10-K 1 wnr12311110k.htm WNR 12.31.11 10K
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
þ
 
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
 
For the Fiscal Year Ended December 31, 2011
OR
¨
 
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
 
For the transition period from            to           
Commission File Number: 001-32721
WESTERN REFINING, INC.
(Exact name of registrant as specified in its charter)
Delaware
 
20-3472415
(State or other jurisdiction of incorporation or organization)
 
(I.R.S. Employer Identification No.)
123 W. Mills Ave., Suite 200
El Paso, Texas
(Address of principal executive offices)
 
79901
(Zip Code)
Registrant’s telephone number, including area code:
(915) 534-1400
Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class
 
Name of Each Exchange on Which Registered
Common Stock
 
New York Stock Exchange
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 þ     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 registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  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 þ                                         Accelerated Filer o
Non-Accelerated Filer o (Do not check if a smaller reporting company)
Smaller Reporting Company o
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, 2011 (the last business day of the registrant’s most recently completed second fiscal quarter) was $1,018,068,534.
As of February 24, 2012, there were 90,814,773 shares outstanding, par value $0.01, of the registrant’s common stock.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the definitive proxy statement for the registrant’s 2012 annual meeting of stockholders are incorporated by reference into Part III of this report.



WESTERN REFINING, INC. AND SUBSIDIARIES
INDEX

Item 1.
Item 1A.
Item 1B.
Item 2.
Item 3.
Item 4.
 
Item 5.
Item 6.
Item 7.
Item 7A.
Item 8.
Item 9.
Item 9A.
Item 9B.
 
Item 10.
Item 11.
Item 12.
Item 13.
Item 14.
 
Item 15.
 EX-10.32
 EX-10.33
 EX-12.1
 EX-23.1
 EX-31.1
 EX-31.2
 EX-32.1
 EX-32.2


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. Management’s Discussion and Analysis of Financial Condition and Results of Operations, relating to matters that are not historical fact are forward-looking statements that represent management’s beliefs and assumptions based on currently available information. These forward-looking statements relate to matters such as our industry, business strategy, future operations, our expectations for margins, deferred taxes, capital expenditures, liquidity and capital resources, our working capital requirements, our ability to improve our capital structure through strategic initiatives, asset sales and/or through certain financings, and other financial and operating information. Forward-looking statements also include those regarding 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. 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:
changes in the underlying demand for our refined products;
availability, costs, and price volatility of crude oil, other refinery feedstocks, and refined products;
instability and volatility in the financial markets, including as a result of potential disruptions caused by economic uncertainties in Europe;
a potential economic recession in the United States and/or abroad;
availability of renewable fuels for blending and Renewable Identification Numbers, or RINs, to meet Renewable Fuel Standards, or RFS, obligations;
changes in crack spreads;
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;
changes in the spread between WTI crude oil and Dated Brent crude oil;
effects of, and exposure to risks related to, our commodity hedging strategies and transactions;
adverse changes in the credit ratings assigned to our debt instruments;
construction of new, or expansion of existing product or crude pipelines in the areas where we operate;
actions of customers and competitors;
changes in fuel and utility costs incurred by our refineries;
the effect of weather-related problems on our operations;
disruptions due to equipment interruption, pipeline disruptions, or failure at our or third-party facilities;
execution of planned capital projects, cost overruns relating to those projects, and failure to realize the expected benefits from those projects;
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;
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;

1


the price, availability, and acceptance of alternative fuels and alternative fuel vehicles;
operating hazards, natural disasters, casualty losses, acts of terrorism, and other matters beyond our control; and
other factors discussed in more detail under Part 1. — Item 1A. Risk Factors of this report, which are incorporated herein by this reference.
Any one of these factors or a combination of these factors could materially affect our results of operations or financial position 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.

Item 1.
Business
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. In September 2010, we temporarily suspended refining operations at our Yorktown facility and on December 29, 2011, we completed the sale of our Yorktown refining and terminal assets. We continue to market refined products in the Mid-Atlantic region through our wholesale segment. We indefinitely suspended refining operations at our Bloomfield refinery in November 2009 and continue to supply our refined products to the area through a distribution terminal at the Bloomfield facility. 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; and Bloomfield; as well as asphalt terminals in Phoenix and Tucson, Arizona; Albuquerque; and El Paso. At February 24, 2012, we also operated 210 retail service stations and convenience stores in Arizona, Colorado, New Mexico, and Texas; 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, Maryland, and Virginia.
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. 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 refined products such as gasoline, diesel fuel, jet fuel, and asphalt. Our refineries market refined 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.
Demand for gasoline is generally higher during the summer months than during the winter months. 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. Refining margins remain volatile and our results of operations may not reflect these historical seasonal trends.

3


Refining Segment
Our refining group operates a refinery in El Paso, Texas (the El Paso refinery) and a refinery near Gallup, New Mexico (the Gallup refinery), two on-site refined product distribution terminals at the El Paso and Gallup refineries, and two stand-alone refined product distribution terminals in Albuquerque and Bloomfield, New Mexico. Prior to December 29, 2011, we also operated a stand alone product distribution terminal in Yorktown, Virginia. Refining operations also include an asphalt plant in El Paso and four asphalt terminals in El Paso, Phoenix, Tucson, and Albuquerque. Our refining group operates a crude oil gathering pipeline system in the Four Corners region of New Mexico. Prior to December 29, 2011, we owned a pipeline running from Southeast to Northwest New Mexico, known as the Texas-New Mexico pipeline. On December 29, 2011, we completed the sale of an 82 mile section of this pipeline starting north of Lynch, New Mexico, and extending south to Jal, New Mexico. Our pipeline now originates at the sale point north of Lynch and has the capacity to transport crude oil from Southeast New Mexico to the Four Corners region. Although we do not currently utilize this capacity, the pipeline provides a raw material supply alternative for our Gallup refinery.
In September 2010, due to continued unfavorable economic conditions in domestic refining markets, especially the East Coast region, and the consequential financial performance of the Yorktown refinery, we temporarily suspended our refining operations at the Yorktown facility. As a result of the suspension, we incurred employee severance and related other costs of approximately $4.9 million during the third quarter of 2010. Following the suspension, until December 29, 2011, we operated Yorktown as a refined products distribution terminal supplying refined products to the region. On December 29, 2011, we completed a sales transaction to dispose of our Yorktown refining and terminal assets. Completion of the sales transaction resulted in a loss on disposal of the Yorktown assets of $465.6 million included in Loss and impairments on disposal of assets, net in our Consolidated Statement of Operations for the year ended December 31, 2011. See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Major Influences on Results of Operations — Long-lived Asset Impairment Losses.
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 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.
As a result of the indefinite suspension of refining activities at the Bloomfield refinery, we recorded a non-cash impairment charge of $52.8 million and incurred employee severance and related other costs of approximately $2.2 million during the fourth quarter of 2009. During the fourth quarters of 2011 and 2010, we recorded additional impairment charges of $11.7 million and $9.1 million, respectively resulting from our fourth quarters 2011 and 2010 analyses 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. Our 2011 fourth quarter analysis demonstrated that existing market conditions and availability of superior economical alternatives further reduced the potential benefit of relocating Bloomfield assets to the Gallup refinery, resulting in impairment of the two remaining assets initially set aside for relocation. These non-cash impairment losses are included under Loss and impairments on disposal of assets, net in the Consolidated Statements of Operations for each of the three years ended December 31, 2011. See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Major Influences on Results of Operations — Long-lived Asset Impairment Loss.

4


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 refined 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. Management’s 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:

 
Year Ended December 31,
 
2011
 
2010
 
2009
Gasoline
44.1
%
 
54.0
%
 
57.2
%
Diesel fuel
35.1

 
32.3

 
30.2

Jet fuel
12.9

 
5.6

 
4.6

Asphalt
3.6

 
2.5

 
2.7

Other
4.3

 
5.6

 
5.3

Total sales percentage by type
100.0
%
 
100.0
%
 
100.0
%

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 2011.
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 6.2%, 8.3%, and 8.5% of our consolidated net sales during the years ended December 31, 2011, 2010, and 2009, 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 and represented approximately 15.2%, 9.9%, and 7.1% of our total sales volumes during the years ended December 31, 2011, 2010, and 2009, respectively. The increase in purchases from 2010 to 2011 was primarily the result of our wholesale refined product sales activities in the Mid-Atlantic region where we satisfy our refined product customer sales requirements through third-party purchases since we no longer produce refined products in the region.
Competition.  We operate primarily in West Texas, Arizona, New Mexico, Utah, and Colorado. 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., HollyFrontier 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.
Prior to the fourth quarter 2011 sale of our Yorktown refining and refined product distribution terminal assets in the Mid-Atlantic region, our Yorktown refinery 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.

5


To the extent that climate change legislation passes to impose greenhouse gas restrictions on domestic refiners, those refiners will be at competitive disadvantage to offshore refineries not subject to the legislation. In 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 and a set of in-state cap regulations to take effect the earlier of January 2013 or six months after the regional cap-and-trade regulations are no longer in effect. New Mexico repealed its regional cap-and-trade regulations in February 2012. New Mexico is currently reviewing its in-state cap regulations with a decision expected in the latter part of the first quarter of 2012.
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 refined 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 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, DuPont constructed and operates two sulfuric acid regeneration plants on property we lease to DuPont within our El Paso refinery.
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 are crude oil, isobutane, and alkylate. Operation of our fluid catalytic gasoline hydrotreater, or CGHT, since startup in May 2009 has allowed for higher rates of sour crude oil. Currently, we have the capability to process WTS crude oil at up to 22% of throughput capacity at the El Paso refinery, an increase of more than 10% over historical average prior to operating the CGHT. Additionally, we have analyzed smaller projects for the El Paso refinery that would allow for potential incremental increases in our WTS crude oil processing capability. We will consider implementation of these projects should economic and market conditions, particularly the sweet/sour spread, make the projects economically viable. The following table summarizes the historical feedstocks used by our El Paso refinery for the years indicated:

Refinery Feedstocks
Year Ended December 31,
 
Percentage For Year Ended December 31,
(bpd)
2011
 
2010
 
2009
 
2011
Crude Oils:
 

 
 

 
 

 
 

Sweet crude oil
91,589

 
104,119

 
99,680

 
77.5
%
Sour crude oil
19,876

 
14,007

 
17,601

 
16.8
%
Total Crude Oils
111,465

 
118,126

 
117,281

 
94.3
%
Other Feedstocks and Blendstocks:
 

 
 

 
 

 
 

Intermediates and other
3,928

 
4,359

 
3,611

 
3.3
%
Blendstocks
2,752

 
4,692

 
5,573

 
2.4
%
Total Other Feedstocks and Blendstocks
6,680

 
9,051

 
9,184

 
5.7
%
Total Crude Oils and Other Feedstocks and Blendstocks
118,145

 
127,177

 
126,465

 
100.0
%

6



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 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 Morgan’s 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 refined product distribution terminal. See Item 7. Management’s 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 refined 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, primarily Northern New Mexico and Utah. We take delivery of crude through Company owned and third-party pipelines connected to our refinery and product distribution terminal and through Company owned trucks into either pipeline injection points or refinery storage tanks. Our crude oil pipeline system reaches into the San Juan Basin, located in the Four Corners area, and connects with local common carrier pipelines and is approximately 200 miles in length. We also own a pipeline with the capacity to transport crude oil from Southeast New Mexico to the Four Corners region. Although we do not currently utilize all of this capacity, the pipeline provides a crude oil supply alternative for our Gallup 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:

Refinery Feedstocks
Year Ended December 31,
 
Percentage For Year Ended December 31,
(bpd)
2011
 
2010
 
2009 (1)
 
2011
Crude Oil:
 

 
 

 
 

 
 

Sweet crude oil
21,758

 
21,140

 
24,763

 
90.2
%
Total Crude Oil
21,758

 
21,140

 
24,763

 
90.2
%
Other Feedstocks and Blendstocks:
 

 
 

 
 

 
 

Intermediates and other
853

 
1,822

 
1,425

 
3.5
%
Blendstocks
1,501

 
1,149

 
429

 
6.3
%
Total Other Feedstocks and Blendstocks
2,354

 
2,971

 
1,854

 
9.8
%
Total Crude Oil and Other Feedstocks and Blendstocks
24,112

 
24,111

 
26,617

 
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 refined product terminals in Albuquerque and Bloomfield. The Bloomfield product distribution terminal is permitted to operate at 19,000 bpd. This terminal has approximately 251,000 barrels of refined product tankage and a truck loading rack with three loading spots. We utilize a pipeline connection and a long-term exchange agreement to supply barrels to the Bloomfield product distribution 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 refined 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 refined 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 refined product trucks operated by our wholesale group.
Mid-Atlantic
Yorktown Facility
During the fourth quarter of 2011, we entered into a sales agreement to sell our Yorktown, Virginia, refining assets and our Yorktown product distribution terminal assets. Prior to the sale, we had temporarily suspended refining operations at Yorktown in September 2010 due primarily to the continued effect of unfavorable economic conditions in the refining industry, especially the East Coast region. Following the temporary suspension and through completion of the sale on December 29, 2011, we operated our Yorktown facility as a stand-alone product distribution terminal through our wholesale business segment to supply refined product in the Mid-Atlantic area. Prior to the temporary suspension and sale of our Yorktown assets, the refinery and terminal primarily served Yorktown, Virginia; Salisbury, Maryland; Norfolk, Virginia; North Carolina; and the New York Harbor.
Process Summary.  When owned and operated by Western, our Yorktown refinery was a nominal 70,000 bpd heavy crude oil coking facility that was capable of processing a wide variety of crude oils including certain lower quality crude oils. Yorktown produced high value refined products including conventional and reformulated gasoline, ultra low sulfur diesel fuel, and heating oil. Yorktown also produced liquefied petroleum gases, or LPGs, fuel oil, and petroleum coke.

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Power Supply.  The Yorktown facility received electrical power supply from the regional electric company via two independent transformers. All process computers and controls were protected by various uninterruptible power supply systems. A natural gas pipeline supplied a back-up to refinery produced fuel gas used to power certain refining units and other processes.
Raw Material Supply.  When owned and operated by Western, most of the crude oil for our Yorktown refinery came from South America. Our Yorktown refinery’s strategic location on the York River and its own deep water port access allowed it to receive its entire crude supply via crude oil tanker shipments from various regions of the world. Its ability to process a wide range of crude oils allowed our Yorktown refinery to vary its crude oil slate to process lower quality crude oils when those types of crude were available at a lower cost compared to higher quality crude oils. The Yorktown refinery also purchased other feedstocks and blendstocks to optimize refinery and blending operations.
The following table summarizes the historical feedstocks used by our Yorktown refinery for the years indicated:
 
 
 
 
 
Refinery Feedstocks
Year Ended December 31,
 
(bpd)
2010 (1)
 
2009
 
Crude Oil:
 

 
 

 
Sweet crude oil
7,713

 
1,885

 
Heavy crude oil
40,274

 
47,659

 
Total Crude Oils
47,987

 
49,544

 
Other Feedstocks and Blendstocks:
 

 
 

 
Intermediates and other
4,522

 
5,398

 
Blendstocks
5,255

 
7,791

 
Total Other Feedstocks and Blendstocks
9,777

 
13,189

 
Total Crude Oils and Other Feedstocks and Blendstocks
57,764

 
62,733

 
_______________________________________
(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 refined products sold by the refinery were shipped by barge, with the remaining volume 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.
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 refined product trucks and lubricant delivery trucks. Our wholesale group distributes wholesale petroleum products primarily in Arizona, California, Colorado, Nevada, New Mexico, Texas, Utah, Virginia, and Maryland. Beginning in January 2011, wholesale operations include the distribution of refined product through the refined product distribution terminal at the recently sold Yorktown facility. Following the sale of our Yorktown terminal assets, our wholesale business continues to operate through the terminal as a customer. Our wholesale group purchases petroleum fuels and lubricants from our refining group and from third-party suppliers.
Our principal customers are retail fuel distributors and the mining, construction, utility, manufacturing, transportation, aviation, and agricultural industries. We compete with other wholesale petroleum products distributors in the Southwest such as Pro Petroleum, Inc.; Southern Counties Fuels; Union Distributing; Brown Evans Distributing Co.; and Maxum Petroleum, Inc. On the east coast, we compete with wholesale petroleum products distributors such as Shell Oil Company, BP Oil, CITGO Petroleum Corporation, Valero Energy Corporation, and Exxon Mobil Corporation.
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 24, 2012, our retail group operated 210 service stations with convenience stores or kiosks located in Arizona, New Mexico, Colorado, and Texas.

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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, Quik-Trip, ampm, 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 24, 2012, our retail group had 210 convenience stores operating under various brands, including Giant, Western, Western Express, Howdy's, Mustang, and Sundial. Gasoline brands sold through these stores include Western, Giant, Mustang, Phillips 66, Conoco, Shell, Chevron, and Texaco.
Location
Owned
 
Leased
 
Total
Arizona
27

 
39

 
66

New Mexico
76

 
31

 
107

Colorado
10

 
2

 
12

Texas

 
25

 
25

 
113

 
97

 
210


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, reporting, and control 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 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. Management’s 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. We purchased a non-cancelable Pollution and Legal Liability and Clean-Up Cost Cap Insurance policy which 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 exceed the $20 million policy coverage. 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.

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On June 30, 2011, the U.S. Environmental Protection Agency (“EPA”) filed notice with the federal district court in El Paso that we and the EPA had entered into a proposed Consent Decree under the Petroleum Refinery Enforcement Initiative (“EPA Initiative”). On September 2, 2011, the court entered the Consent Decree. Under the EPA Initiative, the EPA is investigating industry-wide noncompliance with certain Clean Air Act rules. The EPA Initiative has resulted in many refiners entering into similar consent decrees typically requiring penalties and substantial capital expenditures for additional air pollution control equipment. The Consent Decree does not require any soil or groundwater remediation or clean-up.
Based on the terms of the Consent Decree and current information, we estimate the total capital expenditures necessary to address the Consent Decree issues would be approximately $51.0 million, of which we have already expended $39.1 million, including $15.2 million for the installation of a flare gas recovery system completed in 2007 and $23.9 million for nitrogen oxides (“NOx”) emission controls on heaters and boilers through December 2011. We estimate remaining expenditures of approximately $11.9 million for the NOx emission controls on heaters and boilers during 2012 through 2013. This amount is included in our estimated capital expenditures for regulatory projects. Under the terms of the Consent Decree, we paid a civil penalty of $1.5 million in September 2011.
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 administered the program for 16 years with the EPA’s full knowledge. In June 2010, the EPA disapproved the TCEQ Flexible Permits Program. In July 2010, the Texas Attorney General filed a legal challenge to the EPA’s disapproval in a federal appeals court asking for reconsideration. Although we believe our Texas Flexible Permit is federally enforceable, we agreed in 2010 to submit an application to the 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. We submitted the application on November 22, 2011. 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 ourselves 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.

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Based on current information and the 2009 NMED Amendment, and favorably negotiating a second amendment to reflect the indefinite suspension of refining operations at our Bloomfield facility and to delay NOx controls on heaters, boilers, and the FCCU at the Gallup refinery, we estimate $48.0 million total capital expenditures pursuant to the 2009 NMED Amendment. Through 2011, we have expended $11.3 million and expect to spend the remaining $36.7 million during 2012 and 2013. 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 Gallup refinery. The 2009 NMED Amendment also provided for a $2.3 million penalty. We completed payment of the penalty between November 2009 and September 2010 to fund Supplemental Environmental Projects (“SEPs”). The NMED has proposed a penalty of $0.4 million to be paid with the second amendment. We intend to negotiate the amount of the penalty and do not expect implementation of the requirements in the 2005 NMED Agreement, the associated 2009 NMED Amendment, or the second 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 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 investigate the extent of such releases, perform interim remediation measures, and implement corrective measures.
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 the New Mexico Oil Conservation Division. As of December 31, 2011, we had expended $2.6 million and estimate a remaining cost of $3.1 million for implementing the investigation and interim measures of 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 EPA’s 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 additional soil or groundwater remediation or clean-up costs not otherwise required. Based on current information, we currently estimate capital expenditures of approximately $33.7 million to upgrade the wastewater treatment plant at our Gallup refinery pursuant to the requirements of the final settlement. In September 2010, the final settlement was modified to establish May 31, 2012 as the deadline for completing startup of the upgraded plant. Through 2011, we have expended $20.8 million on the upgrade of the wastewater treatment plant and expect to spend the remaining $12.9 million during 2012.
Gallup 2010 NMED AQB Compliance Order. In October 2010, the NMED Air Quality Bureau (“NMED AQB”) issued the Gallup refinery a Compliance Order alleging certain violations related to compressor engines and demanded a penalty of $0.6 million. Although we believe no violations occurred and the assessment of a penalty is not appropriate, we paid a $0.4 million penalty in June 2011 to reach a settlement with the NMED AQB.
Yorktown Refinery
Yorktown 1991 and 2006 Orders. In August 2006, Giant agreed with the EPA to the terms of a 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. Through December 2011, we have expended $32.9 million related to the EPA order.
In December 2011, we sold the Yorktown refinery, an adjacent 83 acre parcel of land, and all other related real estate and assets. As part of this transaction, the purchaser agreed to assume all obligations and remaining work required by the EPA. The purchaser agreed to indemnify us for costs associated with the EPA order, following the sale, with the exception of the completion and related liability for construction of the second phase of the Corrective Action Measures Unit ("CAMU"). At this time we have completed construction of this phase of the CAMU and have incurred substantially all costs anticipated to complete this work. We currently anticipate less than $0.3 million in costs to complete the work. The purchaser has agreed with us that it will replace Giant as the respondent under the EPA order. The replacement is pending the EPA's agreement as of February 24, 2012.
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. Following the sale of the refinery on December 29, 2011, the purchaser assumed all obligations and all remaining work required under the Consent Decree with the exception of any penalties or fines assessed in the future for issues related to compliance with the Consent Decree that occurred prior to the date of sale.

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In August 2011, pursuant to the Consent Decree, the EPA reinstated a formal demand first issued in March 2010 for stipulated penalties in the amount of $0.5 million for a flaring event that occurred at the Yorktown refinery in October 2009. We responded in September 2011 offering to settle for $0.1 million, although we believe no stipulated penalties are due. The EPA accepted our offer which we paid in November 2011.
Following the sale of the Yorktown refinery, an adjacent 83 acre parcel of land, and all other related real estate and assets in December, 2011, the purchaser assumed all obligations and all remaining work required under the Consent Decree with the exception of any penalties or fines assessed in the future for issues related to compliance with the Consent Decree that occurred prior to the date of sale.
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 with the EPA for this enforcement notice for $0.2 million, which was paid prior to December 31, 2010.
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 all refineries to reduce sulfur content in gasoline to 30 parts per million, or ppm, by January 1, 2006, and to reduce sulfur content in on-road diesel to 15 ppm by June 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. Our El Paso and Gallup refineries timely achieved compliance with these regulations related to gasoline, on-road diesel, and off-road (excluding locomotive and marine) diesel through capital investments completed by 2009, use of the “small refiners” and waiver provisions in the regulations as well as operational and marketing changes.
All off-road diesel, with the exception of off-road diesel for locomotive and marine use, had to meet a 15 ppm sulfur standard as of June 2010. Off-road diesel produced for locomotive and marine use is allowed to meet a 500 ppm sulfur standard through May 2012. 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. Our compliance strategy includes use of credits purchased in 2010 and a planned expansion of our El Paso diesel hydrotreater. Based on current estimates we expect to spend $5.0 million for this expansion in 2012.
Our El Paso and Gallup refineries are required to meet Mobile Source Air Toxics, or MSAT II, regulations to reduce the benzene content of gasoline. The MSAT II regulations required reduction of benzene in the finished gasoline pool 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, 2011, we expended $63.7 million to comply with MSAT II regulations at our El Paso refinery by completing construction of a benzene saturation unit, which began operating in May 2011. Our El Paso and Gallup refineries will use early credits previously generated at our Yorktown and Gallup refineries, along with a deficit carryover, to comply with the 2011 0.62 volume percent requirement. We anticipate approximately $2.0 million in capital expenditures in 2012 for our Gallup refinery to meet the 1.30 volume percent requirement. In early 2013 we plan to purchase credits from third parties to eliminate the 2011 carry-over deficit as well as any carry-over deficit incurred through 2012 operations. We anticipate our refineries will have the processing capability to comply with the MSAT II regulations without purchasing third-party credits or carrying forward a deficit by 2014. For additional details, see Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources - Capital Spending.
In 2011, the EPA began drafting MSAT III regulations for gasoline. We expect these regulations to require lower sulfur and lower vapor pressure limits with an effective date between 2016 and 2018. If and when these new regulations take effect, they will require capital spending and adjustments to our refinery 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. The standards have been enforced at our El Paso refinery since September 2007. Our Gallup refinery became subject to RFS in January 2011. Annually, the EPA establishes a volume of renewable fuels that obligated refineries must blend into their refined petroleum fuels. The obligated volume increases over time until 2022. Blending renewable fuels into their refined petroleum fuels will displace an increasing volume of a refinery’s product pool. Our compliance strategy includes blending at our refineries, transferring credits from blending across our refinery and terminal system, and purchasing third-party credits.


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In late 2011, the EPA initiated civil and criminal enforcement against companies it believes produced invalid fuel credits known as Renewable Identification Numbers, or RINs.  At the same time EPA issued Notices of Violation to 24 companies who it claims purchased and used invalid RINs to satisfy their obligations under the Renewable Fuels Standard, or RFS, program. As of yet, we have not received such notice. The EPA's position is that purchasers of RINs are responsible for acquiring and using valid RINs, and any company that purchased invalid RINs must replace them with valid RINs. The EPA may subject those purchasers to enforcement actions. We purchase RINs to satisfy our obligations under the RFS program and may have purchased and used RINs considered by EPA to be invalid. Sufficient time has not elapsed for us to reasonably estimate the potential impact of the emerging situation surrounding invalid RINs.
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 24, 2012, we employed approximately 3,600 people, approximately 380 of whom were covered by collective bargaining agreements. During 2011, we successfully renegotiated a collective bargaining agreement covering employees at our Gallup refinery that expires in 2014. 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 was set to expire in April 2012. The new collective bargaining agreement covering the El Paso refinery employees expires in April 2015. 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 SEC’s 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 SEC’s Internet site at http://www.sec.gov contains the reports, proxy, and information statements, and other information filed electronically.
As required by Section 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, 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.

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On July 7, 2011, the Company’s Chief Executive Officer certified to the NYSE that he was not aware of any violation by the Company of the NYSE’s 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.

Item 1A.
Risk Factors
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 2011 ranged from $75.67 to $113.93 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:
changes in global and local economic conditions;
demand for crude oil and refined products, especially in the U.S., China, and India;
worldwide political conditions, particularly in significant oil producing regions such as the Middle East, West Africa, and Latin America;
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;
U.S. government regulations;
utilization rates of U.S. refineries;
changes in fuel specifications required by environmental and other laws;
the ability of the members of the Organization of Petroleum Exporting Countries, or OPEC, to maintain oil price and production controls;
development and marketing of alternative and competing fuels;
pricing and other actions taken by competitors that impact the market;
product pipeline capacity, including the Magellan Southwest System pipeline, as well as Kinder Morgan’s expansion of its East Line, both of which could increase supply in certain of our service areas and therefore reduce our margins;
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
local factors, including market conditions, weather conditions, and the level of operations of other refineries and pipelines in our service areas.
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

15


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 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 at 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, 2011. We also experienced LIFO liquidations based on decreased levels in our inventories. These LIFO liquidations resulted in decreases in cost of products sold of $22.3 million, $16.9 million, and $9.4 million, respectively for the years ended December 31, 2011, 2010, and 2009.
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.
Our hedging transactions may limit our gains and expose us to other risks.
We enter into hedges from time to time to manage our exposure to commodity price risks or to fix sales margins on future gasoline and distillate production. These transactions limit our potential gains if commodity prices rise above the levels established by our hedging instruments. These transactions may also expose us to risks of financial losses, for example, if our production is less than we anticipated at the time we entered into a hedge agreement or if a counterparty to our hedge contracts fails to perform its obligations under the contracts. Some of our hedging agreements may also require us to furnish cash collateral, letters of credit or other forms of performance assurance in the event that mark-to-market calculations result in settlement obligations by us to the counterparties, which would impact our liquidity and capital resources.
We have a significant amount of indebtedness.
As of December 31, 2011, our total debt was $804.0 million and our stockholders’ equity was $819.8 million. On September 22, 2011, the Company entered into an amended and restated Revolving Credit Agreement. Lenders under the agreement extended $1.0 billion in revolving line commitments that mature on September 22, 2016 and incorporate a borrowing base tied to eligible accounts receivable and inventory. As of December 31, 2011, we had gross availability under the Revolving Credit Agreement of $745.3 million, of which $344.7 million was used for outstanding letters of credit. On February 24, 2012, we had gross availability under the Revolving Credit Agreement of $752.6 million, of which $287.2 million was used for outstanding letters of credit. Our level of debt may have important consequences to you. Among other things, it may:
limit our ability to use our cash flow, or obtain additional financing, for future working capital, capital expenditures, acquisitions, or other general corporate purposes;
restrict our ability to pay dividends;
require a substantial portion of our cash flow from operations to make debt service payments;
limit our flexibility to plan for, or react to, changes in our business and industry conditions;
place us at a competitive disadvantage compared to our less leveraged competitors; and
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.

16


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. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Working Capital and Item 7. Management’s 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:
creating liens;
engaging in mergers, consolidations, and sales of assets;
incurring additional indebtedness;
providing guarantees;
engaging in different businesses;
making investments;
making certain dividend, debt, and other restricted payments;
engaging in certain transactions with affiliates; and
entering into certain contractual obligations.
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 under the Revolving Credit Agreement. 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 requirements by the 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.

17


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:
natural disasters;
weather-related disruptions;
fires;
explosions;
pipeline ruptures and spills;
third-party interference;
disruption of natural gas deliveries;
disruptions of electricity deliveries;
disruption of sulfur gas processing by E.I. du Pont de Nemours at our El Paso refinery; and
mechanical failure of equipment at our refineries or third-party facilities.
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 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 were 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.
Severe weather, including hurricanes, could interrupt the supply of some of our feedstocks.
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

18


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.
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 facilities 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 facilities 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, reporting, and control 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 regulation, 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 incurred, and continue to incur, substantial costs to comply with the EPA’s low sulfur and low benzene rules. Our strategy for complying with low sulfur gasoline regulations at our refineries relies partially on purchasing credits. If credits are not available or are too costly, we may not be able to meet the EPA’s deadlines using a credit strategy. Failure to meet the EPA’s 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 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. Annually, the EPA establishes a volume of renewable fuels that obligated refineries must blend into their refined petroleum fuels. The obligated volume increases over time until 2022. Blending renewable fuels into their refined petroleum fuels will displace an increasing volume of a refinery’s product pool. Alternatively, refineries can meet their RFS obligations by purchasing RINs. If sufficient valid RINs are unavailable for purchase, or if we are otherwise unable to meet the EPA’s 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.
The EPA has recently adopted and implemented regulations to restrict emissions of greenhouse gases under certain provisions of the Clean Air Act. One of the rules adopted by the EPA requires permitting of 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 considered 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, including capital expenditures, will increase and additional operating restrictions could be imposed on our business; all of which could have a material adverse effect on our business, financial condition, and results of operations.

19


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 refinery’s 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 from non-local sources to supply the Gallup refinery, we may not have sufficient crude oil to run the Gallup refinery at the historical levels of 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 refinery’s 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.

20


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.
A substantial portion of our refining workforce is unionized, and we may face labor disruptions that would interfere with our operations.
As of February 24, 2012, we employed approximately 3,600 people, approximately 380 of whom were covered by collective bargaining agreements. During 2011, we successfully renegotiated a collective bargaining agreement covering employees at our Gallup refinery that expires in 2014. We also successfully negotiated a new collective bargaining agreement covering employees at our El Paso refinery, renewing the collective bargaining agreement that was set to expire in April 2012. The new collective bargaining agreement covering the El Paso refinery employees expires in April 2015. 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.

21


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, cash flows, investment rates, interest/equity rates, and growth rates, that could significantly impact the fair value of the asset being tested for impairment.
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. 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.
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, 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 35% 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.

22


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.

Item 1B.
Unresolved Staff Comments
None.

Item 2.
Properties
Our principal properties are described under Item 1. Business and the information is incorporated herein by reference. As of December 31, 2011, 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.

Item 4.
Mine Safety Disclosures

Not Applicable.

23



PART II

Item 5.
Market for Registrant’s Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities

Market Information
Our common stock is listed on the NYSE under the symbol “WNR.” As of February 24, 2012, we had 142 holders of record of our common stock. The following table summarizes the high 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:

 
High
 
Low
 
Dividends per
Common Share
2011:
 

 
 

 
 

First quarter
$
18.03

 
$
10.23

 
$

Second quarter
19.08

 
14.82

 

Third quarter
21.44

 
12.46

 

Fourth quarter
18.13

 
11.20

 

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

 


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. No dividends were declared or paid during fiscal years 2011 or 2010. On January 4, 2012, our Board of Directors approved a cash dividend of $0.04 per share of common stock which was paid on February 13, 2012.
Securities Authorized for Issuance Under Equity Compensation Plans
See Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.
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 60-month total stockholder return on the Company’s common stock relative to the cumulative total stockholder returns of the Standard & Poor’s, or S&P, 500 index, and a customized peer group of seven companies that includes: Alon USA Energy, Inc., Delek US Holdings Inc., HollyFrontier 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 December 31, 2007. The index on December 31, 2011, 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.

24


COMPARISON OF 60-MONTH CUMULATIVE TOTAL RETURN

COMPARISON OF 60-MONTH CUMULATIVE TOTAL RETURN
(Tabular representation of data in graph above)

 
Jan
 
Mar
 
Jun
 
Sep
 
Dec
 
Mar
 
Jun
 
Sep
 
Dec
 
Mar
 
Jun
2007- June 2009
2007
 
2007
 
2007
 
2007
 
2007
 
2008
 
2008
 
2008
 
2008
 
2009
 
2009
Western Refining, Inc. 

$100

 
$153.41
 
$227.47
 
$159.96
 
$95.67
 
$53.23
 
$47.07
 
$40.19
 
$30.85
 
$47.46
 
$28.06
S&P 500
100

 
100.64
 
106.96
 
109.13
 
105.50
 
95.53
 
92.92
 
85.15
 
66.45
 
59.13
 
68.55
Peer Group
100

 
125.25
 
143.10
 
128.45
 
131.95
 
93.43
 
76.55
 
60.80
 
50.21
 
41.86
 
38.90


 
 
Sep
 
Dec
 
Mar
 
Jun
 
Sep
 
Dec
 
Mar
 
Jun
 
Sep
 
Dec
September 2009-2011
 
2009
 
2009
 
2010
 
2010
 
2010
 
2010
 
2011
 
2011
 
2011
 
2011
Western Refining, Inc. 
 
$
25.64

 
$
18.72

 
$
21.86

 
$
19.99

 
$
20.83

 
$
42.05

 
$
67.37

 
$
71.82

 
$
49.52

 
$
52.82

S&P 500
 
79.25

 
84.03

 
88.55

 
78.43

 
87.29

 
96.68

 
102.4

 
102.5

 
88.29

 
98.72

Peer Group
 
44.94

 
39.94

 
45.4

 
43.79

 
44.21

 
54.93

 
69.97

 
62.27

 
47.38

 
55.22


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, 2011. In addition, we currently do not have any share repurchase plans or programs.

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 as of and for the five years ended December 31, 2011 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 fiscal periods ended after 2008 are not comparable to periods ended prior to 2008.

25


The information presented below should be read in conjunction with Item 7. Management’s 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,
 
2011
 
2010
 
2009
 
2008
 
2007 (1)
 
(In thousands, except per share data)
Statement of Operations Data
 

 
 

 
 

 
 

 
 

Net sales
$
9,071,037

 
$
7,965,053

 
$
6,807,368

 
$
10,725,581

 
$
7,305,032

Operating costs and expenses:
 

 
 

 
 

 
 

 
 

Cost of products sold (exclusive of depreciation and amortization) (2)
7,532,423

 
7,155,967

 
5,944,128

 
9,735,500

 
6,385,623

Direct operating expenses (exclusive of depreciation and amortization)
463,563

 
444,531

 
486,164

 
532,325

 
382,690

Selling, general, and administrative expenses
105,768

 
84,175

 
109,697

 
115,913

 
77,350

Loss and impairments on disposal of assets, net
447,166

 
13,038

 
52,788

 

 

Goodwill impairment loss

 

 
299,552

 

 

Maintenance turnaround expense
2,443

 
23,286

 
8,088

 
28,936

 
15,947

Depreciation and amortization
135,895

 
138,621

 
145,981

 
113,611

 
64,193

Total operating costs and expenses
8,687,258

 
7,859,618

 
7,046,398

 
10,526,285

 
6,925,803

Operating income (loss)
383,779

 
105,435

 
(239,030
)
 
199,296

 
379,229

Other income (expense):
 

 
 

 
 

 
 

 
 

Interest income
510

 
441

 
248

 
1,830

 
18,852

Interest expense and other financing costs
(134,601
)
 
(146,549
)
 
(121,321
)
 
(102,202
)
 
(53,843
)
Amortization of loan fees
(8,926
)
 
(9,739
)
 
(6,870
)
 
(4,789
)
 
(1,912
)
Write-off of unamortized loan fees

 

 
(9,047
)
 
(10,890
)
 

Loss on extinguishment of debt
(34,336
)
 

 

 

 
(774
)
Other, net
(3,898
)
 
7,286

 
(15,184
)
 
1,176

 
(1,049
)
Income (loss) before income taxes
202,528

 
(43,126
)
 
(391,204
)
 
84,421

 
340,503

Provision for income taxes
(69,861
)
 
26,077

 
40,583

 
(20,224
)
 
(101,892
)
Net income (loss)
$
132,667

 
$
(17,049
)
 
$
(350,621
)
 
$
64,197

 
$
238,611

Basic earnings (loss) per share
$
1.46

 
$
(0.19
)
 
$
(4.43
)
 
$
0.94

 
$
3.50

Diluted earnings (loss) per share
1.34

 
(0.19
)
 
(4.43
)
 
0.94

 
3.50

Dividends declared per common share
$

 
$

 
$

 
$
0.06

 
$
0.22

Weighted average basic shares outstanding
88,981

 
88,204

 
79,163

 
67,715

 
67,180

Weighted average dilutive shares outstanding
109,792

 
88,204

 
79,163

 
67,715

 
67,180



26


 
Year Ended December 31,
 
2011
 
2010
 
2009
 
2008
 
2007 (1)
 
(In thousands, except per share data)
Cash Flow Data
 

 
 

 
 

 
 

 
 

Net cash provided by (used in):
 

 
 

 
 

 
 

 
 

Operating activities
$
508,200

 
$
134,456

 
$
140,841

 
$
285,575

 
$
113,237

Investing activities
(72,194
)
 
(73,777
)
 
(115,361
)
 
(220,554
)
 
(1,334,028
)
Financing activities
(325,089
)
 
(75,657
)
 
(30,407
)
 
(274,769
)
 
1,247,191

Other Data
 

 
 

 
 

 
 

 
 

Adjusted EBITDA (3)
$
965,895

 
$
288,107

 
$
191,438

 
$
405,854

 
$
477,172

Capital expenditures
83,809

 
78,095

 
115,854

 
222,288

 
277,073

Cash paid for Giant acquisition, net of cash acquired

 

 

 

 
1,056,955

Balance Sheet Data (at end of period)
 

 
 

 
 

 
 

 
 

Cash and cash equivalents
$
170,829

 
$
59,912

 
$
74,890

 
$
79,817

 
$
289,565

Restricted cash
220,355

 

 

 

 

Working capital
544,981

 
272,750

 
311,254

 
314,521

 
621,362

Total assets
2,570,344

 
2,628,146

 
2,824,654

 
3,076,792

 
3,559,716

Total debt
803,990

 
1,069,531

 
1,116,664

 
1,340,500

 
1,583,500

Stockholders’ equity
819,828

 
675,593

 
688,452

 
811,489

 
756,485

_______________________________________
(1)
Includes the results of operations and cash flows for Giant beginning June 1, 2007, the date of acquisition.
(2)
Cost of products sold for the periods presented includes the net effect of commodity hedging gains and losses as follows:
 
Year Ended December 31,
 
2011
 
2010
 
2009
 
2008
 
2007 (1)
 
(In thousands)
Realized commodity hedging gains (losses)
$
(76,033
)
 
$
(9,770
)
 
$
(20,184
)
 
$
5,208

 
$
(6,635
)
Unrealized commodity hedging gains (losses)
183,286

 
337

 
(1,510
)
 
6,187

 
(3,288
)
Total realized and unrealized commodity hedging gains (losses)
$
107,253

 
$
(9,433
)
 
$
(21,694
)
 
$
11,395

 
$
(9,923
)
 
 
 
 
 
 
 
 
 
 
(3)
Adjusted EBITDA represents earnings before interest expense and other financing costs, amortization of loan fees, provision for income taxes, depreciation, amortization, maintenance turnaround expense, and other non-cash income and expense items. 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;

27


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.
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,
 
2011
 
2010
 
2009
 
2008
 
2007 (1)
 
(In thousands)
Net income (loss)
$
132,667

 
$
(17,049
)
 
$
(350,621
)
 
$
64,197

 
$
238,611

Interest expense and other financing costs
134,601

 
146,549

 
121,321

 
102,202

 
53,843

Amortization of loan fees
8,926

 
9,739

 
6,870

 
4,789

 
1,912

Provision for income taxes
69,861

 
(26,077
)
 
(40,583
)
 
20,224

 
101,892

Depreciation and amortization
135,895

 
138,621

 
145,981

 
113,611

 
64,193

Maintenance turnaround expense
2,443

 
23,286

 
8,088

 
28,936

 
15,947

Loss and impairments on disposal of assets, net
447,166

 
13,038

 
52,788

 

 

Goodwill impairment loss

 

 
299,552

 

 

Loss on extinguishment of debt
34,336

 

 

 

 
774

Write-off of unamortized loan fees

 

 
9,047

 
10,890

 

Net change in lower of cost or market inventory reserve

 

 
(61,005
)
 
61,005

 

Adjusted EBITDA
$
965,895

 
$
288,107


$
191,438


$
405,854


$
477,172


Item 7.
Management’s 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 management’s 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 finalized the sale of our Yorktown refining and terminal assets in December 2011. We indefinitely suspended refining operations at the Bloomfield refinery in November 2009. We continue to operate Bloomfield as a product distribution terminal to supply refined products to the area. Our primary operating areas encompass West Texas, Arizona, New Mexico, Colorado, Virginia, and Maryland. In addition to the refineries, we also own and operate stand-alone refined product distribution terminals in Albuquerque and Bloomfield, New Mexico, as well as asphalt terminals in Phoenix and Tucson, Arizona; Albuquerque; and El Paso. Between September 2010 and December 29, 2011, we operated a stand-alone refined product distribution terminal at Yorktown. As of December 31, 2011, we also operated 209 retail service stations and convenience stores in Arizona, Colorado, New Mexico, and Texas; a fleet of crude oil and refined product truck transports; and a petroleum products wholesaler that operates in Arizona, California, Colorado, Nevada, New Mexico, Texas, Maryland, and Virginia.

28


On May 31, 2007, we completed the acquisition of Giant. 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 refined products such as gasoline, diesel fuel, jet fuel, and asphalt. Our refineries market refined 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.
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 2009 and were somewhat less volatile in 2010 and 2011. Gasoline margin averages have improved each year since 2008 and average diesel margins for 2011 showed improvement over 2010 and 2009 levels. Another factor impacting our recent annual margins is the year-to-year narrowing of heavy light crude oil differentials beginning in the second quarter of 2009. When we owned and operated our Yorktown refinery, it was capable of processing up to 100% of its throughput capacity with heavy crude oil. Heavy light differentials narrowed significantly through 2010 and remained historically narrow during 2011. The impact of this trend was particularly negative on the East coast, where refiners are traditionally dependent on the economic benefit of processing a heavier crude slate. In addition, we had changes in our LCM reserve of $61.0 million related to our Yorktown inventories that decreased our cost of products sold for the year ended December 31, 2009. There were no such LCM reserve changes in the years ended December 31, 2010 or 2011. Over the past three years, refining results of operations have been impacted by various impairment charges and a loss on disposal of certain refining assets. Additional discussion of these charges and losses follows below under Goodwill Impairment Loss and Long-lived Asset Impairment Losses.
Other factors that impact our overall refinery gross margins include the sale of lower value products such as residuum and propane when crude costs are higher. Our refinery gross margin is further reduced because our refinery product yield is less than our total refinery throughput volume. Also affecting refining margins within refinery cost of products sold is the impact of our economic hedging activity entered into primarily to fix the margin on a portion of our future gasoline and distillate production and to protect the value of certain crude oil, refined product, and blendstock inventories. Our refining cost of products sold includes $107.3 million in net realized and unrealized economic hedging gains, and $9.4 million and $21.7 million in net realized and unrealized economic hedging losses for the years ended December 31, 2011, 2010, and 2009, respectively. 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. 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. 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 and equipment related outages experienced at our El Paso refinery during February and December 2011,respectively, 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, the margin environment, and the availability of resources to perform the required maintenance.

29


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 maintenance turnaround at the south side of the El Paso refinery during the first quarter of 2010. Our next scheduled maintenance turnarounds are during the fourth quarter of 2012 for Gallup and the first quarter of 2013 for El Paso.
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 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-cash charge to our cost of products sold. 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 2008 LCM LIFO inventory write-downs. 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 $22.3 million, $16.9 million, and $9.4 million for the years ended December 31, 2011, 2010, and 2009, respectively. 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 total cost of sales. Cost of sales connected to our Mid-Atlantic region wholesale business includes the results of our economic hedging activities for refined product purchases in the region. Margins are impacted by local supply, demand, and competition. Wholesale results of operations were impacted by an impairment charge related to goodwill during 2009. Additional discussion of this charge follows below under Goodwill Impairment Loss.
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 at our service stations, and by the sales and margins of merchandise sold at our 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. Retail results of operations were impacted by an impairment charge related to goodwill during 2009. Additional discussion of this charge follows below under Goodwill Impairment Loss.
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 a goodwill impairment analysis at March 31, 2009. We determined that no such impairment existed as of that date. Our last 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 unit’s 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 unit’s 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 charges for our refining, wholesale, and retail segments of $230.7 million, $41.2 million, and $27.6 million, respectively, were 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.

30


Long-lived Asset Impairment Losses.  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 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 $52.8 million of certain refinery related long-lived and intangible assets were impaired. During the fourth quarters of 2011 and 2010, we recorded additional impairment charges of $11.7 million and $9.1 million, respectively, resulting from our fourth quarters 2011 and 2010 analyses 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. Our 2011 fourth quarter analysis demonstrated that existing market conditions and availability of superior economic alternatives further reduced the potential benefit of relocating Bloomfield assets to the Gallup refinery, resulting in impairment of the two remaining assets initially set aside for relocation. All of these non-cash impairment losses are included under Loss and impairments on disposal of assets, net in the Consolidated Statements of Operations for the years ended December 31, 2011, 2010, and 2009, respectively.
In September 2010, we temporarily suspended refining operations at our Yorktown facility. We took this action because narrow heavy light crude oil differentials and other continuing unfavorable economic conditions that began in the second quarter of 2009 precluded us from profitably operating the refinery. We performed an impairment analysis at that time in connection with the temporary suspension of our Yorktown refining operations. Based on that analysis, we determined that the undiscounted forecasted cash flows exceeded the carrying amount of our Yorktown long-lived and intangible assets and thus, no impairment was recorded. Throughout the period that refining operations were suspended through the date of the sale of our Yorktown facility, we routinely monitored refining industry market data, including crack spread and heavy light crude oil differential forecasts and other refining industry market data to determine whether assumptions used in our impairment analysis should be revised or updated. Our impairment analysis included considerable estimates and judgment, the most significant of which was the restart of refining operations during the latter part of 2013.
On November 30, 2011, we announced that we had entered into agreements to sell the Yorktown refining and terminal asset facilities, which transaction closed on December 29, 2011. The sales agreements also provided for the transfer of virtually all Yorktown related remediation liabilities to the buyer and an equal sharing of future net proceeds if the Yorktown refining assets are sold. We retained our East Coast wholesale business and continue to market finished products in the Mid-Atlantic region. This transaction allowed us to monetize the Yorktown assets and exit the volatile East Coast refining market. Continued extreme volatility of refining economics on the East Coast, with a noticeable decline during the latter part of 2011 in forecasted East Coast refining margins and the announcements during the latter part of 2011 of additional East Coast refining facility closures, significantly reduced the probability of restarting refining operations at Yorktown. In addition, during the latter part of 2011, we became aware of potential changes in pricing methodology of crude oils used for production at the Yorktown facility from one based on WTI to one based on Brent. As a result of our fourth quarter decision to sell the Yorktown facility, we recorded a loss of $465.6 million, including transaction costs of $1.2 million. This loss has been included in Loss and impairments on disposal of assets, net in the Consolidated Statement of Operations for the year ended December 31, 2011.
In a separate transaction with the third-party buyer of the Yorktown facility, we also sold an 82-mile section of our Texas New Mexico crude pipeline. Prior to the sale of the section of the line, the Texas New Mexico pipeline extended 424 miles from Southeast to Northwest New Mexico. The sale of this segment of pipeline resulted in a gain of $26.6 million, including transaction costs of $0.1 million. We performed an impairment analysis on the remaining 342 miles of our pipeline in connection with the sale and determined that no impairment of our remaining pipeline system existed as of December 31, 2011. This gain has been included in Loss and impairments on disposal of assets, net in our Consolidated Statement of Operations for the year ended December 31, 2011.
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.

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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. In December 2011, we redeemed the entire tranche of floating rate notes at a premium to par of 5%. The floating rate notes paid 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%. Through December 21, 2011, the interest rate on the Floating Rate Notes was 10.75%.
See Note 13, Long-Term Debt, and Note 18, Stockholders’ Equity, in the Consolidated Financial Statements included in this annual report for more detailed information.
Asset Impairments and Disposals
During the fourth quarter of 2011, we entered into two separate agreements for the sale of our Yorktown, Virginia, refining and terminal assets and an 82-mile section of our 424 mile crude oil pipeline system in Southeast New Mexico. Gross proceeds for these two asset sales totaled $220.4 million, resulting in a loss on disposal of the Yorktown assets of $465.6 million and a gain on disposal of the 82-mile pipeline section of $26.6 million. During the first quarter of 2011, we sold platinum assets from our Yorktown refinery. Gross proceeds on the sale totaled $11.3 million resulting in a gain on the sale of $3.6 million. A loss of $435.4 million related to these 2011 disposals has been included in Loss and impairments on disposal of assets, net in the Consolidated Statement of Operations for the year ending December 31, 2011.
In the fourth quarter of 2009, in connection with the indefinite suspension of refining operations at our Bloomfield refinery, we recorded an impairment loss of $52.8 million related to long-lived and intangible assets. During the fourth quarters of 2011 and 2010, respectively, we recorded additional impairment charges of $11.7 million and $9.1 million resulting from our 2011 and 2010 fourth quarter analyses of specific assets that we had previously planned to relocate from our Bloomfield facility to our Gallup refinery. These non-cash impairment losses are included in Loss and impairments on disposal of assets, net in our Consolidated Statements of Operations for the years ended December 31, 2011, 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 Loss and impairments on disposal of assets, net 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 Statement of Operations for the year ended December 31, 2009.
Employee Benefit Plans
Through December 31, 2011, the Company had distributed $20.0 million ($7.2 million  in 2011 and $12.8 million in 2010) from plan assets to plan participants as a result of the temporary idling of Yorktown refining operations in 2010 and resultant termination of several participants of the Yorktown cash balance plan. The Company contributed $4.4 million to its Yorktown pension plan during 2011. The Company expects to contribute $2.5 million to its Yorktown pension plan in 2012. Subject to a Memorandum of Understanding between Western Refining Yorktown, Inc. and the 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 $4.5 million as of December 31, 2011 (an increase of $0.8 million

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in 2011 and a decrease of $5.3 million in 2010). Currently, we do not plan to terminate the Yorktown retiree medical plan. During 2009 we terminated our defined benefit plan covering certain El Paso refinery employees. 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.
Debt Extinguishments and Write-off of Unamortized Loan Fees
On December 21, 2011, we retired $275.0 million of our floating rate notes at an aggregate redemption price of $288.8 million, including a 5 percent premium for early retirement. Including the write-off of related unamortized debt costs, we incurred a loss of $29.7 million. This loss has been included in Loss on extinguishment of debt in the Consolidated Statement of Operations for the year ended December 31, 2011.
On March 29, 2011, we amended and restated our Term Loan Agreement. To effect this amendment and restatement, we paid $3.7 million in amendment fees. As a result of the amendment and restatement, we recorded a loss of $4.6 million that has been included in Loss on extinguishment of debt in the Consolidated Statement of Operations for the year ended December 31, 2011.
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. We completed an additional amendment to our Revolving Credit Agreement in December 2010. We 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.
Commodity Hedging Activities, Environmental Cost Recoveries, Property Tax Refunds, and Other
Our operating results for the year ended December 31, 2011 included realized and unrealized net gains from our commodity hedging activities of $107.3 million compared to net losses of $9.4 million and $21.7 million for the years ended December 31, 2010 and 2009, respectively. The current year results are primarily the result of our use of swap contracts for the purpose of fixing the margin on a portion of our future gasoline and distillate production. See Note 16, Crude Oil and Refined Product Risk Management, in Notes to Consolidated Financial Statements included in this annual report for further discussion on our commodity hedging activities. Our income tax provision for the year ended December 31, 2011 includes the effects of a valuation allowance of $23.7 million against the deferred tax assets for Virginia and Maryland generated through the operations of the Yorktown facility prior to the sale of the facility in December 2011. 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 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 the years ended December 31, 2011, 2010, and 2009, we incurred costs of $2.4 million, $23.3 million, and $8.1 million, respectively, for maintenance turnarounds. Costs incurred during 2011 related to the planned 2012 fourth quarter turnaround for Gallup. During 2010, we incurred costs of $23.3 million in connection with a maintenance turnaround at the El Paso refinery. 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. Our next scheduled maintenance turnarounds are during the fourth quarter of 2012 for Gallup and the first quarter of 2013 for El Paso. We expense the cost of maintenance turnarounds when the expense is incurred. Most of our competitors, however, capitalize and amortize maintenance turnarounds.

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Critical Accounting Policies and Estimates
We prepare our financial statements in conformity with U.S. GAAP. Note 2 to our Consolidated Financial Statements contains a summary of our significant accounting policies, many of which require the use of estimates and assumptions. We believe that of our significant accounting policies, the following are noteworthy because they are based on estimates and assumptions that require complex, subjective assumptions by management, which can materially impact reported results. Changes in these estimates or assumptions, or actual results that are different, could materially impact our financial condition and results of operations.
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. 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. We determine market value inventory adjustments by evaluating crude oil, refined products, and other inventories on an aggregate basis by geographic region.
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 refined product, lubricant, and related inventories are determined using the FIFO inventory valuation method. Refined 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 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.
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. We do not amortize goodwill for financial reporting purposes.
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 asset’s economic useful life is determined to be indefinite, then that asset is not amortized. We consider factors such as the asset’s 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.

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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.
Asset Retirement Obligations, or 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. We recognize all the commodity hedge transactions that we enter as either assets or liabilities in the Consolidated Balance Sheets and those instruments are measured at fair value. For instruments used to mitigate the change in value of volumes subject to market prices, the Company elected not to pursue hedge accounting treatment for financial accounting purposes, generally because of the difficulty of establishing the required documentation that would allow for hedge accounting at the date that the hedging instrument is entered into. The swap contracts used to fix the margin on a portion of the Company’s future gasoline and distillate production do not qualify for hedge accounting treatment. Therefore, changes in the fair value of these commodity hedging 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 plan’s overfunded status or liability for the plan’s underfunded status, (b) measure the plan’s assets and obligations that determine its funded status as of the end of the employer’s 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
The accounting provisions covering the presentation of comprehensive income were amended to allow an entity the option to present the total of comprehensive income (loss), the components of net income (loss), and the components of other comprehensive income (loss) either in a single continuous statement or in two separate but consecutive statements. These provisions are effective for the first interim or annual period beginning after December 15, 2011, and are to be applied retrospectively, with early adoption permitted. The adoption of this guidance effective January 1, 2012 will not affect the Company’s financial position or results of operations because these requirements only affect disclosures.
The accounting provisions covering fair value measurements and disclosures were amended to clarify the application of existing fair value measurement requirements and to change certain fair value measurement and disclosure requirements. Amendments that change measurement and disclosure requirements relate to (i) fair value measurement of financial instruments that are managed within a portfolio, (ii) application of premiums and discounts in a fair value measurement, and (iii) additional disclosures about fair value measurements categorized within Level 3 of the fair value hierarchy. These provisions are effective for the first interim or annual period beginning after December 15, 2011. The adoption of this guidance

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effective January 1, 2012 will not affect the Company’s financial position or results of operations, but may result in additional disclosures.
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, 2011:


Consolidated
 
Year Ended December 31,
 
2011
 
2010
 
2009
 
(In thousands)
Net sales (1)
$
9,071,037

 
$
7,965,053

 
$
6,807,368

Operating costs and expenses:
 

 
 

 
 

Cost of products sold (exclusive of depreciation and amortization) (1)
7,532,423

 
7,155,967

 
5,944,128

Direct operating expenses (exclusive of depreciation and amortization) (1)
463,563

 
444,531

 
486,164

Selling, general, and administrative expenses
105,768

 
84,175

 
109,697

Loss and impairments on disposal of assets, net
447,166

 
13,038

 
52,788

Goodwill impairment loss

 

 
299,552

Maintenance turnaround expense
2,443

 
23,286

 
8,088

Depreciation and amortization
135,895

 
138,621

 
145,981

Total operating costs and expenses
8,687,258

 
7,859,618

 
7,046,398

Operating income (loss)
$
383,779

 
$
105,435

 
$
(239,030
)
_______________________________________
(1)
Excludes $5,022.8 million, $3,294.0 million, and $2,095.0 million of intercompany sales; $5,010.9 million, $3,287.5 million, and $2,088.8 million of intercompany cost of products sold; and $11.9 million, $6.5 million, and $6.2 million of intercompany direct operating expenses for the years ended December 31, 2011, 2010, and 2009, respectively.
Fiscal Year Ended December 31, 2011 Compared to Fiscal Year Ended December 31, 2010
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, 2011 were $9,071.0 million, compared to $7,965.1 million for the year ended December 31, 2010, an increase of $1,106.0 million, or 13.9%. This increase was the result of increased sales from our wholesale and retail groups of $2,090.3 million and $219.0 million, respectively, offset by decreased sales from our refining group of $1,203.3 million, net of intercompany transactions that eliminate in consolidation. The average sales price per barrel of refined products for all operating segments increased from $93.18 in 2010 to $126.41in 2011. This increase was partially offset by a decrease in sales volume. Our sales volume decreased from 117.1 million barrels in 2010 to 105.5 million barrels in 2011, a decrease of 11.6 million barrels, or 9.9%.
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 $7,532.4 million for the year ended December 31, 2011, compared to $7,156.0 million for the year ended December 31, 2010, an increase of $376.5 million, or 5.3%. This increase was primarily the result of increased cost of products sold from our wholesale and retail groups of $2,072.6 million and $215.6 million, respectively, offset by decreased cost of products sold from our refining group of $1,911.8 million, net of intercompany transactions that eliminate in consolidation. The average cost per barrel of crude oil, feedstocks, and refined products for all operating segments increased from $86.94 in 2010 to $112.67 in 2011. Cost of products sold includes $107.3 million in realized and unrealized economic hedging gains that includes $183.3 million in unrealized economic hedging gains for the year ended December 31, 2011. Cost of products sold includes $9.4 million in realized and unrealized economic hedging losses for the year ended December 31, 2010.
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 $463.6 million for the year ended December 31, 2011, compared to $444.5 million for the year ended December 31, 2010, an increase of $19.0 million, or 4.3%.

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The increase in direct operating expenses resulted from increases of $13.9 million and $13.5 million in direct operating expenses from our wholesale and retail groups, respectively, and a decrease of $8.4 million from our refining group, net of intercompany transactions that eliminate in consolidation. Direct operating expenses for the year ended December 31, 2010 were reduced by $8.5 million related to the first quarter 2010 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.
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 $105.8 million for the year ended December 31, 2011, compared to $84.2 million for the year ended December 31, 2010, an increase of $21.6 million, or 25.7%. The increase in selling, general, and administrative expenses resulted from increased expenses in our refining and retail groups of $7.3 million and $2.2 million, respectively, a $13.5 million increase in corporate overhead, and a $1.5 million decrease in our wholesale group. Selling, general, and administrative expenses were reduced $6.2 million related to the reversal of our December 2009 incentive bonus accrual during the first quarter of 2010. See Direct Operating Expenses (exclusive of depreciation and amortization) for the year ended December 31, 2010 for additional discussion of the bonus accrual reversal.
The increase of $13.5 million in corporate overhead was primarily due to increased incentive compensation ($8.0 million), increased wages and other employee expenses ($2.8 million), the cost of various information technology initiatives ($1.4 million), and increased group insurance expense ($1.1 million).
Loss and Impairments on Disposal of Assets, Net. We recorded a net loss on disposal of assets of $447.2 million for the year ended December 31, 2011, compared to $13.0 million for the year ended December 31, 2010, an increase of $434.1 million related primarily to the loss on disposal of the Yorktown refining and refined product terminal assets.
The loss for 2011 was comprised of a $465.6 million loss related to the sale of the Yorktown refinery and an $11.7 million loss related to certain Bloomfield refinery assets, offset by a $26.6 million gain related to the sale of a segment of our pipeline system and a $3.6 million gain related to the sale of platinum assets at Yorktown in the first quarter.
The loss for 2010 was the result of our decision to permanently close our product distribution terminal in Flagstaff, Arizona and additional impairment related to certain of our Bloomfield refinery assets. Non-cash impairment charges of $4.0 million primarily related to the Flagstaff long-lived assets and $9.1 million related to the Bloomfield assets were reported during 2010.
Maintenance Turnaround Expense.  Maintenance turnaround expense includes periodic maintenance and repairs generally performed every two to six years, depending on the processing unit involved. We incurred turnaround expenses of $2.4 million in connection with a planned 2012 turnaround at our Gallup refinery for the year ended December 31, 2011. Including the $2.4 million incurred during 2011, we estimate that the total maintenance turnaround expense for the 2012 Gallup turnaround will be $25 million. We incurred costs of $23.3 million in connection with a turnaround at our El Paso refinery for the year ended December 31, 2010.
Depreciation and Amortization.  Depreciation and amortization was $135.9 million for the year ended December 31, 2011, compared to $138.6 million for the year ended December 31, 2010, a decrease of $2.7 million, or 2.0%. The majority of the decrease was due to differences in the timing of various assets reaching the end of their estimated useful lives and the disposal of the Yorktown facility in December 2011.
Operating Income.  Operating income was $383.8 million for the year ended December 31, 2011, compared to $105.4 million for the year ended December 31, 2010, an increase of $278.3 million. This increase was primarily attributable to increased refinery gross margins coupled with decreased maintenance turnaround expense and decreased depreciation and amortization expense offset by loss and impairments on disposal of assets, increased direct operating expenses, and increased selling, general, and administrative expenses.
Interest Income.  Interest income for the years ended December 31, 2011 and 2010 was $0.5 million and $0.4 million, respectively.
Interest Expense.  Interest expense was $134.6 million (net of capitalized interest of $2.0 million) for the year ended December 31, 2011, compared to $146.5 million (net of capitalized interest of $4.2 million) for the year ended December 31, 2010, a decrease of $11.9 million, or 8.2%. The decrease was primarily attributable to our lower average cost of borrowing during the year ended December 31, 2011 compared to 2010.
Amortization of Loan Fees.  Amortization of loan fees for 2011 was $8.9 million, compared to $9.7 million for 2010, a decrease of $0.8 million, or 8.3%.
Loss on extinguishment of debt.  We recorded a loss on extinguishment of debt of $34.3 million for the year ended

37


December 31, 2011 that was the result of our early redemption of the Floating Rate Notes on December 21, 2011 and an amendment to our Term Loan Credit Agreement during 2011. No debt extinguishment losses were recorded for the year ended December 31, 2010.
Other, Net.  Other expenses, net, were $3.9 million for the year ended December 31, 2011, compared to other income, net, of $7.3 million for the year ended December 31, 2010. Both periods include amounts related to the settlement of lawsuits.
Provision for Income Taxes.  Our effective tax rate can be affected by any estimated tax credits that we plan to utilize for the year’s 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 income tax expense of $69.9 million for the year ended December 31, 2011, using an estimated effective tax rate of 34.5%, compared to the federal statutory rate of 35%. Our 2011 income tax provision includes the effect of a full valuation of $23.7 million against certain net operating loss carry-forwards related to Yorktown operations.
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%, 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.
Net Income (Loss).  We reported net income of $132.7 million for the year ended December 31, 2011, representing $1.46 and $1.34 net income per share on weighted average basic and dilutive shares outstanding of 89.0 million and 109.8 million, respectively. We reported a net loss of $17.0 million for the year ended December 31, 2010, representing $0.19 net loss per share on both basic and dilutive weighted average shares outstanding of 88.2 million.
See additional analysis under the Refining Segment, Wholesale Segment, and Retail Segment.
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 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 years ended December 31, 2010 and 2009 includes $9.4 million and $21.7 million in economic hedging losses, respectively.
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%. 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. Direct operating expenses for the year ended December 31, 2010 were reduced by $8.5 million related to the first quarter 2010 reversal of our December 2009 incentive bonus accrual. Accrued incentive bonus of $4.7 million was included in consolidated direct operating expenses for the year ended December 31, 2010.

38


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.
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%. 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. 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.
The decrease of $4.6 million in corporate overhead was primarily caused by decreased professional and legal fees ($4.2 million). An accrued incentive bonus of $3.6 million was included in consolidated selling, general, and administrative expenses for the year ended December 31, 2010.
Goodwill Impairment Loss.  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 for the year ended December 31, 2009.
Loss and Impairments on Disposal of Assets, Net.  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 our Bloomfield refinery assets and recorded a resulting non-cash charge of $9.1 million.
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 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 a non-cash goodwill impairment loss of $299.6 million in 2009 and loss on disposal of assets of $52.8 million recorded in 2009 compared to $13.0 million in 2010. Also contributing to the increase were decreased direct operating expenses, decreased selling, general, and administrative expenses, and 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.

39


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 year’s 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%, 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%, 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 basic and 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 basic and diluted 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.


40


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, 2011 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,
 
2011
 
2010
 
2009
 
(In thousands, except per barrel data)
Net sales (including intersegment sales)
$
8,399,698

 
$
8,070,119

 
$
6,608,075

Operating costs and expenses:
 

 
 

 
 

Cost of products sold (exclusive of depreciation and amortization) (1)
7,059,210

 
7,439,826

 
5,919,499

Direct operating expenses (exclusive of depreciation and amortization)
329,237

 
335,869

 
375,690

Selling, general, and administrative expenses
27,451

 
20,155

 
36,021

Loss and impairments on disposal of assets, net
447,166

 
12,832

 
52,788

Goodwill impairment loss

 

 
230,712

Maintenance turnaround expense
2,443

 
23,286

 
8,088

Depreciation and amortization
119,057

 
118,661

 
125,537

Total operating costs and expenses
7,984,564

 
7,950,629

 
6,748,335

Operating income (loss)
$
415,134

 
$
119,490

 
$
(140,260
)
Key Operating Statistics
 

 
 

 
 

Total sales volume (bpd) (2) (7)
189,339

 
248,785

 
258,259

Total refinery production (bpd) (7)
140,124

 
192,997

 
213,833

Total refinery throughput (bpd) (3) (7)
142,257

 
194,492

 
215,815

Per barrel of throughput:
 

 
 

 
 

Refinery gross margin (1) (4)
$
25.82

 
$
8.88

 
$
8.74

Gross profit (4)
23.52

 
7.21

 
7.15

Direct operating expenses (5)
6.34

 
4.73

 
4.77



41


Southwest Refineries (El Paso and Four Corners and Related Operations)
 
Year Ended December 31,
 
2011
 
2010
 
2009
 
(In thousands, except per barrel data)
Net sales (including intersegment sales)
$
8,383,594

 
$
6,321,322

 
$
4,877,985

Operating costs and expenses:
 

 
 

 
 

Cost of products sold (exclusive of depreciation and amortization)
7,048,140

 
5,745,996

 
4,326,182

Direct operating expenses (exclusive of depreciation and amortization)
285,800

 
242,422

 
262,259

Selling, general, and administrative expenses
27,451

 
20,155

 
36,021

Goodwill impairment loss

 

 
73,148

(Gain) loss and impairments on disposal of assets, net
(14,829
)
 
12,832

 
52,788

Maintenance turnaround expense
2,443

 
23,286

 
6,898

Depreciation and amortization
76,254

 
72,886

 
78,732

Total operating costs and expenses
7,425,259

 
6,117,577

 
4,836,028

Operating income
$
958,335

 
$
203,745

 
$
41,957

Key Operating Statistics
 

 
 

 
 

Total sales volume (bpd) (2)
189,007

 
189,613

 
184,108

Total refinery production (bpd)
140,124

 
149,007

 
150,411

Total refinery throughput (bpd) (3)
142,257

 
151,288

 
153,082

Per barrel of throughput:
 

 
 

 
 

Refinery gross margin (4)
$
25.72

 
$
10.42

 
$
9.88

Gross profit (4)
24.25

 
9.10

 
8.47

Direct operating expenses (5)
5.50

 
4.39

 
4.69


All Refineries
 
Year Ended December 31,
 
2011
 
2010 (7)
 
2009
Refinery Product Yields (bpd)
 

 
 

 
 

Gasoline
74,224

 
102,927

 
113,364

Diesel and jet fuel
57,037

 
73,774

 
80,157

Residuum
5,219

 
4,899

 
5,504

Other
3,644

 
7,174

 
9,349

Liquid by-products
140,124

 
188,774

 
208,374

By-products (coke)

 
4,223

 
5,459

Total refinery production (bpd)
140,124

 
192,997

 
213,833

Refinery Throughput (bpd)
 

 
 

 
 

Sweet crude oil
113,347

 
131,028

 
126,328

Sour or heavy crude oil
19,876

 
44,129

 
65,260

Other feedstocks and blendstocks
9,034

 
19,335

 
24,227

Total refinery throughput (bpd)
142,257

 
194,492

 
215,815



42


Southwest Refineries (El Paso and Four Corners)
 
Year Ended December 31,
 
2011
 
2010
 
2009 (6)
Refinery Product Yields (bpd)
 

 
 

 
 

Gasoline
74,224

 
81,953

 
82,540

Diesel and jet fuel
57,037

 
58,122

 
57,976

Residuum
5,219

 
4,899

 
5,504

Other
3,644

 
4,033

 
4,391

Total refinery production (bpd)
140,124

 
149,007

 
150,411

Refinery Throughput (bpd)
 

 
 

 
 

Sweet crude oil
113,347

 
125,259

 
124,443

Sour crude oil
19,876

 
14,007

 
17,601

Other feedstocks and blendstocks
9,034

 
12,022

 
11,038

Total refinery throughput (bpd)
142,257

 
151,288

 
153,082


 
Year Ended December 31,
El Paso Refinery
2011
 
2010
 
2009
Key Operating Statistics
 

 
 

 
 

Refinery product yields (bpd):
 

 
 

 
 

Gasoline
58,236

 
65,740

 
65,160

Diesel and jet fuel
50,211

 
51,571

 
50,524

Residuum
5,219

 
4,899

 
5,504

Other
2,882

 
3,245

 
3,341

Total refinery production (bpd)
116,548

 
125,455

 
124,529

Refinery throughput (bpd):
 

 
 

 
 

Sweet crude oil
91,589

 
104,119

 
99,680

Sour crude oil
19,876

 
14,007

 
17,601

Other feedstocks and blendstocks
6,680

 
9,051

 
9,184

Total refinery throughput (bpd)
118,145

 
127,177

 
126,465

Total sales volume (bpd) (2)
155,196

 
153,398

 
147,854

Per barrel of throughput:
 

 
 

 
 

Refinery gross margin (4)
$
23.18

 
$
9.37

 
$
9.20

Direct operating expenses (5)
4.50

 
3.50

 
3.60



43


 
Year Ended December 31,
Four Corners Refineries
2011
 
2010
 
2009 (6)
Key Operating Statistics
 

 
 

 
 

Refinery product yields (bpd):
 

 
 

 
 

Gasoline
15,988

 
16,213

 
17,380

Diesel and jet fuel
6,826

 
6,551

 
7,452

Other
762

 
788

 
1,050

Total refinery production (bpd)
23,576

 
23,552

 
25,882

Refinery throughput (bpd):
 

 
 

 
 

Sweet crude oil
21,758

 
21,140

 
24,763

Other feedstocks and blendstocks
2,354

 
2,971

 
1,854

Total refinery throughput (bpd)
24,112

 
24,111

 
26,617

Total sales volume (bpd) (2)
33,811

 
36,215

 
36,254

Per barrel of throughput:
 

 
 
 
 

Refinery gross margin (4)
$
26.05

 
$
16.82

 
$
15.17