|
$
|
0.43
|
|
|
$
|
(0.68
|
)
|
Liquidation of LIFO layers:
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss)
|
|
$
|
16,886
|
|
|
$
|
9,366
|
|
|
$
|
(66,937
|
)
|
Net income (loss)
|
|
|
6,675
|
|
|
|
5,219
|
|
|
|
(50,899
|
)
|
Earnings (loss) per diluted share
|
|
$
|
0.08
|
|
|
$
|
0.07
|
|
|
$
|
(0.75
|
)
|
Average LIFO cost per barrel of the Companys refined
products and crude oil and other raw materials inventories as of
December 31, 2010 and 2009, is shown below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
|
|
|
|
|
|
|
Average
|
|
|
|
|
|
|
|
|
Average
|
|
|
|
|
|
|
|
|
|
LIFO
|
|
|
|
|
|
|
|
|
LIFO
|
|
|
|
|
|
|
|
|
|
Cost Per
|
|
|
|
|
|
|
|
|
Cost Per
|
|
|
|
Barrels
|
|
|
LIFO Cost
|
|
|
Barrel
|
|
|
Barrels
|
|
|
LIFO Cost
|
|
|
Barrel
|
|
|
|
(In thousands, except cost per barrel)
|
|
|
Refined products
|
|
|
2,574
|
|
|
$
|
180,031
|
|
|
$
|
69.94
|
|
|
|
2,135
|
|
|
$
|
135,087
|
|
|
$
|
63.27
|
|
Crude oil and other
|
|
|
3,115
|
|
|
|
152,155
|
|
|
|
48.85
|
|
|
|
4,194
|
|
|
|
221,374
|
|
|
|
52.78
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5,689
|
|
|
$
|
332,186
|
|
|
|
58.39
|
|
|
|
6,329
|
|
|
$
|
356,461
|
|
|
|
56.32
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
93
WESTERN
REFINING, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Prepaid expenses were as follows:
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
|
(In thousands)
|
|
|
Prepaid crude oil and other raw materials inventories
|
|
$
|
56,257
|
|
|
$
|
11,407
|
|
Prepaid insurance and other
|
|
|
15,678
|
|
|
|
17,809
|
|
|
|
|
|
|
|
|
|
|
Prepaid expenses
|
|
$
|
71,935
|
|
|
$
|
29,216
|
|
|
|
|
|
|
|
|
|
|
Other current assets were as follows:
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
|
(In thousands)
|
|
|
Materials and chemicals inventories
|
|
$
|
38,591
|
|
|
$
|
31,988
|
|
Derivative activities receivable
|
|
|
3,173
|
|
|
|
3,778
|
|
Income taxes receivable and prepaid
|
|
|
1,456
|
|
|
|
42,685
|
|
Spare parts inventories
|
|
|
747
|
|
|
|
781
|
|
Other
|
|
|
319
|
|
|
|
508
|
|
|
|
|
|
|
|
|
|
|
Other current assets
|
|
$
|
44,286
|
|
|
$
|
79,740
|
|
|
|
|
|
|
|
|
|
|
|
|
8.
|
Property,
Plant, and Equipment
|
Property, plant, and equipment were as follows:
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
|
(In thousands)
|
|
|
Refinery facilities and related equipment
|
|
$
|
1,733,803
|
|
|
$
|
1,712,295
|
|
Pipelines, terminals, and transportation equipment
|
|
|
91,149
|
|
|
|
94,485
|
|
Retail and wholesale facilities and related equipment
|
|
|
185,359
|
|
|
|
183,681
|
|
Other
|
|
|
20,856
|
|
|
|
20,537
|
|
Construction in progress
|
|
|
94,894
|
|
|
|
81,337
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,126,061
|
|
|
|
2,092,335
|
|
Accumulated depreciation
|
|
|
(437,907
|
)
|
|
|
(324,435
|
)
|
|
|
|
|
|
|
|
|
|
Property, plant, and equipment, net
|
|
$
|
1,688,154
|
|
|
$
|
1,767,900
|
|
|
|
|
|
|
|
|
|
|
Depreciation expense was $130.6 million,
$137.7 million, and $105.3 million for the years ended
December 31, 2010, 2009, and 2008, respectively.
The Company has a policy to test goodwill for impairment
annually or more frequently if indications of impairment exist.
Various indications of possible goodwill impairment prompted the
Company to perform goodwill impairment analyses at
December 31, 2008 and March 31, 2009. Management
determined that no such impairment existed as of those dates.
The Company performed its 2009 annual impairment test as of
June 30, 2009. Performance
94
WESTERN
REFINING, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
of the test is a two-step process. Step 1 of the impairment test
compares the fair values of the applicable reporting units with
their aggregate carrying values, including goodwill. If the
carrying amount of a reporting unit exceeds the reporting
units fair value, the Company performs Step 2 of the
goodwill impairment test to determine the amount of impairment
loss. Step 2 of the goodwill impairment test compares the
implied fair value of the affected reporting units
goodwill against the carrying value of that goodwill.
The Companys impairment testing of its goodwill in Step 1
is based on the estimated fair value of its reporting units.
This estimated fair value is determined based on discounted
expected future cash flows supported by various other market
based valuation methods including market capitalization,
earnings before interest expense, tax expense, depreciation, and
amortization (EBITDA) multiples, and refining
complexity barrels. The discounted cash flow model is sensitive
to changes in future cash flow forecasts and the discount rate
used. The market capitalization model is sensitive to changes in
the Companys traded stock price. The EBITDA and complexity
barrel models are sensitive to changes in recent historical
results of operations within the refining industry. The Company
compares and contrasts the results of the various valuation
models to determine if impairment exists at the end of a
reporting period. The estimates and assumptions used in
determining fair value of each reporting unit require
considerable judgment and were based on historical experience,
financial forecasts, and industry trends and conditions.
From the first to the second quarter of 2009, there was a
decline in margins within the refining industry as well as a
downward change in industry analysts forecasts for the
remainder of 2009 and 2010. This, along with other negative
financial forecasts released by independent refiners during the
latter part of the second quarter of 2009, contributed to
declines in common stock trading prices within the independent
refining sector, including declines in the Companys common
stock trading price. As a result, the Companys equity
market capitalization fell below the net book value of the
Companys assets. Through the filing date of the
Companys second quarter of 2009
Form 10-Q
and through the end of the fourth quarter of 2009, the trading
price of the Companys stock had experienced further
reductions.
The Company completed Step 1 of the impairment test during the
second quarter of 2009 and concluded that impairment existed.
The Company finalized its Step 2 analysis during the third
quarter of 2009, maintaining that the Companys prior
quarters assumptions and forecasts had not significantly
changed. Consistent with the preliminary Step 2 analysis
completed during the second quarter of 2009, the Company
concluded that all of its goodwill was impaired. The resulting
non-cash charge of $299.6 million was reported in the
Companys second quarter of 2009 results of operations.
There were no such impairment charges in the years ended
December 31, 2010 or 2008.
A summary of intangible assets is presented in the table below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2010
|
|
|
December 31, 2009
|
|
|
Weighted
|
|
|
|
Gross
|
|
|
|
|
|
Net
|
|
|
Gross
|
|
|
|
|
|
Net
|
|
|
Average
|
|
|
|
Carrying
|
|
|
Accumulated
|
|
|
Carrying
|
|
|
Carrying
|
|
|
Accumulated
|
|
|
Carrying
|
|
|
Amortization
|
|
|
|
Value
|
|
|
Amortization
|
|
|
Value
|
|
|
Value
|
|
|
Amortization
|
|
|
Value
|
|
|
Period (Years)
|
|
|
|
(In thousands)
|
|
|
|
|
|
Amortizable assets(1):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Licenses and permits
|
|
$
|
39,151
|
|
|
$
|
(10,698
|
)
|
|
$
|
28,453
|
|
|
$
|
39,151
|
|
|
$
|
(7,717
|
)
|
|
$
|
31,434
|
|
|
|
9.6
|
|
Customer relationships
|
|
|
6,300
|
|
|
|
(1,305
|
)
|
|
|
4,995
|
|
|
|
6,300
|
|
|
|
(885
|
)
|
|
|
5,415
|
|
|
|
11.9
|
|
Rights-of-way
|
|
|
6,525
|
|
|
|
(1,267
|
)
|
|
|
5,258
|
|
|
|
4,203
|
|
|
|
(905
|
)
|
|
|
3,298
|
|
|
|
6.5
|
|
Other
|
|
|
1,360
|
|
|
|
(670
|
)
|
|
|
690
|
|
|
|
1,149
|
|
|
|
(652
|
)
|
|
|
497
|
|
|
|
7.8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
53,336
|
|
|
|
(13,940
|
)
|
|
|
39,396
|
|
|
|
50,803
|
|
|
|
(10,159
|
)
|
|
|
40,644
|
|
|
|
|
|
Unamortizable assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Trademarks
|
|
|
4,800
|
|
|
|
|
|
|
|
4,800
|
|
|
|
5,300
|
|
|
|
|
|
|
|
5,300
|
|
|
|
|
|
Liquor licenses
|
|
|
15,749
|
|
|
|
|
|
|
|
15,749
|
|
|
|
15,749
|
|
|
|
|
|
|
|
15,749
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Intangible assets, net
|
|
$
|
73,885
|
|
|
$
|
(13,940
|
)
|
|
$
|
59,945
|
|
|
$
|
71,852
|
|
|
$
|
(10,159
|
)
|
|
$
|
61,693
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
95
WESTERN
REFINING, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
(1) |
|
During the fourth quarter of 2009, as a result of the indefinite
suspension of refining operations at the Bloomfield refinery,
the Company recorded an $11.0 million impairment of
refining licenses and technology permits. |
Intangible asset amortization expense for the three years ended
December 31, 2010 was $4.0 million, $4.6 million,
and $4.8 million, respectively, based upon estimates of
useful lives ranging from 3 to 15 years. Estimated
amortization expense for the next five fiscal years is as
follows (in thousands):
|
|
|
|
|
2011
|
|
$
|
4,651
|
|
2012
|
|
|
4,626
|
|
2013
|
|
|
4,342
|
|
2014
|
|
|
4,151
|
|
2015
|
|
|
3,673
|
|
|
|
10.
|
Other
Assets, Net of Amortization
|
Other assets, net of amortization, were as follows:
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
|
(In thousands)
|
|
|
Unamortized loan fees
|
|
$
|
38,930
|
|
|
$
|
35,841
|
|
Other
|
|
|
15,414
|
|
|
|
15,062
|
|
|
|
|
|
|
|
|
|
|
Other assets, net of amortization
|
|
$
|
54,344
|
|
|
$
|
50,903
|
|
|
|
|
|
|
|
|
|
|
Accrued liabilities were as follows:
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
|
(In thousands)
|
|
|
Excise taxes
|
|
$
|
39,086
|
|
|
$
|
34,898
|
|
Payroll and related costs
|
|
|
28,987
|
|
|
|
35,293
|
|
Professional fees and other
|
|
|
21,661
|
|
|
|
22,480
|
|
Property taxes
|
|
|
11,323
|
|
|
|
10,536
|
|
Environmental reserve
|
|
|
10,565
|
|
|
|
8,024
|
|
Short-term pension obligation
|
|
|
7,084
|
|
|
|
3,015
|
|
Interest
|
|
|
3,672
|
|
|
|
4,323
|
|
|
|
|
|
|
|
|
|
|
Accrued liabilities
|
|
$
|
122,378
|
|
|
$
|
118,569
|
|
|
|
|
|
|
|
|
|
|
|
|
12.
|
Asset
Retirement Obligations
|
The Company determines the estimated fair value of its AROs
based on the estimated current cost escalated to an inflation
rate and discounted at a credit adjusted risk free rate. This
liability is capitalized as part of the cost of the related
asset and amortized using the straight-line method. The
liability accretes until the Company settles the liability. The
legally restricted assets that are set aside for purposes of
settling ARO liabilities were $0.4 million as of
December 31, 2010, and are included in other assets, net in
the Companys Consolidated Balance Sheets. These assets are
set aside to fund costs associated with the closure of certain
solid waste management facilities.
96
WESTERN
REFINING, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The Company has identified the following AROs:
Landfills. Pursuant to Virginia law, the two
solid waste management facilities at the Yorktown refinery must
satisfy closure and post-closure care and financial
responsibility requirements.
Crude Pipelines. The Companys
right-of-way
agreements generally require that pipeline properties be
returned to their original condition when the agreements are no
longer in effect. This means that the pipeline surface
facilities must be dismantled and removed and certain site
reclamation performed. The Company does not believe these
right-of-way
agreements will require it to remove the underground pipe upon
taking the pipeline permanently out of service. Regulatory
requirements, however, may mandate that such out of service
underground pipe be purged at the time the pipelines are taken
permanently out of service.
Storage Tanks. The Company has a legal
obligation under applicable law to remove or close in place
certain underground and aboveground storage tanks, both on owned
property and leased property, once they are taken out of
service. Under some lease arrangements, the Company has also
committed to restore the leased property to its original
condition.
Other. The Company identified certain refinery
piping and heaters as a conditional ARO since it has the legal
obligation to properly remove or dispose of materials that
contain asbestos that surround certain refinery piping and
heaters.
The following table reconciles the beginning and ending
aggregate carrying amount of the Companys AROs for the
years ended December 31, 2010 and 2009:
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
|
(In thousands)
|
|
|
Liability, beginning of period
|
|
$
|
5,326
|
|
|
$
|
4,991
|
|
Liabilities incurred
|
|
|
33
|
|
|
|
|
|
Liabilities settled
|
|
|
(229
|
)
|
|
|
(10
|
)
|
Accretion expense
|
|
|
355
|
|
|
|
345
|
|
|
|
|
|
|
|
|
|
|
Liability, end of period
|
|
$
|
5,485
|
|
|
$
|
5,326
|
|
|
|
|
|
|
|
|
|
|
Long-term debt was as follows:
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
|
(In thousands)
|
|
|
11.25% Senior Secured Notes, due 2017, net of unamortized
discount of $24,619 and $26,943, respectively
|
|
$
|
300,382
|
|
|
$
|
298,057
|
|
Floating Rate Senior Secured Notes, due 2014, net of unamortized
discount of $16,822 and $20,467, respectively
|
|
|
258,177
|
|
|
|
254,533
|
|
5.75% Senior Convertible Notes, due 2014, net of conversion
feature of $46,285 and $56,183, respectively
|
|
|
169,165
|
|
|
|
159,267
|
|
Term Loan, due 2014
|
|
|
341,807
|
|
|
|
354,807
|
|
Revolving Credit Agreement, due 2015
|
|
|
|
|
|
|
50,000
|
|
|
|
|
|
|
|
|
|
|
Total long-term debt
|
|
|
1,069,531
|
|
|
|
1,116,664
|
|
Current portion of long-term debt
|
|
|
(63,000
|
)
|
|
|
(63,000
|
)
|
|
|
|
|
|
|
|
|
|
Long-term debt, net of current portion
|
|
$
|
1,006,531
|
|
|
$
|
1,053,664
|
|
|
|
|
|
|
|
|
|
|
97
WESTERN
REFINING, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Amounts outstanding under the Revolving Credit Agreement are
included in the current portion of long-term debt. Estimated
mandatory principal prepayments of $50.0 million related to
the annual excess cash flows requirements under the Term Loan
Credit Agreement (Term Loan) are included in the
current portion of long-term debt at December 31, 2010.
These prepayments are scheduled to be made by the end of the
first quarter of 2011.
Interest expense and other financing costs were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands)
|
|
|
Contractual interest:
|
|
|
|
|
|
|
|
|
|
|
|
|
11.25% Senior Secured Notes
|
|
$
|
36,563
|
|
|
$
|
20,211
|
|
|
$
|
|
|
Floating Senior Secured Notes
|
|
|
29,973
|
|
|
|
16,670
|
|
|
|
|
|
5.75% Senior Convertible Notes
|
|
|
12,388
|
|
|
|
6,848
|
|
|
|
|
|
Term loan
|
|
|
37,611
|
|
|
|
66,459
|
|
|
|
89,757
|
|
Revolving Credit Agreement
|
|
|
5,036
|
|
|
|
835
|
|
|
|
7,414
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
121,571
|
|
|
|
111,023
|
|
|
|
97,171
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amortization of original issuance discount:
|
|
|
|
|
|
|
|
|
|
|
|
|
11.25% Senior Secured Notes
|
|
|
2,324
|
|
|
|
861
|
|
|
|
|
|
Floating Senior Secured Notes
|
|
|
3,645
|
|
|
|
1,533
|
|
|
|
|
|
5.75% Senior Convertible Notes
|
|
|
9,898
|
|
|
|
4,697
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
15,867
|
|
|
|
7,091
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other interest expense
|
|
|
13,359
|
|
|
|
9,622
|
|
|
|
14,966
|
|
Capitalized interest
|
|
|
(4,248
|
)
|
|
|
(6,415
|
)
|
|
|
(9,935
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
146,549
|
|
|
$
|
121,321
|
|
|
$
|
102,202
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Senior Secured Notes. In June 2009, the
Company issued two tranches of Senior Secured Notes under an
indenture dated June 12, 2009. The first tranche consisted
of $325.0 million in aggregate principal amount of
11.25% Senior Secured Notes (the Fixed Rate
Notes). The second tranche consisted of
$275.0 million Senior Secured Floating Rate Notes (the
Floating Rate Notes, and together with the Fixed
Rate Notes, the Senior Secured Notes). The Fixed
Rate Notes pay interest semi-annually in cash in arrears on June
15 and December 15 of each year at a rate of 11.25% per annum
and will mature on June 15, 2017. The Fixed Rate Notes may
be redeemed by the Company at the Companys option
beginning on June 15, 2013 through June 14, 2014 at a
premium of 5.625%; from June 15, 2014 through June 14,
2015 at a premium of 2.813%; and at par thereafter. As of
December 31, 2010, the fair value of the Fixed Rate Notes
was $347.8 million.
The Floating Rate Notes pay interest quarterly at a per annum
rate, reset quarterly, equal to three-month LIBOR (subject to a
LIBOR floor of 3.25%) plus 7.50% and will mature on
June 15, 2014. The interest rate on the Floating Rate Notes
as of December 31, 2010 was 10.75%. The Floating Rate Notes
may be redeemed by the Company at the Companys option
beginning on December 15, 2011 through June 14, 2012
at a premium of 5.0%; from June 15, 2012 through
June 14, 2013 at a premium of 3.0%; and at a premium of
1.0% thereafter. The fair value of the Floating Rate Notes was
$291.5 million at December 31, 2010. The Company is
amortizing the original issue discounts using the effective
interest rate method over the life of the notes. The combined
proceeds from the issuance and sale of the Senior Secured Notes
were used to repay a portion of the outstanding indebtedness
under the Term Loan. Proceeds from the issuance of the Fixed
Rate Notes were $290.7 million, net of an original issue
discount of $27.8 million and underwriting discounts of
$6.5 million. Proceeds from the issuance of the Floating
98
WESTERN
REFINING, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Rate Notes were $247.5 million, net of original issue
discount of $22.0 million and underwriting discounts of
$5.5 million. The Company paid $2.1 million in other
financing costs related to the Senior Secured Notes in 2009.
The Senior Secured Notes are guaranteed by all of the
Companys domestic restricted subsidiaries in existence on
the date the Senior Secured Notes were issued. The Senior
Secured Notes will also be guaranteed by all future wholly-owned
domestic restricted subsidiaries and by any restricted
subsidiary that guarantees any of the Companys
indebtedness under credit facilities that are secured by a lien
on the collateral securing the Senior Secured Notes. The Senior
Secured Notes are also secured on a first priority basis,
equally and ratably with the Companys Term Loan and any
future other pari passu secured obligation, by the collateral
securing the Term Loan, which consists of the Companys
fixed assets, and on a second priority basis, equally and
ratably with the Term Loan and any future other pari passu
secured obligation, by the collateral securing the Revolving
Credit Agreement, which consists of the Companys cash and
cash equivalents, trade accounts receivables, and inventory.
The indenture governing the Senior Secured Notes contains
covenants that limit the Companys (and most of its
subsidiaries) ability to, among other things: (i) pay
dividends or make other distributions in respect of their
capital stock or make other restricted payments; (ii) make
certain investments; (iii) sell certain assets;
(iv) incur additional debt or issue certain preferred
shares; (v) create liens on certain assets to secure debt;
(vi) consolidate, merge, sell or otherwise dispose of all
or substantially all of their assets; (vii) restrict
dividends or other payments from restricted subsidiaries; and
(viii) enter into certain transactions with their
affiliates. These covenants are subject to a number of important
limitations and exceptions. The indenture governing the Senior
Secured Notes also provides for events of default, which, if any
of them occur, would permit or require the principal, premium,
if any, and interest on all then outstanding Senior Secured
Notes to be due and payable immediately.
The Company may issue additional notes from time to time
pursuant to the indenture governing the Senior Secured Notes.
Convertible Senior Notes. The Company issued
and sold $215.5 million in aggregate principal amount of
its 5.75% Senior Convertible Notes due 2014 (the
Convertible Senior Notes) during June and July 2009.
The Convertible Senior Notes are unsecured and pay interest
semi-annually in arrears at a rate of 5.75% per year beginning
on December 15, 2009. The Convertible Senior Notes will
mature on June 15, 2014. The initial conversion rate for
the Convertible Senior Notes is 92.5926 shares of common
stock per $1,000 principal amount of Convertible Senior Notes
(equivalent to an initial conversion price of approximately
$10.80 per share of common stock). In lieu of delivery of shares
of common stock in satisfaction of the Companys obligation
upon conversion of the Convertible Senior Notes, the Company may
elect to settle conversions entirely in cash or by net share
settlement. Proceeds from the issuance of the Convertible Senior
Notes of $209.0 million, net of underwriting discounts of
$6.5 million, were used to repay a portion of outstanding
indebtedness under the Term Loan. Issuers of convertible debt
instruments that may be settled in cash upon conversion
(including partial cash settlement) are required to separately
account for the liability and equity (conversion feature)
components of the instruments in a manner reflective of the
issuers nonconvertible debt borrowing rate. The borrowing
rate used by the Company to determine the liability and equity
components of the Convertible Senior Notes was 13.75%. The
Company paid $0.5 million in other financing costs related
to the Convertible Senior Notes in 2009. The Company valued the
conversion feature at June 30, 2009 at $60.9 million
and recorded additional paid-in capital of $36.3 million,
net of deferred income taxes of $22.6 million and
transaction costs of $2.0 million, related to the equity
portion of this convertible debt. The discount on the
Convertible Senior Notes is amortized using the effective
interest method through maturity on June 15, 2014. As of
December 31, 2010, the fair value of the Convertible Senior
Notes was $275.5 million and the if-converted value is less
than its principal amount.
Term Loan Credit Agreement. The Term Loan has
a maturity date of May 30, 2014. The Term Loan is secured
on a first priority basis, together with the Senior Secured
Notes and any future other pari passu secured obligations, by
the Companys fixed assets, and on a second priority basis,
together with the Senior Secured Notes and any future other pari
passu secured obligations, by the collateral securing the
Revolving Credit Agreement, which consists of the Companys
cash and cash equivalents, trade accounts receivable, and
inventory. The Term
99
WESTERN
REFINING, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Loan provides for principal payments on a quarterly basis of
$13.0 million annually until March 31, 2014, with the
remaining balance due on the maturity date. The Company made
principal payments on the Term Loan of $13.0 million in
2010, $925.7 million in 2009, primarily from the net
proceeds of the debt and common stock offerings in June and July
2009, and $13.0 million during 2008. Since 2009, interest
rates under the Term Loan are equal to LIBOR (subject to a floor
of 3.25%) plus 7.50%. The average interest rates under the Term
Loan for 2010 and 2009 were 10.75% and 8.67%, respectively. As
of December 31, 2010, the interest rate under the Term Loan
was 10.75%. The Company amended the Term Loan during the second
and fourth quarters of 2009 in connection with the new debt
offerings and to modify certain financial covenants. To effect
these amendments, the Company paid $3.4 million in
amendment fees. As a result of the partial paydown of the Term
Loan in June 2009, the Company expensed $9.0 million during
the second quarter of 2009 to write-off a portion of the
unamortized loan fees related to the Term Loan. At
December 31, 2010, the fair value of the Term Loan was
$346.9 million.
Revolving Credit Agreement. On
December 23, 2010, the Company completed an amendment to
the Revolving Credit Agreement resulting in, among other items,
the extension of the maturity of a portion of the commitment
thereunder to January 1, 2015. The amended Revolving Credit
Agreement included commitments of $800.0 million composed
of a $145.0 million tranche that matures on May 31,
2012 and a $655.0 million tranche that matures on
January 1, 2015. The Revolving Credit Agreement is secured
on a first priority basis by certain cash and cash equivalents,
trade accounts receivable, and inventory, and on a second
priority basis by the collateral securing the Term Loan, the
Senior Secured Notes, and any future other pari passu secured
obligations, which consist of the Companys fixed assets.
The Revolving Credit Agreement can be used to finance working
capital and capital expenditures, refinance existing
indebtedness of the Company and its subsidiaries, and for other
general corporate purposes; and also provides for letters of
credit and swing line loans. The Revolving Credit Agreement is
an asset-based facility with the borrowing capacity primarily
dependent on the Companys eligible receivables and
inventory. Interest rates for the $145.0 million tranche
vary based on the Companys consolidated leverage ratio and
range from 3.75% to 4.50% over LIBOR or 2.75% to 3.50% over the
Base Rate (as defined in the Revolving Credit Agreement).
Interest rates for the $655.0 million tranche vary based on
the Companys excess availability of the Revolving Credit
Agreement and range from 3.00% to 3.75% over LIBOR or 2.00% to
2.75% over the Base Rate. As of December 31, 2010, the
gross availability under the Revolving Credit Agreement was
$624.0 million. As of December 31, 2010, the Company
had net availability under the Revolving Credit Agreement of
$335.6 million due to $288.4 million in letters of
credit outstanding. The average interest rates under the
Revolving Credit Agreement for 2010 and 2009 were 6.15% and
5.20%, respectively. At December 31, 2010, there were no
outstanding borrowings under the Revolving Credit Agreement.
Among other amendments, the 2010 amendment replaced financial
maintenance covenants with a fixed charge coverage ratio
covenant that applies only when unused availability falls below
a specified level. The Company incurred $12.7 million in
fees related to the Revolving Credit Agreement amendment in
2010. The Company also amended the Revolving Credit Agreement
during the second and fourth quarters of 2009 in connection with
the new debt offerings and to modify certain of the financial
covenants. The Company incurred $5.6 million in fees
related to these amendments.
As a result of the 2009 amendment, the Companys Revolving
Credit Agreement required a structure mandating that all
receipts be swept daily to reduce borrowings outstanding under
the Revolving Credit Agreement. This arrangement, combined with
the existence of a material adverse change clause in the
Revolving Credit Agreement require outstanding borrowings under
the Revolving Credit Agreement to be classified as a current
liability. As a result of the 2010 amendment, going forward the
cash dominion requirement will only be in effect if the excess
availability under the Revolving Credit Agreement falls below
certain thresholds ranging from 15.0% to 17.5% of the Borrowing
Base.
Guarantors of the Term Loan and the Revolving Credit
Agreement. The Term Loan and the Revolving Credit
Agreement (together, the Agreements) are guaranteed,
on a joint and several basis, by subsidiaries of Western
Refining, Inc. No amounts have been recorded for these
guarantees.
100
WESTERN
REFINING, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Certain Covenants. The Agreements contain
certain covenants, including limitations on debt, investments,
and dividends. The Term Loan contains financial covenants
relating to minimum interest coverage and maximum leverage and,
for certain periods in 2010 through September 30, 2010,
minimum EBITDA. The Company was in compliance with all
applicable covenants set forth in the Term Loan at
December 31, 2010. The following table sets forth the
financial covenant requirements for minimum consolidated
interest coverage (as defined therein), and maximum consolidated
leverage (as defined therein) under the Term Loan by quarter:
|
|
|
|
|
|
|
|
|
|
|
Minimum
|
|
Maximum
|
|
|
Consolidated
|
|
Consolidated
|
|
|
Interest Coverage
|
|
Leverage
|
|
|
Ratio
|
|
Ratio
|
|
December 31, 2010 and March 31, 2011
|
|
|
1.50 to 1.00
|
|
|
|
5.25 to 1.00
|
|
June 30, 2011 and thereafter
|
|
|
2.00 to 1.00
|
|
|
|
4.50 to 1.00
|
|
Letters
of Credit
The Revolving Credit Agreement provides for the issuance of
letters of credit. The Company issues and cancels letters of
credit on a periodic basis depending upon its needs. At
December 31, 2010, there were $288.4 million of
irrevocable letters of credit outstanding, primarily issued to
crude oil suppliers under the Revolving Credit Agreement.
The following is an analysis of the Companys consolidated
income tax expense (benefit) for the three years ended
December 31, 2010:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands)
|
|
|
Current:
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal
|
|
$
|
(7,554
|
)
|
|
$
|
20,387
|
|
|
$
|
4,744
|
|
State
|
|
|
(1,036
|
)
|
|
|
2,395
|
|
|
|
1,365
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current
|
|
|
(8,590
|
)
|
|
|
22,782
|
|
|
|
6,109
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred:
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal
|
|
|
(15,297
|
)
|
|
|
(53,704
|
)
|
|
|
16,627
|
|
State
|
|
|
(2,190
|
)
|
|
|
(9,661
|
)
|
|
|
(2,512
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total deferred
|
|
|
(17,487
|
)
|
|
|
(63,365
|
)
|
|
|
14,115
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Provision for income taxes
|
|
$
|
(26,077
|
)
|
|
$
|
(40,583
|
)
|
|
$
|
20,224
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The Company received income tax refunds of $49.8 million,
$7.2 million, and $51.1 million for the three years
ended December 31, 2010. The following is a reconciliation
of total income tax expense (benefit) to income taxes
101
WESTERN
REFINING, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
computed by applying the 35% statutory federal income tax rate
to income (loss) before income tax expense (benefit) for the
three years ended December 31, 2010:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands)
|
|
|
Tax computed at the federal statutory rate
|
|
$
|
(15,094
|
)
|
|
$
|
(136,921
|
)
|
|
$
|
29,547
|
|
State income taxes, net of federal tax benefit
|
|
|
(5,588
|
)
|
|
|
(6,261
|
)
|
|
|
(476
|
)
|
Goodwill impairment loss
|
|
|
|
|
|
|
104,843
|
|
|
|
|
|
Federal tax credit for production of ultra low sulfur diesel
|
|
|
(4,747
|
)
|
|
|
(4,601
|
)
|
|
|
(6,787
|
)
|
Other, net
|
|
|
(648
|
)
|
|
|
2,357
|
|
|
|
(2,060
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total income tax expense (benefit)
|
|
$
|
(26,077
|
)
|
|
$
|
(40,583
|
)
|
|
$
|
20,224
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The effective tax rate for 2010 was 60.5%, as compared to the
federal statutory rate of 35%. The effective tax rate was higher
primarily because of the federal income tax credit available to
small business refiners that produce ultra low sulfur diesel
fuel.
The effective tax rate for 2009 was 44.3%, excluding the effect
of the non-deductible goodwill impairment of
$299.6 million, as compared to the federal statutory rate
of 35%. The effective tax rate was higher primarily due to the
federal income tax credit available to small business refiners
related to the production of ultra low sulfur diesel fuel.
The effective tax rate for 2008 was 24.0% as compared to the
federal statutory rate of 35%. The effective tax rate was lower
primarily due to the federal income tax credit available to
small business refiners related to the production of ultra low
sulfur diesel fuel.
The Company adopted the provisions related to accounting for
uncertainties in income taxes. These provisions clarify the
accounting for uncertainty in income taxes recognized in the
financial statements. As a result of the Giant acquisition on
May 31, 2007, the Company recorded a liability of
$5.2 million for unrecognized tax benefits, of which
$0.5 million would affect the Companys effective tax
rate if recognized.
The Company is currently under examination by the Internal
Revenue Service (IRS) for tax years ended
December 31, 2007 and December 31, 2008. The Company
concluded the 2006 and short period 2007 exam for legacy Giant
with no material changes. The Company will continue to work with
the IRS to expedite the conclusion of the 2007 and 2008
examinations. The Company does not believe the results of these
examinations will have a material adverse effect on the
Companys financial position or results of operations upon
conclusion. While the Company does not believe the results of
these examinations will have a material adverse effect on the
Companys financial position or results of operations, the
timing and results of any final determination remain uncertain.
The Company had no unrecognized tax benefits for 2010 and
recognized no interest or penalties for 2010.
102
WESTERN
REFINING, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The following is a reconciliation of unrecognized tax benefits
for the three years ended December 31, 2010:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands)
|
|
|
Unrecognized tax benefits at beginning of year
|
|
$
|
|
|
|
$
|
5,898
|
|
|
$
|
5,165
|
|
Increases (decreases) related to current year tax positions
|
|
|
|
|
|
|
|
|
|
|
|
|
Increases (decreases) related to prior year tax positions
|
|
|
|
|
|
|
|
|
|
|
3,930
|
|
Decreases related to settlements with taxing authorities
|
|
|
|
|
|
|
(5,898
|
)
|
|
|
|
|
Decreases resulting from the expiration of the statute of
limitations
|
|
|
|
|
|
|
|
|
|
|
(3,197
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrecognized tax benefits at end of year
|
|
$
|
|
|
|
$
|
|
|
|
$
|
5,898
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Based on the results of the examination of the Companys
2005 federal income tax return, the Companys uncertain tax
positions were settled favorably. Accordingly, $6.3 million
in estimated liabilities related to the Companys uncertain
tax positions were reversed during the third quarter of 2009,
including $0.5 million that affected the Companys
effective tax rate and $0.4 million for interest and
penalties. As of December 31, 2009, the Company had no
unrecognized tax benefits.
The Company classifies interest to be paid on an underpayment of
income taxes and any related penalties as income tax expense.
The Company recognized no interest or penalties related to
uncertain tax positions for the three years ended
December 31, 2010. The tax years
2006-2010
remain open to examination by the major tax jurisdictions to
which the Company is subject (U.S. Federal, Texas,
Virginia, Maryland, New Mexico, Arizona, and California).
103
WESTERN
REFINING, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The tax effects of significant temporary differences
representing deferred income tax assets and liabilities were as
follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
|
Assets
|
|
|
Liabilities
|
|
|
Net
|
|
|
Assets
|
|
|
Liabilities
|
|
|
Net
|
|
|
|
(In thousands, except cost per barrel)
|
|
|
Current deferred taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Inventories
|
|
$
|
|
|
|
$
|
(58,934
|
)
|
|
$
|
(58,934
|
)
|
|
$
|
|
|
|
$
|
(50,625
|
)
|
|
$
|
(50,625
|
)
|
Stock-based compensation
|
|
|
1,576
|
|
|
|
|
|
|
|
1,576
|
|
|
|
1,176
|
|
|
|
|
|
|
|
1,176
|
|
Other current, net
|
|
|
(1,571
|
)
|
|
|
|
|
|
|
(1,571
|
)
|
|
|
3,798
|
|
|
|
|
|
|
|
3,798
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current deferred taxes
|
|
|
5
|
|
|
|
(58,934
|
)
|
|
|
(58,929
|
)
|
|
|
4,974
|
|
|
|
(50,625
|
)
|
|
|
(45,651
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Noncurrent deferred taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property, plant, and equipment
|
|
|
|
|
|
|
(444,218
|
)
|
|
|
(444,218
|
)
|
|
|
|
|
|
|
(438,939
|
)
|
|
|
(438,939
|
)
|
Intangible assets
|
|
|
|
|
|
|
(9,829
|
)
|
|
|
(9,829
|
)
|
|
|
|
|
|
|
(10,382
|
)
|
|
|
(10,382
|
)
|
Pension obligations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,536
|
|
|
|
|
|
|
|
4,536
|
|
Postretirement obligations
|
|
|
1,721
|
|
|
|
|
|
|
|
1,721
|
|
|
|
3,405
|
|
|
|
|
|
|
|
3,405
|
|
Debt discount
|
|
|
|
|
|
|
(17,375
|
)
|
|
|
(17,375
|
)
|
|
|
|
|
|
|
(20,883
|
)
|
|
|
(20,883
|
)
|
Environmental and retirement obligations
|
|
|
3,321
|
|
|
|
|
|
|
|
3,321
|
|
|
|
8,324
|
|
|
|
|
|
|
|
8,324
|
|
Other noncurrent, net
|
|
|
|
|
|
|
5,766
|
|
|
|
5,766
|
|
|
|
|
|
|
|
5,023
|
|
|
|
5,023
|
|
Net operating loss and tax credit carryforwards
|
|
|
99,322
|
|
|
|
|
|
|
|
99,322
|
|
|
|
57,568
|
|
|
|
|
|
|
|
57,568
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Noncurrent deferred taxes
|
|
|
104,364
|
|
|
|
(465,656
|
)
|
|
|
(361,292
|
)
|
|
|
73,833
|
|
|
|
(465,181
|
)
|
|
|
(391,348
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net deferred taxes
|
|
$
|
104,369
|
|
|
$
|
(524,590
|
)
|
|
$
|
(420,221
|
)
|
|
$
|
78,807
|
|
|
$
|
(515,806
|
)
|
|
$
|
(436,999
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
104
WESTERN
REFINING, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
At December 31, 2010, the Company had the following credits
and net operating loss (NOL) carryforwards:
|
|
|
|
|
|
|
|
|
|
|
|
|
Type of Credit
|
|
Gross Amount
|
|
|
Tax Effected Amount
|
|
|
Expiration
|
|
|
|
(In thousands)
|
|
|
Alternative minimum tax credit
|
|
$
|
|
|
|
$
|
(35,469
|
)
|
|
|
No expiration
|
|
General business credit carryforwards
|
|
|
|
|
|
|
(21,521
|
)
|
|
|
2028 - 2030
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total credits
|
|
|
|
|
|
|
(56,990
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal NOL carryforwards
|
|
|
(52,067
|
)
|
|
|
(18,223
|
)
|
|
|
2029 - 2030
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
State NOL carryforwards
|
|
|
|
|
|
|
|
|
|
|
|
|
Arizona and New Mexico
|
|
|
(7,926
|
)
|
|
|
(539
|
)
|
|
|
2013
|
|
Arizona and New Mexico
|
|
|
(45,888
|
)
|
|
|
(2,169
|
)
|
|
|
2014
|
|
Arizona and New Mexico
|
|
|
(28,820
|
)
|
|
|
(1,389
|
)
|
|
|
2015
|
|
Virginia and Maryland
|
|
|
(14,401
|
)
|
|
|
(562
|
)
|
|
|
2023
|
|
Virginia and Maryland
|
|
|
(636
|
)
|
|
|
(25
|
)
|
|
|
2024
|
|
Virginia and Maryland
|
|
|
(34,729
|
)
|
|
|
(1,386
|
)
|
|
|
2026
|
|
Virginia and Maryland
|
|
|
(59,277
|
)
|
|
|
(2,468
|
)
|
|
|
2027
|
|
Virginia and Maryland
|
|
|
(91,878
|
)
|
|
|
(3,752
|
)
|
|
|
2028
|
|
Virginia and Maryland
|
|
|
(154,526
|
)
|
|
|
(6,401
|
)
|
|
|
2029
|
|
Virginia and Maryland
|
|
|
(130,559
|
)
|
|
|
(5,418
|
)
|
|
|
2030
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total state NOL carryforwards
|
|
|
(568,640
|
)
|
|
|
(24,109
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total credits and NOL carryforwards
|
|
$
|
(620,707
|
)
|
|
$
|
(99,322
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred tax assets should be reduced by a valuation allowance
if it is more likely than not that some portion or all of the
deferred tax assets will not be realized. The realization of
deferred tax assets can be affected by, among other things,
future company performance and market conditions. In making the
determination of whether or not a valuation allowance was
required, the Company considered all available positive and
negative evidence and made certain assumptions. The Company
performed an analysis of the reversal of deferred tax
liabilities, and then considered the overall business
environment, historical earnings, and the outlook for future
years. The Company performed this analysis as of
December 31, 2010, and determined that there was sufficient
positive evidence to conclude that it is more likely than not
that its deferred tax assets will be realized. The Company
assesses the need for a deferred tax asset valuation allowance
on a quarterly basis.
The Company fully recognizes the obligations associated with its
single-employer defined benefit pension, retiree healthcare, and
other postretirement plans in its financial statements.
Pensions
In connection with the negotiation of a collective bargaining
agreement covering employees of the El Paso refinery during
the second quarter of 2009, the Company terminated the defined
benefit plan covering certain El Paso refinery employees.
Regulatory approval of this termination was received during the
first quarter of 2010. No changes to the Companys proposed
plan of termination were required. Through December 2010, the
Company had distributed $21.7 million ($4.2 million in
2010 and $17.5 million in 2009) from plan assets to
plan participants as a result of the termination agreement.
Distributions made were in accordance with the termination
agreement. The Company transferred $2.5 million from plan
assets to a third-party annuity. The termination resulted in
reductions to the related pension obligation of
$5.6 million and $24.3 million, and to other
comprehensive loss
105
WESTERN
REFINING, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
(before income taxes) of $0.6 million and
$25.1 million, in the years ended December 31, 2010
and 2009, respectively.
Through December 31, 2010, the Company had distributed
$12.8 million from plan assets to plan participants as a
result of the temporary idling of Yorktown refining operations
and resultant termination of several participants of the
Yorktown cash balance plan. The termination resulted in
increases to the related pension obligation of $1.4 million
and to other comprehensive loss (before income taxes) of
$1.1 million.
The following tables set forth significant information about the
Companys pension plans for certain El Paso and
Yorktown refinery employees. The reconciliation of the benefit
obligation, plan assets, funded status, and significant
assumptions are based upon an annual measurement date of
December 31:
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
|
(In thousands)
|
|
|
Benefit obligation at beginning of year
|
|
$
|
28,186
|
|
|
$
|
66,122
|
|
Service cost
|
|
|
1,802
|
|
|
|
2,476
|
|
Interest cost
|
|
|
1,221
|
|
|
|
2,415
|
|
Benefits paid
|
|
|
(27
|
)
|
|
|
(653
|
)
|
Termination benefits paid
|
|
|
(19,460
|
)
|
|
|
(17,463
|
)
|
Actuarial (gain) loss
|
|
|
4,435
|
|
|
|
(17,982
|
)
|
Plan amendments
|
|
|
(553
|
)
|
|
|
(6,729
|
)
|
Curtailment
|
|
|
181
|
|
|
|
|
|
Settlement
|
|
|
(1,042
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Benefit obligation at end of year
|
|
$
|
14,743
|
|
|
$
|
28,186
|
|
|
|
|
|
|
|
|
|
|
Fair value of plan assets at beginning of year
|
|
$
|
15,973
|
|
|
$
|
24,820
|
|
Company contribution
|
|
|
10,640
|
|
|
|
4,786
|
|
Actual return on plan assets
|
|
|
533
|
|
|
|
4,483
|
|
Benefits paid
|
|
|
(27
|
)
|
|
|
(653
|
)
|
Termination benefits paid
|
|
|
(19,460
|
)
|
|
|
(17,463
|
)
|
|
|
|
|
|
|
|
|
|
Fair value of plan assets at end of year
|
|
$
|
7,659
|
|
|
$
|
15,973
|
|
|
|
|
|
|
|
|
|
|
Current liabilities
|
|
$
|
(7,084
|
)
|
|
$
|
(3,015
|
)
|
Noncurrent liabilities
|
|
|
|
|
|
|
(9,198
|
)
|
|
|
|
|
|
|
|
|
|
Unfunded status recognized in the consolidated balance sheets
|
|
$
|
(7,084
|
)
|
|
$
|
(12,213
|
)
|
|
|
|
|
|
|
|
|
|
Accumulated benefit obligation
|
|
$
|
14,743
|
|
|
$
|
26,666
|
|
|
|
|
|
|
|
|
|
|
106
WESTERN
REFINING, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands)
|
|
|
Net periodic benefit cost includes:
|
|
|
|
|
|
|
|
|
|
|
|
|
Service cost
|
|
$
|
1,802
|
|
|
$
|
2,476
|
|
|
$
|
4,030
|
|
Interest cost
|
|
|
1,221
|
|
|
|
2,415
|
|
|
|
3,283
|
|
Expected return on assets
|
|
|
(1,436
|
)
|
|
|
(2,609
|
)
|
|
|
(1,984
|
)
|
Recognized net actuarial loss
|
|
|
5
|
|
|
|
156
|
|
|
|
814
|
|
Recognized settlement (income) expense
|
|
|
4,407
|
|
|
|
1,793
|
|
|
|
|
|
Recognized curtailment (gain) loss
|
|
|
(1,006
|
)
|
|
|
(1,508
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net periodic benefit cost
|
|
$
|
4,993
|
|
|
$
|
2,723
|
|
|
$
|
6,143
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pre-tax unrecognized net loss included in accumulated other
comprehensive loss at beginning of year
|
|
$
|
3,123
|
|
|
$
|
30,150
|
|
|
$
|
12,544
|
|
Net actuarial (gain) loss
|
|
|
4,296
|
|
|
|
(26,871
|
)
|
|
|
18,420
|
|
Recognition of gain (loss) due to settlement
|
|
|
(3,773
|
)
|
|
|
|
|
|
|
|
|
Amortization of net actuarial gain (loss)
|
|
|
(5
|
)
|
|
|
(156
|
)
|
|
|
(814
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pre-tax unrecognized net loss included in accumulated other
comprehensive loss at end of year
|
|
$
|
3,641
|
|
|
$
|
3,123
|
|
|
$
|
30,150
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
2010(1)
|
|
2009
|
|
2008
|
|
Weighted average assumptions used to determine
benefit obligations at December 31:
|
|
|
|
|
|
|
|
|
|
|
|
|
Discount rate
|
|
|
4.63
|
%
|
|
|
5.37
|
%
|
|
|
5.78
|
%
|
Rate of compensation increase
|
|
|
3.50
|
|
|
|
3.50
|
|
|
|
3.50
|
|
Weighted average assumptions used to determine
net periodic benefit cost:
|
|
|
|
|
|
|
|
|
|
|
|
|
Discount rate
|
|
|
5.25
|
|
|
|
5.80
|
|
|
|
6.30
|
|
Expected long-term return on assets(2)
|
|
|
8.50
|
|
|
|
8.50
|
|
|
|
7.15
|
|
Rate of compensation increase
|
|
|
3.50
|
|
|
|
3.50
|
|
|
|
3.39
|
|
|
|
|
(1) |
|
Weighted average assumptions used to determine the expected
benefit obligation and net periodic benefit cost in 2010 are for
the Yorktown pension plan only. |
|
(2) |
|
All benefit plan assets for the Yorktown pension plan have been
moved into cash equivalents and the Companys expected
long-term rate of return on assets has been lowered to 1.9%. |
The following benefit payments (in thousands), which reflect
future service, are expected to be paid in the years indicated:
|
|
|
|
|
2011
|
|
$
|
7,833
|
|
2012
|
|
|
707
|
|
2013
|
|
|
793
|
|
2014
|
|
|
813
|
|
2015
|
|
|
758
|
|
2016-2020
|
|
|
3,192
|
|
107
WESTERN
REFINING, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Postretirement
Obligations
The following tables set forth significant information about the
Companys retiree medical plans for certain El Paso
and Yorktown employees. Unlike the pension plans, the Company is
not required to fund the retiree medical plans on an annual
basis. Based on an annual measurement date of December 31,
and discount rates of 5.57% and 5.92% at December 31, 2010
and 2009, respectively, to determine the benefit obligation, the
components of the postretirement obligation were:
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
|
(In thousands)
|
|
|
Benefit obligation at beginning of year
|
|
$
|
8,486
|
|
|
$
|
8,396
|
|
Service cost
|
|
|
490
|
|
|
|
511
|
|
Interest cost
|
|
|
493
|
|
|
|
442
|
|
Benefits paid
|
|
|
(81
|
)
|
|
|
(42
|
)
|
Actuarial (gain) loss
|
|
|
720
|
|
|
|
(821
|
)
|
Curtailment (gain)
|
|
|
(6,038
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Benefit obligation at end of year
|
|
$
|
4,070
|
|
|
$
|
8,486
|
|
|
|
|
|
|
|
|
|
|
Unfunded status
|
|
$
|
(4,070
|
)
|
|
$
|
(8,486
|
)
|
|
|
|
|
|
|
|
|
|
Current liabilities
|
|
$
|
(161
|
)
|
|
$
|
(78
|
)
|
Noncurrent liabilities
|
|
|
(3,909
|
)
|
|
|
(8,408
|
)
|
|
|
|
|
|
|
|
|
|
Unfunded status recognized in the consolidated balance sheets
|
|
$
|
(4,070
|
)
|
|
$
|
(8,486
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands)
|
|
|
Net periodic benefit cost includes:
|
|
|
|
|
|
|
|
|
|
|
|
|
Service cost
|
|
$
|
490
|
|
|
$
|
511
|
|
|
$
|
416
|
|
Interest cost
|
|
|
493
|
|
|
|
442
|
|
|
|
456
|
|
Amortization of net actuarial (gain) loss
|
|
|
(20
|
)
|
|
|
(11
|
)
|
|
|
(1
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net periodic benefit cost
|
|
$
|
963
|
|
|
$
|
942
|
|
|
$
|
871
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pre-tax unrecognized net gain included in accumulated other
comprehensive gain at beginning of year
|
|
$
|
(859
|
)
|
|
$
|
(49
|
)
|
|
$
|
(302
|
)
|
Net actuarial (gain) loss
|
|
|
(24
|
)
|
|
|
(821
|
)
|
|
|
252
|
|
Recognition of curtailment gain
|
|
|
453
|
|
|
|
|
|
|
|
|
|
Amortization of net actuarial gain (loss)
|
|
|
20
|
|
|
|
11
|
|
|
|
1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pre-tax unrecognized net gain included in accumulated other
comprehensive gain at end of year
|
|
$
|
(410
|
)
|
|
$
|
(859
|
)
|
|
$
|
(49
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
108
WESTERN
REFINING, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The weighted average discount rates used to determine net
periodic benefit costs were 5.92%, 5.75%, and 6.55% for 2010,
2009, and 2008, respectively. The following benefit payments (in
thousands) are expected to be paid in the year indicated:
|
|
|
|
|
2011
|
|
$
|
166
|
|
2012
|
|
|
171
|
|
2013
|
|
|
189
|
|
2014
|
|
|
209
|
|
2015
|
|
|
228
|
|
2016-2020
|
|
|
1,324
|
|
The health care cost trend rate for the plan covering
El Paso employees for 2010 and future years is capped at
4.0%. The health care cost trend rate for the plan covering
Yorktown employees for 2010 is 8.0% trending to 4.5% in 2015. A
1%-point change in the assumed health care cost trend rate for
both plans will have the following effect:
|
|
|
|
|
|
|
|
|
|
|
1%-points
|
|
|
Increase(1)
|
|
Decrease
|
|
|
(In thousands)
|
|
Effect on total service cost and interest cost
|
|
$
|
55
|
|
|
$
|
(72
|
)
|
Effect on accumulated benefit obligation
|
|
|
121
|
|
|
|
(399
|
)
|
|
|
|
(1) |
|
There is no impact for a 1%-point increase in the El Paso
plan because the plan covers up to a 4% increase per year. Any
increase in health care costs in excess of 4% is absorbed by the
participant. |
The following tables present the fair values of the assets of
our pension plans as of December 31, 2010 and 2009 by level
of the fair value hierarchy. Assets categorized in Level 1
of the hierarchy are measured at fair value using a market
approach based on quotations from national securities exchanges.
Assets categorized in Level 2 of the hierarchy are measured
at net asset value as a practical expedient for fair value. As
noted above, our other postretirement benefit plans are funded
on a pay-as-you-go basis and have no assets.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurement Using
|
|
|
|
|
|
|
Significant
|
|
|
|
|
|
|
|
|
Other
|
|
Significant
|
|
|
Total as of
|
|
Quoted Prices in
|
|
Observable
|
|
Unobservable
|
|
|
December 31,
|
|
Active Markets
|
|
Inputs
|
|
Inputs
|
|
|
2010
|
|
(Level 1)
|
|
(Level 2)
|
|
(Level 3)
|
|
|
(In thousands)
|
|
Cash and cash equivalents
|
|
$
|
7,657
|
|
|
$
|
7,657
|
|
|
$
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Significant
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
|
|
|
Significant
|
|
|
|
Total as of
|
|
|
Quoted Prices in
|
|
|
Observable
|
|
|
Unobservable
|
|
|
|
December 31,
|
|
|
Active Markets
|
|
|
Inputs
|
|
|
Inputs
|
|
|
|
2009
|
|
|
(Level 1)
|
|
|
(Level 2)
|
|
|
(Level 3)
|
|
|
|
(In thousands)
|
|
|
Mutual funds:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Growth equity
|
|
$
|
3,967
|
|
|
$
|
|
|
|
$
|
3,967
|
|
|
$
|
|
|
Bonds
|
|
|
10,564
|
|
|
|
|
|
|
|
10,564
|
|
|
|
|
|
Cash and cash equivalents
|
|
|
1,435
|
|
|
|
1,435
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
15,966
|
|
|
$
|
1,435
|
|
|
$
|
14,531
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
109
WESTERN
REFINING, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Defined
Contribution Plans
The Company sponsors a 401(k) defined contribution plan that
resulted from the merger of legacy Western and Giant 401(k)
defined contribution plans, effective January 1, 2009.
Under the merged plan, participants may contribute a percentage
of their eligible compensation to the plan and invest in various
investment options. The Company will match participant
contributions to the merged plan subject to certain limitations
and a per participant maximum contribution. For each 1% of
eligible compensation contributed by the participant throughout
the year ended December 31, 2009, the Company matched 2% up
to a maximum of 8% of eligible compensation, provided the
participant had a minimum of one year of service with the
Company. Beginning January 1, 2010, for each 1% of eligible
compensation contributed by the participant, the Company matched
1% up to a maximum of 4% of eligible compensation, provided the
participant had a minimum of one year of service with the
Company. The Company expensed $6.2 million in connection
with this plan for the year ended December 31, 2010. For
the predecessor plans, the Company expensed $8.9 million
and $9.1 million for the years ended December 31, 2009
and 2008, respectively.
Prior to the merger of the plans, the legacy Western plan
provided for a match of 8% of the participants eligible
compensation provided the Western participant had contributed a
minimum of 2% of their eligible compensation. The legacy Giant
plan provided for a match of the employees contributions
up to 8% of eligible compensation at a 2 to 1 ratio of the
percentage of eligible compensation contributed by the Giant
employee. Both plans had one year minimum service requirements.
|
|
16.
|
Crude Oil
and Refined Product Risk Management
|
The Company enters into crude oil forward contracts to
facilitate the supply of crude oil to the refineries. During
2010, 2009, and 2008, the Company entered into forward, fixed
price contracts to physically receive and deliver crude oil
which qualify as normal purchases and normal sales and are
exempt from derivative reporting requirements.
The Company also uses crude oil and refined products futures,
swap contracts, or options to mitigate the change in value for a
portion of its volumes subject to market prices. Under a refined
products swap contract, the Company agrees to buy or sell an
amount equal to a fixed price times a set number of barrels and
to buy or sell in return an amount equal to a specified variable
price times the same amount of barrels. The physical volumes are
not exchanged and these contracts are net settled with cash. The
Company elected not to pursue hedge accounting treatment for
these instruments for financial accounting purposes. The
contract fair value is reflected on the Consolidated Balance
Sheets and the related net gain or loss is recorded within cost
of products sold in the Consolidated Statements of Operations.
Quoted prices for similar assets or liabilities in active
markets (Level 2) are considered to determine the fair
values for the purpose of marking to market the derivative
instruments at each period end.
At December 31, 2010, the Company had open commodity
derivative instruments consisting of crude oil futures and
finished products price swaps on 1,023,000 barrels
primarily to protect the value of certain crude oil, finished
product, and blendstock inventories for the first quarter of
2011. The Company recognized $9.4 million within cost of
products sold, of net realized and unrealized losses from
derivative activities during 2010. The fair value of the
outstanding contracts at December 31, 2010, was a net
unrealized loss of $1.2 million, of which $1.0 million
were unrealized gains and $2.2 million were unrealized
losses. The Company recognized $21.7 million, within cost
of products sold, of net realized and unrealized losses from
derivative activities during 2009. The fair value of the
outstanding contracts at December 31, 2009, was a net
unrealized loss of $1.5 million, of which $0.8 million
were unrealized gains and $2.3 million were unrealized
losses. The Company did not record an unrealized gain or loss on
open positions at December 31, 2008, since the fair value
equaled the trade price on these swaps. During 2008, the Company
recognized an $11.4 million net gain from derivative
contracts in cost of products sold.
110
WESTERN
REFINING, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
17.
|
Stock-Based
Compensation
|
In January 2006, 1,772,041 shares of restricted stock
having an aggregate fair value of $30.1 million at the
measurement date were granted to employees of Western Refining
LP that participated in a deferred compensation plan prior to
the initial public offering. The vesting of such restricted
shares occurred over a two-year period, and ended in the first
quarter of 2008. Additional shares of restricted stock have been
granted to other employees and outside directors of the Company.
These shares generally vest ratably over a three-year period.
Although ownership of the shares does not transfer to the
recipients until the shares have vested, recipients have voting
and nonforfeitable dividend rights on these shares from the date
of grant. The fair value of each share of restricted stock
awarded was measured based on the market price as of the
measurement date and will be amortized on a straight-line basis
over the respective vesting periods.
In January 2009, the Company adopted the provisions related to
specific accounting requirements for realized income tax
benefits from dividends. A realized income tax benefit from
dividends or dividend equivalents that are (a) paid to
employees holding equity-classified nonvested shares,
equity-classified nonvested share units, or equity-classified
outstanding share options and (b) charged to retained
earnings, should be recognized as an increase to additional
paid-in capital. The amount recognized in additional paid-in
capital for the realized income tax benefit from dividends on
those awards should be included in the pool of excess tax
benefits available to absorb tax deficiencies on share-based
payment awards. The adoption of these provisions did not have an
impact on the Companys financial position or results of
operations during 2010 and 2009.
The Company recorded stock compensation expense of
$5.9 million for the year ended December 31, 2010, of
which $0.6 million was included in direct operating
expenses and $5.3 million in selling, general, and
administrative expenses. The tax deficiency related to the
shares that vested during the year ended December 31, 2010
was $1.1 million using a statutory blended rate of 37.54%.
The aggregate fair value at the grant date of the shares that
vested during the year ended December 31, 2010 was
$4.8 million. The related aggregate intrinsic value of
these shares was $1.9 million at the vesting date.
The Company recorded stock compensation expense of
$4.7 million for the year ended December 31, 2009, of
which $1.1 million was included in direct operating
expenses and $3.6 million in selling, general, and
administrative expenses. The tax deficiency related to the
shares that vested during the year ended December 31, 2009,
was $1.1 million using a statutory blended rate of 37.17%.
The aggregate fair value at the grant date of the shares that
vested during the year ended December 31, 2009, was
$5.1 million. The related aggregate intrinsic value of
these shares was $3.0 million at the vesting date.
The Company recorded stock compensation expense of
$7.7 million for the year ended December 31, 2008, of
which $1.3 million was included in direct operating
expenses and $6.4 million in selling, general, and
administrative expenses. The tax deficiency related to the
shares that vested during the year ended December 31, 2008,
was $1.7 million using a statutory blended rate of 37.17%.
The aggregate fair value at the grant date of the shares that
vested during the year ended December 31, 2008, was
$6.7 million. The related aggregate intrinsic value of
these shares was $4.7 million at the vesting date.
As of December 31, 2010, there were 2,438,147 shares
of restricted stock outstanding with an aggregate fair value at
grant date of $16.4 million and an aggregate intrinsic
value of $25.8 million. The compensation cost of nonvested
awards not recognized as of December 31, 2010 was
$12.2 million, which will be recognized over a
111
WESTERN
REFINING, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
weighted average period of approximately 2.25 years. The
following table summarizes the Companys restricted stock
activity for the three years ended December 31, 2010:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average
|
|
|
|
|
|
|
Grant Date
|
|
|
|
Number of Shares
|
|
|
Fair Value
|
|
|
Nonvested at December 31, 2007
|
|
|
506,562
|
|
|
$
|
23.36
|
|
Awards granted
|
|
|
410,826
|
|
|
|
13.56
|
|
Awards vested
|
|
|
(321,862
|
)
|
|
|
20.74
|
|
Awards forfeited
|
|
|
(1,266
|
)
|
|
|
32.36
|
|
|
|
|
|
|
|
|
|
|
Nonvested at December 31, 2008
|
|
|
594,260
|
|
|
|
18.55
|
|
|
|
|
|
|
|
|
|
|
Awards granted
|
|
|
509,210
|
|
|
|
10.39
|
|
Awards vested
|
|
|
(261,723
|
)
|
|
|
19.54
|
|
Awards forfeited
|
|
|
(47,068
|
)
|
|
|
23.12
|
|
|
|
|
|
|
|
|
|
|
Nonvested at December 31, 2009
|
|
|
794,679
|
|
|
|
12.72
|
|
|
|
|
|
|
|
|
|
|
Awards granted
|
|
|
2,072,797
|
|
|
|
5.81
|
|
Awards vested
|
|
|
(336,293
|
)
|
|
|
14.35
|
|
Awards forfeited
|
|
|
(93,036
|
)
|
|
|
10.00
|
|
|
|
|
|
|
|
|
|
|
Nonvested at December 31, 2010
|
|
|
2,438,147
|
|
|
|
6.73
|
|
|
|
|
|
|
|
|
|
|
In January 2006, the Companys Board of Directors and
shareholders authorized the issuance of up to
5,000,000 shares of common stock under the Western Refining
2006 Long-Term Incentive Plan (2006 LTIP). At
December 31, 2010, there were 77,984 shares of common
stock reserved for future grants under the 2006 LTIP. On
April 7, 2010, the Companys Board of Directors
authorized the issuance of up to 3,850,000 shares of common
stock under the 2010 Incentive Plan of Western Refining
(2010 Incentive Plan). The 2010 Incentive Plan was
approved by the Companys shareholders on May 25,
2010. At December 31, 2010, there were
3,751,859 shares of common stock reserved for future grants
under the 2010 Incentive Plan.
On January 24, 2006, the Company completed an initial
public offering of 18,750,000 shares of its common stock at
an aggregate offering price of $318.8 million. The Company
received approximately $297.2 million in net proceeds from
the initial public offering.
On June 10, 2009, the Company issued an additional
20,000,000 shares of its common stock, par value $0.01 per
share at an aggregate offering price of $180.0 million. The
net proceeds of this issuance were $170.4 million, net of
underwriting discounts of $9.0 million and
$0.6 million in issuance costs related to this offering. In
addition, during June and July 2009, the Company issued and sold
$215.5 million in Convertible Senior Notes and recorded
additional paid-in capital of $36.3 million, net of
deferred income taxes of $22.6 million and transaction
costs of $2.0 million, related to the equity portion of
this convertible debt. The proceeds of these issuances were used
to repay a portion of the outstanding indebtedness under the
Companys Term Loan.
The Company repurchased 51,103 and 80,668 shares of its
common stock to cover payroll withholding taxes for certain
employees pursuant to the vesting of restricted shares awarded
under the Western Refining Long-Term Incentive Plan in 2009 and
2008, respectively. The aggregate cost paid for these shares was
$0.6 million and $1.2 million for 2009 and 2008,
respectively. The Company recorded these repurchases as treasury
stock. There were no such repurchases for the year ended
December 31, 2010.
112
WESTERN
REFINING, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
On January 1, 2009, the Company adopted the provisions
related to the accounting treatment of certain participating
securities for the purpose of determining earnings per share.
These provisions address unvested share-based payment awards
that contain nonforfeitable rights to dividends or dividend
equivalents and states that they are participating securities
and should be included in the computation of earnings per share
pursuant to the two-class method. As discussed in
Note 17, Stock-Based Compensation, the Company has
granted shares of restricted stock to certain employees and
outside directors of the Company. Although ownership of these
shares does not transfer to the recipients until the shares have
vested, recipients have voting and nonforfeitable dividend
rights on these shares from the date of grant. As a result of
the adoption of the provisions related to participating
securities, the Company applied the two-class method to
determine its earnings per share for all periods presented. The
Companys Convertible Senior Notes, although potentially
dilutive, were not included in the Companys computation of
diluted loss per share for the year ended December 31, 2010.
The computation of basic and diluted earnings per share under
the two-class method is presented below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands, except per share data)
|
|
|
Allocation of earnings (losses):
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
(17,049
|
)
|
|
$
|
(350,621
|
)
|
|
$
|
64,197
|
|
Distributed earnings
|
|
|
|
|
|
|
|
|
|
|
(8,182
|
)
|
Income allocated to participating securities
|
|
|
|
|
|
|
|
|
|
|
(467
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Undistributed income (loss) available to common shareholders
|
|
$
|
(17,049
|
)
|
|
$
|
(350,621
|
)
|
|
$
|
55,548
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average number of commons shares outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic and dilutive number of common shares outstanding
|
|
|
88,204
|
|
|
|
79,163
|
|
|
|
67,715
|
|
Basic earnings (loss) per common share:
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributed earnings per share
|
|
$
|
|
|
|
$
|
|
|
|
$
|
0.12
|
|
Undistributed earnings (loss) per share
|
|
|
(0.19
|
)
|
|
|
(4.43
|
)
|
|
|
0.82
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings (loss) per common share
|
|
$
|
(0.19
|
)
|
|
$
|
(4.43
|
)
|
|
$
|
0.94
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted earnings (loss) per common share:
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributed earnings per share
|
|
$
|
|
|
|
$
|
|
|
|
$
|
0.12
|
|
Undistributed earnings (loss) per share
|
|
|
(0.19
|
)
|
|
|
(4.43
|
)
|
|
|
0.82
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted earnings (loss) per common share
|
|
$
|
(0.19
|
)
|
|
$
|
(4.43
|
)
|
|
$
|
0.94
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following table reflects potentially dilutive securities
that were excluded from the diluted earnings (loss) per common
share calculation as the effect of including such shares would
have been antidilutive:
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
|
(In thousands)
|
|
|
Common equivalent shares from Convertible Senior Notes
|
|
|
19,949
|
|
|
|
19,949
|
|
Restricted stock
|
|
|
179
|
|
|
|
20
|
|
113
WESTERN
REFINING, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
20.
|
Related
Party Transactions
|
Effective May 1, 2009, the non-exclusive aircraft lease
with an entity controlled by the Companys majority
stockholder was terminated by the Company and as a result, it no
longer operates a private aircraft. The hourly rental payment
was $1,775 per flight hour and the Company was responsible for
all operating and maintenance costs of the aircraft. Personal
use of the aircraft by certain officers of the Company was
reimbursed to the Company at the highest rate allowed by the
Federal Aviation Administration for a non-charter operator. In
addition, the Company had a policy requiring that its officers
deposit in advance of any personal use of the aircraft an amount
equal to three months of anticipated expenses for the use of the
aircraft. The following table summarizes the total costs
incurred for the lease of the aircraft for the years ended
December 31, 2009 and 2008:
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands)
|
|
|
Lease payments
|
|
$
|
181
|
|
|
$
|
601
|
|
Operating and maintenance expenses
|
|
|
456
|
|
|
|
1,313
|
|
Reimbursed by officers
|
|
|
(321
|
)
|
|
|
(561
|
)
|
|
|
|
|
|
|
|
|
|
Total costs
|
|
$
|
316
|
|
|
$
|
1,353
|
|
|
|
|
|
|
|
|
|
|
The Company sells refined products to Transmountain Oil Company,
L.C. (Transmountain), a refined products distributor
in the El Paso area. An entity controlled by the
Companys majority stockholder acquired a 61.1% interest in
Transmountain on June 30, 2004, and acquired the remaining
interest in February 2008. On November 18, 2008,
Transmountain was sold to another entity and is no longer a
related party to the Company. All accounts receivable were
assumed by the third party on that date. Sales to Transmountain
for the period from January 1 through November 18, 2008
were $80.9 million.
The Company had entered into a lease agreement with
Transmountain, pursuant to which Transmountain leased certain
office space from the Company. The lease commenced on
December 1, 2005, for a period of ten years and contained
two five-year renewal options. The lease was assumed by a third
party as of November 18, 2008, and was subsequently
terminated in March 2009. Rental payments received from
Transmountain were less than $0.1 million for the year
ended December 31, 2008.
Environmental
Matters
Like other petroleum refiners, the Companys operations are
subject to extensive and periodically changing federal and state
environmental regulations governing air emissions, wastewater
discharges, and solid and hazardous waste management activities.
The Companys policy is to accrue environmental and
clean-up
related costs of a non-capital nature when it is probable that a
liability has been incurred and the amount can be reasonably
estimated. Such estimates may be subject to revision in the
future as regulations and other conditions change.
Periodically, the Company receives communications from various
federal, state, and local governmental authorities asserting
violation(s) of environmental laws
and/or
regulations. These governmental entities may also propose or
assess fines or require corrective action for these asserted
violations. The Company intends to respond in a timely manner to
all such communications and to take appropriate corrective
action. The Company does not anticipate that any such matters
currently asserted will have a material adverse impact on its
financial condition, results of operations, or cash flows.
Environmental remediation accruals are recorded in the current
and long-term sections of the Companys Consolidated
Balance Sheets, according to their nature. As of
December 31, 2010, the Company had environmental liability
accruals of $18.3 million, of which $10.6 million is
in accrued liabilities as a current liability. These
114
WESTERN
REFINING, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
liabilities have been recorded using an inflation factor of 2.7%
and a discount rate of 7.1%. Environmental liabilities of
$1.3 million accrued at December 31, 2010 have not
been discounted. As of December 31, 2009, the Company had
environmental liability accruals of $28.6 million, of which
$8.0 million was in accrued liabilities as a current
liability. As of December 31, 2010, the unescalated,
undiscounted environmental reserve related to these liabilities
totaled $23.0 million, leaving $5.0 million to be
accreted over time.
The table below summarizes the Companys environmental
liability accruals:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
Increase
|
|
|
|
|
|
December 31,
|
|
|
|
2009
|
|
|
(Decrease)
|
|
|
Payments
|
|
|
2010
|
|
|
|
(In thousands)
|
|
|
Discounted liabilities
|
|
$
|
27,249
|
|
|
$
|
(916
|
)
|
|
$
|
(9,399
|
)
|
|
$
|
16,934
|
|
Undiscounted liabilities
|
|
|
1,339
|
|
|
|
523
|
|
|
|
(542
|
)
|
|
|
1,320
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total environmental liabilities
|
|
$
|
28,588
|
|
|
$
|
(393
|
)
|
|
$
|
(9,941
|
)
|
|
$
|
18,254
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following table summarizes the Companys estimated
undiscounted cash flows for accrued remediation liabilities for
each of the next five years and in the aggregate thereafter (in
thousands):
|
|
|
|
|
2011
|
|
$
|
11,095
|
|
2012
|
|
|
969
|
|
2013
|
|
|
632
|
|
2014
|
|
|
633
|
|
2015
|
|
|
632
|
|
2016 and thereafter
|
|
|
9,327
|
|
El Paso
Refinery
The groundwater and certain solid waste management units and
other areas at and adjacent to the El Paso refinery have
been impacted by prior spills, releases, and discharges of
petroleum or hazardous substances and are currently undergoing
remediation by the Company and Chevron Products Company
(Chevron) pursuant to certain agreed administrative
orders with the Texas Commission on Environmental Quality
(TCEQ). Pursuant to the Companys purchase of
the north side of the El Paso refinery from Chevron,
Chevron retained responsibility to remediate their solid waste
management units in accordance with its Resource Conservation
Recovery Act (RCRA) permit, which Chevron has
fulfilled. Chevron also retained liability for, and control of,
certain groundwater remediation responsibilities, which are
ongoing.
In May 2000, the Company entered into an Agreed Order with the
Texas Natural Resources Conservation Commission, now known as
the TCEQ, for remediation of the south side of the El Paso
refinery property. In August 2000, the Company purchased a
Pollution and Legal Liability and
Clean-Up
Cost Cap Insurance policy at a cost of $10.3 million, which
was expensed in 2000. The policy is non-cancelable and covers
environmental
clean-up
costs related to contamination that occurred prior to
December 31, 1999, including the costs of the Agreed Order
activities. The insurance provider assumed responsibility for
all environmental
clean-up
costs related to the Agreed Order up to $20 million. In
addition, under a settlement agreement with the Company, a
subsidiary of Chevron is obligated to pay 60% of any Agreed
Order environmental
clean-up
costs that would otherwise have been covered under the policy
but that exceed the $20 million threshold. Under the
policy, environmental costs outside the scope of the Agreed
Order are covered up to $20 million and require payment by
the Company of a deductible of $0.1 million per incident as
well as any costs that exceed the covered limits of the
insurance policy.
The U.S. Environmental Protection Agency (EPA)
has embarked on a Petroleum Refinery Enforcement Initiative
(EPA Initiative) whereby it is investigating
industry-wide noncompliance with certain Clean Air Act rules.
The EPA Initiative has resulted in many refiners entering into
consent decrees typically requiring penalties and substantial
capital expenditures for additional air pollution control
equipment. Since December 2003, the
115
WESTERN
REFINING, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Company has been voluntarily discussing a settlement pursuant to
the EPA Initiative related to the El Paso refinery.
Negotiations with the EPA regarding this Initiative have focused
exclusively on air emission programs. The Company does not
expect these negotiations to result in any soil or groundwater
remediation or
clean-up
requirements. In May 2008, the EPA and the Company agreed on the
basic EPA Initiative requirements related to the Fluid Catalytic
Cracking Unit (FCCU) and heaters and boilers that
the Company expects will ultimately be incorporated into a final
settlement agreement between the Company and the EPA. Based on
current negotiations and information, the Company estimates the
total capital expenditures necessary to address the EPA
Initiative issues would be approximately $60.0 million of
which $38.8 million has already been expended;
$15.2 million for the installation of a flare gas recovery
system that was completed in 2007 and $23.6 million for
nitrogen oxides (NOx) emission controls on heaters
and boilers was expended in 2008 and 2009. The Company estimates
remaining expenditures of approximately $21.2 million for
the NOx emission controls on heaters and boilers from 2011
through 2013. This amount is included in the Companys
estimated capital expenditures for regulatory projects and could
change depending upon the actual final settlement reached. The
Company anticipates meeting the EPA Initiative NOx requirements
for the FCCU using catalyst additives and therefore does not
expect additional capital expenditures related to the EPA
Initiative NOx requirements for the FCCU.
The Company received a proposed draft settlement agreement from
the EPA in April 2009. In August 2009, the EPA demanded
penalties of $1.5 million. As of December 31, 2010,
the Company had accrued $1.5 million related to this
matter. As of February 25, 2011, a final settlement between
the Company and the EPA relating to this matter is still pending.
In March 2008, the TCEQ notified the Company that it would
present the Company with a proposed Agreed Order regarding six
excess air emission incidents that occurred at the El Paso
refinery during 2007 and early 2008. While at this time it is
not known precisely how or when the Agreed Order may affect the
Company, the Company may be required to implement corrective
action under the Agreed Order and may be assessed penalties. The
Company does not expect any penalties or corrective action
requested to have a material adverse effect on its business,
financial condition, or results of operations or that any
penalties assessed or increased costs associated with the
corrective action will be material.
In 2004 and 2005, the El Paso refinery applied for and was
issued a Texas Flexible Permit by the TCEQ Flexible Permits
program, under which the refinery continues to operate.
Established in 1994 under the Texas Clean Air Act, the program
grants operational flexibility to industrial facilities and
permits the allocation of emissions on a facility-wide basis in
exchange for emissions reduction and controlling previously
unregulated grandfathered emission sources. The TCEQ
submitted its Flexible Permits Program rules to the EPA for
approval in 1994 and has administered the program for
16 years with the EPAs full knowledge. In May 2010,
the El Paso refinery received a request from the EPA,
pursuant to Section 114 of the Clean Air Act, seeking
information about the refinerys air permits. The Company
responded to the EPAs request in June 2010. Also in June
2010, the EPA disapproved the TCEQ Flexible Permits Program. In
July 2010, the Texas Attorney General filed a legal challenge to
the EPAs disapproval in a federal appeals court asking for
reconsideration. Although the Company believes its Texas
Flexible Permit is federally enforceable, the Company agreed in
December 2010 to submit within one year an application to TCEQ
for a permit amendment to obtain a State Implementation Plan, or
SIP, approved state air quality permit to address concerns
raised by the EPA about all flexible permits. Sufficient time
has not elapsed for the Company to reasonably estimate any
potential impact of these regulatory developments in the Texas
air permits program.
In September 2010, the Company received a notice of intent to
sue under the Clean Air Act from several environmental groups.
While not entirely clear, the notice apparently contends that
the Companys El Paso refinery is not operating under
a valid permit or permits because the EPA has disapproved the
TCEQ Flexible Permits program and that the Companys
El Paso refinery may have exceeded certain emission
limitations under these same permits. The Company disputes these
claims and maintains its El Paso refinery is properly
operating, and has not exceeded emissions limitations, under the
validly issued TCEQ permits. The Company intends to defend
itself accordingly.
116
WESTERN
REFINING, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Four
Corners Refineries
Four Corners 2005 Consent Agreements. In July
2005, as part of the EPA Initiative, Giant reached an
administrative settlement with the New Mexico Environment
Department (NMED) and the EPA in the form of consent
agreements that resolved certain alleged violations of air
quality regulations at the Gallup and Bloomfield refineries in
the Four Corners area of New Mexico (the 2005 NMED
Agreement). In January 2009, the Company and the NMED
agreed to an amendment of the 2005 administrative settlement
with the NMED (the 2009 NMED Amendment), which
altered certain deadlines and allowed for alternative air
pollution controls.
In November 2009, the Company indefinitely suspended refining
operations at the Bloomfield refinery. The Company currently
operates the site as a products distribution terminal and crude
storage facility. Bloomfield continues to use some of the
refinery equipment to support the terminal and to store crude
for the Gallup refinery. The Company has begun negotiations with
the NMED to revise the 2009 NMED Amendment to reflect the
indefinite suspension.
Based on current information and the 2009 NMED Amendment, and
favorably negotiating a revision to reflect the indefinite
suspension of refining operations at the Bloomfield facility,
the Company estimates $17.6 million total remaining capital
expenditures will be required pursuant to the 2009 NMED
Amendment. Through 2010, the Company has expended
$5.9 million and expects to spend the remaining
$11.7 million during 2011 and 2012. These capital
expenditures will primarily be for installation of emission
controls on the heaters, boilers, and FCCU, and for reducing
sulfur in fuel gas to reduce emissions of sulfur dioxide, NOx,
and particulate matter from the refineries. The 2009 NMED
Amendment also provided for a $2.4 million penalty. The
Company completed payment of the penalty between November 2009
and September 2010 to fund a Supplemental Environmental Project
(SEP). The Company does not expect implementation of
the requirements in the 2005 NMED Agreement and the associated
2009 NMED Amendment will result in any soil or groundwater
remediation or
clean-up
costs.
Bloomfield 2007 NMED Remediation Order. In
July 2007, the Company received a final administrative
compliance order from the NMED alleging that releases of
contaminants and hazardous substances that have occurred at the
Bloomfield refinery over the course of its operation prior to
June 1, 2007, have resulted in soil and groundwater
contamination. Among other things, the order requires the
Company to:
|
|
|
|
|
investigate and determine the nature and extent of such releases
of contaminants and hazardous substances;
|
|
|
|
perform interim remediation measures, or continue interim
measures already begun, to mitigate any potential threats to
human health or the environment from such releases;
|
|
|
|
identify and evaluate alternatives for corrective measures to
clean up any contaminants and hazardous substances released at
the refinery and prevent or mitigate their migration at or from
the site;
|
|
|
|
implement any corrective measures that may be approved by the
NMED;
|
|
|
|
develop investigation work plans over a period of approximately
four years; and
|
|
|
|
implement corrective measures pursuant to the investigation.
|
The order recognizes that prior work satisfactorily completed
may fulfill some of the foregoing requirements. In that regard,
the Company has already put in place some remediation measures
with the approval of the NMED and New Mexico Oil Conservation
Division.
Based on current information, the Company estimates a remaining
undiscounted cost of $3.3 million for implementing the
investigation and interim measures of the order. At
December 31, 2010, the Company had a liability of
$2.5 million relating to the investigation and interim
measures of the final order implementation costs. As of
December 31, 2010, the Company had expended
$2.3 million to implement the order.
Gallup 2007 Resource Conservational Recovery Act
(RCRA) Inspection. In September 2007,
the Gallup refinery was inspected jointly by the EPA and the
NMED (the Gallup 2007 RCRA Inspection) to determine
117
WESTERN
REFINING, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
compliance with the EPAs hazardous waste regulations
promulgated pursuant to the RCRA. The Company reached a final
settlement with the agencies in August 2009 and paid a penalty
of $0.7 million in October 2009. The Company does not
expect implementation of the requirements in the final
settlement will result in any soil or groundwater remediation or
clean-up
costs. Based on current information, the Company estimates
capital expenditures of approximately $15.4 million to
upgrade the wastewater treatment plant at the Gallup refinery
pursuant to the requirements of the final settlement. Through
2010, the Company has expended $4.2 million on the upgrade
of the wastewater treatment plan and expects to spend the
remaining $11.2 million during 2011 and 2012. In April
2010, the Company submitted to the NMED, for approval, a plan
with the design and construction schedule to upgrade the
wastewater treatment plant. The Company negotiated with the NMED
and the EPA regarding modifications to the plan issued by the
NMED in its May 2010 approval letter, which resulted in a
September 2010 modification to the August 2009 final settlement
establishing a May 2010 deadline for
start-up of
the upgraded wastewater treatment plant.
Yorktown
Refinery
Yorktown 1991 and 2006 Orders. Giant and a
subsidiary company, assumed certain liabilities and obligations
in connection with the 2002 purchase of the Yorktown refinery
from BP Corporation North America Inc. and BP Products North
America Inc. (collectively BP), and BP agreed to
indemnify Giant for certain costs. During 2007, BP disputed
indemnification for certain costs. In the related lawsuit styled
Western Refining Yorktown, Inc. f/k/a Giant Yorktown,
Inc. v. BP Corporation North America, Inc. and BP Products
North America, Inc., all claims and counterclaims were
voluntarily dismissed with prejudice in 2009 by mutual agreement
of the parties.
In August 2006, Giant agreed to the terms of the final
administrative consent order pursuant to which Giant would
implement a
clean-up
plan for the refinery. Following the acquisition of Giant, the
Company completed the first phase of the soil
clean-up
plan and negotiated revisions with the EPA for the remainder of
the soil
clean-up
plan. The Company anticipates completing the soil
clean-up in
2011. The EPA issued an approval in January 2010 that allowed
the Company to begin implementing its revised soil
clean-up
plan during the second quarter of 2010. The January 2010 EPA
approval and a prior EPA approval in 2008 allowed adjustments to
the cost estimates for the groundwater monitoring plan and
reductions to the Companys estimate of total remediation
expenditures.
The Company currently estimates that total remediation
expenditures associated with the EPA order are approximately
$39.1 million. Through December 2010, the Company has
expended $22.7 million related to the EPA order. The
Company currently anticipates further expenditures of
$16.0 million primarily during 2011 with the remainder over
the next 29 years, ending in 2040.
Yorktown 2002 Amended Consent Decree. In May
2002, Giant acquired the Yorktown refinery and assumed certain
environmental obligations including responsibilities under a
consent decree among various parties covering many locations
(the Consent Decree) entered in August 2001 under
the EPA Initiative. Parties to the Consent Decree include the
United States, BP Exploration and Oil Co., Amoco Oil Company,
and Atlantic Richfield Company. As applicable to the Yorktown
refinery, the Consent Decree required, among other things, a
reduction of NOx, sulfur dioxide, and particulate matter
emissions and upgrades to the refinerys leak detection and
repair program. The Company does not expect implementation of
the Consent Decree requirements will result in any soil or
groundwater remediation or
clean-up
requirements. Pursuant to the Consent Decree and prior to
May 31, 2007, Giant had installed a new sour water stripper
and sulfur recovery unit with a tail gas treating unit and an
electrostatic precipitator on the FCCU and had begun using
sulfur dioxide emissions reducing catalyst additives in the
FCCU. The Company believes additional capital expenditures will
be required to complete implementation of the Consent Decree
requirements. The current estimate of $5.0 million could
differ significantly from what is required when refining
operations are resumed. The Company does not expect completing
the requirements of the Consent Decree will result in material
increased operating costs, nor does it expect the completion of
these requirements to have a material effect on its business,
financial condition, or results of operations.
118
WESTERN
REFINING, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Yorktown EPA EPCRA Potential Enforcement
Notice. In January 2010, the EPA issued the
Yorktown refinery a notice to show cause why the EPA
should not bring an enforcement action pursuant to the
notification requirements under the Emergency Planning and
Community
Right-to-Know
Act related to two separate flaring events that occurred in 2007
prior to the Companys acquisition of Giant. The Company
reached a settlement with the EPA for this enforcement notice
for $0.2 million, which was paid prior to December 31,
2010.
Legal
Matters
Over the last several years, lawsuits have been filed in
numerous states alleging that methyl tertiary butyl ether
(MTBE), a high octane blendstock used by many
refiners in producing specially formulated gasoline, has
contaminated water supplies
and/or
damaged natural resources. A subsidiary of the Company, Western
Refining Yorktown, Inc. (Western Yorktown), is
currently a defendant in a lawsuit brought by the State of New
Jersey alleging damage to the State of New Jerseys natural
resources. Western Yorktown denies these allegations and intends
to defend itself accordingly.
Owners of a small hotel in Aztec, New Mexico filed a lawsuit in
San Juan County, New Mexico alleging migration of
underground gasoline onto their property from underground
storage tanks located on a convenience store property across the
street, which is owned by a subsidiary of the Company.
Plaintiffs claim a component of the gasoline, MTBE, has
contaminated their property as a result of this release. The
Trial Court granted summary judgment against Plaintiffs and
dismissed all claims related to the alleged 1992 release. On
appeal by Plaintiffs to the New Mexico Court of Appeals, the
Court reversed and reinstated certain of its claims but only to
the extent they relate to releases that occurred after
January 1, 1999.
A lawsuit has been filed in the Federal District Court for the
District of New Mexico by certain Plaintiffs who allege the
Bureau of Indian Affairs (BIA), acted improperly in
approving certain
rights-of-way
on land allotted to the individual Plaintiffs by the Navajo
Nation, Arizona, New Mexico, and Utah (Navajo
Nation). The lawsuit names the Company and numerous other
defendants
(Right-of-Way
Defendants), and seeks imposition of a constructive trust
and asserts these
Right-of-Way
Defendants are in trespass on the Allottees lands. The
Court dismissed Plaintiffs claims in this matter.
Plaintiffs then attempted to re-file these claims with the
Department of Interior which also dismissed Plaintiffs claims.
Plaintiffs are now attempting to appeal this dismissal within
the Department of Interior. The Company disputes these claims
and will defend itself accordingly.
In February 2009, subsidiaries of the Company, Western Refining
Pipeline, Co. (Western Pipeline) and Western
Refining Southwest, Inc. (Western Southwest) filed a
Compliant at the FERC against TEPPCO Crude Pipeline, LLC
(TEPPCO Pipeline) and TEPPCO Crude Oil, LLC
(TEPPCO Crude) and collectively
(TEPPCO), asserting violations of the Interstate
Commerce Act and breaches of contracts between the parties
including that TEPPCO Pipeline had wrongfully seized crude oil
belonging to Western Southwest and wrongfully taken pipeline
capacity lease payments from Western Pipeline in a cumulative
amount in excess of $5 million. After filing this
Complaint, Western Pipeline and Western Southwest gave TEPPCO
Pipeline and TEPPCO Crude notification of termination of
pipeline capacity lease agreements and a crude oil purchase
agreement with TEPPCO Pipeline and TEPPCO Crude. FERC dismissed
the Complaint on the basis that it does not have jurisdiction.
Western Pipeline and Western Southwest requested the FERC to
reconsider its dismissal and the FERC has denied this request
for reconsideration. Western Pipeline and Western Southwest have
appealed the FERCs ruling to the United States Fifth
Circuit Court of Appeals. After the initial FERC dismissal,
TEPPCO Pipeline and TEPPCO Crude filed a lawsuit against Western
Pipeline and Western Southwest in the Midland Texas District
Court which alleges breach of contract and seeks damages in
excess of $16.4 million. Western Pipeline and Western
Southwest believe their termination of the contracts was
appropriate and believe that TEPPCO owes Western compensation
for the crude oil that TEPPCO wrongfully seized. Western intends
to defend itself against TEPPCOs claims accordingly.
In January 2011, 13 current/former employees of the
Companys Yorktown facility asserted that the elimination
of a temporary annuity supplement under the Companys cash
balance plan was not permitted by the
119
WESTERN
REFINING, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Employee Retirement Income Security Act (ERISA).
These employees have filed an administrative claim with the
administrator of the Companys cash balance plan, which is
currently under review by the administrator. These same
13 employees have also filed a charge of discrimination
with the Norfolk, Virginia Area Office of the Equal Employment
Opportunity Commission asserting that the above mentioned
benefit changes to the cash balance plan and the substitution of
severance benefits in lieu of retiree medical benefits, which
the Company made prior to the shutdown of Yorktown facilities,
violated the Age Discrimination in Employment Act. The Company
does not think there is any merit to this assertion and will
defend itself accordingly.
In July 2010, subsidiaries of the Company, Western Southwest and
Western Refining Company, L.P., were sued in bankruptcy
preference actions brought by the bankruptcy Litigation Trustee
(Trustee) for a former customer of these
subsidiaries. These subsidiaries have reached an agreement to
amicably resolve these preference actions with the Trustee and
the Company expects these claims to be voluntarily dismissed in
the immediate future.
Regarding the claims asserted against the Company referenced
above, potentially applicable factual and legal issues have not
been resolved, the Company has yet to determine if a liability
is probable and the Company cannot reasonably estimate the
amount of any loss associated with these matters. Accordingly,
the Company has not recorded a liability for these pending
lawsuits.
Union
Matters
As of February 25, 2011, the Company employed approximately
2,950 people, approximately 380 of whom were covered by
collective bargaining agreements. Subject to a Memorandum of
Understanding dated August 23, 2010 between Western
Refining Yorktown, Inc. and the local union representing the
covered Yorktown refinery employees, the collective bargaining
agreement at the Yorktown refinery was terminated in connection
with the temporary suspension of refining activities at the
Yorktown facility. If the Company restarts refining operations
at the Yorktown facility prior to March 15, 2012, the
collective bargaining agreement for covered Yorktown employees
will be reinstated. All separated covered employees have recall
rights if the Company restarts Yorktown refining operations
prior to March 16, 2012. In 2008, the Company successfully
negotiated collective bargaining agreements covering employees
at the Gallup and Bloomfield refineries that expire in 2011 and
2012, respectively. Although the collective bargaining agreement
remains in force, the covered employees at the Bloomfield
refinery were terminated in connection with the indefinite
suspension of refining operations at the Bloomfield refinery
during November 2009. The Company also successfully negotiated a
new collective bargaining agreement covering employees at the
El Paso refinery, renewing the collective bargaining
agreement that expired in April 2009. The collective bargaining
agreement covering the El Paso refinery employees expires
in April 2012. While all of the collective bargaining agreements
contain no strike provisions, those provisions are
not effective in the event that an agreement expires.
Accordingly, the Company may not be able to prevent a strike or
work stoppage in the future, and any such work stoppage could
have a material adverse affect on the Companys business,
financial condition, and results of operations.
Other
Matters
The Company is party to various other claims and legal actions
arising in the normal course of business. The Company believes
that the resolution of these matters will not have a material
adverse effect on its financial condition, results of
operations, or cash flows.
|
|
22.
|
Concentration
of Risk
|
Significant
Customers
The Company sells a variety of refined products to a diverse
customer base. No customer accounted for more than 10% of
consolidated net sales during the three years ended
December 31, 2010.
120
WESTERN
REFINING, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Sales
by Product
All sales were domestic sales in the United States, except for
sales of gasoline and diesel fuel for export into Mexico. The
sales for export were to PMI Trading Limited, an affiliate of
Petroleos Mexicanos, the Mexican state-owned oil company, and
accounted for approximately 8.3%, 8.5%, and 8.3% of consolidated
sales during the years ended December 31, 2010, 2009, and
2008, respectively.
The following table summarizes the percentages of all refined
product sales to total sales for the three years ended
December 31, 2010:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
Refined products:
|
|
|
|
|
|
|
|
|
|
|
|
|
Gasoline
|
|
|
54.8
|
%
|
|
|
56.5
|
%
|
|
|
48.1
|
%
|
Diesel fuel
|
|
|
31.0
|
|
|
|
29.4
|
|
|
|
37.5
|
|
Jet fuel
|
|
|
4.3
|
|
|
|
3.5
|
|
|
|
4.4
|
|
Asphalt
|
|
|
1.7
|
|
|
|
1.9
|
|
|
|
0.8
|
|
Other
|
|
|
3.7
|
|
|
|
3.7
|
|
|
|
5.5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
95.5
|
|
|
|
95.0
|
|
|
|
96.3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lubricants
|
|
|
1.2
|
|
|
|
1.6
|
|
|
|
1.5
|
|
Merchandise and other
|
|
|
3.3
|
|
|
|
3.4
|
|
|
|
2.2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
100.0
|
%
|
|
|
100.0
|
%
|
|
|
100.0
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
23.
|
Operating
Leases and Other Commitments
|
The Company has commitments under various operating leases with
initial terms greater than one year for buildings, warehouses,
card locks, barges, railcars, and other facilities. These leases
have terms that will expire on various dates through 2030.
The Company expects that in the normal course of business, these
leases will be renewed or replaced by other leases. Certain of
the Companys lease agreements provide for the fair value
purchase of the leased asset at the end of lease. Rent expense
for operating leases that provide for periodic rent escalations
or rent holidays over the term of the lease is recognized on a
straight-line basis.
In the normal course of business, the Company also has long-term
commitments to purchase services, such as natural gas,
electricity, water, and transportation services for use by its
refineries at market-based rates. The Company also is party to
various refined product and crude oil supply and exchange
agreements.
In June 2005, Western Refining LP entered into a sulfuric acid
regeneration and sulfur gas processing agreement with E.I. du
Pont de Nemours (DuPont). Under the agreement,
Western Refining LP has a long-term commitment to purchase
services for use by its El Paso refinery. In exchange for
this commitment, DuPont agreed to design, construct, and operate
two sulfuric acid regeneration plants on property leased from
the Company at the El Paso refinery. In November 2008, the
Company began processing all sulfur gas from the north side of
the El Paso refinery at the DuPont facility. In January
2009, the Company began processing all sulfur gas from the south
side of the El Paso refinery at the DuPont facility. The
annual commitment for these services will range from
$14.0 million to $16.0 million per year over the next
20 years. Prior to this agreement, Western Refining LP
incurred direct operating expenses related to sulfuric acid
regeneration under a short-term agreement.
In August 2005, Western Refining LP entered into a throughput
and distribution agreement and associated storage agreement with
Magellan Pipeline Company, L.P. Under these agreements, Western
Refining LP has a long-term commitment that began in February
2006 to provide for the transportation and storage of alkylate
and other
121
WESTERN
REFINING, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
refined products from the Gulf Coast to the Companys
El Paso refinery via the Magellan South System pipeline.
Western Refining LP is committed to pay $2.6 million per
quarter through the end of the agreement in February 2011.
As a result of the Giant acquisition, a subsidiary of the
Company is a party to a ten-year lease agreement for an
administrative office building in Scottsdale, Arizona that ends
in 2013. During 2008, the Company entered into an agreement to
sublease a portion of this property for $0.3 million
annually from February 15, 2009 through October 31,
2013. The rental payments for this property have been included
as part of our estimated rental payments in the table below.
In November 2007, a subsidiary of the Company entered into a
ten-year lease agreement for an office space in downtown
El Paso. The building will serve as the Companys
headquarters. In December 2007, a subsidiary of the Company
entered into an eleven-year lease agreement for an office
building in Tempe, Arizona. The building centralized the
Companys operational and administrative offices in the
Phoenix area.
The following are the Companys annual minimum rental
payments under non-cancelable operating leases that have lease
terms of one year or more (in thousands):
|
|
|
|
|
2011
|
|
$
|
16,059
|
|
2012
|
|
|
13,025
|
|
2013
|
|
|
10,693
|
|
2014
|
|
|
9,045
|
|
2015
|
|
|
7,270
|
|
2016 and thereafter
|
|
|
38,413
|
|
Total rental expense was $15.7 million, $16.1 million,
and $17.0 million for the years ended December 31,
2010, 2009, and 2008, respectively. Contingent rentals and
subleases were not significant in any year.
|
|
24.
|
Quarterly
Financial Information (Unaudited)
|
Demand for gasoline is generally higher during the summer months
than during the winter months. In addition, higher volumes of
ethanol are blended to the gasoline produced in the Southwest
region during the winter months, thereby increasing the supply
of gasoline. This combination of decreased demand and increased
supply during the winter months can lower gasoline prices. As a
result, the Companys operating results for the first and
fourth calendar quarters are generally lower than those for the
second and third calendar quarters of each year. The effects of
seasonal demand for gasoline are partially offset by increased
demand during the winter months for diesel fuel in the Southwest
and heating oil in the Northeast. During 2010, the volatility in
crude oil prices and refining margins also contributed to the
variability of the Companys results of operations for the
four calendar quarters.
During the latter part of March 2010, the Company reversed
$14.7 million related to its accrued bonus estimate for
2009. This revision of the Companys 2009 bonus estimate
reduced direct operating expenses (exclusive of depreciation and
amortization) and selling, general, and administrative expenses
reported for the three months ended March 31, 2010 by
$8.5 million and $6.2 million, respectively. During
the fourth quarter of 2009, we recovered $10.6 million from
various third parties related to environmental costs recorded
during 2009 and prior years. These recoveries are included in
direct operating expenses reported for the three months ended
December 31, 2009. Additionally, during the third quarter
of 2009, we decreased our property tax expense estimate by
$5.5 million resulting from revised El Paso property
appraisal rolls for 2006 through 2008. The revision to the
property appraisal rolls also resulted in a refund of
$2.9 million from various taxing authorities, further
reducing our property tax expense for a total decrease of
$8.4 million for the quarter ended September 30, 2009.
We also recorded a fourth quarter 2009 legal settlement charge
of $20.0 million, which was included in other income
(expense), net.
122
WESTERN
REFINING, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2010
|
|
|
|
Quarter
|
|
|
|
First
|
|
|
Second
|
|
|
Third
|
|
|
Fourth
|
|
|
|
(Unaudited)
|
|
|
|
(In thousands, except for share data)
|
|
|
Net sales
|
|
$
|
1,915,395
|
|
|
$
|
2,145,337
|
|
|
$
|
2,038,296
|
|
|
$
|
1,866,025
|
|
Operating costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of products sold (exclusive of depreciation and
amortization)
|
|
|
1,765,461
|
|
|
|
1,906,941
|
|
|
|
1,807,411
|
|
|
|
1,676,154
|
|
Direct operating expenses (exclusive of depreciation and
amortization)
|
|
|
106,980
|
|
|
|
113,968
|
|
|
|
116,982
|
|
|
|
106,601
|
|
Selling, general, and administrative expenses
|
|
|
16,501
|
|
|
|
21,072
|
|
|
|
24,031
|
|
|
|
22,571
|
|
Other impairment losses
|
|
|
|
|
|
|
|
|
|
|
3,963
|
|
|
|
9,075
|
|
Maintenance turnaround expense
|
|
|
23,286
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization
|
|
|
34,282
|
|
|
|
34,759
|
|
|
|
35,253
|
|
|
|
34,327
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating costs and expenses
|
|
|
1,946,510
|
|
|
|
2,076,740
|
|
|
|
1,987,640
|
|
|
|
1,848,728
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss)
|
|
|
(31,115
|
)
|
|
|
68,597
|
|
|
|
50,656
|
|
|
|
17,297
|
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest income
|
|
|
30
|
|
|
|
136
|
|
|
|
151
|
|
|
|
124
|
|
Interest expense and other financing costs
|
|
|
(36,774
|
)
|
|
|
(37,295
|
)
|
|
|
(37,099
|
)
|
|
|
(35,381
|
)
|
Amortization of loan fees
|
|
|
(2,414
|
)
|
|
|
(2,420
|
)
|
|
|
(2,453
|
)
|
|
|
(2,452
|
)
|
Other income (expense), net
|
|
|
(294
|
)
|
|
|
4,213
|
|
|
|
712
|
|
|
|
2,655
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before income taxes
|
|
|
(70,567
|
)
|
|
|
33,231
|
|
|
|
11,967
|
|
|
|
(17,757
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Provision for income taxes
|
|
|
39,878
|
|
|
|
(18,878
|
)
|
|
|
(5,108
|
)
|
|
|
10,185
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
(30,689
|
)
|
|
$
|
14,353
|
|
|
$
|
6,859
|
|
|
$
|
(7,572
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic earnings (loss) per common share
|
|
$
|
(0.35
|
)
|
|
$
|
0.16
|
|
|
$
|
0.08
|
|
|
$
|
(0.09
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted earnings (loss) per common share
|
|
$
|
(0.35
|
)
|
|
$
|
0.16
|
|
|
$
|
0.08
|
|
|
$
|
(0.09
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
123
WESTERN
REFINING, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2009
|
|
|
|
Quarter
|
|
|
|
First
|
|
|
Second
|
|
|
Third
|
|
|
Fourth
|
|
|
|
(Unaudited)
|
|
|
|
(In thousands, except for share data)
|
|
|
Net sales
|
|
$
|
1,368,198
|
|
|
$
|
1,583,545
|
|
|
$
|
1,896,273
|
|
|
$
|
1,959,352
|
|
Operating costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of products sold (exclusive of depreciation and
amortization)
|
|
|
1,047,831
|
|
|
|
1,368,380
|
|
|
|
1,699,399
|
|
|
|
1,828,518
|
|
Direct operating expenses (exclusive of depreciation and
amortization)
|
|
|
133,538
|
|
|
|
123,940
|
|
|
|
116,717
|
|
|
|
111,969
|
|
Selling, general, and administrative expenses
|
|
|
35,018
|
|
|
|
27,160
|
|
|
|
23,725
|
|
|
|
23,794
|
|
Goodwill impairment losses
|
|
|
|
|
|
|
299,552
|
|
|
|
|
|
|
|
|
|
Other impairment losses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
52,788
|
|
Maintenance turnaround expense
|
|
|
104
|
|
|
|
3,218
|
|
|
|
1,031
|
|
|
|
3,735
|
|
Depreciation and amortization
|
|
|
34,240
|
|
|
|
40,417
|
|
|
|
34,725
|
|
|
|
36,599
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating costs and expenses
|
|
|
1,250,731
|
|
|
|
1,862,667
|
|
|
|
1,875,597
|
|
|
|
2,057,403
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss)
|
|
|
117,467
|
|
|
|
(279,122
|
)
|
|
|
20,676
|
|
|
|
(98,051
|
)
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest income
|
|
|
143
|
|
|
|
37
|
|
|
|
17
|
|
|
|
51
|
|
Interest expense and other financing costs
|
|
|
(27,055
|
)
|
|
|
(27,968
|
)
|
|
|
(33,024
|
)
|
|
|
(33,274
|
)
|
Amortization of loan fees
|
|
|
(1,554
|
)
|
|
|
(1,483
|
)
|
|
|
(1,795
|
)
|
|
|
(2,038
|
)
|
Write-off of unamortized loan fees
|
|
|
|
|
|
|
(9,047
|
)
|
|
|
|
|
|
|
|
|
Other income (expense), net
|
|
|
922
|
|
|
|
3,711
|
|
|
|
(39
|
)
|
|
|
(19,778
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before income taxes
|
|
|
89,923
|
|
|
|
(313,872
|
)
|
|
|
(14,165
|
)
|
|
|
(153,090
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Provision for income taxes
|
|
|
(30,995
|
)
|
|
|
6,555
|
|
|
|
9,383
|
|
|
|
55,640
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
58,928
|
|
|
$
|
(307,317
|
)
|
|
$
|
(4,782
|
)
|
|
$
|
(97,450
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic earnings (loss) per common share
|
|
$
|
0.86
|
|
|
$
|
(4.24
|
)
|
|
$
|
(0.05
|
)
|
|
$
|
(1.11
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted earnings (loss) per common share
|
|
$
|
0.86
|
|
|
$
|
(4.24
|
)
|
|
$
|
(0.05
|
)
|
|
$
|
(1.11
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
124
|
|
Item 9.
|
Changes
In and Disagreements With Accountants on Accounting and
Financial Disclosure
|
None.
|
|
Item 9A.
|
Controls
and Procedures
|
Evaluation of disclosure controls and
procedures. Our chief executive officer and chief
financial officer, after evaluating the effectiveness of the
Companys disclosure controls and procedures
(as defined in the Securities Exchange Act of 1934
Rules 13a-15(e)
and
15d-15(e))
as of December 31, 2010 (the Evaluation Date),
concluded that as of the Evaluation Date, our disclosure
controls and procedures were effective.
Managements Report on Internal Control Over Financial
Reporting. Included herein under the caption
Managements Report on Internal Control Over
Financial Reporting on page 71 of this report.
Changes in internal control over financial
reporting. There were no changes in our internal
control over financial reporting that occurred during the
quarter ended December 31, 2010, that materially affected,
or are reasonably likely to materially affect, our internal
control over financial reporting.
|
|
Item 9B.
|
Other
Information
|
None.
PART III
Certain information required in this Part III is
incorporated by reference to Western Refining, Inc.s
Definitive Proxy Statement to be filed with the Securities and
Exchange Commission pursuant to Regulation 14A within
120 days after the end of the fiscal year covered by this
report.
|
|
Item 10.
|
Directors,
Executive Officers, and Corporate Governance
|
The information required by this item is incorporated by
reference to the information contained in Western Refining,
Inc.s 2010 Definitive Proxy Statement under the headings
Election of Directors and Executive
Compensation and Other Information.
|
|
Item 11.
|
Executive
Compensation
|
The information required by this item is incorporated by
reference to the information contained in Western Refining,
Inc.s 2010 Definitive Proxy Statement under the heading
Executive Compensation and Other Information.
|
|
Item 12.
|
Security
Ownership of Certain Beneficial Owners and Management and
Related Stockholder Matters
|
Security
Ownership of Certain Beneficial Owners and Management
The information required by this item is incorporated by
reference to the information contained in Western Refining,
Inc.s 2010 Definitive Proxy Statement under the heading
Security Ownership of Certain Beneficial Owners and
Management.
125
Securities
Authorized for Issuance Under Equity Compensation
Plans
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(c)
|
|
|
|
|
|
|
|
|
|
Number of
|
|
|
|
|
|
|
|
|
|
securities
|
|
|
|
(a)
|
|
|
|
|
|
remaining available
|
|
|
|
Number of
|
|
|
|
|
|
for future issuance
|
|
|
|
securities to be
|
|
|
(b)
|
|
|
under equity
|
|
|
|
issued upon
|
|
|
Weighted average
|
|
|
compensation plans
|
|
|
|
exercise of
|
|
|
exercise price of
|
|
|
(excluding
|
|
|
|
outstanding
|
|
|
outstanding
|
|
|
securities
|
|
|
|
options, warrants,
|
|
|
options, warrants,
|
|
|
reflected in column
|
|
Plan Category
|
|
and rights
|
|
|
and rights
|
|
|
(a))
|
|
|
Equity compensation plans approved by security holders
|
|
|
|
|
|
|
|
|
|
|
3,829,843
|
|
Equity compensation plans not approved by security holders
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
3,829,843
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Item 13.
|
Certain
Relationships and Related Transactions, and Director
Independence
|
The information required by this item is incorporated by
reference to the information contained in Western Refining,
Inc.s 2010 Definitive Proxy Statement under the heading
Certain Relationships and Related Transactions.
|
|
Item 14.
|
Principal
Accountant Fees and Services
|
The information required by this item is incorporated by
reference to the information contained in Western Refining,
Inc.s 2010 Definitive Proxy Statement under the heading
Proposal 2: Ratification of Independent Auditor.
PART IV
|
|
Item 15.
|
Exhibits
and Financial Statement Schedules
|
(a) Financial Statements:
See Index to Financial Statements included in Item 8.
(b) The following exhibits are filed herewith (or
incorporated by reference herein):
|
|
|
|
|
Number
|
|
Exhibit Title
|
|
|
2
|
.1
|
|
Agreement and Plan of Merger, dated August 26, 2006, by and
among Western Refining, Inc., New Acquisition Corporation and
Giant Industries, Inc. (incorporated by reference to
Exhibit 2.1 to the Companys Current Report on
Form 8-K,
filed with the SEC on August 28, 2006).
|
|
2
|
.2
|
|
Amendment No. 1 to the Agreement and Plan of Merger, dated
November 12, 2006, by and among Western Refining, Inc., New
Acquisition Corporation and Giant Industries, Inc. (incorporated
by reference to Exhibit 2.1 to the Companys Current
Report on
Form 8-K,
filed with the SEC on November 13, 2006).
|
|
3
|
.1
|
|
Certificate of Incorporation of the Company (incorporated by
reference to Exhibit 3.1 to the Companys Annual
Report on
Form 10-K,
filed with the SEC on March 24, 2006).
|
|
3
|
.2
|
|
Bylaws of the Company (incorporated by reference to
Exhibit 3.2 to the Companys Annual Report on
Form 10-K,
filed with the SEC on March 24, 2006).
|
|
4
|
.1
|
|
Specimen of Company Common Stock Certificate (incorporated by
reference to Exhibit 4.1 to the Companys Registration
Statement on
Form S-1/A,
filed with the SEC on December 5, 2005 (SEC File
No. 333-128629)).
|
126
|
|
|
|
|
Number
|
|
Exhibit Title
|
|
|
4
|
.2
|
|
Registration Rights Agreement, dated January 24, 2006, by
and between the Company and each of the stockholders listed on
the signature pages thereto (incorporated by reference to
Exhibit 4.1 to the Companys Current Report on
Form 8-K,
filed with the SEC on January 25, 2006 (SEC File
No. 001-32721)).
|
|
4
|
.3
|
|
Indenture dated June 10, 2009 between Western Refining,
Inc. and The Bank of New York Mellon Trust Company, N.A.,
as trustee (incorporated by reference to Exhibit 4.1 to the
Companys Quarterly Report on
Form 10-Q,
filed with the SEC on August 7, 2009).
|
|
4
|
.4
|
|
Supplemental Indenture dated June 10, 2009 between Western
Refining, Inc. and The Bank of New York Mellon
Trust Company, N.A., as trustee (incorporated by reference
to Exhibit 4.1 to the Companys Current Report on
Form 8-K
filed on June 10, 2009).
|
|
4
|
.5
|
|
Form of Convertible Senior Note (included in Exhibit 4.4).
|
|
4
|
.6
|
|
Indenture dated June 12, 2009 among Western Refining, Inc.,
the Guarantors named therein and The Bank of New York Mellon
Trust Company, N.A., as trustee, paying agent, registrar
and transfer agent (incorporated by reference to
Exhibit 4.1 to the Companys Current Report on
Form 8-K
filed on June 15, 2009).
|
|
4
|
.7
|
|
Form of 11.25% Senior Secured Note (included in
Exhibit 4.6)
|
|
4
|
.8
|
|
Form of Senior Secured Floating Rate Note (included in
Exhibit 4.6)
|
|
10
|
.1
|
|
Employment Agreement, dated January 24, 2006, by and
between Western Refining GP, LLC and Paul L. Foster
(incorporated by reference to Exhibit 10.1 to the
Companys Current Report on
Form 8-K,
filed with the SEC on January 25, 2006 (SEC File
No. 001-32721)).
|
|
10
|
.1.1
|
|
First Amendment to the Employment Agreement referred to in
Exhibit 10.1, dated December 28, 2006 (incorporated by
reference to Exhibit 10.1.1 to the Companys Annual
Report on
Form 10-K,
filed with the SEC on March 8, 2007 (SEC File
No. 001-32721)).
|
|
10
|
.1.2
|
|
Second Amendment to the Employment Agreement referred to in
Exhibit 10.1, dated December 31, 2008 (incorporated by
reference to Exhibit 10.1.2 to the Companys Annual
Report on
Form 10-K,
filed with the SEC on March 8, 2007 (SEC File
No. 001-32721)).
|
|
10
|
.2
|
|
Employment Agreement, dated January 24, 2006, by and
between Western Refining GP, LLC and Jeff A. Stevens
(incorporated by reference to Exhibit 10.2 to the
Companys Current Report on
Form 8-K,
filed with the SEC on January 25, 2006 (SEC File
No. 001-32721)).
|
|
10
|
.2.1
|
|
First Amendment to the Employment Agreement referred to in
Exhibit 10.2, dated December 28, 2006 (incorporated by
reference to Exhibit 10.2.1 to the Companys Annual
Report on
Form 10-K,
filed with the SEC on March 8, 2007 (SEC File
No. 001-32721).
|
|
10
|
.2.2
|
|
Second Amendment to the Employment Agreement referred to in
Exhibit 10.2, dated December 31, 2008 (incorporated by
reference to Exhibit 10.2.2 to the Companys Annual
Report on
Form 10-K,
filed with the SEC on March 13, 2007 (SEC File
No. 001-32721)).
|
|
10
|
.3
|
|
Employment Agreement, dated January 24, 2006, by and
between Western Refining GP, LLC and Scott D. Weaver
(incorporated by reference to Exhibit 10.4 to the
Companys Current Report on
Form 8-K,
filed with the SEC on January 25, 2006 (SEC File
No. 001-32721)).
|
|
10
|
.3.1
|
|
First Amendment to the Employment Agreement referred to in
Exhibit 10.3, dated December 28, 2006 (incorporated by
reference to Exhibit 10.3.1 to the Companys Annual
Report on
Form 10-K,
filed with the SEC on March 8, 2007 (SEC File
No. 001-32721)).
|
|
10
|
.3.2
|
|
Letter of Termination of Employment Agreement dated
December 31, 2007, between Western Refining GP, LLC and
Scott D. Weaver (incorporated by reference to
Exhibit 10.3.2 to the Companys Annual Report on
Form 10-K,
filed with the SEC on February 29, 2008).
|
|
10
|
.4
|
|
Employment Agreement, dated January 24, 2006, by and
between Western Refining GP, LLC and Gary R. Dalke (incorporated
by reference to Exhibit 10.5 to the Companys Current
Report on
Form 8-K,
filed with the SEC on January 25, 2006 (SEC File
No. 001-32721)).
|
|
10
|
.4.1
|
|
First Amendment to the Employment Agreement referred to in
Exhibit 10.4, dated December 31, 2008 (incorporated by
reference to Exhibit 10.4.1 to the Companys Annual
Report on
Form 10-K,
filed with the SEC on March 13, 2007 (SEC File
No. 001-32721)).
|
127
|
|
|
|
|
Number
|
|
Exhibit Title
|
|
|
10
|
.5
|
|
Employment Agreement, dated January 24, 2006, by and
between Western Refining GP, LLC and Lowry Barfield
(incorporated by reference to Exhibit 10.6 to the
Companys Current Report on
Form 8-K,
filed with the SEC on January 25, 2006 (SEC File
No. 001-32721)).
|
|
10
|
.5.1
|
|
First Amendment to the Employment Agreement referred to in
Exhibit 10.5, dated December 31, 2008 (incorporated by
reference to Exhibit 10.5.1 to the Companys Annual
Report on
Form 10-K,
filed with the SEC on March 13, 2007 (SEC File
No. 001-32721)).
|
|
10
|
.6
|
|
Term Loan Credit Agreement, dated May 31, 2007, among
Western Refining, Inc., Bank of America, N.A., as administrative
agent, and the lenders party thereto (incorporated by reference
to Exhibit 10.2 to the Companys Current Report on
Form 8-K,
filed with the SEC on June 1, 2007 (SEC File
No. 001-32721)).
|
|
10
|
.6.1
|
|
First Amendment to Term Loan Credit Agreement dated as of
June 30, 2008, by and among Western Refining, Inc., the
lenders party thereto and Bank of America, N.A., as the
Administrative Agent (incorporated by reference to
Exhibit 10.2 to the Companys Current Report on
Form 8-K,
filed with the Securities and Exchange Commission on
July 1, 2008).
|
|
10
|
.6.2
|
|
Second Amendment to Term Loan Credit Agreement dated as of
May 29, 2009, among the Company, as Borrower, the lenders
from time to time party thereto, and Bank of America, N.A., as
Administrative Agent, amending that certain Term Loan Credit
Agreement, dated May 31, 2007, as amended by the First
Amendment to Term Loan Credit Agreement dated as of
June 30, 2008 (incorporated by reference to
Exhibit 10.1 to the Companys Current Report on
Form 8-K,
filed with the Securities and Exchange Commission on
May 29, 2009).
|
|
10
|
.6.3
|
|
Third Amendment to the Term Loan Credit Agreement, dated as of
November 24, 2009, among the Company, as Borrower, the
lenders from time to time party thereto, and Bank of America,
N.A., as Administrative Agent, amending that certain Term Loan
Credit Agreement, dated May 31, 2007, as amended by the
First Amendment to Term Loan Credit Agreement dated as of
June 30, 2008 and the Second Amendment to the Term Loan
Credit Agreement dated as of May 29, 2009 (incorporated by
reference to Exhibit 10.1 to the Companys Current
Report on
Form 8-K,
filed with the Securities and Exchange Commission on
November 24, 2009).
|
|
10
|
.7
|
|
Revolving Credit Agreement, dated May 31, 2007, among
Western Refining, Inc., Bank of America, N.A., as administrative
agent, swing line lender and L/C issuer, and the lenders party
thereto (incorporated by reference to Exhibit 10.1 to the
Companys Current Report on
Form 8-K,
filed with the SEC on June 1, 2007 (SEC File
No. 001-32721)).
|
|
10
|
.7.1
|
|
First Amendment to Revolving Credit Agreement dated as of
June 30, 2008, by and among Western Refining, Inc., the
lenders party thereto and Bank of America, N.A., as the
Administrative Agent, Swing Line Lender, L/C Issuer and a Lender
(incorporated by reference to Exhibit 10.1 to the
Companys Current Report on
Form 8-K,
filed with the Securities and Exchange Commission on
July 1, 2008).
|
|
10
|
.7.2
|
|
Second Amendment to the Revolving Credit Agreement dated as of
May 29, 2009, among the Company, as Borrower, the lenders
from time to time party thereto, and Bank of America, N.A., as
Administrative Agent, Swing Line Lender and L/C Issuer, amending
that certain Revolving Credit Agreement, dated May 31,
2007, as amended by the First Amendment to Revolving Credit
Agreement dated as of June 30, 2008 (incorporated by
reference to Exhibit 10.2 to the Companys Current
Report on
Form 8-K,
filed with the Securities and Exchange Commission on
May 29, 2009).
|
|
10
|
.7.3
|
|
Third Amendment to the Revolving Credit Agreement dated as of
November 24, 2009, among the Company, as Borrower, the
lenders from time to time party thereto, and Bank of America,
N.A., as Administrative Agent, Swing Line Lender and L/C Issuer,
amending that certain Revolving Credit Agreement, dated
May 31, 2007, as amended by the First Amendment to
Revolving Credit Agreement dated as of June 30, 2008 and
the Second Amendment to Revolving Credit Agreement dated as of
May 29, 2009 (incorporated by reference to
Exhibit 10.2 to the Companys Current Report on
Form 8-K,
filed with the Securities and Exchange Commission on
November 24, 2009).
|
128
|
|
|
|
|
Number
|
|
Exhibit Title
|
|
|
10
|
.7.4
|
|
Fourth Amendment to the Revolving Credit Agreement dated as of
February 18, 2010, among the Company, as Borrower, the
lenders from time to time party thereto, and Bank of America,
N.A., as Administrative Agent, Swing Line Lender and L/C Issuer,
amending that certain Revolving Credit Agreement, dated
May 31, 2007, as amended by the First Amendment to
Revolving Credit Agreement dated as of June 30, 2008, the
Second Amendment to Revolving Credit Agreement dated as of
May 29, 2009, and the Third Amendment to Revolving Credit
Agreement dated as of November 24, 2009 (incorporated by
reference to Exhibit 10.7.4 to the Companys Annual
Report on
Form 10-K,
filed with the SEC on March 12, 2010 (SEC File
No. 001-32721)).
|
|
10
|
.7.5
|
|
Fifth Amendment to Revolving Credit Agreement dated as of
December 23, 2010, among the Company, as Borrower, the
lenders from time to time party thereto, and Bank of America,
N.A., as Administrative Agent, Swing Line Lender and L/C Issuer,
amending that certain Revolving Credit Agreement, dated
May 31, 2007, as amended by the First Amendment to
Revolving Credit Agreement dated as of June 30, 2008, the
Second Amendment to Revolving Credit Agreement dated as of
May 29, 2009, and the Third Amendment to Revolving Credit
Agreement dated as of November 24, 2009, and the Fourth
Amendment to Revolving Credit Agreement dated February 18,
2010 (incorporated by reference to Exhibit 10.1 to the
Companys Current Report on
Form 8-K,
filed with the SEC on December 28, 2010 (SEC File
No. 001-32721)).
|
|
10
|
.8
|
|
L/C Credit Agreement, dated as of June 30, 2008 among
Western Refining, Inc., Bank of America, N.A., as Administrative
Agent and L/C Issuer and the lenders party thereto (incorporated
by reference to Exhibit 10.3 to the Companys Current
Report on
Form 8-K,
filed with the Securities and Exchange Commission on
July 1, 2008).
|
|
10
|
.9
|
|
Form of Indemnification Agreement, by and between the Company
and each director and officer of the Company party thereto
(incorporated by reference to Exhibit 10.7 to the
Companys Current Report on
Form 8-K,
filed with the SEC on January 25, 2006 (SEC File
No. 001-32721)).
|
|
10
|
.10
|
|
Operating Agreement, dated May 6, 1993, by and between
Western Refining LP and Chevron U.S.A. Inc. (incorporated by
reference to Exhibit 10.10 to the Companys
Registration Statement on
Form S-1/A,
filed with the SEC on November 3, 2005 (SEC File
No. 333-128629)).
|
|
10
|
.11
|
|
Purchase and Sale Agreement, dated May 29, 2003, by and
among Chevron U.S.A. Inc., Chevron Pipe Line Company, Western
Refining LP and Kaston Pipeline Company, L.P. (incorporated by
reference to Exhibit 10.11 to the Companys
Registration Statement on
Form S-1/A,
filed with the SEC on November 3, 2005 (SEC File
No. 333-128629)).
|
|
10
|
.12
|
|
Lease Agreement, dated October 24, 2005, by and between
Western Refining LP and Transmountain Oil Company, L.C.
(incorporated by reference to Exhibit 10.12 to the
Companys Registration Statement on
Form S-1/A,
filed with the SEC on November 3, 2005 (SEC File
No. 333-128629)).
|
|
10
|
.14
|
|
RHC Holdings, L.P. Long-Term Unit Equity Appreciation Rights
Plan, dated August 25, 2003 (incorporated by reference to
Exhibit 10.13 to the Companys Registration Statement
on
Form S-1/A,
filed with the SEC on November 3, 2005 (SEC File
No. 333-128629)).
|
|
10
|
.15
|
|
RHC Holdings, L.P. Long-Term Equity Appreciation Rights Award,
dated August 25, 2003, by and between Gary R. Dalke and RHC
Holdings, L.P. (incorporated by reference to Exhibit 10.14
to the Companys Registration Statement on
Form S-1/A,
filed with the SEC on November 3, 2005 (SEC File
No. 333-128629)).
|
|
10
|
.16
|
|
Long-Term Equity Appreciation Rights Award Amendment Agreement,
dated November 9, 2005, by and between Gary R. Dalke, RHC
Holdings, L.P., the Company and Western Refining LP
(incorporated by reference to Exhibit 10.15 to the
Companys Registration Statement on
Form S-1/A,
filed with the SEC on December 5, 2005 (SEC File
No. 333-128629)).
|
|
10
|
.17
|
|
Long-Term Equity Appreciation Rights Award Second Amendment
Agreement, dated December 31, 2005, by and between Gary R.
Dalke, the Company and Western Refining LP (incorporated by
reference to Exhibit 10.24 to the Companys
Registration Statement on
Form S-1/A,
filed with the SEC on January 3, 2006 (SEC File
No. 333-128629)).
|
|
10
|
.18
|
|
Long-Term Equity Appreciation Rights Awards Third Amendment
Agreement, dated December 22, 2006, by and between Gary R.
Dalke, the Company and Western Refining LP (incorporated by
reference to Exhibit 10.16 to the Companys Annual
Report on
Form 10-K,
filed with the SEC on March 8, 2007).
|
129
|
|
|
|
|
Number
|
|
Exhibit Title
|
|
|
10
|
.19
|
|
Western Refining Long-Term Incentive Plan (incorporated by
reference to Exhibit 10.17 to the Companys Annual
Report on
Form 10-K,
filed with the SEC on March 24, 2006).
|
|
10
|
.19.1
|
|
First Amendment to the Western Refining Long-Term Incentive Plan
referred to in Exhibit 10.19, dated December 4, 2007
(incorporated by reference to Exhibit 10.19.1 to the
Companys Annual Report on
Form 10-K,
filed with the SEC on March 13, 2009 (SEC File
No. 001-32721)).
|
|
10
|
.19.2
|
|
Second Amendment to the Western Refining Long-Term Incentive
Plan referred to in Exhibit 10.19, dated November 20,
2008 (incorporated by reference to Exhibit 10.19.2 to the
Companys Annual Report on
Form 10-K,
filed with the SEC on March 13, 2009 (SEC File
No. 001-32721)).
|
|
10
|
.20
|
|
Form of Restricted Stock Grant Agreement (incorporated by
reference to Exhibit 10.20 to the Companys
Registration Statement on
Form S-1/A,
filed with the SEC on December 5, 2005 (SEC File
No. 333-128629)).
|
|
10
|
.21
|
|
Form of Nonqualified Stock Option Agreement (incorporated by
reference to Exhibit 10.21 to the Companys
Registration Statement on
Form S-1/A,
filed with the SEC on December 5, 2005 (SEC File
No. 333-128629)).
|
|
10
|
.22
|
|
Letter Agreement, dated June 24, 2005, by and between
Western Refining Company, L.P. and Ascarate Group LLP
(incorporated by reference to Exhibit 10.17 to the
Companys Registration Statement on
Form S-1/A,
filed with the SEC on November 3, 2005 (SEC File
No. 333-128629)).
|
|
10
|
.23
|
|
Promissory Note, dated June 24, 2005, by Ascarate Group LLP
in favor of Western Refining LP (incorporated by reference to
Exhibit 10.16 to the Companys Registration Statement
on
Form S-1/A,
filed with the SEC on November 3, 2005 (SEC File
No. 333-128629)).
|
|
10
|
.24
|
|
Summary of Compensation for Non-Employee Directors (incorporated
by reference to Exhibit 10.19 to the Companys
Registration Statement on
Form S-1/A,
filed with the SEC on November 3, 2005 (SEC File
No. 333-128629)).
|
|
10
|
.25
|
|
Form of Time Share Agreement, dated November 20, 2004, by
and between Western Refining LP and the persons parties thereto
(incorporated by reference to Exhibit 10.23 to the
Companys Registration Statement on
Form S-1/A,
filed with the SEC on December 5, 2005 (SEC File
No. 333-128629)).
|
|
10
|
.26
|
|
Consulting and Non-Competition Agreement, dated August 26,
2006, by and between the Company and Fred L. Holliger
(incorporated by reference to Exhibit 99.1 to the
Companys Current Report on
Form 8-K,
filed with the SEC on August 28, 2006).
|
|
10
|
.26.1
|
|
Amendment No. 1 to the Consulting and Non-Competition
Agreement, dated November 12, 2006, by and between Western
Refining, Inc. and Fred L. Holliger (incorporated by reference
to Exhibit 99.1 to the Companys Current Report on
Form 8-K,
filed with the SEC on November 13, 2006).
|
|
10
|
.27
|
|
Employment agreement, effective August 28, 2006, made by
and between Western Refining GP, LLC and Mark J. Smith
(incorporated by reference to Exhibit 10.1 to the
Companys Current Report on
Form 8-K,
filed with the SEC on August 16, 2006).
|
|
10
|
.27.1
|
|
First Amendment to the Employment Agreement referred to in
Exhibit 10.27, dated December 31, 2008 (incorporated
by reference to Exhibit 10.27.1 to the Companys
Annual Report on
Form 10-K,
filed with the SEC on March 31, 2009 (SEC File
No. 001-32721)).
|
|
10
|
.28
|
|
Non-Exclusive Aircraft Lease Agreement, dated October 3,
2006, by and between Western Refining LP and Franklin Mountain
Assets LLC (incorporated by reference to Exhibit 10.3 to
the Companys Quarterly Report on
Form 10-Q,
filed with the SEC on November 14, 2006).
|
|
10
|
.29
|
|
Employment agreement, dated November 4, 2008, made by and
between Western Refining GP, LLC and Mark B. Cox (incorporated
by reference to Exhibit 10.1 to the Companys
Quarterly Report on
Form 10-Q,
filed with the SEC on November 7, 2008).
|
|
10
|
.30
|
|
Employment agreement, dated November 4, 2008, made by and
between Western Refining GP, LLC and William R. Jewell
(incorporated by reference to Exhibit 10.2 to the
Companys Quarterly Report on
Form 10-Q,
filed with the SEC on November 7, 2008).
|
|
10
|
.31
|
|
Employment agreement, dated March 9, 2010, made by and
between Western Refining GP, LLC and Jeffrey S. Beyersdorfer
(incorporated by reference to Exhibit 10.31 to the
Companys Annual Report on
Form 10-K,
filed with the SEC on March 12, 2010 (SEC File
No. 001-32721)).
|
130
|
|
|
|
|
Number
|
|
Exhibit Title
|
|
|
10
|
.32*
|
|
Form of Performance Unit Award Agreement between the Company and
Participant under the 2010 Incentive Plan of Western Refining,
Inc.
|
|
10
|
.33*
|
|
Form of Western Refining, Inc. Restricted Share Unit Award
Agreement between the Company and Participant under the 2010
Incentive Plan of Western Refining, Inc.
|
|
10
|
.34
|
|
2010 Incentive Plan of Western Refining, Inc. (incorporated by
reference to Exhibit 10.1 to the Companys Current
Report on
Form 8-K,
filed with the SEC on May 27, 2010).
|
|
12
|
.1*
|
|
Statements of Computation of Ratio of Earnings to Fixed Charges.
|
|
21
|
.1
|
|
List of Subsidiaries (incorporated by reference to
Exhibit 21.1 to the Companys Annual Report on
Form 10-K,
filed with the SEC on February 29, 2008 (SEC File No.
001-32721)).
|
|
23
|
.1*
|
|
Consent of Deloitte & Touche LLP, dated March 7,
2011.
|
|
31
|
.1*
|
|
Certification Statement of Chief Executive Officer of the
Company pursuant to Section 302 of the Sarbanes-Oxley Act
of 2002.
|
|
31
|
.2*
|
|
Certification Statement of Chief Financial Officer of the
Company pursuant to Section 302 of the Sarbanes-Oxley Act
of 2002.
|
|
32
|
.1*
|
|
Certification Statement of Chief Executive Officer of the
Company pursuant to Section 906 of the Sarbanes-Oxley Act
of 2002.
|
|
32
|
.2*
|
|
Certification Statement of Chief Financial Officer of the
Company pursuant to Section 906 of the Sarbanes-Oxley Act
of 2002.
|
|
|
|
* |
|
Filed herewith. |
|
|
|
Management contract or compensatory plan or arrangement. |
|
|
|
|
(c)
|
All financial statement schedules are omitted because the
required information is not present or is not present in amounts
sufficient to require submission of the schedule, or because the
information required is included in the consolidated financial
statements or notes thereto.
|
The Companys 2010 Annual Report is available upon request.
Stockholders of the Company may obtain a copy of any exhibits to
this
Form 10-K
at a charge of $0.10 per page. Requests should be made to:
Investor Relations, Western Refining, Inc.,
123 W. Mills Ave., Suite 200, El Paso, Texas
79901.
131
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.
WESTERN
REFINING, INC.
|
|
|
|
|
|
|
Signature
|
|
Title
|
|
Date
|
|
|
|
|
|
|
/s/ Jeff
A. Stevens
Jeff
A. Stevens
|
|
Chief Executive Officer and President
|
|
March 7, 2011
|
Pursuant to the requirements of the Securities Exchange Act of
1934, this report has been signed below by the following persons
on behalf of the registrant and in the capacities and on the
dates indicated.
|
|
|
|
|
|
|
Signature
|
|
Title
|
|
Date
|
|
|
|
|
|
|
/s/ Jeff
A. Stevens
Jeff
A. Stevens
|
|
Chief Executive Officer, President and Director (Principal
Executive Officer)
|
|
March 7, 2011
|
|
|
|
|
|
/s/ Gary
R. Dalke
Gary
R. Dalke
|
|
Chief Financial Officer
(Principal Financial Officer)
|
|
March 7, 2011
|
|
|
|
|
|
/s/ Paul
L. Foster
Paul
L. Foster
|
|
Executive Chairman and Director
|
|
March 7, 2011
|
|
|
|
|
|
/s/ Scott
D. Weaver
Scott
D. Weaver
|
|
Vice President and Director
|
|
March 7, 2011
|
|
|
|
|
|
/s/ William
R. Jewell
William
R. Jewell
|
|
Chief Accounting Officer
(Principal Accounting Officer)
|
|
March 7, 2011
|
|
|
|
|
|
/s/ Carin
M. Barth
Carin
M. Barth
|
|
Director
|
|
March 7, 2011
|
|
|
|
|
|
/s/ L.
Frederick Francis
L.
Frederick Francis
|
|
Director
|
|
March 7, 2011
|
|
|
|
|
|
/s/ Brian
J. Hogan
Brian
J. Hogan
|
|
Director
|
|
March 7, 2011
|
|
|
|
|
|
/s/ William
D. Sanders
William
D. Sanders
|
|
Director
|
|
March 7, 2011
|
|
|
|
|
|
/s/ Ralph
A. Schmidt
Ralph
A. Schmidt
|
|
Director
|
|
March 7, 2011
|
132