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

Direct operating expenses (5)
8.27

 
6.68

 
8.79


 
 
Year Ended December 31,
Yorktown Refinery
 
2010 (7)
 
2009
Key Operating Statistics
 
 

 
 

Refinery Product Yields (bpd):
 
 

 
 

Gasoline
 
28,043

 
30,824

Diesel and jet fuel
 
20,926

 
22,181

Other
 
4,199

 
4,958

Liquid by-products
 
53,168

 
57,963

By-products (coke)
 
5,647

 
5,459

Total refinery production (bpd)
 
58,815

 
63,422

Refinery throughput (bpd):
 
 

 
 

Sweet crude oil
 
7,713

 
1,885

Heavy crude oil
 
40,274

 
47,659

Other feedstocks and blendstocks
 
9,777

 
13,189

Total refinery throughput (bpd)
 
57,764

 
62,733

Total sales volume (bpd) (2) (7)
 
59,172

 
74,151

Per barrel of throughput:
 
 

 
 

Refinery gross margin (1) (4)
 
$
3.49

 
$
5.97

Direct operating expenses (5)
 
5.93

 
4.95

_______________________________________
(1)
Cost of products sold includes non-cash LCM recoveries of $61.0 million for 2009 related to valuation of our Yorktown inventories at net realizable market values. These non-cash recoveries resulted in a corresponding increase of $0.78 per barrel in combined refinery gross margin and $2.66 per barrel in Yorktown’s refinery gross margin for the year ended December 31, 2009.
(2)
Includes sales of refined products sourced from our refinery production as well as refined products purchased from third parties.
(3)
Total refinery throughput includes crude oil, other feedstocks, and blendstocks.
(4)
Refinery gross margin is a per barrel measurement calculated by dividing the difference between net sales and cost of products sold by our refineries’ total throughput volumes for the respective periods presented. Economic hedging gains and losses included in the combined refining segment gross margins are not allocated to the individual refineries. Cost of products sold does not include any depreciation or amortization. Refinery gross margin is a non-GAAP performance

44


measure that we believe is important to investors in evaluating our refinery performance as a general indication of the amount above our cost of products that we are able to sell refined products. Each of the components used in this calculation (net sales and cost of products sold) can be reconciled directly to our statement of operations. Our calculation of refinery gross margin may differ from similar calculations of other companies in our industry, thereby limiting its usefulness as a comparative measure.
The following table reconciles combined gross profit for all refineries to combined gross margin for all refineries for the periods presented:

 
Year Ended December 31,
 
2011
 
2010
 
2009
 
(In thousands, except per barrel data)
Net sales (including intersegment sales)
$
8,399,698

 
$
8,070,119

 
$
6,608,075

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

 
7,439,826

 
5,919,499

Depreciation and amortization
119,057

 
118,661

 
125,537

Gross profit
1,221,431

 
511,632

 
563,039

Plus depreciation and amortization
119,057

 
118,661

 
125,537

Refinery gross margin
$
1,340,488

 
$
630,293

 
$
688,576

Refinery gross margin per refinery throughput barrel (4)
$
25.82

 
$
8.88

 
$
8.74

Gross profit per refinery throughput barrel (4)
$
23.52

 
$
7.21

 
$
7.15


The following table reconciles gross profit for our Southwest refineries to combined gross margin for our Southwest refineries for the periods presented:

 
Year Ended December 31,
 
2011
 
2010
 
2009
 
(In thousands, except per barrel data)
Net sales (including intersegment sales)
$
8,383,594

 
$
6,321,322

 
$
4,877,985

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

 
5,745,996

 
4,326,182

Depreciation and amortization
76,254

 
72,886

 
78,732

Gross profit
1,259,200

 
502,440

 
473,071

Plus depreciation and amortization
76,254

 
72,886

 
78,732

Refinery gross margin
$
1,335,454

 
$
575,326

 
$
551,803

Refinery gross margin per refinery throughput barrel (4)
$
25.72

 
$
10.42

 
$
9.88

Gross profit per refinery throughput barrel (4)
$
24.25

 
$
9.10

 
$
8.47


(5)
Refinery direct operating expenses per throughput barrel is calculated by dividing direct operating expenses by total throughput volumes for the respective periods presented. Direct operating expenses do not include any depreciation or amortization, and combined refinery direct operating expenses include transportation and other related expenses not specific to a particular refinery.
(6)
Until November 2009, Four Corners refining was comprised of two separate facilities; the Bloomfield refinery and the Gallup refinery. In late November 2009, we consolidated refining operations into the Gallup facility and indefinitely suspended refining operations at the Bloomfield refinery. We calculated total bpd refinery production, refinery throughput, and sales volume related to the Four Corners refineries by dividing by 365 days.
(7)
In September 2010, we temporarily suspended refining operations at the Yorktown refinery. We calculated Yorktown total bpd refinery production and refinery throughput by dividing total volumes by 273 days. Total Yorktown sales volume includes refined product sales, following the temporary suspension, through December 31, 2010. We calculated Yorktown’s bpd sales volume by dividing total refinery sales volume by 365 days. We had no refinery production at Yorktown during any part of 2011, and we subsequently sold all of the Yorktown refining assets in December 2011.
For our combined refining operating statistics, we calculated total bpd refinery sales volume, refinery production, refinery throughput, and refinery product yields by dividing all refineries’ operations by 365 days.

45


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 petroleum products, net of customer rebates, discounts, and excise taxes. Net sales for the year ended December 31, 2011 were $8,399.7 million, compared to $8,070.1 million for the year ended December 31, 2010, an increase of $329.6 million, or 4.1%. This increase primarily resulted from an increase in the average per barrel sales price of refined products at El Paso and Gallup. The average sales price per barrel increased 33% from $91.26 in 2010 to $121.34 in 2011. The impact of this increase was substantially offset by lower sales volumes of refined products at our El Paso and Gallup refineries in part due to the weather-related outage at our El Paso refinery during the first quarter of 2011. Our volume sold decreased from 90.8 million barrels in 2010 (including 21.6 million barrels sold from our Yorktown refinery) to 69.0 million barrels in 2011.
Cost of Products Sold (exclusive of depreciation and amortization).  Cost of products sold primarily includes cost of crude oil, other feedstocks and blendstocks, purchased products for resale, and transportation and distribution costs. Cost of products sold for the year ended December 31, 2011 was $7,059.2 million, compared to $7,439.8 million for the year ended December 31, 2010, a decrease of $380.6 million, or 5.1%. This decrease was the result of lower crude volume purchases at our El Paso and Gallup refineries in part due to the weather-related outage at our El Paso refinery during the first quarter of 2011. During 2010 we purchased 63.4 million barrels of crude oil (including 12.2 million barrels for Yorktown), compared to 48.7 million barrels in 2011. These decreases were offset by increases at our Southwest refineries in the average costs of crude oil. Our average cost per barrel increased from $95.77 in 2010 to $117.43 in 2011, an increase of 22.6%. Refinery gross margin per throughput barrel increased from $8.88 in 2010 to $25.82 in 2011 reflecting higher refining margins. Gross profit per barrel, based on the closest comparable GAAP measure to refinery gross margin, was $23.52 and $7.21 for 2011 and 2010, respectively. Cost of products sold for 2011 includes $103.3 million in realized and unrealized economic hedging gains compared to $9.4 million in realized and unrealized economic hedging losses in 2010.
Direct Operating Expenses (exclusive of depreciation and amortization).  Direct operating expenses include costs associated with the operations of our refineries, such as energy and utility costs, catalyst and chemical costs, periodic maintenance, labor, insurance, property taxes, and environmental compliance costs. Direct operating expenses were $329.2 million for the year ended December 31, 2011, compared to $335.9 million for the year ended December 31, 2010, a decrease of $6.7 million, or 2.0%. This decrease primarily resulted from the idling of our Yorktown refinery ($50.0 million). Also contributing to the decrease were decreased maintenance expenses ($6.3 million) including a $4.8 million insurance recovery due to a weather-related outage during the first quarter of 2011 at our southwest operations, decreased natural gas expense ($1.1 million), and decreased property taxes ($1.0 million). Partially offsetting these decreases were increased labor and repair expense ($19.7 million), increased material and supplies expense ($8.3 million), increased personnel costs ($7.2 million), increased chemicals and catalyst ($6.9 million), increased outside services ($4.1 million), and increased environmental expenses ($2.0 million).
Selling, General, and Administrative Expenses.  Selling, general, and administrative expenses consist primarily of segment overhead, marketing expenses, and stock-based compensation. Selling, general, and administrative expenses were $27.5 million for the year ended December 31, 2011, compared to $20.2 million for the year ended December 31, 2010, an increase of $7.3 million, or 36.2%. This increase primarily resulted from increases in personnel costs ($6.9 million), including the reversal of the 2009 incentive bonus accrual in the first quarter of 2010. See consolidated direct operating expenses (exclusive of depreciation and amortization) for the fiscal year ended December 31, 2011 for additional discussion of the bonus accrual reversal.
Loss and Impairments on Disposal of Assets, Net. We recorded a loss of disposal of assets of $447.2 million for the year ended December 31, 2011, compared to $12.8 million for the year ended December 31, 2010, an increase of $434.4 million related primarily to the loss on disposal of the Yorktown refining and refined product terminal assets.
The net 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.
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. From this analysis, we determined that impairment existed. Accordingly, we recorded an impairment charge of $3.8 million primarily related to the Flagstaff long-lived assets during the year ended December 31, 2010. Also during 2010, we determined the existence of additional impairment related to certain of Bloomfield’s refinery assets and recorded a resulting non-cash charge of $9.1 million.

46


Maintenance Turnaround Expense.  Maintenance turnaround expense includes planned periodic maintenance and repairs generally performed every two to six years, depending on the processing unit involved. During the year ended December 31, 2011, we incurred costs of $2.4 million in anticipation of the turnaround scheduled for the third quarter of 2012 at the Gallup refinery. During the year ended December 31, 2010, we incurred costs of $23.3 million in connection with a turnaround in the first quarter of 2010 at the El Paso refinery.
Depreciation and Amortization.  Depreciation and amortization for the year ended December 31, 2011 was $119.1 million compared to $118.7 million for the year ended December 31, 2010.
Operating Income.  Operating income was $415.1 million for the year ended December 31, 2011, compared to $119.5 million for the year ended December 31, 2010, an increase of $295.6 million. This increase was primarily attributable to increased sales along with decreased cost of products sold, decreased direct operating expenses, and decreased maintenance turnaround expenses. This increase was partially offset by a net loss on disposal of assets, increased selling, general, and administrative expenses, and increased depreciation and amortization expense.
Fiscal Year Ended December 31, 2010, Compared to Fiscal Year Ended December 31, 2009
Net Sales.  Net sales primarily consist of gross sales of refined petroleum products, net of customer rebates, discounts, and excise taxes. Net sales for the year ended December 31, 2010 were $8,070.1 million, compared to $6,608.1 million for the year ended December 31, 2009, an increase of $1,462.0 million, or 22.1%. This increase primarily resulted from an increase in the average per barrel sales price. The average sales price per barrel increased from $70.09 in 2009 to $88.87 in 2010. This increase was partially offset by a decrease in sales volume of 3.5 million barrels, or 3.7%, from 94.3 million barrels in 2009 to 90.8 million barrels in 2010.
Cost of Products Sold (exclusive of depreciation and amortization).  Cost of products sold primarily includes cost of crude oil, other feedstocks and blendstocks, purchased products for resale, and transportation and distribution costs. Cost of products sold for the year ended December 31, 2010 was $7,439.8 million, compared to $5,919.5 million for the year ended December 31, 2009, an increase of $1,520.3 million, or 25.7%. This increase was primarily the result of increased average costs of crude oil. The average cost per barrel increased from $58.49 in 2009 to $77.31 in 2010, an increase of 32.2%. Also contributing to this increase were increased refined product and blendstock purchases. Partially offsetting this increase were decreased crude purchase volumes. During 2010, we purchased 63.4 million barrels of crude oil compared to 69.5 million barrels in 2009, a decrease of 8.8% primarily related to the temporary suspension of refining operations at our Yorktown refinery. Refinery gross margin per throughput barrel increased from $8.74 in 2009 to $8.88 in 2010. Gross profit per barrel, based on the closest comparable GAAP measure to refinery gross margin, was $7.21 in 2010 compared to $7.15 in 2009. Cost of products sold for the year ended December 31, 2009 includes $21.7 million in economic hedging losses previously reported as loss from derivative activities under other income (expense). The prior year amount was reclassified to conform to current presentation. Cost of products sold for the year ended December 31, 2010 includes $9.4 million in economic hedging losses.
Direct Operating Expenses (exclusive of depreciation and amortization).  Direct operating expenses include costs associated with the operations of our refineries, such as energy and utility costs, catalyst and chemical costs, periodic maintenance, labor, insurance, property taxes, and environmental compliance costs. Direct operating expenses were $335.9 million for the year ended December 31, 2010, compared to $375.7 million for the year ended December 31, 2009, a decrease of $39.8 million, or 10.6%. This decrease primarily resulted from decreased personnel costs ($24.9 million), including the reversal of our 2009 incentive bonus accrual in the first quarter of 2010. See consolidated direct operating expenses (exclusive of depreciation and amortization) for the fiscal year ended December 31, 2010 for additional discussion of the bonus accrual reversal. Also contributing to the decrease were decreased maintenance expenses ($7.1 million), decreased chemicals and catalyst purchases ($7.0 million), decreased electricity expense ($5.7 million), decreased insurance expense ($3.4 million), decreased outside support services ($2.5 million), and decreased professional, legal, and other expenses ($2.7 million). Partially offsetting these decreases were increased environmental expenses ($5.7 million), increased natural gas expense ($5.3 million), and increased property taxes ($4.0 million).
Selling, General, and Administrative Expenses.  Selling, general, and administrative expenses consist primarily of segment overhead, marketing expenses, and stock-based compensation. Selling, general, and administrative expenses were $20.2 million for the year ended December 31, 2010 compared to $36.0 million for the year ended December 31, 2009, a decrease of $15.8 million, or 43.9%. This decrease primarily resulted from decreases in personnel costs ($6.9 million), including the reversal of the 2009 incentive bonus accrual in the first quarter of 2010. See consolidated direct operating expenses (exclusive of depreciation and amortization) for the fiscal year ended December 31, 2010 for additional discussion of the bonus accrual reversal. Also contributing to the decrease were decreased marketing expenses ($2.5 million), decreased information technology expenses ($1.7 million), decreased professional, legal, and other expenses ($1.7 million), decreased bad debt expense ($1.5 million), and decreased environmental fines and penalties ($1.5 million).

47


Goodwill Impairment Loss. During 2009, we determined that all of the goodwill in two of our three refining reporting units was fully impaired. The total impact of this impairment was a non-cash charge of $230.7 million.
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 $3.8 million primarily related to the Flagstaff long-lived assets. Also during 2010, we determined the existence of additional impairment to certain of Bloomfield’s refinery assets and recorded a non-cash impairment charge of $9.1 million. During 2009, as a result of our decision to indefinitely suspend the refining operations of our Bloomfield refinery, we completed an impairment analysis of the related long-lived and intangible assets and determined that impairment of certain of the Bloomfield refinery related assets existed and accordingly recorded a non-cash charge of $52.8 million related to this impairment.
Maintenance Turnaround Expense.  Maintenance turnaround expense includes planned periodic maintenance and repairs generally performed every two to six years, depending on the processing unit involved. During the year ended December 31, 2010, we incurred costs of $23.3 million in connection with a turnaround in the first quarter of 2010 at the El Paso refinery. During the year ended December 31, 2009, we incurred costs of $2.9 million in a crude unit shutdown and $4.0 million in connection with the planned turnaround in the first quarter 2010 at the El Paso refinery, and $1.2 million related to the anticipated 2010 turnaround at the Yorktown refinery, which was subsequently canceled.
Depreciation and Amortization.  Depreciation and amortization for the year ended December 31, 2010 was $118.7 million, compared to $125.5 million for the year ended December 31, 2009. The decrease was primarily due to differences in the timing of various assets reaching the end of their estimated useful lives.
Operating Income (Loss).  Operating income was $119.5 million for the year ended December 31, 2010, compared to an operating loss of $140.3 million for the year ended December 31, 2009, an increase of $259.8 million. This increase is primarily attributable to the 2009 goodwill impairment loss and higher 2009 asset impairment losses compared to 2010, decreased direct operating and selling, general, and administrative expenses, and decreased depreciation and amortization expense. These decreases were partially offset by increased maintenance turnaround expense in 2010 compared to 2009.


Wholesale Segment
 
Year Ended December 31,
 
2011 (3)
 
2010
 
2009
 
(In thousands, except per gallon data)
Statement of Operations Data
 

 
 

 
 

Net sales (including intersegment sales)
$
4,753,790

 
$
2,470,586

 
$
1,664,397

Operating costs and expenses:
 

 
 

 
 

Cost of products sold (exclusive of depreciation amortization)
4,645,851

 
2,383,931

 
1,579,910

Direct operating expenses (exclusive of depreciation and amortization)
65,829

 
48,222

 
51,775

Selling, general, and administrative expenses
11,177

 
12,638

 
16,566

Goodwill impairment loss

 

 
41,230

Depreciation and amortization
4,312

 
5,069

 
5,616

Total operating costs and expenses
4,727,169

 
2,449,860

 
1,695,097

Operating income (loss)
$
26,621

 
$
20,726

 
$
(30,700
)
Operating Data
 

 
 

 
 

Fuel gallons sold (in thousands)
1,543,173

 
1,009,786

 
823,207

Fuel margin per gallon (1)
$
0.05

 
$
0.07

 
$
0.07

Lubricant sales
$
117,478

 
$
102,200

 
$
111,193

Lubricant margin (2)
11.5
%
 
11.5
%
 
9.6
%
_______________________________________
(1)
Fuel margin per gallon is a measurement calculated by dividing the difference between fuel sales and cost of fuel sales for our wholesale segment by the number of gallons sold. Fuel margin per gallon is a measure frequently used in the petroleum products wholesale industry to measure operating results related to fuel sales.

48


(2)
Lubricant margin is a measurement calculated by dividing the difference between lubricant sales and lubricant cost of products sold by lubricant sales. Lubricant margin is a measure frequently used in the petroleum products wholesale industry to measure operating results related to lubricant sales.
(3)
Our wholesale segment began selling refined product through our Yorktown facility during January 2011, and continues to supply refined product to the region as a customer of the terminal facility which we sold in December 2011. The refined products sold through our Yorktown facility were purchased from third parties. Net sales of $1,338.7 million, cost of products sold of $1,327.6 million, and direct operating costs of $6.8 million for the twelve months ended December 31, 2011 were from 2011 wholesale activities through our Yorktown facility with no comparable activity in the prior period. Further discussion of the impact of this new wholesale activity is included in the period to period comparisons below.
The following table reconciles fuel sales and cost of fuel sales to net sales and cost of products sold:
 
Year Ended December 31,
 
2011
 
2010
 
2009
 
(In thousands, except per gallon data)
Net sales:
 

 
 

 
 

Fuel sales (including intersegment sales)
$
4,971,199

 
$
2,588,628

 
$
1,749,431

Excise taxes included in fuel sales
(366,393
)
 
(250,550
)
 
(224,771
)
Lubricant sales
117,478

 
102,200

 
111,193

Other sales (including intersegment sales)
31,506

 
30,308

 
28,544

Net sales
$
4,753,790

 
$
2,470,586

 
$
1,664,397

Cost of products sold:
 

 
 

 
 

Fuel cost of products sold
$
4,895,302

 
$
2,527,758

 
$
1,692,177

Excise taxes included in fuel sales
(366,393
)
 
(250,550
)
 
(224,771
)
Lubricant cost of products sold
103,925

 
90,411

 
100,567

Other cost of products sold
13,017

 
16,312

 
11,937

Cost of products sold
$
4,645,851

 
$
2,383,931

 
$
1,579,910

Fuel margin per gallon
$
0.05

 
$
0.07

 
$
0.07


Fiscal Year Ended December 31, 2011, Compared to Fiscal Year Ended December 31, 2010
Net Sales.  Net sales consist primarily of sales of refined products net of excise taxes, lubricants, and freight. Net sales for the year ended December 31, 2011 were $4,753.8 million compared to $2,470.6 million for the year ended December 31, 2010, an increase of $2,283.2 million, or 92.4%. Net sales of $1,338.7 million on 458.9 million gallons of fuel were from 2011 wholesale activities through the recently sold Yorktown facility with no comparable activity in the prior period. The remainder of the increase was primarily due to an increase in the sales price of refined products, increased fuel sales volume, and increased sales price of lubricants. The average sales price per gallon of refined products increased from $2.56 in 2010 to $3.26 in 2011. Fuel sales volume increased from 1,009.8 million gallons in 2010 to 1,543.2 million gallons in 2011. Fuel sales volume for the year ended December 31, 2011 included 131.1 million gallons sold to our Retail group compared to 113.0 million gallons for 2010. The average sales price per gallon of lubricants increase from $9.58 in 2010 to $10.85 in 2011.
Cost of Products Sold (exclusive of depreciation and amortization).  Cost of products sold includes costs of refined products net of excise taxes, lubricants, and delivery freight. Cost of products sold was $4,645.9 million for the year ended December 31, 2011, compared to $2,383.9 million for the year ended December 31, 2010, an increase of $2,262.0 million, or 94.9%. Cost of products sold of $1,327.6 million was from 2011 wholesale activities through the recently sold Yorktown facility with no comparable activity in the prior period. The remainder of the increase was primarily due to an increase in cost of refined products, lubricants, and purchased fuel volume. The average cost per gallon increased from $2.50 in 2010 to $3.20 in 2011. The average cost of lubricants per gallon increase from $8.48 in 2010 to $9.60 in 2011.

49


Direct Operating Expenses (exclusive of depreciation and amortization).  Direct operating expenses include costs associated with the operations of our wholesale division such as labor, repairs and maintenance, rentals and leases, insurance, property taxes, and environmental compliance costs. Direct operating expenses were $65.8 million for the year ended December 31, 2011, compared to $48.2 million for the year ended December 31, 2010, an increase of $17.6 million, or 36.5%. Direct operating expenses of $6.8 million were for 2011 terminalling and storage fees at our Yorktown facility with no comparable activity in the prior period. The remainder of the increase was primarily due to increased in personnel costs ($5.5 million), increased operating materials and supplies ($3.5 million), and lease expenses ($1.2 million).
Selling, General, and Administrative Expenses.  Selling, general, and administrative expenses consist primarily of overhead and marketing expenses. Selling, general, and administrative expenses were $11.2 million in December 31, 2011, compared to $12.6 million for the year ended December 31, 2010, a decrease of $1.4 million, or 11.1%. This decrease primarily resulted from decreased bad debt expense ($2.4 million). This decrease was partially offset by an increase in personnel costs ($0.6 million) and other expenses ($0.6 million).
Depreciation and Amortization.  Depreciation and amortization was $4.3 million for the year ended December 31, 2011, compared to $5.1 million for the year ended December 31, 2010, a decrease of $0.8 million, or 15.7%.
Operating Income.  Operating income for the year ended December 31, 2011 was $26.6 million compared to operating income of $20.7 million for the year ended December 31, 2010, an increase of $5.9 million. The increase was primarily due to operating income from wholesale activity in the Northeast with no comparable activity in the prior period.
Fiscal Year Ended December 31, 2010, Compared to Fiscal Year Ended December 31, 2009
Net Sales.  Net sales consist primarily of sales of refined products net of excise taxes, lubricants, and freight. Net sales for the year ended December 31, 2010 were $2,470.6 million compared to $1,664.4 million for the year ended December 31, 2009, an increase of $806.2 million, or 48.4%. This increase was primarily due to an increase in the sales price of refined products, increased fuel sales volume, and increased freight billed. The average sales price per gallon of refined products increased from $2.13 in 2009 to $2.56 in 2010. Fuel sales volume increased from 823.2 million gallons in 2009 to 1,009.8 million gallons in 2010. Fuel sales volume for the year ended December 31, 2010 included 113.0 million gallons sold to our Retail group without comparable wholesale sales for the same period during 2009. During 2009, such sales of fuel were reported under our Refining group. This increase was partially offset by a decrease in lubricant sales volume. Lubricant sales volume decreased from 11.8 million gallons in 2009 to 10.7 million gallons in 2010.
Cost of Products Sold (exclusive of depreciation and amortization).  Cost of products sold includes costs of refined products net of excise taxes, lubricants, and delivery freight. Cost of products sold was $2,383.9 million for the year ended December 31, 2010, compared to $1,579.9 million for the year ended December 31, 2009, an increase of $804.0 million, or 50.9%. This increase was primarily due to increased delivery freight expenses and costs of refined products and purchased fuel volume. The average cost per gallon increased from $2.06 in 2009 to $2.50 in 2010. This increase was partially offset by a decrease in the purchased volume of lubricants.
Direct Operating Expenses (exclusive of depreciation and amortization).  Direct operating expenses include costs associated with the operations of our wholesale division such as labor, repairs and maintenance, rentals and leases, insurance, property taxes, and environmental compliance costs. Direct operating expenses were $48.2 million for the year ended December 31, 2010, compared to $51.8 million for the year ended December 31, 2009, a decrease of $3.6 million, or 6.9%. This decrease primarily resulted from decreases in personnel costs ($6.1 million). This decrease was partially offset by increased vehicle fuel costs ($1.8 million) and repairs and maintenance ($0.7 million).
Selling, General, and Administrative Expenses.  Selling, general, and administrative expenses consist primarily of overhead and marketing expenses. Selling, general, and administrative expenses were $12.6 million in December 31, 2010, compared to $16.6 million for the year ended December 31, 2009, a decrease of $4.0 million, or 24.1%. This decrease primarily resulted from decreases in personnel costs ($2.6 million), taxes, licenses, and fees ($0.3 million), outside services ($0.2 million), and bank fees ($0.2 million).
Goodwill Impairment Loss.  During 2009, we determined that all of the goodwill in our wholesale reporting unit was fully impaired. The total impact of the goodwill impairment for the year ended December 31, 2009 was a non-cash charge of $41.2 million. No impairment losses were recorded in 2010.
Depreciation and Amortization.  Depreciation and amortization was $5.1 million for the year ended December 31, 2010, compared to $5.6 million for the year ended December 31, 2009, a decrease of $0.5 million, or 8.9%.
Operating Income (Loss).  Operating income for the year ended December 31, 2010 was $20.7 million compared to an operating loss of $30.7 million for the year ended December 31, 2009, an increase of $51.4 million. This increase primarily resulted from a goodwill impairment loss in 2009, decreased direct operating expenses, decreased selling, general, and

50


administrative expenses, and increased fuel and lubricant margins for the year ended December 31, 2010 compared to the same period in 2009.

Retail Segment
 
Year Ended December 31,
 
2011
 
2010
 
2009
 
(In thousands, except per gallon data)
Statement of Operations Data
 

 
 

 
 

Net sales (including intersegment sales)
$
940,395

 
$
718,369

 
$
629,938

Operating costs and expenses:
 

 
 

 
 

Cost of products sold (exclusive of depreciation and amortization)
838,247

 
619,674

 
533,481

Direct operating expenses (exclusive of depreciation and amortization)
80,458

 
66,997

 
64,979

Selling, general, and administrative expenses
7,329

 
5,095

 
6,216

Goodwill impairment loss

 

 
27,610

Depreciation and amortization
9,653

 
10,245

 
9,820

Total operating costs and expenses
935,687

 
702,011

 
642,106

Operating income (loss)
$
4,708

 
$
16,358

 
$
(12,168
)
Operating Data
 

 
 

 
 

Fuel gallons sold (in thousands)
230,429

 
207,303

 
205,532

Fuel margin per gallon (1)
$
0.17

 
$
0.19

 
$
0.18

Merchandise sales
$
204,998

 
$
191,324

 
$
189,096

Merchandise margin (2)
28.0
%
 
28.5
%
 
28.4
%
Operating retail outlets at period end
209

 
150

 
149

_______________________________________
(1)
Fuel margin per gallon is a measurement calculated by dividing the difference between fuel sales and cost of fuel sales for our retail segment by the number of gallons sold. Fuel margin per gallon is a measure frequently used in the retail industry to measure operating results related to fuel sales.
(2)
Merchandise margin is a measurement calculated by dividing the difference between merchandise sales and merchandise cost of products sold by merchandise sales. Merchandise margin is a measure frequently used in the convenience store industry to measure operating results related to merchandise sales.
The following table reconciles fuel sales and cost of fuel sales to net sales and cost of products sold:

 
Year Ended December 31,
 
2011
 
2010
 
2009
 
(In thousands, except per gallon data)
Net sales:
 

 
 

 
 

Fuel sales (including intersegment sales)
$
792,502

 
$
582,688

 
$
489,033

Excise taxes included in fuel revenues
(83,255
)
 
(79,639
)
 
(71,998
)
Merchandise sales
204,998

 
191,324

 
189,096

Other sales
26,150

 
23,996

 
23,807

Net sales
$
940,395

 
$
718,369

 
$
629,938

Cost of products sold:
 

 
 

 
 

Fuel cost of products sold
$
753,487

 
$
543,916

 
$
451,485

Excise taxes included in fuel cost of products sold
(83,255
)
 
(79,639
)
 
(71,998
)
Merchandise cost of products sold
147,692

 
136,855

 
135,459

Other cost of products sold
20,323

 
18,542

 
18,535

Cost of products sold
838,247

 
619,674

 
533,481

Fuel margin per gallon
$
0.17

 
$
0.19

 
$
0.18


51


Fiscal Year Ended December 31, 2011, Compared to Fiscal Year Ended December 31, 2010
Net Sales.  Net sales consist primarily of gross sales of gasoline and diesel fuel net of excise taxes, general merchandise, and beverage and food products. Net sales for the year ended December 31, 2011 were $940.4 million, compared to $718.4 million for the year ended December 31, 2010, an increase of $222.0 million, or 30.9%. This increase was primarily due to an increase in the sales price of gasoline and diesel fuel and fuel sales volume. The new retail outlets added during 2011 contributed $81.2 million of the increase in fuel sales period over period. The average sales price per gallon, including excise taxes, increased from $2.81 in 2010 to $3.44 in 2011. Fuel sales volume increased from 207.3 million gallons in 2010 to 230.4 million gallons in 2011, of which 24.6 million gallons were due to the new retail outlets added in 2011.
Cost of Products Sold (exclusive of depreciation and amortization).  Cost of products sold includes costs of gasoline and diesel fuel net of excise taxes, general merchandise, and beverage and food products. Cost of products sold was $838.2 million for the year ended December 31, 2011, compared to $619.7 million for the year ended December 31, 2010, an increase of $218.5 million, or 35.3%. This increase was primarily due to increased costs of gasoline and diesel fuel and purchased fuel volume. Cost of products sold for the new retail outlets added in 2011 was $78.4 million of the increase in fuel cost of sales period over period. Average fuel cost per gallon, including excise taxes, increased from $2.62 in 2010 to $3.27 in 2011. Also contributing to this increase were higher merchandise cost of sales.
Direct Operating Expenses (exclusive of depreciation and amortization).  Direct operating expenses include costs associated with the operations of our retail division such as labor, repairs and maintenance, rentals and leases, insurance, property taxes, and environmental compliance costs. Direct operating expenses were $80.5 million for the year ended December 31, 2011, compared to $67.0 million for the year ended December 31, 2010, an increase of $13.5 million, or 20.1%. Direct operating expenses for the new retail outlets added during 2011was $10.9 million. This increase was primarily due to increased personnel costs ($3.7 million), bank fees primarily related to credit card sales ($3.3 million), rent expense ($2.7 million), utilities expense ($0.8 million), and operations materials and supplies expense ($0.8 million).
Selling, General, and Administrative Expenses.  Selling, general, and administrative expenses consist primarily of overhead and marketing expenses. Selling, general, and administrative expenses were $7.3 million for the year ended December 31, 2011, compared to $5.1 million for the year ended December 31, 2010, an increase of $2.2 million, or 43.1%. This increase was primarily due to increased personnel costs including the first quarter 2010 reversal of the 2009 bonus accrual, changed allocations between direct operating expenses and selling, general, and administrative expenses, and the new retail outlets added during 2011. See consolidated direct operating expenses (exclusive of depreciation and amortization) for the year ended December 31, 2011 for additional discussion of the bonus accrual reversal.
Depreciation and Amortization.  Depreciation and amortization for the year ended December 31, 2011 was $9.7 million compared to $10.2 million for the year ended December 31, 2010, a decrease of $0.5 million, or 4.9%.
Operating Income.  Operating income for the year ended December 31, 2011 was $4.7 million compared to operating income of $16.4 million for the year ended December 31, 2010, a decrease of $11.7 million. This decrease was primarily due to increased direct operating expenses and selling, general, and administrative expenses in 2011.
Fiscal Year Ended December 31, 2010, Compared to Fiscal Year Ended December 31, 2009
Net Sales.  Net sales consist primarily of gross sales of gasoline and diesel fuel net of excise taxes, general merchandise, and beverage and food products. Net sales for the year ended December 31, 2010 were $718.4 million, compared to $629.9 million for the year ended December 31, 2009, an increase of $88.5 million, or 14.0%. This increase was primarily due to an increase in the sales price of gasoline and diesel fuel. The average sales price per gallon, including excise taxes, increased from $2.38 in 2009 to $2.81 in 2010.
Cost of Products Sold (exclusive of depreciation and amortization).  Cost of products sold includes costs of gasoline and diesel fuel net of excise taxes, general merchandise, and beverage and food products. Cost of products sold was $619.7 million for the year ended December 31, 2010, compared to $533.5 million for the year ended December 31, 2009, an increase of $86.2 million, or 16.2%. This increase was primarily due to increased costs of gasoline and diesel fuel. Average fuel cost per gallon, including excise taxes, increased from $2.20 in 2009 to $2.62 in 2010.
Direct Operating Expenses (exclusive of depreciation and amortization).  Direct operating expenses include costs associated with the operations of our retail division such as labor, repairs and maintenance, rentals and leases, insurance, property taxes, and environmental compliance costs. Direct operating expenses were $67.0 million for the year ended December 31, 2010, compared to $65.0 million for the year ended December 31, 2009, an increase of $2.0 million, or 3.1%. This increase was primarily due to increased bank fees primarily related to credit card sales ($1.8 million).
Selling, General, and Administrative Expenses.  Selling, general, and administrative expenses consist primarily of overhead and marketing expenses. Selling, general, and administrative expenses were $5.1 million for the year ended

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December 31, 2010, compared to $6.2 million for the year ended December 31, 2009, a decrease of $1.1 million, or 17.7%. This decrease was primarily due to decreased personnel costs ($0.6 million), insurance expense ($0.3 million), and environmental expense ($0.2 million).
Goodwill Impairment Loss. During 2009, we determined that all of the goodwill in our retail reporting unit was fully impaired. The total impact of this impairment for the year ended December 31, 2009 was a non-cash charge of $27.6 million. No impairment losses were recorded in 2010.
Depreciation and Amortization.  Depreciation and amortization for the year ended December 31, 2010 was $10.2 million compared to $9.8 million for the year ended December 31, 2009, an increase of $0.4 million, or 4.1%.
Operating Income (Loss).  Operating income for the year ended December 31, 2010 was $16.4 million compared to an operating loss of $12.2 million for the year ended December 31, 2009, an increase of $28.6 million. This increase was primarily due to a goodwill impairment charge in 2009.

Outlook
The weak global economy over the past two years has resulted in decreased demand for refined products. The decreased demand along with narrowing differentials between light and heavy crude oil prices negatively impacted our refining margins through the first quarter of 2010 and all of 2009. Beginning in the second quarter of 2010, our refining margins in the Southwest improved somewhat due to increased demand, primarily for diesel fuel. During 2011, our refining margins continued to strengthen. This strengthening was due to a combination of factors including increased gasoline crack spreads, continued strong diesel demand, and the continued widening of the discount of WTI crude oil to Brent crude throughout most of 2011. This was a positive development for us as all of our crude oil purchases are based on pricing tied to WTI. Thus far during the first quarter of 2012, these factors appear as if they will largely remain stable, which should result in continuing strong margins. Nevertheless, our margins have shown significant volatility in recent periods and this volatility could return for any number of reasons discussed elsewhere in this Form 10-K.

Liquidity and Capital Resources
Our primary sources of liquidity are cash generated from our operating activities, existing cash balances, and borrowings under our Revolving Credit Agreement. We ended 2011 with $170.8 million of cash and cash equivalents, $220.4 million in non-current restricted cash, and $745.3 million in gross availability under the Revolving Credit Agreement, of which $344.7 million was used for outstanding letters of credit. At December 31, 2011, we had no direct borrowings under the Revolving Credit Agreement. The $220.4 million of restricted cash is considered restricted as the cash was the net proceeds we received from the sale of the Yorktown assets and a portion of the pipeline in New Mexico, of which both assets are subject to lien restrictions in our debt agreements. We have indicated to our holders of debt that we intend to use the proceeds from the sale to reinvest within our business over a 365 day period from December 29, 2011 and, if there are any remaining funds after the 365 day period, to repay the Term Loan.
We continually evaluate additional alternatives to further improve our capital structure by increasing our cash balances and/or reducing or refinancing a portion of the remaining balance on our long-term debt. These alternatives include various strategic initiatives and potential asset sales as well as potential public or private equity or debt financings. We may also prepay certain of our long-term debt. If additional funds are obtained by issuing equity securities, our existing stockholders could be diluted. We can give no assurances that we will be able to sell any of our assets or that we will be able to obtain additional financing on terms acceptable to us, or at all. In addition, our future capital expenditures and other cash requirements could be higher than we currently expect as a result of various factors described in Part I. - Item 1A. Risk Factors elsewhere in this report.

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Cash Flows
The following table sets forth our cash flows for the periods indicated:
 
Year Ended December 31,
 
2011
 
2010
 
2009
 
(In thousands)
Cash flows provided by operating activities
$
508,200

 
$
134,456

 
$
140,841

Cash flows used in investing activities
(72,194
)
 
(73,777
)
 
(115,361
)
Cash flows used in financing activities
(325,089
)
 
(75,657
)
 
(30,407
)
Net increase (decrease) in cash and cash equivalents
$
110,917

 
$
(14,978
)
 
$
(4,927
)
Cash Flows Provided By Operating Activities
Net cash provided by operating activities for the year ended December 31, 2011 was $508.2 million compared to $134.5 million for the year ended December 31, 2010. The increase in net cash from operating activities was due in part to our period increase in net income ($149.7 million) and period increases in adjustments to net income for non-cash items including increased losses on disposal of assets ($434.1 million), loss on extinguishment of debt ($34.3 million), and increased amortization of original issue discount ($2.4 million). These increases to cash from operating activities were substantially offset by increased period uses of cash from our operating assets and liabilities ($29.2 million) and decreased deferred income taxes ($35.4 million).
Net cash provided by operating activities for the year ended December 31, 2010 was $134.5 million, compared to $140.8 million for the year ended December 31, 2009. The decrease in net cash from operating activities was primarily due to period decreases in adjustments to net losses for non-cash items such as goodwill impairments and other losses on disposal of assets ($339.3 million), decreased deferred income taxes ($26.2 million), and decreased write-off of unamortized loan fees ($9.0 million). These decreases to cash from operating activities were partially offset by our period decrease in net loss ($333.6 million) and decreased cash used in our operating assets and liabilities ($32.3 million).
Cash Flows Used In Investing Activities
Net cash used in investing activities for the year ended December 31, 2011 was $72.2 million, compared to $73.8 million in net cash used for the year ended December 31, 2010. The decrease in net cash used in investing activities was due to our period increase in proceeds provided from the sale of assets ($227.7 million). This decrease in cash used was substantially offset by a period increase in cash restrictions ($220.4 million) and an increase in our capital expenditures ($5.7 million).
Net cash used in investing activities for the year ended December 31, 2010 was $73.8 million, compared to $115.4 million for the year ended December 31, 2009. The decrease in net cash used by investing activities was due to a period decrease in our capital expenditures ($37.8 million) and our period increase in proceeds from the sale of assets ($3.8 million).
Cash Flows Used In Financing Activities
Net cash used in financing activities for the year ended December 31, 2011 was $325.1 million, compared to $75.7 million for the year ended December 31, 2010. The change between periods was driven by payments made on long-term debt and capital lease obligations during the year ended December 31, 2011 ($302.5 million) versus payments made on long-term debt during the same period in 2010 ($13.0 million), a payment on our financing arrangement in 2011 ($10.6 million), and excess tax benefit from stock-based compensation during 2011 ($3.3 million). The increase in cash used in investing was partially offset by net borrowing decreases under our Revolving Credit Agreement during 2010 ($50.0 million), proceeds from a financing arrangement in 2011 ($12.3 million), and decreased deferred financing costs ($5.4 million).
Net cash used in financing activities for the year ended December 31, 2010 was $75.7 million, compared to $30.4 million for the year ended December 31, 2009. The change between periods was primarily driven by net proceeds received in 2009 from the issuance of our Senior Secured Notes ($538.2 million), our Convertible Senior Notes ($209.0 million), and common stock ($170.4 million) along with net borrowing increases under our Revolving Credit agreement ($40.0 million) and increased deferred financing costs ($0.9 million). The increase in cash used in financing activities was generally the difference in principal payments on our Term Loan during the year ended December 31, 2010 ($13.0 million) versus payment made on our Term Loan during the same period in 2009 ($925.7 million) along with repurchases of common stock to cover payroll withholding taxes for certain employees in connection with the vesting of restricted shares awarded under the Western Refining Long-Term Incentive Plan in 2009 ($0.6 million).

54


Working Capital
Working capital at December 31, 2011 was $545.0 million, consisting of $1,210.7 million in current assets and $665.7 million in current liabilities. Working capital at December 31, 2010 was $272.8 million consisting of $825.7 million in current assets and $553.0 million in current liabilities.
Indebtedness
Senior Secured Notes.  In June 2009, we issued two tranches of Senior Secured Notes under an indenture dated June 12, 2009. The first tranche consisted of $325.0 million in aggregate principal amount of 11.25% Senior Secured Notes (the “Fixed Rate Notes”). The second tranche consisted of $275.0 million Senior Secured Floating Rate Notes (the “Floating Rate Notes,” and together with the Fixed Rate Notes, the “Senior Secured Notes”). The Fixed Rate Notes pay interest semi-annually in cash in arrears on June 15 and December 15 of each year at a rate of 11.25% per annum and will mature on June 15, 2017. We may redeem the Fixed Rate Notes at our option beginning on June 15, 2013 through June 14, 2014 at a premium of 5.625%; from June 15, 2014 through June 14, 2015 at a premium of 2.813%; and at par thereafter.

On December 21, 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%.
We amortize original issue discounts using the effective interest rate method over the life of the notes. We used the combined proceeds from the issuance and sale of the Senior Secured Notes to repay a portion of the outstanding term loan indebtedness. Proceeds from the issuance of the Fixed Rate Notes were $290.7 million, net of an original issue discount of $27.8 million and underwriting discounts of $6.5 million. Proceeds from the issuance of the Floating Rate Notes were $247.5 million, net of original issue discount of $22.0 million and underwriting discounts of $5.5 million. We paid $2.1 million in other financing costs related to the Senior Secured Notes in 2009.
The Fixed Rate Notes are guaranteed by all of our domestic restricted subsidiaries in existence on the date the Fixed Rate Notes were issued. The Fixed Rate Notes will also be guaranteed by all future wholly-owned domestic restricted subsidiaries and by any restricted subsidiary that guarantees any of our indebtedness under credit facilities that are secured by a lien on the collateral securing the Fixed Rate Notes. The Fixed Rate Notes are also secured on a first priority basis, equally and ratably with our Term Loan (as defined below) and any future other pari passu secured obligation, by the collateral securing the Term Loan, which consists of our fixed assets, and on a second priority basis, equally and ratably with the Term Loan and any future other pari passu secured obligation, by the collateral securing the Revolving Credit Agreement, which consists of our cash and cash equivalents, trade accounts receivables, and inventory.
The indenture governing the Fixed Rate Notes contains covenants that limit our (and most of our subsidiaries’) ability to, among other things: (i) pay dividends or make other distributions in respect of our capital stock or make other restricted payments; (ii) make certain investments; (iii) sell certain assets; (iv) incur additional debt or issue certain preferred shares; (v) create liens on certain assets to secure debt; (vi) consolidate, merge, sell or otherwise dispose of all or substantially all of our assets; (vii) restrict dividends or other payments from restricted subsidiaries; and (viii) enter into certain transactions with our affiliates. These covenants are subject to a number of important limitations and exceptions. The indenture governing the Fixed Rate Notes also provides for events of default, which, if any of them occur, would permit or require the principal, premium, if any, and interest on all then outstanding Fixed Rate Notes to be due and payable immediately.
Convertible Senior Notes.  We issued and sold $215.5 million in aggregate principal amount of our 5.75% Senior Convertible Notes due 2014 (the “Convertible Senior Notes”) during June and July 2009. The Convertible Senior Notes are unsecured and pay interest semi-annually in arrears at a rate of 5.75% per year beginning on December 15, 2009. The Convertible Senior Notes will mature on June 15, 2014. The initial conversion rate for the Convertible Senior Notes is 92.5926 shares of common stock per $1,000 principal amount of Convertible Senior Notes (equivalent to an initial conversion price of approximately $10.80 per share of common stock). In lieu of delivery of shares of common stock in satisfaction of our obligation upon conversion of the Convertible Senior Notes, we may elect to settle conversions entirely in cash or by net share settlement. Proceeds from the issuance of the Convertible Senior Notes of $209.0 million, net of underwriting discounts of $6.5 million, were used to repay a portion of outstanding term loan indebtedness. Issuers of convertible debt instruments that may be settled in cash upon conversion (including partial cash settlement) are required to separately account for the liability and equity (conversion feature) components of the instruments in a manner reflective of the issuer’s nonconvertible debt borrowing rate. The borrowing rate that we used to determine the liability and equity components of the Convertible Senior Notes was 13.75%. We paid $0.5 million in other financing costs related to the Convertible Senior Notes. We valued the conversion feature at June 30, 2009 at $60.9 million and recorded additional paid-in capital of $36.3 million, net of deferred income taxes of $22.6 million and transaction costs of $2.0 million, related to the equity portion of this convertible debt in 2009. The discount on the Convertible Senior Notes is amortized using the effective interest method through maturity on

55


June 15, 2014. As of December 31, 2011, the if-converted value of the Convertible Senior Notes exceeded its principle amount by $49.7 million.
The Convertible Senior Notes will be convertible in any future calendar quarter (prior to maturity) whenever the last reported sale price of the Company’s common stock exceeds $14.04 for twenty days in the thirty consecutive trading day period ending on the last trading day of the immediately preceding calendar quarter. If any Convertible Senior Notes are surrendered for conversion, the Company may elect to satisfy its obligations upon conversion through the delivery of shares of its common stock, in cash, or a combination thereof.
Term Loan Credit Agreement.  On March 29, 2011, we entered into an amended and restated Term Loan Credit Agreement. Lenders under the amended and restated Term Loan Credit Agreement extended a $325.0 million term loan ("Term Loan") at a discount of 1.00%, the proceeds of which were principally used to refinance the term loans outstanding under the Term Loan Credit Agreement prior to the amendment and restatement. The Term Loan, together with the Fixed Rate Notes and any future other pari passu secured obligations, is secured on a first priority basis by our fixed assets, and on a second priority basis by the collateral securing the Revolving Credit Agreement, which consists of our cash and cash equivalents, trade accounts receivable, and inventory. The amended and restated Term Loan Credit Agreement eliminated the financial maintenance covenants previously contained in the Term Loan Credit Agreement. The amended and restated Term Loan Credit Agreement provides for principal payments on a quarterly basis of $0.8 million, with the remaining balance due on the maturity date. The maturity date was extended to March 15, 2017. To effect this amendment and restatement, we paid $3.7 million in amendment fees.
As a result of the March 29, 2011 amendment and restatement, the Term Loan bears interest equal to LIBOR (subject to a floor of 1.5%) plus 6.00%. Prior to the amendment and restatement, the term loan bore interest equal to LIBOR (subject to a floor of 3.25%) plus 7.50%.

The amended and restated Term Loan Credit Agreement contains covenants that limit our (and most of our subsidiaries') ability to among other things: (i) pay dividends or make other distributions in respect of our capital stock or make other restricted payments; (ii) make certain investments; (iii) sell certain assets; (iv) incur additional debt; (v) create liens on certain assets; (vi) consolidate, merge or sell other otherwise dispose of all or substantially all of our assets; (vii) engaging in different businesses; (viii) enter into certain transactions with our affiliates; (ix) restrict dividends or other payments from restricted subsidiaries; and (x) prepay certain indebtedness.
On September 23, 2011, we amended the amended and restated Term Loan Credit Agreement to provide for certain conforming changes made in the amended and restated Revolving Credit Agreement (described below).
Revolving Credit Agreement.  On September 22, 2011, we entered into an amended and restated Revolving Credit Agreement. Lenders under the amended and restated Revolving Credit Agreement extended $1.0 billion in revolving commitments that mature on September 22, 2016, and incorporate a borrowing base tied to eligible accounts receivable and inventory. The amended and restated Revolving Credit Agreement also provides for letters of credit and swing line loans. The amended and restated Revolving Credit Agreement provides for a quarterly commitment fee of either 0.375% or 0.50% per annum subject to adjustment based upon the average excess availability under the amended and restated Revolving Credit Agreement and quarterly letter of credit fees ranging from 2.50% to 3.25% per annum subject to adjustment based upon the average excess availability. Borrowings can be either base rate loans plus a margin ranging from 1.50% to 2.25% or LIBOR loans plus a margin ranging from 2.50% to 3.25% in each case subject to adjustment based upon the average excess availability under the amended and restated Revolving Credit Agreement. The interest rate margins and letter of credit fees are to be reduced by 0.25% upon our achievement and maintenance of a certain fixed charge coverage ratio. The amended and restated Revolving Credit Agreement provides for a cash dominion requirement that is in effect only if there is an event of default or the excess availability under the amended and restated Revolving Credit Agreement falls below the greater of (i)15.0% of the Borrowing Base and (ii) $50.0 million. The amended and restated Revolving Credit Agreement is secured on a first priority basis by our cash and cash equivalents, trade accounts receivable, and inventory, and on a second priority basis by the collateral securing the Term Loan, the Fixed Rate Notes, and any future other pari passu secured obligations, which consist of our fixed assets. The revolving facility is used to fund general working capital needs and letter of credit requirements. We paid $5.9 million in fees to effect the September 22, 2011 amendment and restatement to the Revolving Credit Agreement.
Prior to September 22, 2011 the Revolving Credit Agreement included commitments of $800.0 million composed of a $145.0 million tranche that matured on May 31, 2012 and $655.0 million tranche that matured on January 1, 2015. Interest rates for the $145.0 million tranche were based on our consolidated leverage ratio and ranged from 3.75% to 4.50% over LIBOR. Interest rates for the $655.0 million tranche were based on our borrowing base capacity under the Revolving Credit Agreement and ranged from 3.00% to 3.75% over LIBOR.


56


The amended and restated Revolving Credit Agreement contains covenants that limit our (and most of our subsidiaries') ability to, among other things: (i) pay dividends or make other distributions in respect of our capital stock or make other restricted payments; (ii) make certain investments; (iii) sell certain assets; (iv) incur additional debt; (v) create liens on certain assets; (vi) consolidate, merge, sell or otherwise dispose of all or substantially all of our assets; (vii) engage in different businesses; (viii) enter into certain transactions with our affiliates; (ix) restrict dividends or other payments from restricted subsidiaries; and (x) prepay certain indebtedness.
As of December 31, 2011, the Company had gross availability under the amended and restated Revolving Credit Agreement of $745.3 million, of which $344.7 million was used for outstanding letters of credit.
Guarantors of the Term Loan and the Revolving Credit Agreement.  The amended and restated Term Loan Credit Agreement and the amended and restated Revolving Credit Agreement (together, the “Agreements”) are guaranteed, on a joint and several basis, by subsidiaries of Western Refining, Inc. No amounts have been recorded for these guarantees.
Letters of Credit
The Revolving Credit Agreement provides for the issuance of letters of credit. The Company issues and cancels letters of credit on a periodic basis depending upon its needs. At December 31, 2011, there were $344.7 million of irrevocable letters of credit outstanding, primarily issued to crude oil suppliers under the Revolving Credit Agreement.
Capital Spending
Capital expenditures totaled $83.8 million for the year ended December 31, 2011, and included improvement and regulatory projects for our refining group and several smaller projects for our wholesale group, our retail group, and our corporate group. Capital expenditures included $2.0 million of capitalized interest for 2011.
Our capital expenditure budget for 2012 is $162.1 million, of which $146.5 million is for our refining group, $4.3 million is for our wholesale group, $7.9 million is for our retail group, and $3.4 million is for other general projects. The following table summarizes the spending allocation between sustaining, discretionary, and regulatory projects for 2012:

 
2012
 
(In thousands)
Sustaining
$
24,620

Discretionary
65,360

Regulatory
72,110

Total
$
162,090

Sustaining Projects.  Sustaining maintenance capital expenditures are those related to minor replacement of assets, refurbishing and replacement of components, fire protection, process safety management, and other recurring and safety related capital expenditures.
Discretionary Projects.  Discretionary project capital expenditures are those driven primarily by the economic returns that such projects can generate for us. Our discretionary projects include crude oil logistics projects and preliminary work on a potential crude unit expansion at our El Paso refinery.
Regulatory Projects.  Regulatory projects are undertaken to comply with various regulatory requirements, including those related to environmental, health, and safety matters. Our low sulfur fuel and low benzene gasoline projects are regulatory investments driven primarily by fuels regulations. We completed our capital projects to comply with the EPA’s low sulfur gasoline regulations during 2009. The deadline for compliance with the final phase of the ultra low sulfur diesel regulations to reduce sulfur in locomotive and marine diesel is June 2012 and affects our El Paso refinery only. EPA regulations allow the one-time use of credits to extend the June 2012 deadline by up to 24 months. 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 during 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. We anticipate approximately $2.0 million in capital expenditures by the end of 2012 for our Gallup refinery to meet the 1.30 volume percent requirement.

57


Based on current information, we estimate the total remaining capital expenditures necessary to address the EPA Initiative issues at El Paso would be approximately $11.9 million for NOx emission controls on heaters and boilers and will occur from 2012 through 2013. Based on current information and the 2009 NMED Amendment, and favorably negotiating a revision to reflect the indefinite suspension of refining operations at our Bloomfield facility and to delay NOx controls on heaters, boilers, and the FCCU at the Gallup refinery, we estimate the total remaining capital expenditures that may be required pursuant to the 2009 NMED Amendment to address the EPA Initiative issues at Gallup would be $36.7 million and will occur in 2012 and 2013. These capital expenditures will primarily be for installation of NOx emission controls on heaters and boilers at our El Paso and Gallup refineries and installation of particulate matter controls on our Gallup FCCU. Pursuant to the 2010 modified settlement with the EPA, our Gallup refinery is required to upgrade its wastewater treatment plant by May 31, 2012. Total cost of this project is currently estimated to be $33.7 million. Through the end of 2011, we expended $20.8 million on this project and expect to incur an additional $12.9 million in 2012. See Item 1. Business — Governmental Regulation.
The actual capital expenditures for the regulatory projects described above for the past three years are summarized in the table below:

 
2011
 
2010
 
2009
 
(In millions)
EPA Initiative projects
$
11

 
$

 
$

MSAT II gasoline
2

 
43

 
20

Wastewater Treatment Plant
17

 
4

 

Total
$
30

 
$
47

 
$
20


The estimated capital expenditures for the regulatory projects described above and for other regulatory requirements for the next three years are summarized in the table below:

 
2012
 
2013
 
2014
 
(In millions)
EPA Initiative projects
$
46

 
$
3

 
$

MSAT II gasoline
2

 

 

Wastewater Treatment Plant
13

 

 

Ultra low sulfur locomotive diesel
5

 

 

Various other projects
6

 
40

 
28

Total
$
72

 
$
43

 
$
28


Contractual Obligations and Commercial Commitments
Information regarding our contractual obligations of the types described below as of December 31, 2011, is set forth in the following table:
 
Payments Due by Period
Contractual Obligations
Totals
 
2012
 
2013 and 2014
 
2015 and 2016
 
2017 and Beyond
 
(In thousands)
Long-term debt obligations (1)
$
1,216,857

 
$
76,303

 
$
360,615

 
$
126,124

 
$
653,815

Capital lease obligations
8,259

 
270

 
707

 
735

 
6,547

Operating lease obligations
256,108

 
22,042

 
38,202

 
30,872

 
164,992

Purchase obligations (2)
4,664,026

 
679,688

 
1,138,382

 
1,138,382

 
1,707,574

Environmental reserves (3)
7,033

 
2,448

 
804

 
771

 
3,010

Other obligations (4)(5)
265,799

 
18,993

 
33,480

 
32,949

 
180,377

Total obligations (6)
$
6,418,082

 
$
799,744

 
$
1,572,190

 
$
1,329,833

 
$
2,716,315

_______________________________________
(1)
Includes minimum principal payments and interest calculated using interest rates at December 31, 2011.

58


(2)
Purchase obligations include agreements to buy crude oil and other raw materials. Amounts included in the table were calculated using the pricing at December 31, 2011, multiplied by the contract volumes.
(3)
As of December 31, 2011, the discounted environmental reserve related to these liabilities totaled $4.3 million. Our environmental liabilities are discussed in Note 11, Accrued and Other Long-Term Liabilities, in the Notes to Consolidated Financial Statements elsewhere in this annual report.
(4)
Other commitments include agreements for sulfuric acid regeneration and sulfur gas processing, throughput and distribution, storage services, barges, and professional consulting. The minimum payment commitments are included in the table.
(5)
We are obligated to make future expenditures related to our pension and postretirement obligations. These payments are not fixed and cannot be reasonably determined beyond 2018. As a result, our obligations beyond 2018 related to these plans are not included in the table. Our pension and postretirement obligations are discussed in Note 15, Retirement Plans, in the Notes to Consolidated Financial Statements elsewhere in this annual report.
(6)
As of December 31, 2011, we have no uncertain tax positions or related liabilities recorded.
Dividends
On February 13, 2012, we paid a dividend of $0.04 per share. We anticipate future quarterly dividends, subject to the Board of Director's approval and compliance with our outstanding financing agreements.
Off-Balance Sheet Arrangements
We have no off-balance sheet arrangements.

Item 7A.
Quantitative and Qualitative Disclosure About Market Risk
Changes in commodity prices and interest rates are our primary sources of market risk.
Commodity Price Risk
We are exposed to market risks related to the volatility of crude oil and refined product prices, as well as volatility in the price of natural gas used in our refinery operations. Our financial results can be affected significantly by fluctuations in these prices, which depend on many factors, including demand for crude oil, gasoline and other refined products; changes in the economy; worldwide production levels; worldwide inventory levels; and governmental regulatory initiatives. Our risk management strategy identifies circumstances in which we may utilize the commodity futures market to manage risk associated with these price fluctuations or to fix sales margins on future gasoline and distillate production.
In order to manage the uncertainty relating to inventory price volatility, we have generally applied a policy of maintaining inventories at or below a targeted operating level. In the past, circumstances have occurred, such as turnaround schedules or shifts in market demand, that have resulted in variances between our actual inventory level and our desired target level. We may utilize the commodity futures market to manage these anticipated inventory variances.
We maintain inventories of crude oil, other feedstocks and blendstocks, and refined products, the values of which are subject to wide fluctuations in market prices driven by worldwide economic conditions, regional and global inventory levels, and seasonal conditions. At December 31, 2011, we held approximately 5.2 million barrels of crude oil, refined product, and other inventories valued under the LIFO valuation method with an average cost of $58.32 per barrel. At December 31, 2011, the excess of the current cost of our crude oil, refined product, and other feedstock and blendstock inventories over aggregated LIFO costs was $213.7 million. At December 31, 2010, we held approximately 5.7 million barrels of crude oil, refined product, and other inventories valued under the LIFO valuation method with an average cost of $58.39 per barrel. At December 31, 2010, the excess of the current cost of our crude oil, refined product, and other feedstock and blendstock inventories over aggregated LIFO costs was $173.5 million.
All commodity futures contracts, price swaps, and options are recorded at fair value and any changes in fair value between periods are recorded under cost of products sold in our Consolidated Statements of Operations.
We selectively utilize commodity hedging instruments to manage our price exposure to our LIFO inventory positions or to fix margins on certain future sales volumes. The commodity hedging instruments may take the form of futures contracts, price and crack spread swaps, or options and are entered into with counterparties that we believe to be creditworthy. We elected not to pursue hedge accounting treatment for financial accounting purposes on instruments used to manage price exposure to inventory positions. The financial instruments used to fix margins on future sales volumes do not qualify for hedge accounting.

59


Therefore, changes in the fair value of these hedging instruments are included in income in the period of change. Net gains or losses associated with these transactions are reflected within cost of products sold at the end of each period.
We had $107.3 million in net commodity hedging gains, consisting of $74.8 million in realized losses and $182.1 million in unrealized gains, settled or accounted for using mark-to-market accounting for the year ended December 31, 2011. We had $9.4 million in net commodity hedging losses, consisting of $8.2 million in realized losses and $1.2 million in unrealized losses, settled or accounted for using mark-to-market accounting for the year ended December 31, 2010. We had $21.7 million in net commodity hedging losses, consisting of $20.2 million in realized losses and $1.5 million in unrealized losses, settled or accounted for using mark-to-market accounting for the year ended December 31, 2009.
At December 31, 2011, we had open commodity hedging instruments consisting of crude oil futures on 933,000 barrels and refined products price and crack spread swaps on 29,282,500 barrels 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. The fair value of the outstanding contracts at December 31, 2011 was a net unrealized gain of $182.1 million comprised of both short-term and long-term unrealized gains and losses. This net unrealized gain consists of $129.5 million in other current assets, $54.2 million in other assets, and $1.6 million in current liabilities. A change of 10% in future crack spread swaps and inventory positions would result in an increase or decrease in the related fair values of the commodity hedging instruments of $18.2 million. At December 31, 2010, we had open commodity hedging instruments consisting of crude oil futures and refined products price and crack spread swaps on 1,023,000 barrels 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. The fair value of the outstanding contracts at December 31, 2010 was a net unrealized loss of $1.2 million comprised of short-term unrealized gains and losses. At December 31, 2009, we had open commodity hedging instruments consisting of crude oil futures and refined products price and crack spread swaps on 268,000 barrels 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. The fair value of the outstanding contracts at December 31, 2009 was a net unrealized loss of $1.5 million comprised of short-term unrealized gains and losses.
During the three years ended December 31, 2011, we did not have any commodity derivative instruments that were designated or accounted for as hedges.
Interest Rate Risk
As of December 31, 2011, $322.6 million of our outstanding debt, excluding unamortized discount, was at floating interest rates based on LIBOR and prime rates. An increase in these base rates of 1% would increase our interest expense by $3.2 million per year.


60


Management’s Report on Internal Control Over Financial Reporting
The Company’s management is responsible for establishing and maintaining adequate internal control over financial reporting. Internal control over financial reporting is defined in Rule 13a-15(f) or 15d-15(f) promulgated under the Securities Exchange Act of 1934 as a process designed by, or under the supervision of, the Company’s principal executive and principal financial officers and effected by the Company’s board of directors, management, and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles and includes those policies and procedures that:
Pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of the assets of the Company;
Provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and the receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and
Provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the Company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
The Company’s management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2011. In making this assessment, the Company’s management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) in Internal Control-Integrated Framework. Based on its assessment, the Company’s management believes that, as of December 31, 2011, the Company’s internal control over financial reporting is effective based on those criteria.
The Company’s independent registered public accounting firm, Deloitte & Touche LLP, has issued an audit report on the Company’s internal control over financial reporting. This report appears on page 62 of this annual report.

61


Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders of
Western Refining, Inc.
El Paso, Texas
We have audited the internal control over financial reporting of Western Refining, Inc. and subsidiaries (the "Company")as of December 31, 2011, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying “Management's Report on Internal Control Over Financial Reporting.” Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2011, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended December 31, 2011 of the Company and our report dated February 29, 2012 expressed an unqualified opinion on those financial statements.
/s/ Deloitte & Touche LLP
Phoenix, AZ
February 29, 2012



62


Item 8.
Financial Statements and Supplementary Data
INDEX TO FINANCIAL STATEMENTS


63


Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders of
Western Refining, Inc.
El Paso, Texas
We have audited the accompanying consolidated balance sheets of Western Refining, Inc. and subsidiaries (the “Company”) as of December 31, 2011 and 2010, and the related consolidated statements of operations, comprehensive income (loss), changes in stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2011. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the consolidated financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Western Refining, Inc. and subsidiaries at December 31, 2011 and 2010, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2011, in conformity with accounting principles generally accepted in the United States of America.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated February 29, 2012 expressed an unqualified opinion on the Company’s internal control over financial reporting.

/s/ Deloitte & Touche LLP
Phoenix, AZ
February 29, 2012


64


WESTERN REFINING, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(In thousands, except share data)

 
As of December 31,
 
2011
 
2010
ASSETS
 
 
 
Current assets:
 

 
 

Cash and cash equivalents
$
170,829

 
$
59,912

Accounts receivable, trade, net of a reserve for doubtful accounts of $1,884 and $3,896, respectively
275,478

 
269,596

Inventories
405,754

 
365,673

Prepaid expenses
163,530

 
73,391

Other current assets
195,064

 
57,131

Total current assets
1,210,655

 
825,703

Restricted cash
220,355

 

Property, plant, and equipment, net
995,316

 
1,688,154

Intangible assets, net
44,352

 
59,945

Other assets, net
99,666

 
54,344

Total assets
$
2,570,344

 
$
2,628,146

LIABILITIES AND STOCKHOLDERS’ EQUITY
 
 
 
Current liabilities:
 

 
 

Accounts payable
$
384,523

 
$
294,662

Accrued liabilities
172,001

 
136,362

Deferred income tax liability, net
105,555

 
58,929

Current portion of long-term debt
3,595

 
63,000

Total current liabilities
665,674

 
552,953

Long-term liabilities:
 

 
 

Long-term debt, less current portion
800,395

 
1,006,531

Deferred income tax liability, net
262,492

 
361,292

Other liabilities
21,955

 
31,777

Total long-term liabilities
1,084,842

 
1,399,600

Commitments and contingencies (Note 21)


 


Stockholders’ equity:
 

 
 

Common stock, par value $0.01, 240,000,000 shares authorized; 90,001,537 and 89,025,010 shares issued, respectively
900

 
890

Preferred stock, par value $0.01, 10,000,000 shares authorized; no shares issued and outstanding

 

Additional paid-in capital
599,645

 
588,215

Retained earnings
242,538

 
109,871

Accumulated other comprehensive loss, net of tax
(1,812
)
 
(1,940
)
Treasury stock, 698,006 shares at cost
(21,443
)
 
(21,443
)
Total stockholders’ equity
819,828

 
675,593

Total liabilities and stockholders’ equity
$
2,570,344

 
$
2,628,146


The accompanying notes are an integral part of these consolidated financial statements.


65


WESTERN REFINING, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per share data)

 
Year Ended December 31,
 
2011
 
2010
 
2009
Net sales
$
9,071,037

 
$
7,965,053

 
$
6,807,368

Operating costs and expenses:
 

 
 

 
 

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

 
7,155,967

 
5,944,128

Direct operating expenses (exclusive of depreciation and amortization)
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
)
Other income (expense):
 

 
 

 
 

Interest income
510

 
441

 
248

Interest expense and other financing costs
(134,601
)
 
(146,549
)
 
(121,321
)
Amortization of loan fees
(8,926
)
 
(9,739
)
 
(6,870
)
Write-off of unamortized loan fees

 

 
(9,047
)
Loss on extinguishment of debt
(34,336
)
 

 

Other, net
(3,898
)
 
7,286

 
(15,184
)
Income (loss) before income taxes
202,528

 
(43,126
)
 
(391,204
)
Provision for income taxes
(69,861
)
 
26,077

 
40,583

Net income (loss)
$
132,667

 
$
(17,049
)
 
$
(350,621
)
Net earnings (loss) per share:
 

 
 

 
 

Basic
$
1.46

 
$
(0.19
)
 
$
(4.43
)
Diluted
$
1.34

 
$
(0.19
)
 
$
(4.43
)
Weighted average common shares outstanding:
 

 
 

 
 

Basic
88,981

 
88,204

 
79,163

Diluted
109,792

 
88,204

 
79,163


The accompanying notes are an integral part of these consolidated financial statements.

66


WESTERN REFINING, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN
STOCKHOLDERS’ EQUITY
(In thousands, except share data)

 
 
 
 
 
 
 
 
 
Accumulated
 
 
 
 
 
 
 
Common Stock
 
 
 
Other
 
 
 
 
 
 
 
 
 
 
 
Additional
 
 
 
Comprehensive
 
 
 
 
 
 
 
Shares
 
Par
 
Paid-In
 
Retained
 
Loss,
 
Treasury Stock
 
 
 
Issued
 
Value
 
Capital
 
Earnings
 
Net of Tax
 
Shares
 
Cost
 
Total
Balance at December 31, 2008
68,426,994

 
$
684

 
$
373,118

 
$
477,537

 
$
(19,006
)
 
(646.903
)
 
$
(20,844
)
 
$
811,489

Public offering of common stock
20,000,000

 
200

 
170,242

 

 

 

 

 
170,442

Equity component of convertible notes issuance

 

 
36,281

 

 

 

 

 
36,281

Stock-based compensation

 

 
4,697

 
4

 

 

 

 
4,701

Restricted stock vesting
261,723

 
3

 
(3
)
 

 

 

 

 

Tax deficiency from stock-based compensation

 

 
(877
)
 

 

 

 

 
(877
)
Net loss

 

 

 
(350,621
)
 

 

 

 
(350,621
)
Other comprehensive loss, net of tax benefit of $10,373

 

 

 

 
17,636

 

 

 
17,636

Treasury stock, at cost

 

 

 

 

 
(51.103
)
 
(599
)
 
(599
)
Balance at December 31, 2009
88,688,717

 
887

 
583,458

 
126,920

 
(1,370
)
 
(698.006
)
 
(21,443
)
 
688,452

Stock-based compensation

 

 
5,857

 

 

 

 

 
5,857

Restricted stock vesting
336,293

 
3

 
(3
)
 

 

 

 

 

Tax deficiency from stock-based compensation

 

 
(1,097
)
 

 

 

 

 
(1,097
)
Net loss

 

 

 
(17,049
)
 

 

 

 
(17,049
)
Other comprehensive loss, net of tax benefit of $395

 

 

 

 
(570
)
 

 

 
(570
)
Balance at December 31, 2010
89,025,010

 
890

 
588,215

 
109,871

 
(1,940
)
 
(698.006
)
 
(21,443
)
 
675,593

Stock-based compensation

 

 
8,173

 

 

 

 

 
8,173

Restricted stock vesting
976,527

 
10

 
(10
)
 

 

 

 

 

Excess tax benefit from stock-based compensation

 

 
3,267

 

 

 

 

 
3,267

Net income

 

 

 
132,667

 

 

 

 
132,667

Other comprehensive loss, net of tax of $202

 

 

 

 
128

 

 

 
128

Balance at December 31, 2011
90,001,537

 
$
900

 
$
599,645

 
$
242,538

 
$
(1,812
)
 
(698.006
)
 
$
(21,443
)
 
$
819,828


The accompanying notes are an integral part of these consolidated financial statements.


67


WESTERN REFINING, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)

 
Year Ended December 31,
 
2011
 
2010
 
2009
Cash flows from operating activities:
 

 
 

 
 

Net income (loss)
$
132,667

 
$
(17,049
)
 
$
(350,621
)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
 

 
 

 
 

Goodwill impairment loss

 

 
299,552

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

 
13,038

 
52,788

Depreciation and amortization
135,895

 
138,621

 
145,981

Commodity hedging instrument mark-to-market (increase) decrease
(182,113
)
 
1,173

 
1,510

Reserve for doubtful accounts
2,306

 
3,260

 
6,119

Amortization of loan fees
8,926

 
9,739

 
6,870

Amortization of original issue discount
18,271

 
15,867

 
7,091

Loss on extinguishment of debt
34,336

 

 

Write-off of unamortized loan fees

 

 
9,047

Stock-based compensation expense
8,173

 
5,857

 
4,701

Deferred income taxes
(52,174
)
 
(16,778
)
 
9,410

Excess tax benefit from stock-based compensation
3,267

 

 

Changes in operating assets and liabilities:
 

 
 

 
 

Accounts receivable
(8,188
)
 
50,402

 
(128,403
)
Inventories
(40,081
)
 
57,080

 
2,784

Prepaid expenses
(90,139
)
 
(42,719
)
 
24,281

Other assets
(22,421
)
 
39,972

 
(41,896
)
Accounts payable
89,863

 
(98,190
)
 
97,668

Accrued liabilities
30,122

 
1,539

 
(5,779
)
Other non-current liabilities
(7,676
)
 
(27,356
)
 
(262
)
Net cash provided by operating activities
508,200

 
134,456

 
140,841

Cash flows from investing activities:
 

 
 

 
 

Capital expenditures
(83,809
)
 
(78,095
)
 
(115,854
)
Proceeds from the sale of assets
231,970

 
4,318

 
493

Increase in restricted cash
(220,355
)
 

 

Net cash used in investing activities
(72,194
)
 
(73,777
)
 
(115,361
)
Cash flows from financing activities:
 

 
 

 
 

Additions to long-term debt

 

 
747,183

Payments on long-term debt
(302,524
)
 
(13,000
)
 
(925,693
)
Prepayment fee on early retirement of long-term debt
(13,750
)
 

 

Common stock offering

 

 
170,442

Revolving credit facility, net

 
(50,000
)
 
(10,000
)
Deferred financing costs
(7,281
)
 
(12,657
)
 
(11,740
)
Proceeds from financing arrangement
12,322

 

 

Payment on financing arrangement
(10,589
)
 

 

Repurchases of common stock

 

 
(599
)
Excess tax benefit from stock-based compensation
(3,267
)
 

 

Net cash used in financing activities
(325,089
)
 
(75,657
)
 
(30,407
)
Net increase (decrease) in cash and cash equivalents
110,917

 
(14,978
)
 
(4,927
)
Cash and cash equivalents at beginning of year
59,912

 
74,890

 
79,817

Cash and cash equivalents at end of year
$
170,829

 
$
59,912

 
$
74,890

Supplemental disclosures of cash flow information:
 

 
 

 
 

Income taxes paid (refunded)
$
70,171

 
$
(49,827
)
 
$
(7,201
)
Interest paid, excluding amounts capitalized
121,282

 
135,063

 
129,812

The accompanying notes are an integral part of these consolidated financial statements.

68


WESTERN REFINING, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(In thousands)

 
Year Ended December 31,
 
2011
 
2010
 
2009
Net income (loss)
$
132,667

 
$
(17,049
)
 
$
(350,621
)
Other comprehensive income (loss) items:
 

 
 

 
 

Benefit plans:
 

 
 

 
 

Reclassification of (gain) loss to income
4

 
(15
)
 
145

Pension plan termination adjustment
1,537

 
3,322

 
25,071

Actuarial gain (loss)
(1,211
)
 
(4,272
)
 
2,793

Other comprehensive income (loss) before tax
330

 
(965
)
 
28,009

Income tax
(202
)
 
395

 
(10,373
)
Other comprehensive income (loss), net of tax
128

 
(570
)
 
17,636

Comprehensive income (loss)
$
132,795

 
$
(17,619
)
 
$
(332,985
)

The accompanying notes are an integral part of these consolidated financial statements.


69


WESTERN REFINING, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.
Organization and Basis of Presentation
The “Company” or “Western” may be used to refer to Western Refining, Inc. and, unless the context otherwise requires, its subsidiaries. Any references to the “Company” as of a date prior to September 16, 2005 (the date of Western Refining, Inc.’s formation) are to Western Refining Company, L.P. (“Western Refining LP”). On May 31, 2007, the Company completed the acquisition of Giant Industries, Inc. (“Giant”). Any references to the “Company” prior to this date exclude the operations of Giant.
The Company is an independent crude oil refiner and marketer of refined products and also operates service stations and convenience stores. The Company owns and operates two refineries: one in El Paso, Texas and one near Gallup in the Four Corners region of Northern New Mexico. The Company indefinitely idled its refining facility near Bloomfield, New Mexico during the latter part of 2009. During September of 2010, the Company temporarily suspended refining operations of its Yorktown, Virginia facility. On December 29, 2011, the Company completed the sale of its Yorktown refining and terminal assets. Primarily, the Company operates in West Texas, Arizona, New Mexico, Utah, Colorado, and the Mid-Atlantic region. In addition to the refineries, the Company also owns and operates stand-alone refined product distribution terminals in Bloomfield and Albuquerque, New Mexico, as well as asphalt terminals in Phoenix and Tucson, Arizona; Albuquerque; and El Paso. As of December 31, 2011, the Company 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 wholesale petroleum products distributor that operates in Arizona, California, Colorado, Nevada, New Mexico, Texas, Maryland, and Virginia.
The Company’s operations include three business segments: the refining group, the wholesale group, and the retail group. See Note 3, Segment Information, for further discussion of the Company’s business segments.
Demand for gasoline is generally higher during the summer months than during the winter months. As a result, the Company’s 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. During 2009 and 2010, extreme volatility in domestic refining margins limited the effect of these seasonal trends on the Company’s results of operations. Throughout 2011, the Company's operating results more closely reflected seasonal trends.
The accompanying consolidated financial statements have been prepared in accordance with U.S. generally accepted accounting principles (“GAAP”) for financial information and with the instructions to Form 10-K and Article 10 of Regulation S-X.

2.
Summary of Accounting Policies
Principles of Consolidation
Western Refining, Inc. was formed on September 16, 2005, as a holding company prior to its initial public offering. On May 31, 2007, the Company acquired 100% of Giant’s outstanding shares. The accompanying consolidated financial statements reflect the operations of Giant and its subsidiaries. In connection with the Company’s initial public offering in January 2006, pursuant to a contribution agreement, a reorganization of entities under common control was consummated whereby the Company became the indirect owner of Western Refining LP and all of its refinery assets. All intercompany balances and transactions have been eliminated for all periods presented.
Cash Equivalents
The Company considers all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents. There were no cash equivalents as of December 31, 2011 or 2010 included in the Company’s Consolidated Balance Sheets.
Restricted Cash and Other Non-Cash Activity
Restricted cash reported in the Company's Consolidated Balance Sheet at December 31, 2011 relates to gross proceeds from the sale of the Yorktown refinery and certain portions of our Southwest pipeline system. This cash is restricted through December 29, 2012 and must be used to either repay amounts outstanding under the Company's Term Loan or Senior Secured Fixed Rate Notes or to fund capital projects.


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Non-cash investing and financing activities for the year ended December 31, 2011 included an $8.2 million increase in debt consisting of $3.7 million in other debt costs, an original issue discount of $3.2 million, and a reduction of debt proceeds of $1.3 million to pay accrued interest related to the March 2011 amendment and restatement of the Company's Term Loan Credit Agreement. Other non-cash activities for the year ended December 31, 2011 included $4.4 million of fixed and intangible assets acquired through a capital lease obligation of $3.4 million and a promissory note of $1.0 million.

There were no non-cash investing or financing activities during the year ended December 31, 2010.

Non-cash investing and financing activities for the year ended ended December 31, 2009 included a $68.3 million reduction of long-term debt for original issue discounts and deferred financing costs, an equity component of convertible notes of $36.3 million, net of deferred taxes of $22.6 million and issuance costs of $2.0 million.
Accounts Receivable
Accounts receivable are due from a diverse customer base including companies in the petroleum industry, railroads, airlines, and the federal government and is stated net of an allowance for uncollectible accounts as determined by historical experience and adjusted for economic uncertainties or known trends. Credit is extended based on an evaluation of the customer’s financial condition. In addition, a portion of the sales at the Company’s service stations are on credit terms generally through major credit card companies. Past due or delinquency status of the Company’s trade accounts receivable are generally based on contractual arrangements with the Company’s customers.
Uncollectible accounts receivable are charged against the allowance for doubtful accounts when all reasonable efforts to collect the amounts due have been exhausted. Reserves for doubtful accounts related to trade receivables were $1.9 million, $3.9 million, and $1.6 million for the years ended December 31, 2011, 2010, and 2009, respectively. Additions, deductions, and balances for allowances for doubtful accounts for the three years ended December 31, 2011 are presented below:

 
Year Ended December 31,
 
2011
 
2010
 
2009
 
(In thousands)
Trade receivables:
 

 
 

 
 

Balance at January 1
$
3,896

 
$
1,571

 
$
2,516

Additions
2,306

 
3,260

 
4,400

Reductions
(4,318
)
 
(935
)
 
(5,345
)
Balance at December 31
1,884

 
3,896

 
1,571

Other receivables:
 

 
 

 
 

Balance at January 1

 

 
9,971

Additions

 

 
1,719

Reductions

 

 
(11,690
)
Balance at December 31

 

 

Total allowance for uncollectible accounts
$
1,884

 
$
3,896

 
$
1,571

Inventories
Crude oil, refined product, and other feedstock and blendstock inventories are carried at the lower of cost or market ("LCM"). Cost is determined principally under the last-in, first-out (“LIFO”) valuation method to reflect a better matching of costs and revenues for refining inventories. Costs include both direct and indirect expenditures incurred in bringing an item or product to its existing condition and location but not unusual/non-recurring costs or research and development costs. Ending inventory costs in excess of market value are written down to net realizable market values and charged to cost of products sold in the period recorded. In subsequent periods, a new LCM determination is made based upon current circumstances. The Company determines market value inventory adjustments by evaluating crude oil, refined products, and other inventories on an aggregate basis by geographic region.
Wholesale refined product, lubricants, and related inventories are determined using the first-in, first-out ("FIFO") inventory valuation method. Refined product inventories originate from either the Company’s refineries or from third-party purchases. Retail refined product (fuel) inventory values are determined using the FIFO inventory valuation method. Retail

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merchandise inventory value is determined under the retail inventory method.
Other Current Assets
Other current assets primarily consist of commodity hedging activity receivables, materials and chemicals inventories, taxes receivable, and exchange receivables.
Property, Plant, and Equipment
Property, plant, and equipment are stated at cost. The Company capitalizes interest on expenditures for capital projects in process greater than one year and greater than $5 million until such projects are ready for their intended use.
Depreciation is provided on the straight-line method at rates based upon the estimated useful lives of the various classes of depreciable assets. The lives used in computing depreciation for such assets are as follows:

Refinery facilities and related equipment
3 — 25 years
 
Pipelines, terminals, and transportation equipment
5 — 20 years
 
Wholesale facilities and related equipment
3 — 20 years
 
Retail facilities and related equipment
3 — 30 years
 
Other
3 — 10 years
 
Leasehold improvements are depreciated on the straight-line method over the shorter of the lease term or the improvement’s estimated useful life.
Expenditures for periodic maintenance and repair costs, including major turnaround expenses, are expensed when incurred. Such expenses are reported in direct operating expenses in the Company’s Consolidated Statements of Operations.
Intangible Assets
Intangible assets, net, consist of both amortizable intangible assets, net of accumulated amortization, and intangible assets with indefinite lives. These intangible assets are primarily comprised of licenses, permits, and rights-of-way related to the Company’s refining and retail operations. The Company amortizes its intangible assets, such as rights-of-way, licenses, and permits over their estimated economic useful lives, unless the economic useful lives of the assets are indefinite. If an intangible asset’s economic useful life is determined to be indefinite, then that asset is not amortized. The Company considers factors such as the asset’s history, its plans for that asset, and the market for products associated with the asset when the intangible asset is acquired. The Company considers these same factors when reviewing the economic useful lives of its existing intangible assets as well. The Company evaluates the remaining useful lives of its intangible assets with indefinite lives at least annually. If events or circumstances no longer support an indefinite useful life, the intangible asset is tested for impairment and prospectively amortized over its remaining useful life.
Both amortizable intangible assets and intangible assets with indefinite lives must be tested for recoverability whenever events or changes in circumstances indicate that the carrying amount of those assets may not be recoverable. Amortizable intangible assets are not recoverable if their carrying amount exceeds the sum of the undiscounted cash flows expected to result from their use and eventual disposition. If an amortizable intangible asset is not recoverable, an impairment loss is recognized in an amount by which its carrying amount exceeds its fair value generally based on discounted estimated net cash flows.
In order to test amortizable intangible assets for recoverability, management must make estimates of projected cash flows related to the asset being evaluated, which include, but are not limited to, assumptions about the use or disposition of the asset, its estimated remaining life, and future expenditures necessary to maintain its existing service potential. In order to determine fair value, management must make certain estimates and assumptions including, among other things, an assessment of market conditions, projected volumes, margins, cash flows, investment rates, interest/equity rates, and growth rates, that could significantly impact the fair value of the asset being tested for impairment.
The risk of intangible asset impairment losses may increase to the extent the Company’s results of operations or cash flows decline. Impairment losses may result in a material, non-cash write-down of intangible assets. Furthermore, impairment losses could have a material adverse effect on the Company’s results of operations and shareholders’ equity.
Other Assets

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


Other assets consist primarily of commodity hedging activities receivable, loan origination fees, and various other assets that are related to the general operation of the Company and are stated at cost. Amortization of loan origination fees is provided on a straight-line basis over the term of the agreement, which approximates the effective interest method.
Impairment of Long-Lived Assets
The Company reviews the carrying values of its long-lived assets for possible impairment whenever events or changes in circumstances indicate that the carrying amount of assets to be held and used may not be recoverable. A long-lived asset is not recoverable if its carrying amount exceeds the sum of the undiscounted cash flows expected to result from its use and eventual disposition. If a long-lived asset is not recoverable, an impairment loss is recognized in an amount by which its carrying amount exceeds its fair value.
In order to test long-lived assets for recoverability, management must make estimates of projected cash flows related to the asset being evaluated, which include, but are not limited to, assumptions about the use or disposition of the asset, its estimated remaining life, and future expenditures necessary to maintain its existing service potential. In order to determine fair value, management must make certain estimates and assumptions including, among other things, an assessment of market conditions, projected volumes, margins, cash flows, investment rates, interest/equity rates, and growth rates, that could significantly impact the fair value of the asset being tested for impairment.
The risk of long-lived asset impairment losses may increase to the extent the Company’s results of operations or cash flows decline. Impairment losses may result in a material, non-cash write-down of long-lived assets or intangible assets. Furthermore, impairment losses could have a material effect on the Company’s results of operations and shareholders’ equity.
For assets to be disposed of, the Company reports long-lived assets at the lower of carrying amount or fair value less cost to sell.
Revenue Recognition
Revenues for products sold are recorded upon delivery of the products to customers, which is the point at which title is transferred, the customer has the assumed risk of loss, and when payment has been received or collection is reasonably assured. Transportation, shipping, and handling costs incurred are included in cost of products sold. Excise and other taxes collected from customers and remitted to governmental authorities are not included in revenues.
Cost Classifications
Refining cost of products sold includes cost of crude oil, other feedstocks, blendstocks, the costs of purchased refined products, transportation and distribution costs, and realized and unrealized gains and losses related to the Company's commodity hedging activities. Wholesale cost of products sold includes the cost of fuel and lubricants, transportation and distribution costs, realized and unrealized gains and losses related to the Company's commodity hedging activities, and service parts and labor. Retail cost of products sold includes costs for motor fuels and for merchandise. Motor fuel cost of products sold represents net cost for purchased fuel. Net cost of purchased fuel excludes transportation and motor fuel taxes. Merchandise cost of products sold includes merchandise purchases, net of merchandise rebates and inventory shrinkage.
Refining direct operating expenses include direct costs of labor, maintenance materials and services, chemicals and catalysts, natural gas, utilities, and other direct operating expenses. Wholesale direct operating expenses include direct costs of labor, transportation expense, maintenance materials and services, utilities, and other direct operating expenses. Retail direct operating expenses include direct costs of labor, maintenance materials and services, outside services, bank charges, rent expense, utilities, and other direct operating expenses. Direct operating expenses also include insurance expense and property taxes.
Maintenance Turnaround Expense
Refinery process units require periodic maintenance and repairs that are commonly referred to as “turnarounds.” The required frequency of the maintenance varies by unit, but generally is every two to six years depending on the processing unit involved. Turnaround costs are expensed as incurred.


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Stock-Based Compensation
The cost of employee services received in exchange for an award of equity instruments granted under the Western Refining Long-Term Incentive Plan and 2010 Incentive Plan of Western Refining, Inc. is measured based on the grant date fair value of the award. Awards may be in the form of restricted shares or restricted share units. The fair value of each restricted share or restricted share unit awarded was measured based on the market price of a share at closing as of the measurement date and is amortized on a straight-line basis over the respective vesting periods.
Recipients of restricted shares have voting and dividend rights on these shares from the date of grant.
Recipients of restricted share units do not have voting or dividend rights on these units until the units have vested, and if applicable, the underlying shares have been issued. Upon vesting, the recipient will be entitled to receive, at the Compensation Committee’s election, the number of shares underlying the restricted share units, a cash payment equal to the share value at the vesting date, or a combination of both.
Financial Instruments and Fair Value
Financial instruments that potentially subject the Company to concentrations of credit risk primarily consist of accounts receivable. Credit risk is minimized as a result of the credit quality of the Company’s customer base. No customer accounted for more than 10% of the Company’s consolidated net sales in 2011. The carrying amounts of cash equivalents, restricted cash, accounts receivable, accounts payable, accrued liabilities, and amounts outstanding under the Company’s Revolving Credit Agreement approximate their fair values due to their short-term maturities.
The Company enters into crude oil forward contracts to facilitate the supply of crude oil to the refinery. These contracts qualify for the normal purchases and normal sales exception because the Company physically receives and delivers the crude oil under the contracts and when the Company enters into these contracts, the quantities are expected to be used or sold over a reasonable period of time in the normal course of business. These transactions are reflected in cost of products sold in the period in which delivery of the crude oil takes place.
In addition, the Company uses crude oil and refined products futures, swap contracts, or options to mitigate the change in value for a portion of its LIFO inventory volumes subject to market price fluctuations and swap contracts to fix the margin on a portion of its future gasoline and distillate production. The physical volumes are not exchanged, and these contracts are net settled with cash. 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.
The Company does not believe that there is a significant credit risk associated with the Company’s commodity hedging instruments, which are transacted through counterparties meeting established credit criteria. The Company may be required to collateralize any mark-to-market losses on outstanding commodity hedging contracts. Generally, the Company does not require collateral from counterparties, but may in the future.
See Note 4, Fair Value Measurement; Note 15, Retirement Plans; and Note 16, Crude Oil and Refined Product Risk Management for further fair value disclosures.
Pension and Other Postretirement Obligations
Pension and other postretirement plan expenses and liabilities are determined on an actuarial basis and are affected by the market value of plan assets, estimates of the expected return on plan assets, and assumed discount rates and demographic data.
Pension and other postretirement plan expenses and liabilities are determined based on actuarial valuations. Inherent in these valuations are key assumptions including discount rates, future compensation increases, expected return on plan assets, health care cost trends, and demographic data. Changes in our actuarial assumptions are primarily influenced by factors outside of our control and can have a significant effect on our pension and other postretirement liabilities and costs. A defined benefit postretirement plan sponsor must (a) recognize in its statement of financial position an asset for a 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. See Note 15, Retirement Plans.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


Asset Retirement Obligations
The Company recognizes the fair value of a liability for an asset retirement obligation (“ARO”) in the period in which it is incurred if a reasonable estimate of fair value can be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. The increase in the ARO due to the passage of time is recorded as an operating expense (accretion expense). See Note 12, Asset Retirement Obligations.
Environmental and Other Loss Contingencies
The Company records liabilities for loss contingencies, including environmental remediation costs when such losses are probable and can be reasonably estimated. 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. Where the available information is sufficient to estimate the amount of liability, that estimate is used. Where the information is only sufficient to establish a range of probable liability and no point within the range is more likely than another, the lower end of the range is used. See Note 21, Contingencies.
Liabilities for future remediation costs are recorded when environmental remedial efforts are probable and the costs can be reasonably estimated, generally on an undiscounted basis. Environmental liabilities acquired in a business combination may be discounted dependent upon specific circumstances related to each environmental liability acquired. As a result of purchase accounting related to the Giant acquisition, the majority of the Company’s environmental obligations are recorded on a discounted basis. The timing and magnitude of these accruals generally are based on the completion of investigations or other studies or a commitment to a formal plan of action. Current regulations are applied in determining environmental liabilities and are based on best estimates of probable undiscounted future costs over the estimated period of time expected to complete the remediation activities using currently available technology as well as the Company’s internal environmental policies. Environmental liabilities are difficult to assess and estimate due to uncertainties related to the magnitude of possible remediation and the timing of such remediation. Such estimates are subject to change due to many factors, including the identification of new sites requiring remediation, changes in environmental laws and regulations and their interpretation, additional information related to the extent and nature of remediation efforts, and potential improvements in remediation technologies. Amounts recorded for environmental liabilities are not reduced by possible recoveries from third parties. Recoveries of environmental remediation costs from other parties are recorded as assets when the Company deems their receipt probable.
Income Taxes
Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized to reflect temporary differences between the basis of assets and liabilities for financial reporting purposes and income tax purposes. Generally, deferred tax assets represent future income tax reductions while deferred tax liabilities represent income taxes that the Company expects to pay in the future. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The ultimate realization of the Company's deferred tax assets depends upon generating sufficient future taxable income during the periods in which the temporary differences become deductible or before any net operating loss and tax credit carryforwards expire. If recovery of deferred tax assets is not likely, the Company's provision for taxes is increased by recording a valuation allowance against the deferred tax assets that management estimates will not ultimately be recoverable. As changes occur in management's assessments regarding the Company's ability to recover its deferred tax assets, the tax provision is increased in any period in which the Company determines that the recovery is not probable. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date.
The Company recognizes the benefit of a tax position if that position will more likely than not be sustained in an audit, based on the technical merits of the position. If the tax position meets the more likely than not recognition threshold, the tax effect is recognized at the largest amount of the benefit that has greater than a fifty percent likelihood of being realized upon ultimate settlement. Liabilities created for unrecognized tax benefits are presented as a separate liability and are not combined with deferred tax liabilities or assets. The Company classifies interest to be paid on an underpayment of income taxes and any related penalties as income tax expense.
Use of Estimates
The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the

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date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Reclassifications
Prepaid expenses and other current assets include $1,456 and $12,845, respectively, previously reported as accounts receivable, principally trade in the December 31, 2010 Consolidated Balance Sheet. Accrued liabilities includes $13,984 previously reported as accounts payable in the December 31, 2010 Consolidated Balance Sheet. Items reclassified from accounts receivable included tax refund receivables, prepaid income taxes, product rebate receivables, and other non-trade related receivables. Items reclassified from accounts payable included accrued utilities and various routine non-invoice related accrued expenses. These prior year reclassifications were made to conform to the current presentation.
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 effective January 1, 2012 will not affect the Company’s financial position or results of operations, but may result in additional disclosures.

3.
Segment Information
The Company is organized into three operating segments based on manufacturing and marketing criteria and the nature of their products and services, their production processes, and their types of customers. These segments are the refining group, the wholesale group, and the retail group. See Note 22, Concentration of Risk, for a discussion on significant customers. A description of each segment and its principal products follows:
Refining Group.  The Company’s refining group currently operates two refineries: one in El Paso, Texas (the “El Paso refinery”) and one near Gallup, New Mexico (the “Gallup refinery”). The refining group also operates a crude oil transportation and gathering pipeline system in New Mexico, an asphalt plant in El Paso, two stand-alone refined product distribution terminals, and four asphalt terminals. The refineries make various grades of gasoline, diesel fuel, and other products from crude oil, other feedstocks, and blending components. The Company purchases crude oil, other feedstocks, and blending components from various suppliers. The Company also acquires refined products through exchange agreements and from various third-party suppliers. The Company sells these products through its own service stations, its own wholesale group, independent wholesalers and retailers, commercial accounts, and sales and exchanges with major oil companies.
In September 2010, the Company temporarily suspended refining operations at its Yorktown facility. The Company 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 the Company from profitably operating the refinery. The Company performed an impairment analysis at that time in connection with the temporary suspension of its Yorktown refining operations. Based on that analysis, the Company determined that the undiscounted forecasted cash flows exceeded the carrying amount of its 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 the Yorktown facility, management 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 its impairment analysis should be revised or updated. The Company's impairment analysis included considerable estimates and judgment, the most significant of which was the restart of refining operations during the latter part of 2013, which would have required a six to nine month pre-restart maintenance period, at an estimated cost of approximately $65.0 million.

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On November 30, 2011, the Company announced that it had entered into agreements to sell the Yorktown refining and terminal asset facilities for a sales price of $180.4 million, 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 Yorktown refining assets are sold. The Company has retained its East Coast wholesale business and continues to market refined products in the Mid-Atlantic region. This transaction allowed the Company 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, the Company 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 the Company's fourth quarter decision to sell the Yorktown facility, the Company 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, the Company also sold a section of its Texas New Mexico pipeline for a sales price of $40.0 million. Prior to the sale of the section of the line, the Texas New Mexico pipeline extended from Southeast to Northwest New Mexico. The 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 the Company does not currently utilize this capacity, the pipeline provides a raw material supply alternative for the Gallup refinery. The sale of this segment of pipeline resulted in a gain of $26.6 million, including transaction costs of $0.1 million. The Company performed an impairment analysis on the remaining portion 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.
In the fourth quarter of 2009, the Company announced its plans to indefinitely suspend the refining operations at its Bloomfield refinery and maintain the site as a product distribution terminal and crude oil storage facility. Accordingly, the Company tested the Bloomfield refinery long-lived assets and certain intangible assets for recoverability and determined that $41.8 million and $11.0 million in related refinery fixed and intangible assets, respectively, were impaired. During the fourth quarters of 2010 and 2011, respectively, the Company recorded additional impairment charges of $9.1 million and $11.7 million resulting from changes in management's plans regarding specific assets that it had previously planned to relocate from the Bloomfield facility to the Gallup refinery. Based on the current operations of the Gallup refinery, the Company determined that all three of the assets set aside for relocation to Gallup are no longer required. Non-cash impairment losses of $11.7 million, $9.1 million, and $52.8 million related to the long-lived assets and certain intangible assets 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.
During the third quarter of 2010, the Company permanently closed its product distribution terminal in Flagstaff, Arizona. The Company completed an impairment analysis of the Flagstaff terminal long-lived assets and determined from this analysis that the assets were fully impaired. Accordingly, an impairment charge of $3.8 million related to the Flagstaff long-lived assets is included in Loss and impairments on disposal of assets, net in the Consolidated Statements of Operations for the year ended December 31, 2010.
Wholesale Group.  The Company’s wholesale group includes several lubricant and bulk petroleum distribution plants, unmanned fleet fueling operations, a bulk lubricant terminal facility, and a fleet of refined product and lubricant delivery trucks. The wholesale group distributes commercial wholesale petroleum products primarily in Arizona, California, Colorado, Nevada, New Mexico, Texas, Utah, Virginia, and Maryland. The Company’s wholesale group purchases petroleum fuels and lubricants from third-party suppliers and from the refining group. Beginning in January 2011, wholesale operations include the distribution of refined product through the Yorktown terminal facility. Following the sale of the Yorktown terminal assets, the Company's wholesale business will continue to operate through the terminal as a customer. For the year ended December 31, 2011, the wholesale group results included $1,338.7 million of net sales and $4.3 million of operating income related to the Company’s East Coast wholesale operations through the Yorktown facility. The wholesale group purchases refined products sold through East Coast operations from third parties.
Retail Group.  The Company’s retail group operates service stations that include convenience stores or kiosks. The service stations sell various grades of gasoline, diesel fuel, general merchandise, and beverage and food products to the general public. The Company’s wholesale group supplies the majority of gasoline and diesel fuel that the retail group sells. The Company purchases general merchandise and beverage and food products from various suppliers. During the second and third quarters of 2011, the retail group added 59 stores, primarily under various operating leases. For the year ended December 31,

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2011, the retail group results included $95.3 million in net sales from the convenience stores added during the second and third quarters of 2011. The operations of the additional convenience stores did not have a significant impact on the operating income of the retail group for the year ended December 31, 2011.
At December 31, 2011, the Company’s retail group operated 209 service stations, including one non-fuel convenience store, in Arizona, New Mexico, Colorado, and Texas.
Segment Accounting Principles.  Operating income for each segment consists of net revenues less cost of products sold; direct operating expenses; selling, general, and administrative expenses; maintenance turnaround expense; and depreciation and amortization. Cost of products sold reflects current costs adjusted, where appropriate, for LIFO and LCM inventory adjustments. Intersegment revenues are reported at prices that approximate market.
Operations that are not included in any of the three segments mentioned above are included in the category Other. These operations consist primarily of corporate staff operations and other items not considered to be related to the normal business operations of the other segments. Other items of income and expense not specifically related to the other segments, including income taxes, are not allocated to operating segments.
The total assets of each segment consist primarily of cash and cash equivalents; net property, plant, and equipment; inventories; net accounts receivable; and other assets directly associated with the individual segment’s operations. Included in the total assets of the corporate operations are cash and cash equivalents; various accounts receivable, net of reserve for doubtful accounts; net property, plant, and equipment; and other long-term assets.
During the second quarter of 2009, in performing its annual impairment analysis, the Company determined that the entire balance of its goodwill of $299.6 million that was reported under four of its six reporting units was impaired. Related impairment charges were reported under Goodwill impairment loss in the accompanying Consolidated Statement of Operations for the year ended December 31, 2009.
Disclosures regarding the Company’s reportable segments with reconciliations to consolidated totals for the three years ended December 31, 2011 are presented below:
 
Year Ended December 31, 2011
 
Refining Group
 
Wholesale Group(2)
 
Retail Group
 
Other
 
Consolidated
 
(In thousands)
Net sales to external customers
$
4,124,279

 
$
4,032,790

 
$
913,968

 
$

 
$
9,071,037

Intersegment revenues(1)
4,275,419

 
721,000

 
26,427

 

 

Operating income (loss) before impairment losses
$
862,300

 
$
26,621

 
$
4,708

 
$
(62,684
)
 
$
830,945

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

 

 

 
(447,166
)
Operating income (loss)
$
415,134

 
$
26,621

 
$
4,708

 
$
(62,684
)
 
$
383,779

Other income (expense), net
 

 
 

 
 

 
 

 
(181,251
)
Income before income taxes
 

 
 

 
 

 
 

 
$
202,528

Depreciation and amortization
$
119,057

 
$
4,312

 
$
9,653

 
$
2,873

 
$
135,895

Capital expenditures
63,794

 
3,459

 
14,876

 
1,680

 
83,809

Total assets at December 31, 2011
1,673,745

 
279,463

 
178,155

 
438,981

 
2,570,344

_______________________________________
(1)
Intersegment revenues of $5,022.8 million have been eliminated in consolidation.
(2)
Wholesale group fuel sales volumes included 131.1 million gallons sold to the retail group that in years prior to 2010 were sold to the retail group by the refining group. The average sales price for these gallons was $3.28 per gallon.


78

WESTERN REFINING, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


 
Year Ended December 31, 2010
 
Refining Group
 
Wholesale Group(2)
 
Retail Group
 
Other
 
Consolidated
 
(In thousands)
Net sales to external customers
$
5,327,570

 
$
1,942,527

 
$
694,956

 
$

 
$
7,965,053

Intersegment revenues(1)
2,742,549

 
528,059

 
23,413

 

 

Operating income (loss) before impairment losses
$
132,322

 
$
20,726

 
$
16,358

 
$
(50,933
)
 
$
118,473

Loss and impairments on disposal of assets, net
(12,832
)
 

 

 
(206
)
 
(13,038
)
Operating income (loss)
$
119,490

 
$
20,726

 
$
16,358

 
$
(51,139
)
 
$
105,435

Other income (expense), net
 

 
 

 
 

 
 

 
(148,561
)
Loss before income taxes
 

 
 

 
 

 
 

 
$
(43,126
)
Depreciation and amortization
$
118,661

 
$
5,069

 
$
10,245

 
$
4,646

 
$
138,621

Capital expenditures
71,751

 
726

 
4,940

 
678

 
78,095

Total assets at December 31, 2010
2,253,882

 
163,929

 
155,999

 
54,336

 
2,628,146

_______________________________________
(1)
Intersegment revenues of $3,294.0 million have been eliminated in consolidation.
(2)
Wholesale group fuel sales volumes included 113.0 million gallons sold to the retail group that in years prior to 2010 were sold to the retail group by the refining group. The average sales price for these gallons was $2.64 per gallon.
 
Year Ended December 31, 2009
 
Refining Group
 
Wholesale Group
 
Retail Group
 
Other
 
Consolidated
 
(In thousands)
Net sales to external customers
$
4,756,868

 
$
1,440,493

 
$
610,007

 
$

 
$
6,807,368

Intersegment revenues(1)
1,851,207

 
223,904

 
19,931

 

 

Operating income (loss) before impairment losses
$
143,240

 
$
10,530

 
$
15,442

 
$
(55,902
)
 
$
113,310

Goodwill impairment loss
(230,712
)
 
(41,230
)
 
(27,610
)
 

 
(299,552
)
Loss and impairments on disposal of assets, net
(52,788
)
 

 

 

 
(52,788
)
Operating loss
$
(140,260
)
 
$
(30,700
)
 
$
(12,168
)
 
$
(55,902
)
 
$
(239,030
)
Other income (expense), net
 

 
 

 
 

 
 

 
(152,174
)
Loss before income taxes
 

 
 

 
 

 
 

 
$
(391,204
)
Depreciation and amortization
$
125,537

 
$
5,616

 
$
9,820

 
$
5,008

 
$
145,981

Capital expenditures
110,172

 
864

 
3,411

 
1,407

 
115,854

Total assets at December 31, 2009
2,386,751

 
154,518

 
158,987

 
124,398

 
2,824,654

_______________________________________
(1)
Intersegment revenues of $2,095.0 million have been eliminated in consolidation.

4.
Fair Value Measurement
The Company utilizes the market approach when measuring fair value for its financial assets and liabilities. The market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities.

79

WESTERN REFINING, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


The fair value hierarchy consists of the following three levels:

Level 1
 
Inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities.
Level 2
 
Inputs are quoted prices for similar assets or liabilities in an active market, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable, and market corroborated inputs, which are derived principally from or corroborated by observable market data.
Level 3
 
Inputs are derived from valuation techniques in which one or more significant inputs or value drivers are unobservable and cannot be corroborated by market data or other entity specific inputs.
The carrying amounts of accounts receivable, accounts payable, and accrued liabilities approximated their fair values at December 31, 2011 and 2010 due to their short-term maturities. The following table represents the Company’s assets and liabilities measured at fair value on a recurring basis as of December 31, 2011 and 2010, and the basis for that measurement:
 
 
 
Fair Value Measurement at
December 31, 2011 Using
 
Carrying Value at
December 31, 2011
 
Quoted Prices
in Active
Markets for
Identical Assets
or Liabilities
(Level 1)
 
Significant
Other
Observable
Inputs
(Level 2)
 
Significant
Unobservable
Inputs
(Level 3)
 
(In thousands)
Financial assets:
 

 
 

 
 

 
 

Commodity hedging contracts
$
183,179

 
$

 
$
183,179

 
$

Financial liabilities:
 

 
 

 
 

 
 

Commodity hedging contracts
$
1,066

 
$

 
$
1,066

 
$


 
 
 
Fair Value Measurement at
December 31, 2010 Using
 
Carrying Value at
December 31, 2010
 
Quoted Prices
in Active
Markets for
Identical Assets
or Liabilities
(Level 1)
 
Significant
Other
Observable
Inputs
(Level 2)
 
Significant
Unobservable
Inputs
(Level 3)
 
(In thousands)
Financial liabilities:
 

 
 

 
 

 
 

Commodity hedging contracts
$
1,173

 
$

 
$
1,173

 
$

Carrying amounts of commodity hedging contracts reflected as financial assets are included in both current other assets and non-current other assets in the Consolidated Balance Sheet. Carrying amounts of commodity hedging contracts reflected as financial liabilities are included in accrued liabilities in the Consolidated Balance Sheet.
As of December 31, 2011 and December 31, 2010, the carrying amount and estimated fair value of the Company’s debt was as follows:
 
December 31,
2011
 
December 31,
2010
 
(In thousands)
Carrying amount
$
803,990

 
$
1,069,531

Fair value
997,693

 
1,261,704

The carrying amount of the Company’s debt is the amount reflected in the Consolidated Balance Sheets, including the current portion. The fair value of the debt was determined using Level 2 inputs.

80

WESTERN REFINING, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


There have been no transfers between assets or liabilities whose fair value is determined through the use of quoted prices in active markets (Level 1) and those determined through the use of significant other observable inputs (Level 2).
During the fourth quarter of 2011, the third and fourth quarters of 2010, and the fourth quarter of 2009, the Company impaired certain long-lived assets from its Bloomfield refinery and Flagstaff terminal. The Company determined impairment amounts as the excess of the carrying values of the respective assets over fair values determined based on the lack of future utility to the Company. The carrying value of the assets impaired during 2011 was $11.7 million prior to impairment and was fully impaired to zero value during the fourth quarter. The carrying value of the assets impaired during 2010 prior to impairment was $14.2 million and $1.2 million after impairment. The carrying value of the assets impaired during 2009 was $73.9 million prior to impairment and $22.1 million after impairment. Additionally, during the second quarter of 2009, the Company determined that the entire balance of recorded goodwill was impaired. The carrying value of the goodwill impaired during 2009 was $299.6 million prior to impairment and was fully impaired to zero value during the period.

5.
Inventories
Inventories were as follows:

 
December 31,
 
2011
 
2010
 
(In thousands)
Refined products (1)
$
199,848

 
$
189,994

Crude oil and other raw materials
179,039

 
152,155

Lubricants
11,985

 
11,456

Convenience store merchandise
14,882

 
12,068

Inventories
$
405,754

 
$
365,673

_______________________________________
(1)
Includes $76.5 million and $10.0 million of inventory valued using the FIFO valuation method at December 31, 2011 and 2010, respectively.
The Company values its refinery inventories of crude oil, other raw materials, and asphalt inventories at the lower of cost or market under the LIFO valuation method. Other than refined products inventories held by the Company’s retail and wholesale groups, refined products inventories are valued under the LIFO valuation method. Lubricants and convenience store merchandise are valued under the FIFO valuation method.
As of December 31, 2011 and 2010, refined products valued under the LIFO method and crude oil and other raw materials totaled 5.2 million barrels and 5.7 million barrels, respectively. At December 31, 2011, the excess of the current cost of these crude oil, refined product, and other feedstock and blendstock inventories over LIFO cost was $213.7 million. At December 31, 2010, the excess of the current cost of these crude oil, refined product, and other feedstock and blendstock inventories over LIFO cost was $173.5 million.
The net effect of the change in the lower of cost or market ("LCM") reserve to value the Company’s Yorktown inventories to net realizable market values on the Company’s Consolidated Statements of Operations and the net effect of inventory reductions that resulted in the liquidation of LIFO inventory levels are summarized in the table below:


81

WESTERN REFINING, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


 
Year Ended December 31,
 
2011
 
2010
 
2009
 
(In thousands, except
per share amount)
Effect of Change in LCM Reserve on:
 

 
 

 
 

Operating income
$

 
$

 
$
61,005

Net income

 

 
33,992

Earnings per diluted share
$

 
$

 
$
0.43

Effect of Liquidation of LIFO Layers on:
 

 
 

 
 

Operating income
$
22,290

 
$
16,886

 
$
9,366

Net income
14,600

 
6,675

 
5,219

Earnings per diluted share
$
0.13

 
$
0.08

 
$
0.07

Average LIFO cost per barrel of the Company’s refined products and crude oil and other raw materials inventories as of December 31, 2011 and 2010, is shown below:

 
December 31,
 
2011
 
2010
 
Barrels
 
LIFO Cost
 
Average
LIFO
Cost Per
Barrel
 
Barrels
 
LIFO Cost
 
Average
LIFO
Cost Per
Barrel
 
(In thousands, except cost per barrel)
Refined products
1,896

 
$
123,335

 
$
65.05

 
2,574

 
$
180,031

 
$
69.94

Crude oil and other
3,289

 
179,039

 
54.44

 
3,115

 
152,155

 
48.85

 
5,185

 
$
302,374

 
58.32

 
5,689

 
$
332,186

 
58.39


6.
Prepaid Expenses
Prepaid expenses were as follows:
 
December 31,
 
2011
 
2010
 
(In thousands)
Prepaid crude oil and other raw materials inventories
$
111,521

 
$
56,257

Prepaid insurance and other
52,009

 
17,134

Prepaid expenses
$
163,530

 
$
73,391


7.
Other Current Assets
Other current assets were as follows:

 
December 31,
 
2011
 
2010
 
(In thousands)
Unrealized hedging gains and margin accounts
$
138,922

 
$
3,173

Materials and chemicals inventories
27,196

 
38,591

Excise and other taxes receivable
22,149

 
10,945

Exchange and other receivables
6,797

 
4,422

Other current assets
$
195,064

 
$
57,131


82


8.
Property, Plant, and Equipment, Net
Property, plant, and equipment, net was as follows:

 
December 31,
 
2011
 
2010
 
(In thousands)
Refinery facilities and related equipment
$
1,013,169

 
$
1,733,803

Pipelines, terminals, and transportation equipment
75,172

 
91,149

Wholesale and retail facilities and related equipment
198,060

 
185,359

Other
22,287

 
20,856

Construction in progress
55,062

 
94,894

 
1,363,750

 
2,126,061

Accumulated depreciation
(368,434
)
 
(437,907
)
Property, plant, and equipment, net
$
995,316

 
$
1,688,154


Depreciation expense was $131.3 million, $134.3 million, and $141.4 million for the years ended December 31, 2011, 2010, and 2009, respectively.

The majority of the decrease in property, plant, and equipment was due to the sale of the Yorktown facility. See Note 3, Segment Information for further information on this and other disposals during 2011.

9.
Intangible Assets, Net
From the first to the second quarter of 2009, there was a decline in margins within the refining industry as well as a downward change in industry analysts’ forecasts for the remainder of 2009 and 2010. This, along with other negative financial forecasts released by independent refiners during the latter part of the second quarter of 2009, contributed to declines in common stock trading prices within the independent refining sector, including declines in the Company’s common stock trading price. As a result, the Company’s equity market capitalization fell below the net book value of the Company’s assets. Through the filing date of the Company’s second quarter of 2009 Form 10-Q and through the end of the fourth quarter of 2009, the trading price of the Company’s stock had experienced further reductions.
The Company completed its goodwill impairment test during the second quarter of 2009 and concluded that impairment existed. The Company concluded that all of its goodwill was impaired. The resulting non-cash charge of $299.6 million was reported in the Company’s second quarter of 2009 results of operations. There were no such impairment charges in the years ended December 31, 2011 or 2010.
A summary of intangible assets is presented in the table below:

 
December 31, 2011
 
December 31, 2010
 
 
 
Gross
Carrying
Value
 
Accumulated
Amortization
 
Net
Carrying
Value
 
Gross
Carrying
Value
 
Accumulated
Amortization
 
Net
Carrying
Value
 
Weighted Average
Amortization
Period (Years)
 
(In thousands)
 
 
Amortizable assets:
 

 
 

 
 

 
 

 
 

 
 

 
 

Licenses and permits
$
20,426

 
$
(7,384
)
 
$
13,042

 
$
39,151

 
$
(10,698
)
 
$
28,453

 
8.3

Customer relationships
7,300

 
(1,758
)
 
5,542

 
6,300

 
(1,305
)
 
4,995

 
10.7

Rights-of-way
6,525

 
(1,951
)
 
4,574

 
6,525

 
(1,267
)
 
5,258

 
5.4

Other
1,638

 
(1,395
)
 
243

 
1,360

 
(670
)
 
690

 
4.7

 
35,889

 
(12,488
)
 
23,401

 
53,336

 
(13,940
)
 
39,396

 
 

Unamortizable assets:
 

 
 

 
 

 
 

 
 

 
 

 
 

Trademarks
4,800

 

 
4,800

 
4,800

 

 
4,800

 
 

Liquor licenses
16,151

 

 
16,151

 
15,749

 

 
15,749

 
 

Intangible assets, net
$
56,840

 
$
(12,488
)
 
$
44,352

 
$
73,885

 
$
(13,940
)
 
$
59,945

 
 

Intangible asset amortization expense for the three years ended December 31, 2011 was $4.2 million, $4.0 million, and

83

WESTERN REFINING, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


$4.6 million, respectively, based upon estimates of useful lives ranging from 3 to 15 years. Estimated amortization expense for the next five fiscal years is as follows (in thousands):
2012
$
3,324

2013
3,039

2014
2,849

2015
2,371

2016
2,200


10.
Other Assets, Net
Other assets, net of amortization, were as follows:

 
December 31,
 
2011
 
2010
 
(In thousands)
Unrealized hedging gains
$
54,208

 
$

Unamortized loan fees
33,086

 
38,930

Other
12,372

 
15,414

Other assets, net of amortization
$
99,666

 
$
54,344


11.
Accrued and Other Long-Term Liabilities
Accrued liabilities were as follows:

 
December 31,
 
2011
 
2010
 
(In thousands)
Income taxes
$
52,795

 
$

Payroll and related costs
42,111

 
26,402

Excise taxes
32,000

 
39,086

Professional and other
19,859

 
34,264

Property taxes
13,216

 
11,323

Banking fees and other financing
3,708

 
2,793

Environmental reserves
3,343

 
10,565

Short-term pension obligation
2,461

 
7,084

Interest
2,310

 
3,672

Fair value of open commodity hedging positions, net
198

 
1,173

Accrued liabilities
$
172,001

 
$
136,362


84


Other long-term liabilities were as follows:
 
December 31,
 
2011
 
2010
 
(In thousands)
Retiree plan obligation
$
5,745

 
$
3,831

Asset retirement obligations
4,736

 
5,485

Capital lease obligation
3,337

 

Environmental reserves
2,428

 
7,689

Other
5,709

 
14,772

Other long-term liabilities
$
21,955

 
$
31,777

As of December 31, 2011, the Company had environmental liability accruals of $5.8 million, of which $3.3 million was in accrued liabilities. These liabilities have been recorded using an inflation factor of 2.7% and a discount rate of 7.1%. Environmental liabilities of $1.5 million accrued at December 31, 2011 have not been discounted. As of December 31, 2011, the unescalated, undiscounted environmental reserves related to these liabilities totaled $5.3 million, leaving $1.0 million to be accreted over time. During the fourth quarter of 2009, the Company 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 (exclusive of depreciation and amortization) in the Consolidated Statement of Operations.
The table below summarizes the Company’s environmental liability accruals:
 
December 31,
2010
 
Increase
(Decrease)
 
Payments
 
December 31,
2011
 
(In thousands)
Discounted liabilities
$
16,934

 
$
(1,864
)
 
$
(10,775
)
 
$
4,295

Undiscounted liabilities
1,320

 
986

 
(830
)
 
1,476

Total environmental liabilities
$
18,254

 
$
(878
)
 
$
(11,605
)
 
$
5,771


The following table summarizes the Company’s estimated undiscounted cash flows for discounted remediation liabilities for each of the next five years and in the aggregate thereafter (in thousands):

2012
$
772

2013
402

2014
402

2015
402

2016
369

2017 and thereafter
3,010

12.
Asset Retirement Obligations
The Company determines the estimated fair value of its AROs based on the estimated current cost escalated to an inflation rate and discounted at a credit adjusted risk free rate. This liability is capitalized as part of the cost of the related asset and amortized using the straight-line method. The liability accretes until the Company settles the liability.
The Company has identified the following AROs:
Crude Pipelines.  The Company’s right-of-way agreements generally require that pipeline properties be returned to their original condition when the agreements are no longer in effect. This means that the pipeline surface facilities must be dismantled and removed and certain site reclamation performed. The Company does not believe these right-of-way agreements will require it to remove the underground pipe upon taking the pipeline permanently out of service. Regulatory requirements, however, may mandate that such out of service underground pipe be purged at the time the pipelines are taken permanently out of service.
Storage Tanks.  The Company has a legal obligation under applicable law to remove or close in place certain underground and aboveground storage tanks, both on owned property and leased property, once they are taken out of service. Under some lease arrangements, the Company has also committed to restore the leased property to its original condition.

85


Other.  The Company identified certain refinery piping and heaters as a conditional ARO since it has the legal obligation to properly remove or dispose of materials that contain asbestos that surround certain refinery piping and heaters.
The following table reconciles the beginning and ending aggregate carrying amount of the Company’s AROs for the three years ended December 31, 2011:

 
December 31,
 
2011
 
2010
 
2009
 
(In thousands)
Liability, beginning of period
$
5,485

 
$
5,326

 
$
4,991

Liabilities incurred
44

 
33

 

Liabilities settled
(1,160
)
 
(229
)
 
(10
)
Accretion expense
367

 
355

 
345

Liability, end of period
$
4,736

 
$
5,485

 
$
5,326


13.
Long-Term Debt
Long-term debt was as follows:

 
December 31,
 
2011
 
2010
 
(In thousands)
11.25% Senior Secured Notes, due 2017, net of unamortized discount of $21,986 and $24,618, respectively
$
303,014

 
$
300,382

Senior Secured Floating Rate Notes, net of unamortized discount of $16,823 in 2010 with interest rate of 10.75% during 2011 and 2010, respectively

 
258,177

5.75% Senior Convertible Notes, due 2014, net of conversion feature of $34,999 and $46,285, respectively
180,451

 
169,165

Term Loan, due 2017, net of unamortized discount of $2,901 in 2011 with average interest rates of 8.31% and 10.75% during 2011 and 2010, respectively
319,661

 
341,807

5.50% promissory note, due 2015
864

 

Revolving Credit Agreement with an interest rate of 5.73% and 6.15% at December 31, 2011 and 2010, respectively

 

     Long-term debt
803,990

 
1,069,531

Current portion of long-term debt
(3,595
)
 
(63,000
)
     Long-term debt, net of current portion
$
800,395

 
$
1,006,531



86


Interest expense and other financing costs were as follows:
 
Year Ended December 31,
 
2011
 
2010
 
2009
 
(In thousands)
Contractual interest:
 

 
 

 
 

11.25% Senior Secured Notes
$
36,563

 
$
36,563

 
$
20,211

Senior Secured Floating Rate Notes
29,152

 
29,973

 
16,670

5.75% Senior Convertible Notes
12,388

 
12,388

 
6,848

Term Loan
27,224

 
37,611

 
66,459

Revolving Credit Agreement
631

 
5,036

 
835

 
105,958

 
121,571

 
111,023

Amortization of original issuance discount:


 
 

 


11.25% Senior Secured Notes
2,632

 
2,324

 
861

Senior Secured Floating Rate Notes
4,004

 
3,645

 
1,533

5.75% Senior Convertible Notes
11,286

 
9,898

 
4,697

Term Loan
349

 

 

 
18,271

 
15,867

 
7,091

Other interest expense
12,330

 
13,359

 
9,622

Capitalized interest
(1,958
)
 
(4,248
)
 
(6,415
)
Interest expense and other financing costs
$
134,601

 
$
146,549

 
$
121,321


The Company amortizes original issue discounts using the effective interest method over the respective term of the debt.

Senior Secured Notes.  In June 2009, the Company issued two tranches of Senior Secured Notes under an indenture dated June 12, 2009. The first tranche consisted of $325.0 million in aggregate principal amount of 11.25% Senior Secured Notes (the “Fixed Rate Notes”). The second tranche consisted of $275.0 million Senior Secured Floating Rate Notes (the “Floating Rate Notes,” and together with the Fixed Rate Notes, the “Senior Secured Notes”). The Fixed Rate Notes pay interest semi-annually in cash in arrears on June 15 and December 15 of each year at a rate of 11.25% per annum and will mature on June 15, 2017. The Fixed Rate Notes may be redeemed by the Company at the Company’s option beginning on June 15, 2013 through June 14, 2014 at a premium of 5.625%; from June 15, 2014 through June 14, 2015 at a premium of 2.813%; and at par thereafter. The Company amortized the original issue discounts using the effective interest rate method over the life of the notes. The combined proceeds from the issuance and sale of the Senior Secured Notes were used to repay a portion of the outstanding indebtedness under the Term Loan. Proceeds from the issuance of the Fixed Rate Notes were $290.7 million, net of an original issue discount of $27.8 million and underwriting discounts of $6.5 million. Proceeds from the issuance of the Floating Rate Notes were $247.5 million, net of original issue discount of $22.0 million and underwriting discounts of $5.5 million. The Company paid $2.1 million in other financing costs related to the Senior Secured Notes in 2009.
On December 21, 2011, the Company redeemed the Floating Rate Notes at a repurchase price of $288.8 million, representing a premium on redemption of the notes of 5.0% above the face value. As a result of this redemption, the Company recorded $29.7 million loss on extinguishment of debt including a $3.2 million write-off of unamortized loan fees in its Consolidated Statement of Operations for the year ended December 31, 2011. Prior to December 21, 2011, 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%. The interest rate on the Floating Rate Notes as of December 21, 2011 was 10.75%. The Floating Rate Notes became redeemable by the Company at the Company’s option beginning on December 15, 2011 at a premium of 5.0%.
The Fixed Rate Notes are guaranteed by all of the Company’s domestic restricted subsidiaries in existence on the date the Fixed Rate Notes were issued. The Fixed Rate Notes will also be guaranteed by all future wholly-owned domestic restricted subsidiaries and by any restricted subsidiary that guarantees any of the Company’s indebtedness under credit facilities that are secured by a lien on the collateral securing the Fixed Rate Notes. The Fixed Rate Notes are also secured on a first priority basis, equally and ratably with the Company’s Term Loan and any future other pari passu secured obligation, by the collateral securing the Term Loan, which consists of the Company’s fixed assets, and on a second priority basis, equally and ratably with the Term Loan and any future other pari passu secured obligation, by the collateral securing the Revolving Credit Agreement, which consists of the Company’s cash and cash equivalents, trade accounts receivables, and inventory.

87


The indenture governing the Senior Secured Notes contains covenants that limit the Company’s (and most of its subsidiaries’) ability to, among other things: (i) pay dividends or make other distributions in respect of their capital stock or make other restricted payments; (ii) make certain investments; (iii) sell certain assets; (iv) incur additional debt or issue certain preferred shares; (v) create liens on certain assets to secure debt; (vi) consolidate, merge, sell or otherwise dispose of all or substantially all of their assets; (vii) restrict dividends or other payments from restricted subsidiaries; and (viii) enter into certain transactions with their affiliates. These covenants are subject to a number of important limitations and exceptions. The indenture governing the Senior Secured Notes also provides for events of default, which, if any of them occur, would permit or require the principal, premium, if any, and interest on all then outstanding Senior Secured Notes to be due and payable immediately.
Convertible Senior Notes.  The Company issued and sold $215.5 million in aggregate principal amount of its 5.75% Senior Convertible Notes due 2014 (the “Convertible Senior Notes”) during June and July 2009. The Convertible Senior Notes are unsecured and pay interest semi-annually in arrears at a rate of 5.75% per year beginning on December 15, 2009. The Convertible Senior Notes will mature on June 15, 2014. The initial conversion rate for the Convertible Senior Notes is 92.5926 shares of common stock per $1,000 principal amount of Convertible Senior Notes (equivalent to an initial conversion price of approximately $10.80 per share of common stock). In lieu of delivery of shares of common stock in satisfaction of the Company’s obligation upon conversion of the Convertible Senior Notes, the Company may elect to settle conversions entirely in cash or by net share settlement. Proceeds from the issuance of the Convertible Senior Notes of $209.0 million, net of underwriting discounts of $6.5 million, were used to repay a portion of outstanding indebtedness under the Term Loan. Issuers of convertible debt instruments that may be settled in cash upon conversion (including partial cash settlement) are required to separately account for the liability and equity (conversion feature) components of the instruments in a manner reflective of the issuer’s nonconvertible debt borrowing rate. The borrowing rate used by the Company to determine the liability and equity components of the Convertible Senior Notes was 13.75%. The Company paid $0.5 million in other financing costs related to the Convertible Senior Notes in 2009. The Company valued the conversion feature at June 30, 2009 at $60.9 million and recorded additional paid-in capital of $36.3 million, net of deferred income taxes of $22.6 million and transaction costs of $2.0 million, related to the equity portion of this convertible debt. The discount on the Convertible Senior Notes is amortized using the effective interest method through maturity on June 15, 2014.
The Convertible Senior Notes are convertible, at the option of the holder, in any future calendar quarter (prior to maturity) whenever the last reported sale price of the Company’s common stock exceeds $14.04 for twenty days in the thirty consecutive trading day period ending on the last trading day of the immediately preceding calendar quarter. If any Convertible Senior Notes are surrendered for conversion, the Company may elect to satisfy its obligations upon conversion through the delivery of shares of its common stock, in cash or a combination thereof.
Term Loan Credit Agreement.  On March 29, 2011, we entered into an amended and restated Term Loan Credit Agreement. Lenders under the amended and restated Term Loan Credit Agreement extended a $325.0 million term loan ("Term Loan") at a discount of 1.00%, the proceeds of which were principally used to refinance the term loans outstanding under the Term Loan Credit Agreement prior to the amendment and restatement. The Term Loan, together with the Fixed Rate Notes and any future other pari passu secured obligations, is secured on a first priority basis by our fixed assets, and on a second priority basis by the collateral securing the Revolving Credit Agreement, which consists of our cash and cash equivalents, trade accounts receivable, and inventory. The amended and restated Term Loan Credit Agreement eliminated the financial maintenance covenants previously contained in the Term Loan Credit Agreement. The amended and restated Term Loan Credit Agreement provides for principal payments on a quarterly basis of $0.8 million, with the remaining balance due on the maturity date. The maturity date was extended to March 15, 2017. To effect this amendment and restatement, we paid $3.7 million in amendment fees.
As a result of the March 29, 2011 amendment and restatement, the Term Loan bears interest equal to LIBOR (subject to a floor of 1.5%) plus 6.00%. Prior to the amendment and restatement, the term loan bore interest equal to LIBOR (subject to a floor of 3.25%) plus 7.50%.

The amended and restated Term Loan Credit Agreement contains covenants that limit our (and most of our subsidiaries') ability to, among other things: (i) pay dividends or make other distributions in respect of our capital stock or make other restricted payments; (ii) make certain investments; (iii) sell certain assets; (iv) incur additional debt; (v) create liens on certain assets; (vi) consolidate, merge, sell or otherwise dispose of all or substantially all of our assets; (vii) engage in different businesses; (viii) enter into certain transactions with our affiliates; (ix) restrict dividends or other payments from restricted subsidiaries; and (x) prepay certain indebtedness. Total dividend distributions for 2012 are limited to $20.0 million in total, increasing by $5.0 million each year through maturity of the amended and restated Term Loan Credit Agreement.

88


On September 23, 2011, we amended the amended and restated Term Loan Credit Agreement to provide for certain conforming changes made in the amended and restated Revolving Credit Agreement (described below).
Revolving Credit Agreement.  On September 22, 2011, we entered into an amended and restated Revolving Credit Agreement. Lenders under the amended and restated Revolving Credit Agreement extended $1.0 billion in revolving commitments that mature on September 22, 2016, and incorporate a borrowing base tied to eligible accounts receivable and inventory. The amended and restated Revolving Credit Agreement also provides for letters of credit and swing line loans. The amended and restated Revolving Credit Agreement provides for a quarterly commitment fee of either 0.375% or 0.50% per annum subject to adjustment based upon the average excess availability under the amended and restated Revolving Credit Agreement and quarterly letter of credit fees ranging from 2.50% to 3.25% per annum subject to adjustment based upon the average excess availability. Borrowings can be either base rate loans plus a margin ranging from 1.50% to 2.25% or LIBOR loans plus a margin ranging from 2.50% to 3.25% in each case subject to adjustment based upon the average excess availability under the amended and restated Revolving Credit Agreement. The interest rate margins and letter of credit fees are to be reduced by 0.25% upon our achievement and maintenance of a certain fixed charge coverage ratio. The amended and restated Revolving Credit Agreement provides for a cash dominion requirement that is in effect only if there is an event of default or the excess availability under the amended and restated Revolving Credit Agreement falls below the greater of (i)15.0% of the Borrowing Base and (ii) $50.0 million. The amended and restated Revolving Credit Agreement is secured on a first priority basis by our cash and cash equivalents, trade accounts receivable, and inventory, and on a second priority basis by the collateral securing the Term Loan, the Fixed Rate Notes, and any future other pari passu secured obligations, which consist of our fixed assets. The revolving facility is used to fund general working capital needs and letter of credit requirements. We paid $5.9 million in fees to effect the September 22, 2011 amendment and restatement to the Revolving Credit Agreement.
Prior to September 22, 2011 the Revolving Credit Agreement included commitments of $800.0 million composed of a $145.0 million tranche that matured on May 31, 2012 and $655.0 million tranche that matured on January 1, 2015. Interest rates for the $145.0 million tranche were based on our consolidated leverage ratio and ranged from 3.75% to 4.50% over LIBOR. Interest rates for the $655.0 million tranche were based on our borrowing base capacity under the Revolving Credit Agreement and ranged from 3.00% to 3.75% over LIBOR.

The amended and restated Revolving Credit Agreement contains covenants that limit our (and most of our subsidiaries') ability to, among other things: (i) pay dividends or make other distributions in respect of our capital stock or make other restricted payments; (ii) make certain investments; (iii) sell certain assets; (iv) incur additional debt; (v) create liens on certain assets; (vi) consolidate, merge, sell or otherwise dispose of all or substantially all of our assets; (vii) engage in different businesses; (viii) enter into certain transactions with our affiliates; (ix) restrict dividends or other payments from restricted subsidiaries; and (x) prepay certain indebtedness.

As of December 31, 2011, the Company had gross availability under the Revolving Credit Agreement of $745.3 million, of which $344.7 million was used for outstanding letters of credit.
Guarantors of the Term Loan and the Revolving Credit Agreement.  The amended and restated Term Loan Credit Agreement and the amended and restated Revolving Credit Agreement (together, the “Agreements”) are guaranteed, on a joint and several basis, by subsidiaries of Western Refining, Inc. No amounts have been recorded for these guarantees.
Letters of Credit
The Revolving Credit Agreement provides for the issuance of letters of credit. The Company issues and cancels letters of credit on a periodic basis depending upon its needs. At December 31, 2011, there were $344.7 million of irrevocable letters of credit outstanding, primarily issued to crude oil suppliers under the Revolving Credit Agreement.


89


14.
Income Taxes
The following is an analysis of the Company’s consolidated income tax expense (benefit) for the three years ended December 31, 2011:

 
Year Ended December 31,
 
2011
 
2010
 
2009
 
(In thousands)
Current:
 

 
 

 
 

Federal
$
106,386

 
$
(7,554
)
 
$
20,387

State
13,268

 
(1,036
)
 
2,395

Total current
119,654

 
(8,590
)
 
22,782

Deferred:
 

 
 

 
 

Federal
(48,085
)
 
(15,297
)
 
(53,704
)
State
(1,708
)
 
(2,190
)
 
(9,661
)
Total deferred
(49,793
)
 
(17,487
)
 
(63,365
)
Provision for income taxes
$
69,861

 
$
(26,077
)
 
$
(40,583
)

The Company paid income tax, net of refunds, of $70.2 million and received income tax refunds of $49.8 million and $7.2 million for the year ended December 31, 2011, 2010, and 2009, respectively. The following is a reconciliation of total income tax expense (benefit) to income taxes computed by applying the 35% statutory federal income tax rate to income (loss) before income taxes for the three years ended December 31, 2011:

 
Year Ended December 31,
 
2011
 
2010
 
2009
 
(In thousands)
Tax computed at the federal statutory rate
$
70,885

 
$
(15,094
)
 
$
(136,921
)
State income taxes, net of federal tax benefit
(15,863
)
 
(5,588
)
 
(6,261
)
Goodwill impairment loss

 

 
104,843

Valuation allowance for state net operating losses
23,700

 

 

Domestic Activity Production Deduction
(8,309
)
 

 

Federal tax credit for production of ultra low sulfur diesel
(109
)
 
(4,747
)
 
(4,601
)
Other, net
(443
)
 
(648
)
 
2,357

Total income tax expense (benefit)
$
69,861

 
$
(26,077
)
 
$
(40,583
)

The effective tax rate for 2011 was 34.5% as compared to the federal statutory rate of 35%. The effective tax rate was lower primarily due to the Domestic Activity Production Deduction and a state tax benefit. The state income tax benefit of $15.9 million for December 31, 2011 was due to a book loss from operations and sale of the Company's Yorktown facility. This benefit is offset by a valuation allowance of $23.7 million against the entire amount of Virginia and Maryland net operating losses.
The effective tax rate for 2010 was 60.5%, as compared to the federal statutory rate of 35%. The effective tax rate was higher primarily because of the federal income tax credit available to small business refiners that produce ultra low sulfur diesel fuel.
The effective tax rate for 2009 was 44.3%, excluding the effect of the non-deductible goodwill impairment of $299.6 million, as compared to the federal statutory rate of 35%. The effective tax rate was higher primarily due to the federal income tax credit available to small business refiners related to the production of ultra low sulfur diesel fuel.
The Company is currently under examination by the Internal Revenue Service (“IRS”) for tax years ended December 31, 2007 and December 31, 2008. The Company concluded the 2006 and short period 2007 exam for legacy Giant with no material

90


changes. The Company continues to work with the IRS in an effort to conclude the 2007 and 2008 examinations. The Company does not believe the results of these examinations will have a material adverse effect on the Company’s financial position or results of operations upon conclusion. While the Company does not believe the results of these examinations will have a material adverse effect on the Company’s financial position or results of operations, the timing and results of any final determination remain uncertain.
As a result of the Giant acquisition on May 31, 2007, the Company recorded a liability of $5.2 million for unrecognized tax benefits, of which $0.5 million would affect the Company’s effective tax rate if recognized. The Company had no unrecognized tax benefits for 2011 or 2010 and recognized no interest or penalties in either year. The following is a reconciliation of unrecognized tax benefits for the three years ended December 31, 2011:
 
December 31,
 
2011
 
2010
 
2009
 
(In thousands)
Unrecognized tax benefits at beginning of year
$

 
$

 
$
5,898

Increases (decreases) related to current year tax positions

 

 

Increases (decreases) related to prior year tax positions

 

 

Decreases related to settlements with taxing authorities

 

 
(5,898
)
Decreases resulting from the expiration of the statute of limitations

 

 

Unrecognized tax benefits at end of year
$

 
$

 
$


Based on the results of the examination of the Company’s 2005 federal income tax return, the Company’s uncertain tax positions were settled favorably. Accordingly, $6.3 million in estimated liabilities related to the Company’s uncertain tax positions were reversed during the third quarter of 2009, including $0.5 million that affected the Company’s effective tax rate and $0.4 million for interest and penalties.
Tax years 2007-2011 remain open to examination by the major tax jurisdictions to which the Company is subject (U.S. Federal, Texas, Virginia, Maryland, New Mexico, Arizona, and California).

91


The tax effects of significant temporary differences representing deferred income tax assets and liabilities were as follows:

 
December 31,
 
2011
 
2010
 
Assets
 
Liabilities
 
Net
 
Assets
 
Liabilities
 
Net
 
(In thousands)
Current deferred taxes:
 

 
 

 
 

 
 

 
 

 
 

Inventories
$

 
$
(39,332
)
 
$
(39,332
)
 
$

 
$
(58,934
)
 
$
(58,934
)
Stock-based compensation
1,841

 

 
1,841

 
1,576

 

 
1,576

Commodity hedging activities

 
(68,365
)
 
(68,365
)
 

 

 

Other current, net
301

 

 
301

 

 
(1,571
)
 
(1,571
)
Current deferred taxes
2,142

 
(107,697
)
 
(105,555
)
 
1,576

 
(60,505
)
 
(58,929
)
Noncurrent deferred taxes:
 

 
 

 
 

 
 

 
 

 
 

Property, plant, and equipment

 
(250,140
)
 
(250,140
)
 

 
(444,218
)
 
(444,218
)
Intangible assets

 
(3,853
)
 
(3,853
)
 

 
(9,829
)
 
(9,829
)
Postretirement obligations
2,604

 

 
2,604

 
1,721

 

 
1,721

Debt discount

 
(13,139
)
 
(13,139
)
 

 
(17,375
)
 
(17,375
)
Environmental and retirement obligations
1,410

 

 
1,410

 
3,321

 

 
3,321

Other noncurrent, net
626

 

 
626

 
5,766

 

 
5,766

Net operating loss and tax credit carryforwards
23,700

 

 
23,700

 
99,322

 

 
99,322

Valuation allowance
(23,700
)
 

 
(23,700
)
 

 

 

Noncurrent deferred taxes
4,640

 
(267,132
)
 
(262,492
)
 
110,130

 
(471,422
)
 
(361,292
)
Net deferred taxes
$
6,782

 
$
(374,829
)
 
$
(368,047
)
 
$
111,706

 
$
(531,927
)
 
$
(420,221
)

At December 31, 2011, the Company had the following credits and net operating loss (“NOL”) carryforwards:

Type of Credit
Gross Amount
 
Tax Effected Amount
 
Expiration
 
(In thousands)
State NOL carryforwards:
 

 
 

 
 
Virginia and Maryland
$
(14,401
)
 
$
(562
)
 
2023
Virginia and Maryland
(636
)
 
(25
)
 
2024
Virginia and Maryland
(34,729
)
 
(1,386
)
 
2026
Virginia and Maryland
(59,277
)
 
(2,468
)
 
2027
Virginia and Maryland
(91,878
)
 
(3,752
)
 
2028
Virginia and Maryland
(154,526
)
 
(6,401
)
 
2029
Virginia and Maryland
(174,507
)
 
(7,421
)
 
2030
Virginia and Maryland
(40,601
)
 
(1,685
)
 
2031
Total state NOL carryforwards
(570,555
)
 
(23,700
)
 
 
Less valuation allowance for operating loss carryforwards
570,555

 
23,700

 
 
Total credits and NOL carryforwards
$

 
$

 
 


92


In assessing the realizability of deferred tax assets, the Company considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. The Company considers the scheduled reversal of deferred tax liabilities, expected future taxable income and tax planning strategies in making this assessment. For the year ended December 31, 2011, the increase in the valuation allowance was $23.7 million against the deferred tax assets for Virginia and Maryland.

15.
Retirement Plans
The Company fully recognizes the obligations associated with its single-employer defined benefit pension, retiree healthcare, and other postretirement plans in its financial statements.
Pensions
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. In connection with the sale of the Yorktown refinery during the fourth quarter of 2011, the Company intends to terminate the defined benefit plan covering certain previous Yorktown refinery employees. Such termination is subject to regulatory approval, which may take several months. The Company expects to contribute $2.5 million to its Yorktown pension plan in 2012, depending upon the plan's status at the end of 2012.
In connection with the negotiation of a collective bargaining agreement covering employees of the El Paso refinery during the second quarter of 2009, the Company terminated the defined benefit plan covering certain El Paso refinery employees. Regulatory approval of this termination was received during the first quarter of 2010. The Company distributed $21.7 million through December 2010, ($4.2 million in 2010 and $17.5 million in 2009) from plan assets to plan participants as a result of the termination agreement. Distributions made were in accordance with the termination agreement. Additionally, the Company transferred $2.5 million from plan assets to a third-party annuity. The termination resulted in reductions to the related pension obligation of $5.2 million and to other comprehensive loss of $0.6 million in the year ended December 31, 2010.

93


The following tables set forth significant information about the Company’s pension plans for certain El Paso and Yorktown refinery employees. The reconciliation of the benefit obligation, plan assets, funded status, and significant assumptions are based upon an annual measurement date of December 31:

 
As of December 31,
 
2011
 
2010
 
(In thousands)
Benefit obligation at beginning of year
$
14,743

 
$
28,186

Service cost

 
1,802

Interest cost
450

 
1,221

Benefits paid
(29
)
 
(27
)
Termination benefits paid
(7,215
)
 
(19,460
)
Actuarial (gain) loss
(675
)
 
4,435

Plan amendments

 
(553
)
Curtailment

 
181

Settlement

 
(1,042
)
Benefit obligation at end of year
$
7,274

 
$
14,743

Fair value of plan assets at beginning of year
$
7,659

 
$
15,973

Company contribution
4,400

 
10,640

Actual return on plan assets
(2
)
 
533

Benefits paid
(29
)
 
(27
)
Termination benefits paid
(7,215
)
 
(19,460
)
Fair value of plan assets at end of year
$
4,813

 
$
7,659

Current liabilities
$
(2,461
)
 
$
(7,084
)
Noncurrent liabilities

 

Unfunded status recognized in the consolidated balance sheets
$
(2,461
)
 
$
(7,084
)
Accumulated benefit obligation
$
7,274

 
$
14,743


 
Year Ended December 31,
 
2011
 
2010
 
2009
 
(In thousands)
Net periodic benefit cost includes:
 

 
 

 
 

Service cost
$


$
1,802


$
2,476

Interest cost
450


1,221


2,415

Expected return on assets
(119
)

(1,436
)

(2,609
)
Amortization of net actuarial loss


5


156

Recognized settlement expense
1,537


4,407


1,793

Recognized curtailment gain


(1,006
)

(1,508
)
Net periodic benefit cost
$
1,868


$
4,993


$
2,723

Pre-tax unrecognized net loss included in accumulated other comprehensive loss at beginning of year
$
3,641


$
3,123


$
30,150

Net actuarial (gain) loss
(554
)

4,296


(26,871
)
Recognition of loss due to settlement
(1,537
)

(3,773
)


Amortization of net actuarial loss


(5
)

(156
)
Pre-tax unrecognized net loss included in accumulated other comprehensive loss at end of year
$
1,550


$
3,641


$
3,123


94



 
Year Ended December 31,
 
2011(1)
 
2010(1)
 
2009
Weighted average assumptions used to determine
benefit obligations at December 31:
 

 
 

 
 

Discount rate
3.67
%

4.63
%

5.37
%
Rate of compensation increase


3.50


3.50

Weighted average assumptions used to determine
net periodic benefit cost:
 

 
 

 
 

Discount rate
4.63


5.25


5.80

Expected long-term return on assets(2)
1.90


8.50


8.50

Rate of compensation increase


3.50


3.50

_______________________________________
(1)
Weighted average assumptions used to determine the expected benefit obligation and net periodic benefit cost in 2011 and 2010 are for the Yorktown pension plan only.
(2)
All benefit plan assets for the Yorktown pension plan have been moved into cash equivalents and the Company’s expected long-term rate of return on assets has been lowered to 1.9%.
The following benefit payments (in thousands) are expected to be paid in the years indicated:

2012
$
2,465

2013
490

2014
530

2015
480

2016
400

2017-2021
1,720

Postretirement Obligations
The following tables set forth significant information about the Company’s retiree medical plans for certain El Paso and Yorktown employees. Unlike the pension plans, the Company is not required to fund the retiree medical plans on an annual basis. Based on an annual measurement date of December 31, and discount rates of 4.33% and 5.92% at December 31, 2011 and 2010, respectively, to determine the benefit obligation, the components of the postretirement obligation were:
 
As of December 31,
 
2011
 
2010
 
(In thousands)
Benefit obligation at beginning of year
$
4,070


$
8,486

Service cost
84


490

Interest cost
257


493

Benefits paid
(211
)

(81
)
Actuarial loss
1,765


720

Curtailment gain


(6,038
)
Benefit obligation at end of year
$
5,965


$
4,070

Unfunded status
$
(5,965
)

$
(4,070
)
Current liabilities
$
(220
)

$
(161
)
Noncurrent liabilities
(5,745
)

(3,909
)
Unfunded status recognized in the consolidated balance sheets
$
(5,965
)

$
(4,070
)

95



 
Year Ended December 31,
 
2011
 
2010
 
2009
 
(In thousands)
Net periodic benefit cost includes:
 

 
 

 
 

Service cost
$
84


$
490


$
511

Interest cost
257


493


442

Amortization of net actuarial (gain) loss
4


(20
)

(11
)
Net periodic benefit cost
$
345


$
963


$
942

Pre-tax unrecognized net gain included in accumulated other comprehensive gain at beginning of year
$
(410
)

$
(859
)

$
(49
)
Net actuarial (gain) loss
1,765


(24
)

(821
)
Recognition of curtailment gain


453



Amortization of net actuarial (gain) loss
(4
)

20


11

Pre-tax unrecognized net (gain) loss included in accumulated other comprehensive gain at end of year
$
1,351


$
(410
)

$
(859
)

The weighted average discount rates used to determine net periodic benefit costs were 5.64%, 5.92%, and 5.75% for 2011, 2010, and 2009, respectively. The following benefit payments (in thousands) are expected to be paid in the year indicated:

2012
$
225

2013
241

2014
267

2015
287

2016-2020
1,989


The health care cost trend rate for the plan covering El Paso employees for 2011 and future years is capped at 4.0%. The health care cost trend rate for the plan covering Yorktown employees for 2011 is 7.0% trending to 4.50% in 2015. A 1%-point change in the assumed health care cost trend rate for both plans will have the following effect:

 
1%-points
 
Increase(1)
 
Decrease
 
(In thousands)
Effect on total service cost and interest cost
$
1


$
(37
)
Effect on accumulated benefit obligation
26


(519
)
_______________________________________
(1)
There is no impact for a 1%-point increase in the El Paso plan because the plan covers up to a 4% increase per year. Any increase in health care costs in excess of 4% is absorbed by the participant.
The following tables present the fair values of the assets of our pension plans as of December 31, 2011 and 2010 by level of the fair value hierarchy. Assets categorized in Level 1 of the hierarchy are measured at fair value using a market approach based on quotations from national securities exchanges. Assets categorized in Level 2 of the hierarchy are measured at net asset value as a practical expedient for fair value. As noted above, our other postretirement benefit plans are funded on a pay-as-you-go basis and have no assets.

96


 
 
 
Fair Value Measurement Using
 
Total as of
December 31,
2011
 
Quoted Prices in
Active Markets
(Level 1)
 
Significant
Other
Observable
Inputs
(Level 2)
 
Significant
Unobservable
Inputs
(Level 3)
 
(In thousands)
Cash equivalents
$
4,813

 
$
4,813

 
$

 
$


 
Total as of
December 31,
2010
 
Quoted Prices in
Active Markets
(Level 1)
 
Significant
Other
Observable
Inputs
(Level 2)
 
Significant
Unobservable
Inputs
(Level 3)
 
(In thousands)
Cash equivalents
$
7,659

 
$
7,659

 
$

 
$

Defined Contribution Plans
The Company sponsors a 401(k) defined contribution plan under which participants may contribute a percentage of their eligible compensation to the plan and invest in various investment options. The Company will match participant contributions to the plan subject to certain limitations and a per participant maximum contribution. Beginning January 1, 2010, for each 1% of eligible compensation contributed by the participant, the Company matched 1% up to a maximum of 4% of eligible compensation, provided the participant had a minimum of one year of service with the Company. For each 1% of eligible compensation contributed by the participant throughout 2009, the Company matched 2% up to a maximum of 8% of eligible compensation, provided the participant had a minimum of one year of service with the Company. The Company expensed $5.8 million, $6.2 million, and $8.9 million in connection with this plan for the years ended December 31, 2011, 2010, and 2009, respectively.

16.
Crude Oil and Refined Product Risk Management
The Company enters into crude oil forward contracts to facilitate the supply of crude oil to the refineries. During 2011, 2010, and 2009, the Company entered into net forward, fixed-price contracts to physically receive and deliver crude oil that qualify as normal purchases and normal sales and are exempt from derivative reporting requirements.
The Company uses crude oil and refined products futures, swap contracts, or options to mitigate the change in value for a portion of its LIFO inventory volumes subject to market price fluctuations, and swap contracts to fix the margin on a portion of its future gasoline and distillate production. The physical volumes are not exchanged, and these contracts are net settled with cash. 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.
The fair value of these contracts is reflected in the Consolidated Balance Sheets and the related net gain or loss is recorded within cost of products sold in the Consolidated Statements of Operations. Quoted prices for similar assets or liabilities in active markets (Level 2) are considered to determine the fair values for the purpose of marking to market the hedging instruments at each period end. At December 31, 2011, the Company had open commodity hedging instruments consisting of crude oil futures on 933,000 barrels and refined products price and crack spread swaps on 29,282,500 barrels primarily to fix the margin on a portion of its future gasoline and distillate production and to protect the value of certain crude oil, refined product, and blendstock inventories. The fair value of the outstanding contracts at December 31, 2011 was a net unrealized gain of $182.1 million comprised of both short-term and long-term unrealized gains and losses. This net unrealized gain consists of $128.1 million in other current assets, $54.2 million in other assets, and $0.2 million in current liabilities.


97


At December 31, 2010, the Company had open commodity hedging instruments consisting of crude oil futures and refined products price and crack spread swaps on 1,023,000 barrels primarily to fix the margin on a portion of its future gasoline and distillate production and to protect the value of certain crude oil, refined product, and blendstock inventories. The fair value of the outstanding contracts at December 31, 2010 was a net unrealized loss of $1.2 million comprised of short-term unrealized gains and losses. This net unrealized loss consists of $1.0 million in other current assets and $2.2 million in current liabilities.

At December 31, 2009, the Company had open commodity hedging instruments consisting of crude oil futures and refined products price and crack spread swaps on 268,000 barrels primarily to fix the margin on a portion of its future gasoline and distillate production and to protect the value of certain crude oil, refined product, and blendstock inventories. The fair value of the outstanding contracts at December 31, 2009 was a net unrealized loss of $1.5 million comprised of short-term unrealized gains and losses. This net unrealized loss consists of $0.8 million in other current assets and $2.3 million in current liabilities.

The Company's commodity hedging activities are initiated within guidelines established by management and approved by the Company's board of directors. Commodity hedging transactions are executed centrally on behalf of all of the Company's operating segments to minimize transaction costs, monitor consolidated net exposures, and to allow for increased responsiveness to changes in market factors. Due to mark-to-market accounting during the term of the various commodity hedging contracts, significant unrealized, non-cash gains and losses could be recorded in period results of operations. Additionally, the Company may be required to collateralize any mark-to-market losses on outstanding commodity hedging contracts.
As of December 31, 2011, we had the following outstanding crude oil and refined product hedging instruments that were entered into as economic hedges. The information presents the notional volume of outstanding contracts by type of instrument and year of maturity (volumes in thousands of barrels):
 
Notional Contract Volumes by Year of Maturity
 
2012
 
2013
 
2014
Inventory positions (futures and swaps):
 
 
 
 
 
Crude oil and refined products — net short positions
933





Refined product positions (crack spread swaps):
 
 
 
 
 
Distillate — net short positions
9,750

8,325,000

8,958

1,800,000

2,700

Unleaded gasoline — net short positions
7,875

9,600





The Company recognized $107.3 million, within cost of products sold, of net realized and unrealized gains from commodity hedging activities for the year ended December 31, 2011. The company recognized $9.4 million and $21.7 million, within cost of products sold, of net realized and unrealized losses from commodity hedging activities for 2010 and 2009, respectively.

17.
Stock-Based Compensation
The Company has two share-based compensation plans, the Western Refining 2006 Long-Term Incentive Plan (the “2006 LTIP”) and the 2010 Incentive Plan of Western Refining, Inc. (the “2010 Incentive Plan”) which allow for restricted share awards and restricted share unit awards. As of December 31, 2011, there were 39,896 and 3,423,408 shares of common stock reserved for future grants under the 2006 LTIP and the 2010 Incentive Plan, respectively. Awards granted under both plans generally vest over a three-year period and their market value at the date of the grant is amortized over the restricted period on a straight-line basis.
    As of December 31, 2011, there were 1,511,242 and 316,917 unvested restricted shares and unvested restricted share units, respectively, outstanding.
In January 2009, the Company adopted the provisions related to specific accounting requirements for realized income tax benefits from dividends. A realized income tax benefit from dividends or dividend equivalents that are (a) paid to employees holding equity-classified nonvested shares, equity-classified nonvested share units, or equity-classified outstanding share options and (b) charged to retained earnings, should be recognized as an increase to additional paid-in capital. The amount recognized in additional paid-in capital for the realized income tax benefit from dividends on those awards should be included in the pool of excess tax benefits available to absorb tax deficiencies on share-based payment awards. The adoption of these provisions did not have an impact on the Company’s financial position or results of operations during 2010 and 2009.

98


The Company recorded stock compensation expense of $8.2 million for the year ended December 31, 2011, of which $0.9 million was included in direct operating expenses and $7.3 million in selling, general, and administrative expenses. The tax benefit related to the shares that vested during the year ended December 31, 2011 was $3.2 million using a statutory blended rate of 37.54%. The aggregate fair value at the grant date of the shares that vested during the year ended December 31, 2011 was $7.5 million. The related aggregate intrinsic value of these shares was $16.0 million at the vesting date.
The Company recorded stock compensation expense of $5.9 million for the year ended December 31, 2010, of which $0.6 million was included in direct operating expenses and $5.3 million in selling, general, and administrative expenses. The tax deficiency related to the shares that vested during the year ended December 31, 2010, was $1.1 million using a statutory blended rate of 37.54%. The aggregate fair value at the grant date of the shares that vested during the year ended December 31, 2010, was $4.8 million. The related aggregate intrinsic value of these shares was $1.9 million at the vesting date.
The Company recorded stock compensation expense of $4.7 million for the year ended December 31, 2009, of which $1.1 million was included in direct operating expenses and $3.6 million in selling, general, and administrative expenses. The tax deficiency related to the shares that vested during the year ended December 31, 2009, was $1.1 million using a statutory blended rate of 37.17%. The aggregate fair value at the grant date of the shares that vested during the year ended December 31, 2009, was $5.1 million. The related aggregate intrinsic value of these shares was $3.0 million at the vesting date.
As of December 31, 2011, the aggregate fair value at grant date of restricted shares and restricted share units was $9.5 million and $5.1 million, respectively. The aggregate intrinsic value of restricted shares and restricted share units was $20.1 million and $4.2 million, respectively. The unrecognized compensation cost of nonvested restricted shares and restricted share units was $6.1 million and $3.6 million, respectively. Unrecognized compensation cost for restricted shares and restricted share units will be recognized over a weighted average period of approximately 1.23 years and 1.99 years, respectively. The following table summarizes the Company’s restricted stock activity for the three years ended December 31, 2011:

 
Restricted Share Units
 
Restricted Shares
 
Number of Units
 
Weighted Average
Grant Date
Fair Value
 
Number of Shares
 
Weighted Average
Grant Date
Fair Value

Nonvested at December 31, 2008

 
$

 
594,260

 
$
18.55

Awards granted

 

 
509,210

 
10.39

Awards vested

 

 
(261,723
)
 
19.54

Awards forfeited

 

 
(47,068
)
 
23.12

Nonvested at December 31, 2009

 

 
794,679

 
12.72

Awards granted

 

 
2,072,797

 
5.81

Awards vested

 

 
(336,293
)
 
14.35

Awards forfeited

 

 
(93,036
)
 
10.00

Nonvested at December 31, 2010

 

 
2,438,147

 
6.73

Awards granted
316,917

 
16.09

 
52,033

 
11.71

Awards vested

 

 
(976,527
)
 
7.64

Awards forfeited

 

 
(2,411
)
 
12.30

Nonvested at December 31, 2011
316,917

 
16.09

 
1,511,242

 
6.29


18.
Stockholders’ Equity
On January 24, 2006, the Company completed an initial public offering of 18,750,000 shares of its common stock at an aggregate offering price of $318.8 million. The Company received approximately $297.2 million in net proceeds from the initial public offering.
On June 10, 2009, the Company issued an additional 20,000,000 shares of its common stock, par value $0.01 per share at an aggregate offering price of $180.0 million. The net proceeds of this issuance were $170.4 million, net of underwriting discounts of $9.0 million and $0.6 million in issuance costs related to this offering. In addition, during June and July 2009, the Company issued and sold $215.5 million in Convertible Senior Notes and recorded additional paid-in capital of $36.3 million, net of deferred income taxes of $22.6 million and transaction costs of $2.0 million related to the equity portion of this

99


convertible debt. The proceeds of these issuances were used to repay a portion of the outstanding indebtedness under the Company’s Term Loan.
Prior to 2010, the Company repurchased 698,006 shares of its common stock to cover payroll withholding taxes for certain employees pursuant to the vesting of restricted shares awarded under the Western Refining Long-Term Incentive Plan. The aggregate cost paid for these shares was $21.4 million. The Company recorded these repurchases as treasury stock. There have been no such repurchases subsequent to 2009.
On January 4, 2012, the Company's Board of Directors approved a cash dividend of $0.04 per share of common stock, which was paid on February 13, 2012.

19.
Earnings Per Share
On January 1, 2009, the Company adopted the provisions related to the accounting treatment of certain participating securities for the purpose of determining earnings per share. These provisions address unvested share-based payment awards that contain nonforfeitable rights to dividends or dividend equivalents and states that they are participating securities and should be included in the computation of earnings per share pursuant to the two-class method. As discussed in Note 17, Stock-Based Compensation, the Company has granted shares of restricted stock to certain employees and outside directors of the Company. Although ownership of these shares does not transfer to the recipients until the shares have vested, recipients have voting and nonforfeitable dividend rights on these shares from the date of grant. As a result of the adoption of the provisions related to participating securities, the Company applied the two-class method to determine its earnings per share for all periods presented. Shares of common stock potentially issuable for the Company’s Convertible Senior Notes were not included in the Company’s computation of diluted loss per share for the year ended December 31, 2010 or 2009 because they were anti-dilutive.
The computation of basic and diluted earnings per share under the two-class method is presented below:
 
Year Ended December 31,
 
2011
 
2010
 
2009
Basic Earnings (loss) per common share:
(In thousands, except per share data)
Allocation of earnings (losses):
 

 
 

 
 

Net income (loss)
$
132,667

 
$
(17,049
)
 
$
(350,621
)
Distributed earnings

 

 

Income allocated to participating securities
(2,673
)
 

 

Undistributed income (loss) available to common shareholders
$
129,994

 
$
(17,049
)
 
$
(350,621
)
Weighted average number of common shares outstanding:
88,981

 
88,204

 
79,163

Basic earnings (loss) per common share:
 

 
 

 
 

Distributed earnings per share
$

 
$

 
$

Undistributed earnings (loss) per share
1.46

 
(0.19
)
 
(4.43
)
Basic earnings (loss) per common share
$
1.46

 
$
(0.19
)
 
$
(4.43
)
 


 


 


Diluted earnings (loss) per common share:
 
 
 
 
 
Net Income (loss)
$
132,667

 
$
(17,049
)
 
$
(350,621
)
Tax effected interest related to convertible debt
14,787

 

 

Net income (loss) available to common stockholders, assuming dilution
147,454

 
(17,049
)
 
(350,621
)
 


 


 


Weighted average number of diluted shares outstanding:
109,792

 
88,204

 
79,163

Diluted earnings (loss) per common share
$
1.34

 
$
(0.19
)
 
$
(4.43
)

The following table reflects potentially dilutive securities that were excluded from the diluted earnings (loss) per common share calculation as the effect of including such shares would have been antidilutive:


100


 
Year Ended December 31,
 
2011
 
2010
 
2009
 
(In thousands)
Common equivalent shares from Convertible Senior Notes

 
19,949

 
19,949

Restricted stock

 
179

 
20


20.
Related Party Transactions
Effective May 1, 2009, the non-exclusive aircraft lease with an entity controlled by the Company’s majority stockholder was terminated by the Company and as a result, it no longer operates a private aircraft. The hourly rental payment was $1,775 per flight hour and the Company was responsible for all operating and maintenance costs of the aircraft. Personal use of the aircraft by certain officers of the Company was reimbursed to the Company at the highest rate allowed by the Federal Aviation Administration for a non-charter operator. In addition, the Company had a policy requiring that its officers deposit in advance of any personal use of the aircraft an amount equal to three months of anticipated expenses for the use of the aircraft. The following table summarizes the total costs incurred for the lease of the aircraft for the year ended December 31, 2009:

 
 
Year Ended December 31, 2009
 
 
(In thousands)
Lease payments
 
$
181

Operating and maintenance expenses
 
456

Reimbursed by officers
 
(321
)
Total costs
 
$
316



21.
Contingencies
Environmental Matters
Like other petroleum refiners, the Company’s operations are subject to extensive and periodically changing federal and state environmental regulations governing air emissions, wastewater discharges, and solid and hazardous waste management activities. The Company’s policy is to accrue environmental and clean-up related costs of a non-capital nature when it is probable that a liability has been incurred and the amount can be reasonably estimated. Such estimates may be subject to revision in the future as regulations and other conditions change.
Periodically, the Company receives communications from various federal, state, and local governmental authorities asserting violation(s) of environmental laws and/or regulations. These governmental entities may also propose or assess fines or require corrective action for these asserted violations. The Company intends to respond in a timely manner to all such communications and to take appropriate corrective action. The Company does not anticipate that any such matters currently asserted will have a material adverse impact on its financial condition, results of operations, or cash flows.
El Paso Refinery
The groundwater and certain solid waste management units and other areas at and adjacent to the El Paso refinery have been impacted by prior spills, releases, and discharges of petroleum or hazardous substances and are currently undergoing remediation by the Company and Chevron Products Company (“Chevron”) pursuant to certain agreed administrative orders with the Texas Commission on Environmental Quality (“TCEQ”). Pursuant to the Company’s purchase of the north side of the El Paso refinery from Chevron, Chevron retained responsibility to remediate their solid waste management units in accordance with its Resource Conservation Recovery Act (“RCRA”) permit, which Chevron has fulfilled. Chevron also retained liability for, and control of, certain groundwater remediation responsibilities, which are ongoing.
In May 2000, the Company entered into an Agreed Order with the Texas Natural Resources Conservation Commission, now known as the TCEQ, for remediation of the south side of the El Paso refinery property. The Company 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

101


addition, under a settlement agreement with the Company, a subsidiary of Chevron is obligated to pay 60% of any Agreed Order environmental clean-up 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 the Company of a deductible of $0.1 million per incident as well as any costs that exceed the covered limits of the insurance policy.
On June 30, 2011, the U.S. Environmental Protection Agency (“EPA”) filed notice with the federal district court in El Paso that the EPA and the Company 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, the Company estimates the total capital expenditures necessary to address the Consent Decree issues would be approximately $51.0 million, of which the Company has 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. The Company estimates remaining expenditures of approximately $11.9 million for the NOx emission controls on heaters and boilers during 2012 and 2013. This amount is included in our estimated capital expenditures for regulatory projects. Under the terms of the Consent Decree, the Company paid a civil penalty of $1.5 million in September 2011.
In March 2008, the TCEQ notified the Company that it would present the Company with a proposed Agreed Order regarding six excess air emission incidents that occurred at the El Paso refinery during 2007 and early 2008. While at this time it is not known precisely how or when the Agreed Order may affect the Company, the Company may be required to implement corrective action under the Agreed Order and may be assessed penalties. The Company does not expect any penalties or corrective action requested to have a material adverse effect on its business, financial condition, or results of operations or that any penalties assessed or increased costs associated with the corrective action will be material.
In 2004 and 2005, the El Paso refinery applied for and was issued a Texas Flexible Permit by the TCEQ Flexible Permits program, under which the refinery continues to operate. Established in 1994 under the Texas Clean Air Act, the program grants operational flexibility to industrial facilities and permits the allocation of emissions on a facility-wide basis in exchange for emissions reduction and controlling previously unregulated “grandfathered” emission sources. The TCEQ submitted its Flexible Permits Program rules to the EPA for approval in 1994 and has administered the program for 16 years with the 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 the Company believes its Texas Flexible Permit is federally enforceable, the Company agreed in 2010 to submit an application to TCEQ for a permit amendment to obtain a Texas State Implementation Plan, or SIP, approved state air quality permit to address concerns raised by the EPA about all flexible permits. The Company submitted the application on November 22, 2011. Sufficient time has not elapsed for the Company to reasonably estimate any potential impact of these regulatory developments in the Texas air permits program.
In September 2010, the Company received a notice of intent to sue under the Clean Air Act from several environmental groups. While not entirely clear, the notice apparently contends that the Company’s El Paso refinery is not operating under a valid permit or permits because the EPA has disapproved the TCEQ Flexible Permits program and that the Company’s El Paso refinery may have exceeded certain emission limitations under these same permits. The Company disputes these claims and maintains its El Paso refinery is properly operating, and has not exceeded emissions limitations, under the validly issued TCEQ permits. The Company intends to defend itself accordingly.
Four Corners Refineries
Four Corners 2005 Consent Agreements.  In July 2005, as part of the EPA Initiative, Giant reached an administrative settlement with the New Mexico Environment Department (“NMED”) and the EPA in the form of consent agreements that resolved certain alleged violations of air quality regulations at the Gallup and Bloomfield refineries in the Four Corners area of New Mexico (“the 2005 NMED Agreement”). In January 2009, the Company and the NMED agreed to an amendment of the 2005 administrative settlement with the NMED (“the 2009 NMED Amendment”), which altered certain deadlines and allowed for alternative air pollution controls.
In November 2009, the Company indefinitely suspended refining operations at the Bloomfield refinery. The Company currently operates the site as a products distribution terminal and crude storage facility. Bloomfield continues to use some of the refinery equipment to support the terminal and to store crude for the Gallup refinery. The Company has begun negotiations with

102


the NMED to revise the 2009 NMED Amendment to reflect the indefinite suspension.
Based on current information and the 2009 NMED Amendment, and favorably negotiating a second amendment to reflect the indefinite suspension of refining operations at the Bloomfield facility and to delay NOx controls on heaters, boilers, and the FCCU at the Gallup refinery, the Company estimates $48.0 million in total capital expenditures pursuant to the 2009 NMED Amendment. Through 2011, the Company has expended $11.3 million and expects 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. The Company 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. The Company intends to negotiate the amount of the penalty, and does 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, the Company received a final administrative compliance order from the NMED alleging that releases of contaminants and hazardous substances that have occurred at the Bloomfield refinery over the course of its operation prior to June 1, 2007, have resulted in soil and groundwater contamination. Among other things, the order requires the Company to investigate 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, the Company has 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, the Company had expended $2.6 million and estimates a remaining cost of $3.1 million for implementing the investigation and interim measures of the order.
Gallup 2007 Resource Conservational Recovery Act (“RCRA”) Inspection.  In September 2007, the Gallup refinery was inspected jointly by the EPA and the NMED (“the Gallup 2007 RCRA Inspection”) to determine compliance with the EPA’s hazardous waste regulations promulgated pursuant to the RCRA. The Company reached a final settlement with the agencies in August 2009 and paid a penalty of $0.7 million in October 2009. The Company does not expect implementation of the requirements in the final settlement will result in any additional soil or groundwater remediation or clean-up costs not otherwise required. Based on current information, the Company estimates capital expenditures of approximately $33.7 million to upgrade the wastewater treatment plant at the 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, the Company has expended $20.8 million on the upgrade of the wastewater treatment plant and expects 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 the Company believes no violations occurred and the assessment of a penalty is not appropriate, the Company 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, the Company completed the first phase of the soil clean-up plan and negotiated revisions with the EPA for the remainder of the soil clean-up plan. Through December 2011, the Company has expended $32.9 million related to the EPA order.
In December 2011, subsidiaries of the Company 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 the Company 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, the Company has completed construction of this phase of the CAMU and has incurred substantially all costs anticipated to complete this work. The purchaser and the Company agreed that the purchaser would replace Giant as the respondent under the EPA order. The replacement is pending the EPA's agreement as of February 25, 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 (the “Consent Decree”) among various parties covering many locations entered in August 2001 under the EPA Initiative.

103


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. The Company responded in September 2011 offering to settle for $0.1 million, although the Company believes no stipulated penalties are due. The EPA accepted the Company's offer which the Company 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 the Yorktown refinery a notice to “show cause” why the EPA should not bring an enforcement action pursuant to the notification requirements under the Emergency Planning and Community Right-to-Know Act related to two separate flaring events that occurred in 2007 prior to the Company’s acquisition of Giant. The Company reached a settlement with the EPA for this enforcement notice for $0.2 million, which was paid prior to December 31, 2010.
Legal Matters
Over the last several years, lawsuits have been filed in numerous states alleging that methyl tertiary butyl ether (“MTBE”), a high octane blendstock used by many refiners in producing specially formulated gasoline, has contaminated water supplies and/or damaged natural resources. A subsidiary of the Company, Western Refining Yorktown, Inc. (“Western Yorktown”), is currently a defendant in a lawsuit brought by the State of New Jersey alleging damage to the State of New Jersey’s natural resources. Western Yorktown denies these allegations and intends to defend itself accordingly.
Owners of a small hotel in Aztec, New Mexico filed a lawsuit in San Juan County, New Mexico alleging migration of underground gasoline onto their property from underground storage tanks located on a convenience store property across the street, which is owned by a subsidiary of the Company. Plaintiffs claim a component of the gasoline, MTBE, has contaminated their property as a result of this release. The Trial Court granted summary judgment against Plaintiffs and dismissed all claims related to the alleged 1992 release. On appeal by Plaintiffs to the New Mexico Court of Appeals, the Court reversed and reinstated certain of its claims but only to the extent they relate to releases that occurred after January 1, 1999.
A lawsuit has been filed in the Federal District Court for the District of New Mexico by certain Plaintiffs who allege the Bureau of Indian Affairs (“BIA”), acted improperly in approving certain rights-of-way on land allotted to the individual Plaintiffs by the Navajo Nation, Arizona, New Mexico, and Utah (“Navajo Nation”). The lawsuit names the Company and numerous other defendants (“Right-of-Way Defendants”), and seeks imposition of a constructive trust and asserts these Right-of-Way Defendants are in trespass on the Allottee’s lands. The Court dismissed Plaintiffs’ claims in this matter. Plaintiffs then attempted to re-file these claims with the Department of Interior which also dismissed Plaintiffs claims. Plaintiffs are now attempting to appeal this dismissal within the Department of Interior. The Company disputes these claims and will defend itself accordingly.
The claim by 13 current/former employees of the Company’s Yorktown facility which asserted that the elimination of a temporary annuity supplement under the Company’s cash balance plan was not permitted by the Employee Retirement Income Security Act (“ERISA”), and the claim by these same 13 employees that this action violated the Age Discrimination in Employment Act has been resolved.
On August 2, 2011, the Company was served with a bankruptcy avoidance action in the Eastern District of Pennsylvania by a Bankruptcy Litigation Trustee for a former customer of the Company. The avoidance action sought the return of approximately $6.4 million alleged to be preferential or otherwise avoidable payments that may have been made by the former customer to the Company. The Court has dismissed approximately $4.8 million of the Trustee's claim and this dismissal is final. The Company disputes the remaining claims and will defend itself accordingly.
Regarding the claims asserted against the Company referenced above, potentially applicable factual and legal issues have not been resolved, the Company has yet to determine if a liability is probable and the Company cannot reasonably estimate the amount of any loss associated with these matters. Accordingly, the Company has not recorded a liability for these pending lawsuits.
Union Matters
During 2011, the Company successfully negotiated a collective bargaining agreement covering employees at the Gallup refinery that expires in 2014. Although the collective bargaining agreement remains in force, the covered employees at the

104


Bloomfield refinery were terminated in connection with the indefinite suspension of refining operations at the Bloomfield refinery during November 2009. The Company also successfully negotiated a new collective bargaining agreement covering employees at the El Paso refinery, renewing the collective bargaining agreement that 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 the collective bargaining agreements contain “no strike” provisions, those provisions are not effective in the event that an agreement expires. Accordingly, the Company may not be able to prevent a strike or work stoppage in the future, and any such work stoppage could have a material adverse affect on the Company’s business, financial condition, and results of operations.
Other Matters

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, the EPA issued Notices of Violation to 24 companies it claims purchased and used invalid RINs to satisfy obligations under the Renewable Fuels Standard, or RFS, program. 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. The Company purchases RINs to satisfy its obligations under the RFS program and may have purchased and used some RINs considered by the EPA to be invalid. Sufficient time has not elapsed for the Company to reasonably estimate the potential impact of the emerging situation surrounding invalid RINs.
The Company is party to various other claims and legal actions arising in the normal course of business. The Company believes that the resolution of these matters will not have a material adverse effect on its financial condition, results of operations, or cash flows.

22.
Concentration of Risk
Significant Customers
The Company sells a variety of refined products to a diverse customer base. No customer accounted for more than 10% of consolidated net sales during the three years ended December 31, 2011.
Sales by Product
All sales were domestic sales in the United States, except for sales of gasoline and diesel fuel for export into Mexico. The sales for export were to PMI Trading Limited, an affiliate of Petroleos Mexicanos, the Mexican state-owned oil company, and accounted for approximately 6.2%, 8.3%, and 8.5% of consolidated sales during the years ended December 31, 2011, 2010, and 2009, respectively.
The following table summarizes the percentages of all refined product sales to total sales for the three years ended December 31, 2011:

 
Year Ended December 31,
 
2011
 
2010
 
2009
Refined products:
 

 
 

 
 

Gasoline
53.9
%
 
54.8
%
 
56.5
%
Diesel fuel
31.8

 
31.0

 
29.4

Jet fuel
6.6

 
4.3

 
3.5

Asphalt
1.6

 
1.7

 
1.9

Other
2.1

 
3.7

 
3.7

 
96.0

 
95.5

 
95.0

Lubricants
1.3

 
1.2

 
1.6

Merchandise and other
2.7

 
3.3

 
3.4

Total
100.0
%

100.0
%

100.0
%


105


23.
Leases and Other Commitments
The Company has commitments under various operating leases with initial terms greater than one year for buildings, warehouses, card locks, barges, railcars, and other facilities. These leases have terms that will expire on various dates through 2036.
The Company expects that in the normal course of business, these leases will be renewed or replaced by other leases. Certain of the Company’s lease agreements provide for the fair value purchase of the leased asset at the end of lease. Rent expense for operating leases that provide for periodic rent escalations or rent holidays over the term of the lease is recognized on a straight-line basis.
In the normal course of business, the Company also has long-term commitments to purchase services, such as natural gas, electricity, water, and transportation services for use by its refineries at market-based rates. The Company is also party to various refined product and crude oil supply and exchange agreements.
Under a sulfuric acid regeneration and sulfur gas processing agreement with E.I. du Pont de Nemours ("DuPont"), DuPont constructed and operates two sulfuric acid regeneration plants on property the Company leased to DuPont within the Company's El Paso refinery.
As a result of the Giant acquisition, a subsidiary of the Company is a party to a ten-year lease agreement for an administrative office building in Scottsdale, Arizona that ends in 2013. During 2008, the Company entered into an agreement to sublease a portion of this property for $0.3 million annually from February 15, 2009 through October 31, 2013. The rental payments for this property have been included as part of our estimated rental payments in the table below.
In November 2007, a subsidiary of the Company entered into a ten-year lease agreement for an office space in downtown El Paso. The building will serve as the Company’s headquarters. In December 2007, a subsidiary of the Company entered into an eleven-year lease agreement for an office building in Tempe, Arizona. The building centralized the Company’s operational and administrative offices in the Phoenix area.
During the second and third quarters of 2011, the Company entered into a number of operating leases related to its retail and wholesale operations. In addition, the Company entered into a capital lease agreement to lease a retail service station and convenience store during the third quarter of 2011 with an initial term of 20 years. The current portion of the capital lease obligation of less than $0.1 million is included in Accrued liabilities and the non-current portion of $3.4 million is included in Other liabilities in the accompanying Consolidated Balance Sheet as of December 31, 2011.
The following table presents the Company’s annual minimum rental payments under non-cancelable operating leases that have lease terms of one year or more (in thousands):

2012
$
22,042

2013
20,059

2014
18,143

2015
16,059

2016
14,813

2017 and thereafter
164,992


Total rental expense was $19.1 million, $15.7 million, and $16.1 million for the years ended December 31, 2011, 2010, and 2009, respectively. Contingent rentals and subleases were not significant in any year.

24.
Quarterly Financial Information (Unaudited)
Demand for gasoline is generally higher during the summer months than during the winter months. As a result, the Company’s 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. During 2011, the volatility in crude oil prices and refining margins also contributed to the variability of the Company’s results of operations for the four calendar quarters.
During the latter part of March 2010, the Company reversed $14.7 million related to its accrued bonus estimate for 2009. This revision of the Company’s 2009 bonus estimate reduced direct operating expenses (exclusive of depreciation and

106

WESTERN REFINING, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


amortization) and selling, general, and administrative expenses reported for the three months ended March 31, 2010 by $8.5 million and $6.2 million, respectively.
 
Year Ended December 31, 2011
 
Quarter
 
First
 
Second
 
Third
 
Fourth
 
(Unaudited)
(In thousands, except for share data)
Net sales
$
1,839,588

 
$
2,557,884

 
$
2,397,139

 
$
2,276,426

Operating costs and expenses:
 

 
 

 
 

 
 

Cost of products sold (exclusive of depreciation and amortization)
1,612,727

 
2,188,184

 
2,053,409

 
1,678,103

Direct operating expenses (exclusive of depreciation and amortization)
111,007

 
117,405

 
109,159

 
125,992

Selling, general, and administrative expenses
24,027

 
24,807

 
27,153

 
29,781

(Gain) loss and impairments on disposal of assets, net
(3,630
)
 

 

 
450,796

Maintenance turnaround expense

 
704

 
632

 
1,107

Depreciation and amortization
35,371

 
34,349

 
35,581

 
30,594

Total operating costs and expenses
1,779,502

 
2,365,449

 
2,225,934

 
2,316,373

Operating income (loss)
60,086

 
192,435

 
171,205

 
(39,947
)
Other income (expense):
 

 
 

 
 

 
 

Interest income
92

 
139

 
114

 
165

Interest expense and other financing costs
(34,492
)
 
(33,504
)
 
(33,195
)
 
(33,410
)
Amortization of loan fees
(2,335
)
 
(2,239
)
 
(2,295
)
 
(2,057
)
Write-off of unamortized loan fees

 

 

 

Loss on extinguishment of debt
(4,641
)
 

 

 
(29,695
)
Other income (expense), net
288

 
880

 
(5,206
)
 
140

Income (loss) before income taxes
18,998

 
157,711

 
130,623

 
(104,804
)
Provision for income taxes
(6,773
)
 
(57,640
)
 
(45,695
)
 
40,247

Net income (loss)
$
12,225

 
$
100,071

 
$
84,928

 
$
(64,557
)
Basic earnings (loss) per common share
$
0.13

 
$
1.10

 
$
0.94

 
$
(0.72
)
Diluted earnings (loss) per common share
$
0.13

 
$
0.94

 
$
0.81

 
$
(0.72
)



107

WESTERN REFINING, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


 
Year Ended December 31, 2010
 
Quarter
 
First
 
Second
 
Third
 
Fourth
 
(Unaudited)
(In thousands, except for share data)
Net sales
$
1,915,395

 
$
2,145,337

 
$
2,038,296

 
$
1,866,025

Operating costs and expenses:
 

 
 

 
 

 
 

Cost of products sold (exclusive of depreciation and amortization)
1,765,461

 
1,906,941

 
1,807,411

 
1,676,154

Direct operating expenses (exclusive of depreciation and amortization)
106,980

 
113,968

 
116,982

 
106,601

Selling, general, and administrative expenses
16,501

 
21,072

 
24,031

 
22,571

Loss and impairments on disposal of assets, net

 

 
3,963

 
9,075

Maintenance turnaround expense
23,286

 

 

 

Depreciation and amortization
34,282

 
34,759

 
35,253

 
34,327

Total operating costs and expenses
1,946,510

 
2,076,740

 
1,987,640

 
1,848,728

Operating income (loss)
(31,115
)
 
68,597

 
50,656

 
17,297

Other income (expense):
 

 
 

 
 

 
 

Interest income
30

 
136

 
151

 
124

Interest expense and other financing costs
(36,774
)
 
(37,295
)
 
(37,099
)
 
(35,381
)
Amortization of loan fees
(2,414
)
 
(2,420
)
 
(2,453
)
 
(2,452
)
Other income (expense), net
(294
)
 
4,213

 
712

 
2,655

Income (loss) before income taxes
(70,567
)
 
33,231

 
11,967

 
(17,757
)
Provision for income taxes
39,878

 
(18,878
)
 
(5,108
)
 
10,185

Net income (loss)
$
(30,689
)
 
$
14,353

 
$
6,859

 
$
(7,572
)
Basic earnings (loss) per common share
$
(0.35
)
 
$
0.16

 
$
0.08

 
$
(0.09
)
Diluted earnings (loss) per common share
$
(0.35
)
 
$
0.16

 
$
0.08

 
$
(0.09
)


108


Item 9.
Changes In and Disagreements With Accountants on Accounting and Financial Disclosure
None.

Item 9A.
Controls and Procedures
Evaluation of disclosure controls and procedures.  Our chief executive officer and chief financial officer, after evaluating the effectiveness of the Company’s “disclosure controls and procedures” (as defined in the Securities Exchange Act of 1934 Rules 13a-15(e) and 15d-15(e)) as of December 31, 2011 (the “Evaluation Date”), concluded that as of the Evaluation Date, our disclosure controls and procedures were effective.
Management’s Report on Internal Control Over Financial Reporting.  Included herein under the caption “Management’s Report on Internal Control Over Financial Reporting” on page 61 of this report.
Changes in internal control over financial reporting.  There were no changes in our internal control over financial reporting that occurred during the quarter ended December 31, 2011, that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Item 9B.
Other Information
None.

PART III
Certain information required in this Part III is incorporated by reference to Western Refining, Inc.’s Definitive Proxy Statement (the "Proxy Statement") to be filed with the Securities and Exchange Commission pursuant to Regulation 14A within 120 days after the end of the fiscal year covered by this report.

Item 10.
Directors, Executive Officers, and Corporate Governance
The information required by this item is incorporated by reference to the information contained in Western Refining, Inc.’s Proxy Statement under the headings “Election of Directors” and “Executive Compensation and Other Information.”

Item 11.
Executive Compensation
The information required by this item is incorporated by reference to the information contained in Western Refining, Inc.’s Proxy Statement under the heading “Executive Compensation and Other Information.”

Item 12.
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Security Ownership of Certain Beneficial Owners and Management
The information required by this item is incorporated by reference to the information contained in Western Refining, Inc.’s Proxy Statement under the heading “Security Ownership of Certain Beneficial Owners and Management.”
Securities Authorized for Issuance Under Equity Compensation Plans
 
(a)
Number of
securities to be
issued upon
exercise of
outstanding
options, warrants,
 
(b)
Weighted average
exercise price of
outstanding
options, warrants,
 
(c)
Number of
securities
remaining available
for future issuance
under equity
compensation plans
(excluding
securities
reflected in column
Plan Category
and rights (1)
 
and rights (2)
 
(a)
Equity compensation plans approved by security holders
316,917

 

 
3,463,304

Equity compensation plans not approved by security holders

 

 

Total
316,917

 

 
3,463,304

_______________________________________
(1)
Represents 316,917 shares underlying restricted share unit awards.
(2)
Restricted share unit awards do not have an exercise price.


109




Item 13.
Certain Relationships and Related Transactions, and Director Independence
The information required by this item is incorporated by reference to the information contained in Western Refining, Inc.’s 2011 Definitive Proxy Statement under the heading “Certain Relationships and Related Transactions.”

Item 14.
Principal Accountant Fees and Services
The information required by this item is incorporated by reference to the information contained in Western Refining, Inc.’s 2011 Definitive Proxy Statement under the heading “Proposal 2: Ratification of Independent Auditor.”


110


PART IV

15.
Exhibits and Financial Statement Schedules
(a) Financial Statements:
See Index to Financial Statements included in Item 8.
(b) The following exhibits are filed herewith (or incorporated by reference herein):

Number
Exhibit Title
 
 
2.1
Agreement and Plan of Merger, dated August 26, 2006, by and among Western Refining, Inc., New Acquisition Corporation and Giant Industries, Inc. (incorporated by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K, filed with the SEC on August 28, 2006).
2.2
Amendment No. 1 to the Agreement and Plan of Merger, dated November 12, 2006, by and among Western Refining, Inc., New Acquisition Corporation and Giant Industries, Inc. (incorporated by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K, filed with the SEC on November 13, 2006).
3.1
Certificate of Incorporation of the Company (incorporated by reference to Exhibit 3.1 to the Company’s Annual Report on Form 10-K, filed with the SEC on March 24, 2006).
3.2
Bylaws of the Company (incorporated by reference to Exhibit 3.2 to the Company’s Annual Report on Form 10-K, filed with the SEC on March 24, 2006).
4.1
Specimen of Company Common Stock Certificate (incorporated by reference to Exhibit 4.1 to the Company’s Registration Statement on Form S-1/A, filed with the SEC on December 5, 2005).
4.2
Registration Rights Agreement, dated January 24, 2006, by and between the Company and each of the stockholders listed on the signature pages thereto (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K, filed with the SEC on January 25, 2006).
4.3
Indenture dated June 10, 2009 between Western Refining, Inc. and The Bank of New York Mellon Trust Company, N.A., as trustee (incorporated by reference to Exhibit 4.1 to the Company’s Quarterly Report on Form 10-Q, filed with the SEC on August 7, 2009).
4.4
Supplemental Indenture dated June 10, 2009 between Western Refining, Inc. and The Bank of New York Mellon Trust Company, N.A., as trustee (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed on June 10, 2009).
4.5
Form of Convertible Senior Note (included in Exhibit 4.4).

4.6
Indenture dated June 12, 2009 among Western Refining, Inc., the Guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee, paying agent, registrar and transfer agent (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed on June 15, 2009).
4.7
Form of 11.25% Senior Secured Note (included in Exhibit 4.6)

4.8
Form of Senior Secured Floating Rate Note (included in Exhibit 4.6)

10.1†
Employment Agreement, dated January 24, 2006, by and between Western Refining GP, LLC and Paul L. Foster (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, filed with the SEC on January 25, 2006).
10.1.1†
First Amendment to the Employment Agreement referred to in Exhibit 10.1, dated December 28, 2006 (incorporated by reference to Exhibit 10.1.1 to the Company's Annual Report on Form 10-K, filed with the SEC on March 8, 2007).
10.1.2†
Second Amendment to the Employment Agreement referred to in Exhibit 10.1, dated December 31, 2008 (incorporated by reference to Exhibit 10.1.2 to the Company's Annual Report on Form 10-K, filed with the SEC on March 8, 2007).


111


Number
Exhibit Title
 
 
10.2†
Employment Agreement, dated January 24, 2006, by and between Western Refining GP, LLC and Jeff A. Stevens (incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K, filed with the SEC on January 25, 2006).
10.2.1†
First Amendment to the Employment Agreement referred to in Exhibit 10.2, dated December 28, 2006 (incorporated by reference to Exhibit 10.2.1 to the Company’s Annual Report on Form 10-K, filed with the SEC on March 8, 2007).
10.2.2†
Second Amendment to the Employment Agreement referred to in Exhibit 10.2, dated December 31, 2008 (incorporated by reference to Exhibit 10.2.2 to the Company’s Annual Report on Form 10-K, filed with the SEC on March 13, 2007).
10.3†
Employment Agreement, dated January 24, 2006, by and between Western Refining GP, LLC and Scott D. Weaver (incorporated by reference to Exhibit 10.4 to the Company’s Current Report on Form 8-K, filed with the SEC on January 25, 2006).
10.3.1†
First Amendment to the Employment Agreement referred to in Exhibit 10.3, dated December 28, 2006 (incorporated by reference to Exhibit 10.3.1 to the Company’s Annual Report on Form 10-K, filed with the SEC on March 8, 2007).
10.3.2†
Letter of Termination of Employment Agreement dated December 31, 2007, between Western Refining GP, LLC and Scott D. Weaver (incorporated by reference to Exhibit 10.3.2 to the Company’s Annual Report on Form 10-K, filed with the SEC on February 29, 2008).
10.4†
Employment Agreement, dated January 24, 2006, by and between Western Refining GP, LLC and Gary R. Dalke (incorporated by reference to Exhibit 10.5 to the Company’s Current Report on Form 8-K, filed with the SEC on January 25, 2006).
10.4.1†
First Amendment to the Employment Agreement referred to in Exhibit 10.4, dated December 31, 2008 (incorporated by reference to Exhibit 10.4.1 to the Company’s Annual Report on Form 10-K, filed with the SEC on March 13, 2007).
10.5†
Employment Agreement, dated January 24, 2006, by and between Western Refining GP, LLC and Lowry Barfield (incorporated by reference to Exhibit 10.6 to the Company’s Current Report on Form 8-K, filed with the SEC on January 25, 2006).
10.5.1†
First Amendment to the Employment Agreement referred to in Exhibit 10.5, dated December 31, 2008 (incorporated by reference to Exhibit 10.5.1 to the Company’s Annual Report on Form 10-K, filed with the SEC on March 13, 2007).
10.6
Term Loan Credit Agreement, dated May 31, 2007, among Western Refining, Inc., Bank of America, N.A., as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K, filed with the SEC on June 1, 2007).
10.6.1
First Amendment to Term Loan Credit Agreement dated as of June 30, 2008, by and among Western Refining, Inc., the lenders party thereto and Bank of America, N.A., as the Administrative Agent (incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K, filed with the Securities and Exchange Commission on July 1, 2008).
10.6.2
Second Amendment to Term Loan Credit Agreement dated as of May 29, 2009, among the Company, as Borrower, the lenders from time to time party thereto, and Bank of America, N.A., as Administrative Agent, amending that certain Term Loan Credit Agreement, dated May 31, 2007, as amended by the First Amendment to Term Loan Credit Agreement dated as of June 30, 2008 (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K, filed with the Securities and Exchange Commission on May 29, 2009).
10.6.3
Third Amendment to the Term Loan Credit Agreement, dated as of November 24, 2009, among the Company, as Borrower, the lenders from time to time party thereto, and Bank of America, N.A., as Administrative Agent, amending that certain Term Loan Credit Agreement, dated May 31, 2007, as amended by the First Amendment to Term Loan Credit Agreement dated as of June 30, 2008 and the Second Amendment to the Term Loan Credit Agreement dated as of May 29, 2009 (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K, filed with the Securities and Exchange Commission on November 24, 2009).
10.6.4
Amended and Restated Term Loan Credit Agreement dated as of March 29, 2011, among the Company, as Borrower, the lenders from time to time party thereto and Bank of America, N.A., as Administrative Agent (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on March 31, 2011).
10.6.5
Amendment No. 1 to the Amended and Restated Term Loan Credit Agreement dated as of September 22, 2011, among the Company, as Borrower, the lenders party thereto and Bank of America, N.A., as Administrative Agent (incorporated by reference to Exhibit 10.2 to the Company’s Quarterly Report on Form 10-Q, filed with the SEC on November 4, 2011).


112


Number
Exhibit Title
 
 
10.7
Revolving Credit Agreement, dated May 31, 2007, among Western Refining, Inc., Bank of America, N.A., as administrative agent, swing line lender and L/C issuer, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K, filed with the SEC on June 1, 2007).
10.7.1
First Amendment to Revolving Credit Agreement dated as of June 30, 2008, by and among Western Refining, Inc., the lenders party thereto and Bank of America, N.A., as the Administrative Agent, Swing Line Lender, L/C Issuer and a Lender (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K, filed with the Securities and Exchange Commission on July 1, 2008).
10.7.2
Second Amendment to the Revolving Credit Agreement dated as of May 29, 2009, among the Company, as Borrower, the lenders from time to time party thereto, and Bank of America, N.A., as Administrative Agent, Swing Line Lender and L/C Issuer, amending that certain Revolving Credit Agreement, dated May 31, 2007, as amended by the First Amendment to Revolving Credit Agreement dated as of June 30, 2008 (incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K, filed with the Securities and Exchange Commission on May 29, 2009).
10.7.3
Third Amendment to the Revolving Credit Agreement dated as of November 24, 2009, among the Company, as Borrower, the lenders from time to time party thereto, and Bank of America, N.A., as Administrative Agent, Swing Line Lender and L/C Issuer, amending that certain Revolving Credit Agreement, dated May 31, 2007, as amended by the First Amendment to Revolving Credit Agreement dated as of June 30, 2008 and the Second Amendment to Revolving Credit Agreement dated as of May 29, 2009 (incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K, filed with the Securities and Exchange Commission on November 24, 2009).
10.7.4
Fourth Amendment to the Revolving Credit Agreement dated as of February 18, 2010, among the Company, as Borrower, the lenders from time to time party thereto, and Bank of America, N.A., as Administrative Agent, Swing Line Lender and L/C Issuer, amending that certain Revolving Credit Agreement, dated May 31, 2007, as amended by the First Amendment to Revolving Credit Agreement dated as of June 30, 2008, the Second Amendment to Revolving Credit Agreement dated as of May 29, 2009, and the Third Amendment to Revolving Credit Agreement dated as of November 24, 2009 (incorporated by reference to Exhibit 10.7.4 to the Company’s Annual Report on Form 10-K, filed with the SEC on March 12, 2010).
10.7.5
Fifth Amendment to Revolving Credit Agreement dated as of December 23, 2010, among the Company, as Borrower, the lenders from time to time party thereto, and Bank of America, N.A., as Administrative Agent, Swing Line Lender and L/C Issuer, amending that certain Revolving Credit Agreement, dated May 31, 2007, as amended by the First Amendment to Revolving Credit Agreement dated as of June 30, 2008, the Second Amendment to Revolving Credit Agreement dated as of May 29, 2009, and the Third Amendment to Revolving Credit Agreement dated as of November 24, 2009, and the Fourth Amendment to Revolving Credit Agreement dated February 18, 2010 (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K, filed with the SEC on December 28, 2010).
10.8
L/C Credit Agreement, dated as of June 30, 2008 among Western Refining, Inc., Bank of America, N.A., as Administrative Agent and L/C Issuer and the lenders party thereto (incorporated by reference to Exhibit 10.3 to the Company’s Current Report on Form 8-K, filed with the Securities and Exchange Commission on July 1, 2008).
10.9†
Form of Indemnification Agreement, by and between the Company and each director and officer of the Company party thereto (incorporated by reference to Exhibit 10.7 to the Company’s Current Report on Form 8-K, filed with the SEC on January 25, 2006).
10.10
Operating Agreement, dated May 6, 1993, by and between Western Refining LP and Chevron U.S.A. Inc. (incorporated by reference to Exhibit 10.10 to the Company’s Registration Statement on Form S-1/A, filed with the SEC on November 3, 2005).
10.11
Purchase and Sale Agreement, dated May 29, 2003, by and among Chevron U.S.A. Inc., Chevron Pipe Line Company, Western Refining LP and Kaston Pipeline Company, L.P. (incorporated by reference to Exhibit 10.11 to the Company’s Registration Statement on Form S-1/A, filed with the SEC on November 3, 2005).
10.12
Lease Agreement, dated October 24, 2005, by and between Western Refining LP and Transmountain Oil Company, L.C. (incorporated by reference to Exhibit 10.12 to the Company’s Registration Statement on Form S-1/A, filed with the SEC on November 3, 2005).

113


Number
Exhibit Title
 
 
10.14†
RHC Holdings, L.P. Long-Term Unit Equity Appreciation Rights Plan, dated August 25, 2003 (incorporated by reference to Exhibit 10.13 to the Company’s Registration Statement on Form S-1/A, filed with the SEC on November 3, 2005).
10.15†
RHC Holdings, L.P. Long-Term Equity Appreciation Rights Award, dated August 25, 2003, by and between Gary R. Dalke and RHC Holdings, L.P. (incorporated by reference to Exhibit 10.14 to the Company’s Registration Statement on Form S-1/A, filed with the SEC on November 3, 2005).
10.16†
Long-Term Equity Appreciation Rights Award Amendment Agreement, dated November 9, 2005, by and between Gary R. Dalke, RHC Holdings, L.P., the Company and Western Refining LP (incorporated by reference to Exhibit 10.15 to the Company’s Registration Statement on Form S-1/A, filed with the SEC on December 5, 2005).
10.17†
Long-Term Equity Appreciation Rights Award Second Amendment Agreement, dated December 31, 2005, by and between Gary R. Dalke, the Company and Western Refining LP (incorporated by reference to Exhibit 10.24 to the Company’s Registration Statement on Form S-1/A, filed with the SEC on January 3, 2006).
10.18†
Long-Term Equity Appreciation Rights Awards Third Amendment Agreement, dated December 22, 2006, by and between Gary R. Dalke, the Company and Western Refining LP (incorporated by reference to Exhibit 10.16 to the Company’s Annual Report on Form 10-K, filed with the SEC on March 8, 2007).
10.19†
Western Refining Long-Term Incentive Plan (incorporated by reference to Exhibit 10.17 to the Company’s Annual Report on Form 10-K, filed with the SEC on March 24, 2006).
10.19.1†
First Amendment to the Western Refining Long-Term Incentive Plan referred to in Exhibit 10.19, dated December 4, 2007 (incorporated by reference to Exhibit 10.19.1 to the Company’s Annual Report on Form 10-K, filed with the SEC on March 13, 2009).
10.19.2†
Second Amendment to the Western Refining Long-Term Incentive Plan referred to in Exhibit 10.19, dated November 20, 2008 (incorporated by reference to Exhibit 10.19.2 to the Company’s Annual Report on Form 10-K, filed with the SEC on March 13, 2009).
10.20†
Form of Restricted Stock Grant Agreement (incorporated by reference to Exhibit 10.20 to the Company’s Registration Statement on Form S-1/A, filed with the SEC on December 5, 2005).
10.21†
Form of Nonqualified Stock Option Agreement (incorporated by reference to Exhibit 10.21 to the Company’s Registration Statement on Form S-1/A, filed with the SEC on December 5, 2005).
10.22
Letter Agreement, dated June 24, 2005, by and between Western Refining Company, L.P. and Ascarate Group LLP (incorporated by reference to Exhibit 10.17 to the Company’s Registration Statement on Form S-1/A, filed with the SEC on November 3, 2005).
10.23
Promissory Note, dated June 24, 2005, by Ascarate Group LLP in favor of Western Refining LP (incorporated by reference to Exhibit 10.16 to the Company’s Registration Statement on Form S-1/A, filed with the SEC on November 3, 2005).
10.24†
Summary of Compensation for Non-Employee Directors (incorporated by reference to Exhibit 10.19 to the Company’s Registration Statement on Form S-1/A, filed with the SEC on November 3, 2005).
10.25
Form of Time Share Agreement, dated November 20, 2004, by and between Western Refining LP and the persons parties thereto (incorporated by reference to Exhibit 10.23 to the Company’s Registration Statement on Form S-1/A, filed with the SEC on December 5, 2005).
10.26
Consulting and Non-Competition Agreement, dated August 26, 2006, by and between the Company and Fred L. Holliger (incorporated by reference to Exhibit 99.1 to the Company’s Current Report on Form 8-K, filed with the SEC on August 28, 2006).
10.26.1
Amendment No. 1 to the Consulting and Non-Competition Agreement, dated November 12, 2006, by and between Western Refining, Inc. and Fred L. Holliger (incorporated by reference to Exhibit 99.1 to the Company’s Current Report on Form 8-K, filed with the SEC on November 13, 2006).
10.27†
Employment agreement, effective August 28, 2006, made by and between Western Refining GP, LLC and Mark J. Smith (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K, filed with the SEC on August 16, 2006).


114


Number
Exhibit Title
 
 
10.27.1†
First Amendment to the Employment Agreement referred to in Exhibit 10.27, dated December 31, 2008 (incorporated by reference to Exhibit 10.27.1 to the Company’s Annual Report on Form 10-K, filed with the SEC on March 31, 2009).
10.28
Non-Exclusive Aircraft Lease Agreement, dated October 3, 2006, by and between Western Refining LP and Franklin Mountain Assets LLC (incorporated by reference to Exhibit 10.3 to the Company’s Quarterly Report on Form 10-Q, filed with the SEC on November 14, 2006).
10.29†
Employment agreement, dated November 4, 2008, made by and between Western Refining GP, LLC and Mark B. Cox (incorporated by reference to Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q, filed with the SEC on November 7, 2008).
10.30†
Employment agreement, dated November 4, 2008, made by and between Western Refining GP, LLC and William R. Jewell (incorporated by reference to Exhibit 10.2 to the Company’s Quarterly Report on Form 10-Q, filed with the SEC on November 7, 2008).
10.31†
Employment agreement, dated March 9, 2010, made by and between Western Refining GP, LLC and Jeffrey S. Beyersdorfer (incorporated by reference to Exhibit 10.31 to the Company’s Annual Report on Form 10-K, filed with the SEC on March 12, 2010).
10.32†
2010 Incentive Plan of Western Refining, Inc. (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K, filed with the SEC on May 27, 2010).
10.33†
Form of Performance Unit Award Agreement between the Company and Participant under the 2010 Incentive Plan of Western Refining, Inc. (incorporated by reference to Exhibit 10.32 to the Company’s Annual Report on Form 10-K, filed with the SEC on March 8, 2011).
10.34†
Form of Western Refining, Inc. Restricted Share Unit Award Agreement between the Company and Participant under the 2010 Incentive Plan of Western Refining, Inc. (incorporated by reference to Exhibit 10.32 to the Company’s Annual Report on Form 10-K, filed with the SEC on March 8, 2011).
10.35
Asset Purchase Agreement by and between Western Refining Yorktown, Inc., and Western Refining Yorktown Holding Company as Seller and Plains Marketing, L.P., as Buyer Dated November 30, 2011 (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, filed with the SEC on December 2, 2011).
10.36
Asset Purchase Agreement by and between Western Refining Pipeline Company as Seller and Plains Pipeline, L.P., as Buyer Dated November 30, 2011 (incorporated by reference to Exhibit 10.2 to the Company's Current Report on Form 8-K, filed with the SEC on December 2, 2011).
12.1*
Statements of Computation of Ratio of Earnings to Fixed Charges.
21.1
List of Subsidiaries (incorporated by reference to Exhibit 21.1 to the Company’s Annual Report on Form 10-K, filed with the SEC on February 29, 2008).
23.1*
Consent of Deloitte & Touche LLP, dated February 29, 2012.
31.1*
Certification Statement of Chief Executive Officer of the Company pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
31.2*
Certification Statement of Chief Financial Officer of the Company pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1*
Certification Statement of Chief Executive Officer of the Company pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2*
Certification Statement of Chief Financial Officer of the Company pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101**
Interactive Data Files.
_______________________________________
 
Filed herewith.
 
 
 
 
Management contract or compensatory plan or arrangement.
 
 
 
**
 
As provided in Rule 406T of Regulation S-T, this information is furnished and not filed for purposes of Sections 11 and 12 of the Securities Act of 1933 and Section 18 of the Securities Exchange Act of 1934.
(c)
All financial statement schedules are omitted because the required information is not present or is not present in amounts sufficient to require submission of the schedule, or because the information required is included in the consolidated financial statements or notes thereto.
The Company’s 2011 Annual Report is available upon request. Stockholders of the Company may obtain a copy of any exhibits to this Form 10-K at a charge of $0.10 per page. Requests should be made to: Investor Relations, Western Refining,

115


Inc., 123 W. Mills Ave., Suite 200, El Paso, Texas 79901.


116


SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
WESTERN REFINING, INC.
Signature
 
Title
 
Date
/s/  Jeff A. Stevens
 
Chief Executive Officer and
 
February 29, 2012
Jeff A. Stevens
 
 President
 
 
________________________________________________________________________________________________________________________

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
Signature
 
Title
 
Date
/s/  Jeff A. Stevens
 
Chief Executive Officer, President and Director
 
February 29, 2012
Jeff A. Stevens
 
 (Principal Executive Officer)
 
 
 
 
 
 
 
/s/  Gary R. Dalke
 
Chief Financial Officer
 
February 29, 2012
Gary R. Dalke
 
(Principal Financial Officer)
 
 
 
 
 
 
 
/s/  Paul L. Foster
 
Executive Chairman and Director
 
February 29, 2012
Paul L. Foster
 
 
 
 
 
 
 
 
 
/s/  Scott D. Weaver
 
Vice President and Director
 
February 29, 2012
Scott D. Weaver
 
 
 
 
 
 
 
 
 
/s/  William R. Jewell
 
Chief Accounting Officer
 
February 29, 2012
William R. Jewell
 
(Principal Accounting Officer)
 
 
 
 
 
 
 
/s/  Carin M. Barth
 
Director
 
February 29, 2012
Carin M. Barth
 
 
 
 
 
 
 
 
 
/s/  Sigmund L. Cornelius
 
Director
 
February 29, 2012
Sigmund L. Cornelius
 
 
 
 
 
 
 
 
 
/s/  L. Frederick Francis
 
Director
 
February 29, 2012
L. Frederick Francis
 
 
 
 
 
 
 
 
 
/s/  Brian J. Hogan
 
Director
 
February 29, 2012
Brian J. Hogan
 
 
 
 
 
 
 
 
 
/s/  William D. Sanders
 
Director
 
February 29, 2012
William D. Sanders
 
 
 
 
 
 
 
 
 
/s/  Ralph A. Schmidt
 
Director
 
February 29, 2012
Ralph A. Schmidt
 
 
 
 


117