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, 2012
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, 2012 (the last business day of the registrant’s most recently completed second fiscal quarter) was $1,345,803,693.

As of February 22, 2013, there were 87,633,121 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 2013 annual meeting of stockholders are incorporated by reference into Part III of this report.

WESTERN REFINING, INC. AND SUBSIDIARIES

INDEX

PART I
Item 1.	Business	3
Item 1A.	Risk Factors	11
Item 1B.	Unresolved Staff Comments	19
Item 2.	Properties	19
Item 3.	Legal Proceedings	19
Item 4.	Mine Safety Disclosures	19
PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities	20
Item 6.	Selected Financial Data	23
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	25
Item 7A.	Quantitative and Qualitative Disclosure About Market Risk	61
Item 8.	Financial Statements and Supplementary Data	63
Item 9.	Changes In and Disagreements With Accountants on Accounting and Financial Disclosure	111
Item 9A.	Controls and Procedures	111
Item 9B.	Other Information	111
PART III
Item 10.	Directors, Executive Officers, and Corporate Governance	111
Item 11.	Executive Compensation	111
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	112
Item 13.	Certain Relationships and Related Transactions, and Director Independence	112
Item 14.	Principal Accountant Fees and Services	112
PART IV
Item 15.	Exhibits and Financial Statement Schedules	113
Signatures		117
EX-10.25
EX-10.26
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 and crack spreads, the discount between West Texas Intermediate ("WTI") crude oil and Dated Brent crude oil as well as the discount between WTI Cushing and WTI Midland crude oils, projects to increase our capacity to process West Texas Sour ("WTS") crude oil, additions to pipeline capacity in the Permian Basin and at Cushing, Oklahoma, crude oil production in the Permian Basin as well as a project to gather and store crude oil in the Permian Basin, taxes, capital expenditures, liquidity and capital resources, certain strategic initiatives we are considering in order to deliver additional value to our shareholders, our working capital requirements, our planned share repurchases, 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 and refinery efficiencies and cost savings, 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 hedging 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 that 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;

• changes in crack spreads;

• changes in the spread between WTI crude oil and WTS crude oil, also known as the sweet/sour spread;

• changes in the spread between WTI crude oil and Dated Brent crude oil and between WTI Cushing crude oil and WTI Midland crude oil;

• effects of, and exposure to risks related to, our commodity hedging strategies and transactions;

• availability, costs, and price volatility of crude oil, other refinery feedstocks, and refined products;

• construction of new, or expansion of existing product or crude pipelines, including in the Permian Basin and at Cushing, Oklahoma;

• 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 Renewal Identification Numbers ("RIN") to meet Renewable Fuel Standards ("RFS") obligations;

• adverse changes in the credit ratings assigned to our debt instruments;

• 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;

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• effects of, and costs relating to, compliance with current and future local, state, and federal environmental, economic, climate change, safety, tax and other laws, policies and regulations, and enforcement initiatives;

• rulings, judgments, or settlements in litigation, tax, or other legal or regulatory matters, including unexpected environmental remediation costs in excess of any reserves or insurance coverage;

• the price, availability, and acceptance of alternative fuels and alternative fuel vehicles;

• operating hazards, natural disasters, casualty losses, acts of terrorism including cyber-attacks, and other matters beyond our control; and

• other factors discussed in more detail under Part 1. — Item 1A. Risk Factors of this report that are incorporated herein by this reference.

Any one of these factors or a combination of these factors could materially affect our results of operations and could influence whether any forward-looking statements ultimately prove to be accurate. You are urged to consider these factors carefully in evaluating any forward-looking statements and are cautioned not to place undue reliance on these forward-looking statements.

Although we believe that our plans, intentions, and expectations reflected in or suggested by the forward-looking statements we make in this report are reasonable, we can provide no assurance that such plans, intentions, or expectations will be achieved. These statements are based on assumptions made by us based on our experience and perception of historical trends, current conditions, expected future developments, and other factors that we believe are appropriate in the circumstances. Such statements are subject to a number of risks and uncertainties, many of which are beyond our control. The forward-looking statements included herein are made only as of the date of this report, and we are not required to update any information to reflect events or circumstances that may occur after the date of this report, except as required by applicable law.

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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. ("WNR") and its subsidiaries, unless the context otherwise requires or where otherwise indicated.

Item 1. Business

Overview

We are an independent crude oil refiner and marketer of refined products incorporated in September 2005 under Delaware law with principal offices located in El Paso, Texas. Our stock trades on the New York Stock Exchange ("NYSE") under the symbol “WNR.” We own and operate two refineries with a total crude oil throughput capacity of 153,000 barrels per day ("bpd") including our 128,000 bpd refinery in El Paso, Texas, and our 25,000 bpd refinery near Gallup, New Mexico. In September 2010, we temporarily suspended refining operations of a 70,000 bpd refinery near Yorktown, Virginia and on December 29, 2011, we completed the sale of the Yorktown refining and terminal assets. We continue to market refined products in the Mid-Atlantic region through our wholesale segment. 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 and Bloomfield, New Mexico; as well as asphalt terminals in Phoenix and Tucson, Arizona; Albuquerque; and El Paso. As of February 22, 2013, we operated 222 retail 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 report 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. We 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 retail stores that sell gasoline, diesel fuel, and convenience store 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 business 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"), on-site refined product distribution terminals at the El Paso and Gallup refineries, and stand-alone refined product distribution terminals in Albuquerque and Bloomfield, New Mexico. We supply refined products to the Four Corners region of New Mexico through operations at our Bloomfield product distribution terminal and by utilizing a pipeline connection and long-term exchange supply agreement in exchange for barrels produced at our El Paso refinery.

Refining operations also include an asphalt plant in El Paso and four asphalt terminals in El Paso, Albuquerque, and Phoenix and Tucson, Arizona. Our refining group operates a crude oil gathering pipeline system in the Four Corners region. We also own a pipeline running from southeast to northwest New Mexico, known as the 16" 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. The portion of the line that we still own originates near Maljamar, New Mexico and is capable of transporting 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. 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 transaction to dispose of the Yorktown refining and terminal assets. 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.

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 wholesale and retail groups, 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 percentages by product for the years indicated:

	Year Ended December 31,
	2012		2011		2010
Gasoline	44.3	%	44.1	%	54.0	%
Diesel fuel	34.3		35.1		32.3
Jet fuel	13.9		12.9		5.6
Asphalt	3.5		3.6		2.5
Other	4.0		4.3		5.6
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 in any of the three years ended December 31, 2012.

All of our refining sales were domestic sales in the United States, except for sales of gasoline and diesel fuel for export into Juarez and other cities in Northern 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 7.5%, 6.2%, and 8.3% of our consolidated net sales during the years ended December 31, 2012, 2011, and 2010, 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 13.8%, 14.8%, and 9.9% of our total sales volumes during the years ended December 31, 2012, 2011, and 2010, respectively. The increase in 2012 and 2011 purchases over 2010 levels 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. Until September 2010, we satisfied these commitments with products refined at the Yorktown facility.

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. We also compete with offshore refiners that deliver product by water transport.

4

Petroleum refining and marketing is highly competitive. Our principal competitive factors include costs of crude oil and other feedstocks, our competitors' refined product pricing, 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., Phillips 66 Company, Alon USA Energy, Inc., HollyFrontier Corporation, Tesoro Corporation, Chevron Products Company ("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 the Yorktown refining and refined product distribution terminal assets in the Mid-Atlantic region, the Yorktown facility primarily competed with Sunoco, Inc., Valero Energy Corp., ConocoPhillips Company, Hess Corporation, and other refineries in the Gulf Coast via the Colonial Pipeline that runs from the Gulf Coast area to New Jersey. We also competed with offshore refiners that deliver product by water transport to the region.

To the extent that climate change legislation 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 March 2012 and its in-state cap regulations in May 2012. Both repeals are being appealed.

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 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. We have the flexibility to process up to 22% WTS crude oil that is typically less expensive than WTI crude oil.

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 we lease to DuPont within our El Paso refinery.

Power Supply. Electricity is supplied to our El Paso 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 El Paso refinery via pipeline under two transportation agreements. One transportation agreement is on an interruptible basis while the other is on a firm basis. We purchase our natural gas at market rates or under fixed-price agreements.

Raw Material Supply. The primary inputs for our El Paso refinery are crude oil and isobutane. Currently, we have the capability to process WTS crude oil at up to 22% of throughput capacity at the El Paso refinery. We will consider projects to increase the WTS capacity should economic and market conditions, particularly the sweet/sour spread, make such projects economically viable.

5

The following table summarizes the historical feedstocks used by our El Paso refinery for the years indicated:

	Year Ended December 31,			Percentage For Year Ended December 31,
Refinery Feedstocks (bpd)	2012	2011	2010	2012
Crude Oils:
Sweet crude oil	94,404	91,589	104,119	74.4	%
Sour crude oil	24,792	19,876	14,007	19.5	%
Total Crude Oils	119,196	111,465	118,126	93.9	%
Other Feedstocks and Blendstocks:
Intermediates and other	4,852	3,928	4,359	3.8	%
Blendstocks	2,882	2,752	4,692	2.3	%
Total Other Feedstocks and Blendstocks	7,734	6,680	9,051	6.1	%
Total Crude Oils and Other Feedstocks and Blendstocks	126,930	118,145	127,177	100.0	%

Our El Paso refinery receives crude oil from a 450 mile crude oil pipeline owned and operated by Kinder Morgan under a 30-year crude oil transportation agreement that expires in 2034. 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. Through the crude oil pipeline, we have access to the majority of the producing fields in the Permian Basin in southeast New Mexico that gives us access to a plentiful supply of WTI and WTS crude oil from fields with long reserve lives. We are in the final stages of completing a crude oil gathering and storage project in the Permian Basin. We expect to complete this project during the second quarter of 2013. Once complete, we will have access to shale crude oil production in the area for shipment to our El Paso refinery through the Kinder Morgan crude oil pipeline. We generally buy our crude oil under contracts with various crude oil providers at market-based pricing. 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 that could result in our paying higher or lower relative prices for crude oil. 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. We supply refined products to the El Paso area via our El Paso refinery product distribution terminal, and to other areas including Tucson, Phoenix, Albuquerque, and Juarez, Mexico through pipeline systems linked to our El Paso refinery. We deliver refined products to Tucson and Phoenix through the Kinder Morgan East Line that has a capacity of over 200,000 bpd, and to Albuquerque and Juarez, Mexico through pipelines owned by Plains All American Pipeline L.P. ("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 (the "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.

Gallup Refinery

Our Gallup refinery, located near Gallup, New Mexico, has a crude oil throughput capacity of 25,000 bpd and approximately 470,000 barrels of storage capacity. 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 for our Gallup refinery comes from Colorado, New Mexico, and Utah.

Process Summary. Our Gallup refinery produces a large percentage of high value products. Each barrel of raw materials processed by our Gallup refinery yielded in excess of 90% of high value refined products, including gasoline and diesel fuel, during the past three years.

Power Supply. A regional electric cooperative supplies electrical power to our Gallup refinery. There are several uninterruptible power supply units throughout the plant to maintain computers and controls in the event of a power outage. We purchase our natural gas at market rates and have two available pipeline sources for natural gas supply to our refinery.

Raw Material Supply. The feedstock for our Gallup refinery is Four Corners Sweet that is sourced primarily from northern New Mexico and Utah. We receive crude through our own pipeline system and through a third-party pipeline connected to our Gallup refinery. Our crude oil pipeline system reaches approximately 200 miles into the San Juan Basin of the Four Corners area and connects with a local common carrier pipeline. We also own a pipeline capable of transporting 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.

6

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.

The following table summarizes the historical feedstocks used by our Gallup refinery for the years indicated:

	Year Ended December 31,			Percentage For Year Ended December 31,
Refinery Feedstocks (bpd)	2012	2011	2010	2012
Crude Oil:
Sweet crude oil	20,941	21,758	21,140	91.5	%
Total Crude Oil	20,941	21,758	21,140	91.5	%
Other Feedstocks and Blendstocks:
Intermediates and other	684	853	1,822	3.0	%
Blendstocks	1,254	1,501	1,149	5.5	%
Total Other Feedstocks and Blendstocks	1,938	2,354	2,971	8.5	%
Total Crude Oil and Other Feedstocks and Blendstocks	22,879	24,112	24,111	100.0	%

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 that could result in our paying higher or lower relative prices for crude oil.

Refined Products Transportation. We distribute all gasoline and diesel fuel produced at our Gallup refinery through the truck loading rack. We supply these refined products to Arizona, Colorado, New Mexico, and Utah, primarily via a fleet of refined product trucks operated by our wholesale group and common carriers.

Terminal Operations

We also 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. 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. This terminal receives product deliveries via truck or 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.

Mid-Atlantic

Yorktown Facility

During the fourth quarter of 2011, we entered into a sales agreement to sell the Yorktown, Virginia, refining assets and the 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 the Yorktown facility as a stand-alone product distribution terminal through our wholesale business group to supply refined product in the Mid-Atlantic area. Prior to the temporary suspension and sale of the Yorktown assets, the refinery and terminal primarily served Yorktown, Virginia; Salisbury, Maryland; Norfolk, Virginia; North Carolina; and the New York Harbor. We continue to market refined products in the Mid-Atlantic region through our wholesale group via a supply agreement. See additional discussion under Wholesale Segment below.

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The following table summarizes the historical feedstocks used by the Yorktown refinery for the year indicated:

	Year Ended December 31,
Refinery Feedstocks (bpd)	2010 (1)
Crude Oil:
Sweet crude oil	7,713
Heavy crude oil	40,274
Total Crude Oils	47,987
Other Feedstocks and Blendstocks:
Intermediates and other	4,522
Blendstocks	5,255
Total Other Feedstocks and Blendstocks	9,777
Total Crude Oils and Other Feedstocks and Blendstocks	57,764

(1) Feedstocks 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.

Wholesale Segment

Our wholesale group includes several lubricant and bulk petroleum distribution plants, unmanned fleet fueling operations, 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, Maryland, and Virginia. Beginning in January 2011, wholesale operations include the distribution of refined product through the refined product distribution terminal at the Yorktown facility that was sold in December 2011. Following the sale of the Yorktown terminal assets, our wholesale business continues to operate through the terminal as a customer. Our wholesale group purchases petroleum fuels and lubricants primarily 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.; SoCo Group, Inc.; C&R Distributing, Inc.; and Brewer Petroleum Services, 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.

Through August 2012, the refined products sold by our wholesale group in the Mid-Atlantic region were purchased from various third parties. On August 31, 2012, we entered into an exclusive supply and marketing agreement with a third party covering activities related to our refined product supply, hedging, and sales in the Mid-Atlantic region. Under this supply agreement, we receive monthly distribution amounts from the supplier equal to one-half of the amount by which our refined product sales exceed the supplier's costs of acquiring, transporting, and hedging the refined product. To the extent our refined product sales do not exceed the refined product costs during any month, we will pay one-half of that amount to the supplier. Our payments to the supplier are limited in an aggregate annual amount of $2.0 million.

Retail Segment

Our retail group operates retail stores that sell various grades of gasoline, diesel fuel, general merchandise, and beverage and food products to the general public. At February 22, 2013, our retail group operated 222 retail stores located in Arizona, Colorado, New Mexico, and Texas. We supply the majority of our retail gasoline and diesel fuel inventories through our wholesale group, and purchase general merchandise as well as beverage and food products from various suppliers.

The main competitive factors affecting our retail segment are the location of the stores, brand identification, and product price and quality. Our retail stores compete with Alon USA Energy, ampm, Brewer Oil Company, Circle K, Kroger, K&G Markets (formerly ConocoPhillips), Maverik, Murphy Oil, Quick-Trip, Valero Energy Corp., 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. Our retail operations are substantially smaller than many of these competitors and they are potentially better able to withstand volatile conditions in the fuel market and lower profitability in merchandise sales due to their integrated operations.

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At February 22, 2013, our retail group had 222 retail 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	43	119
Colorado	10	2	12
Texas	—	25	25
	113	109	222

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 violations 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 actions. 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.

See Note 21, Contingencies, in the Notes to Consolidated Financial Statements included in this annual report for detailed information on certain environmental matters.

Regulation of Fuel Quality

The EPA adopted regulations under the Clean Air Act that require significant reductions in the sulfur content in on-road and off-road diesel fuel. The final phase of these regulations requires that all locomotive and marine diesel must meet the 15 parts per million ("ppm") sulfur standard beginning June 2012. 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 an expansion of our El Paso diesel hydrotreater in 2013.

Our El Paso and Gallup refineries are required to meet Mobile Source Air Toxics ("MSAT II") regulations to reduce the benzene content of gasoline. The MSAT II regulations currently require reduction of benzene in the finished gasoline pool to an annual average of 0.62 volume percent. Between July 1, 2012 and December 31, 2013, and annually thereafter, each refinery must also average 1.30 volume percent benzene without the use of credits. We expended $63.7 million to comply with MSAT II regulations at our El Paso refinery by completing construction of a benzene saturation unit that began operating in March 2011. During 2012 we made $2.5 million in capital expenditures for our Gallup refinery to meet the 1.30 volume percent requirement. In addition to our capital expenditures to build benzene reducing process units, we have utilized and expect to continue utilizing purchased third party credits to comply with the gasoline pool average requirement in the MSAT II regulations. For additional details, see Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Capital Spending.

The EPA is expected to propose MSAT III regulations for gasoline in 2013. We expect these regulations to require lower sulfur content limits with an effective date between 2016 and 2018. If and when these new regulations take effect, they will most likely require capital spending and adjustments to the operations of our refineries.

Pursuant to the Energy Acts of 2005 and 2007, the EPA has issued Renewable Fuels Standards ("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 refined petroleum fuels will displace an increasing

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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.

Beginning in late 2011, the EPA initiated civil and criminal enforcement against companies it believes produced invalid fuel credits known as Renewable Identification Numbers ("RINs") and at the same time, the EPA issued Notices of Violation to several companies, including ourselves, who it claims purchased and used invalid RINs to satisfy their obligations under the Renewable Fuels Standard program. We purchased RINs to satisfy a portion of our obligations under the Renewable Fuels Standard program for calendar year 2010 and had purchased some RINs the EPA considered invalid. In April 2012, we entered into an administrative settlement with the EPA that required us to pay a penalty of less than $0.1 million. We continue to purchase RINs to satisfy our obligations under the RFS program, and we understand the EPA continues to investigate invalid RINs. The EPA completed a draft proposed rule in late 2012 to address RIN validity and minimize the risk to RIN purchasers through use of a quality assurance program. The proposed rule is expected to be published in 2013. While we do not know if the EPA will identify other RINs we have purchased as being invalid or what actions the EPA would take, at this time we do not expect any such action would have a material effect on our financial condition, results of operations, or cash flows. For additional details, see Note 21, Contingencies, in the Notes to Consolidated Financial Statements included in this annual report.

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 those 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 and fueling stations 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 any alleged migration of petroleum or hazardous substances from our facilities or transport operations.

Employees

As of February 22, 2013, we employed approximately 3,800 people, approximately 430 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 2012. The new collective bargaining agreement covering the El Paso refinery employees expires in 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 affect on our business, financial condition, and results of operations. The collective bargaining agreement covering the employees at our Bloomfield refinery who were terminated in connection with the indefinite suspension of refining operations at our Bloomfield facility in November 2009 expired in March 2012.

During 2012, we recognized a union as the bargaining representative for 28 finished product and lube drivers and warehouse employees at one of our Albuquerque, New Mexico facilities. Negotiations related to a collective bargaining agreement are on-going related to these covered employees.

Available Information

We file reports with the Securities and Exchange Commission (the "SEC"), including annual reports on Form 10-K, quarterly reports on Form 10-Q, and other reports from time to time. The public may read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Room 1580, Washington, 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. We do not, however, incorporate any information on that website into this Form 10-K.

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 (the "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

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Form 10-K. We make available on this website under “Investor Relations,” free of charge, our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports simultaneously to the electronic filings of those materials with, or furnishing of those materials to, the SEC. We also make available to shareholders hard copies of our complete audited financial statements free of charge upon request.

On July 9, 2012, our Chief Executive Officer certified to the NYSE that he was not aware of any violation 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 compared to 2012 and 2011 due to decreased demand for refined products, substantial increases in feedstock costs, and lower increases in product prices throughout much of 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 2012 ranged from $77.69 to $109.77 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 ("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, as was the case throughout much of 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

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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” ("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. Due to the volatility in the price of crude oil and other blendstocks, we experienced fluctuations in our LIFO reserves during the past three years. We also experienced LIFO liquidations based on decreased levels in our inventories. These LIFO liquidations resulted in an increase in cost of products sold of $4.0 million for the year ended December 31, 2012 and decreases in cost of products sold of $22.3 million and $16.9 million, respectively, for the years ended December 31, 2011 and 2010.

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 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 hedging transactions 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 that would impact our liquidity and capital resources.

Our indebtedness may limit our ability to obtain additional financing and we also may face difficulties complying with the terms of our indebtedness agreements.

As of December 31, 2012, our total debt was $499.9 million and our stockholders’ equity was $909.1 million. As of December 31, 2012, we had net availability under the amended and restated Revolving Credit Agreement of $394.5 million, consisting of $650.7 million in gross availability and $256.2 million in 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 flows, 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 flows 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.

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 flows 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

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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 would 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 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 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.

The refining business is characterized by high fixed costs resulting from the significant capital outlays associated with refineries, terminals, pipelines, and related facilities. We are dependent on the production and sale of quantities of refined products at refined product margins sufficient to cover operating costs, including any increases in costs resulting from future inflationary pressures or market conditions and increases in costs of fuel and power necessary in operating our facilities. Our short-term working capital needs are primarily crude oil purchase requirements that 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. Furthermore, future regulatory requirements or competitive pressures could result in additional capital expenditures that may not produce a return on investment. Such capital expenditures may require significant financial resources that may be contingent on our access to capital markets and commercial bank loans. Additionally, other matters, such as regulatory requirements or legal actions, may restrict our access to funds for capital expenditures.

Our refineries consist of many processing units, a number of which have been in operation for many years. One or more of the units may require unscheduled downtime for unanticipated maintenance or repairs that are more frequent than our scheduled turnaround for such units. Scheduled and unscheduled maintenance could reduce our revenues during the period of

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time that the units are not operating. We have taken significant measures to expand and upgrade units in our refineries by installing new equipment and redesigning older equipment to improve refinery capacity. The installation and redesign of key equipment at our refineries involves significant uncertainties, including the following: our upgraded equipment may not perform at expected throughput levels; the yield and product quality of new equipment may differ from design and/or specifications and redesign or modification of the equipment may be required to correct equipment that does not perform as expected that could require facility shutdowns until the equipment has been redesigned or modified. Any of these risks associated with new equipment, redesigned older equipment, or repaired equipment could lead to lower revenues or higher costs or otherwise have a negative impact on our future results of operations and financial condition.

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, results of operations, and cash flows.

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 wholesale and retail operations. 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, results of operations, and cash flows.

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. However, we obtain certain of our feedstocks for the El Paso refinery and some refined products we purchase for resale, by pipeline from Gulf Coast refineries. An interruption to our supply of feedstocks for the El Paso refinery could have a material adverse effect on our business, financial condition, results of operations, and cash flows.

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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 ("CERCLA") for contamination of properties that we currently own or operate and facilities to which we transported or arranged for the transportation of wastes or by-products for use, treatment, storage or disposal, without regard to fault or whether our actions were in compliance with law at the time. Our liability could also increase if other responsible parties, including prior owners or operators of our facilities, fail to complete their clean-up obligations. Based on current information, we do not believe these liabilities are likely to have a material adverse effect on our business, financial condition, results of operations, or cash flows. 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, results of operations, and cash flows.

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, 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 and 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, results of operations, and cash flows.

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, results of operations, and cash flows.

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 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, results of operations, and cash flows could be materially adversely affected.

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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, results of operations, and cash flows.

Our business, financial condition, results of operations, and cash flows may be materially adversely affected by a continued economic downturn.

The domestic economy, economic slowdowns, 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 may continue to adversely affect the liquidity, businesses, and/or financial conditions of our customers that 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, results of operations, and cash flows 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 ("Kinder Morgan") for the delivery of all of our 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 our 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, results of operations, and cash flows.

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, results of operations, and cash flows.

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, results of operations, and cash flows.

A material decrease in the supply of crude oil available to our refineries could significantly reduce our production levels.

We continually contract with third-party crude oil suppliers to maintain a sufficient supply of crude oil for production at our refineries. A material decrease in crude oil production from the fields that supply our refineries as a result of economic, regulatory, or natural influences, or an increase in crude oil transport capacities out of the regions that supply our refineries, could result in a decline in the volume of crude oil available to our refineries. In addition, the future growth of our operations may depend in part on whether we can contract for additional supplies of crude oil at a greater rate than the rate of decline in our current supplies. If we are unable to secure sufficient crude oil supplies to our refineries, we may not be able to take full advantage of current and future expansion of our refineries' production capacities. A decline in available crude oil to our refineries or an inability to secure additional crude oil supplies to meet the needs of current or future refinery expansions could result in an overall decline in volumes of refined products produced by our refineries and could have a material adverse effect on our business, financial condition, results of operations, and cash flows.

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We could incur substantial costs or disruptions in our business if we cannot obtain or maintain necessary permits and authorizations.

Our operations require numerous permits and authorizations under various laws and regulations, including environmental and health and safety laws and regulations. These authorizations and permits are subject to revocation, renewal, or modification and can require operational changes that 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 that could have a material adverse effect on our business, financial condition, results of operations, and cash flows.

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 their own 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, results of operations, and cash flows.

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 that 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 adversely 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, results of operations, and cash flows.

We could be subject to damages based on claims brought against us by our customers or lose customers as a result of a failure of our products to meet certain quality specifications.

The products we sell are required to meet certain quality specifications. If certain of our quality control measures were to fail, we could supply products to our customers that do not meet these specifications. This type of incident could result in liability claims regarding damages caused by our products or could impact our ability to retain existing customers or acquire new customers, any of which could have a material adverse effect on our business, financial condition, results of operations, and cash flows.

A substantial portion of our refining workforce is unionized, and we may face labor disruptions that would interfere with our operations.

As of February 22, 2013, we employed approximately 3,800 people, approximately 430 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 2012. The new collective bargaining agreement covering the El Paso refinery employees expires in 2015. While all of our collective bargaining agreements contain “no strike” provisions, those provisions are not effective in the event that an agreement expires.

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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 effect on our business, financial condition, results of operations, and cash flows.

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 at least annually. If events or circumstances no longer support an indefinite life, the intangible asset is tested for impairment and prospectively amortized over its estimated 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 both amortizable intangible assets and intangible assets with indefinite lives for recoverability, management must make estimates of projected cash flows related to the asset being evaluated that 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 stockholders is subject to certain restrictions in our Revolving Credit Agreement and the indenture governing our Senior Secured Notes, including pro forma compliance with a fixed charge coverage ratio test subject to an excess availability test under our Revolving Credit Agreement and compliance with an incurrence-based test and a formula-based maximum dollar amount 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 and Assistant Secretary and a current director) own approximately 30.6% of our common stock as of February 22, 2013. As a result, Mr. Foster and the other members of this group may strongly influence or effectively control the election of our directors, our corporate and management policies, and determine, without the consent of our other stockholders, the outcome of any corporate transaction or other matter submitted to our stockholders for approval, including potential mergers or acquisitions, asset sales, and other significant corporate transactions. The interests of Mr. Foster and the other members of this group may not coincide with the interests of other holders of our common stock.

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If we lose any of our key personnel, our ability to manage our business and continue our growth could be negatively impacted.

Our future performance depends to a significant degree upon the continued contributions of our senior management team, including our Executive Chairman, Chief Executive Officer and President, Chief Financial Officer, Vice President and Assistant Secretary, President-Refining and Marketing, Senior Vice President-Legal, General Counsel and Secretary, Chief Accounting Officer, and Senior Vice President-Treasurer. We do not currently maintain key man life insurance with respect to any member of our senior management team. The loss or unavailability to us of any member of our senior management team or a key technical employee could significantly harm us. We face competition for these professionals from our competitors, our customers, and other companies operating in our industry. To the extent that the services of members of our senior management team would be unavailable to us for any reason, we would be required to hire other personnel to manage and operate our company. We may not be able to locate or employ such qualified personnel on acceptable terms, or at all.

Terrorist attacks, cyber-attacks, threats of war, or actual war may negatively affect our operations, financial condition, results of operations, cash flows, 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, cash flows, and prospects. Energy related assets (that 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, cash flows, 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.

We are dependent on our technology infrastructure and maintain and rely upon certain critical information systems for the effective operation of our business. These information systems include data network and telecommunications, Internet access and our websites, and various computer hardware equipment and software applications, including those that are critical to the safe operation of our refineries, pipelines, and terminals. These information systems are subject to damage or interruption from a number of potential sources including natural disasters, software viruses or other malware, power failures, cyber-attacks, and other events. To the extent that these information systems are under our control, we have implemented measures such as virus protection software, intrusion detection systems, and emergency recovery processes to address the outlined risks. However, security measures for information systems cannot be guaranteed to be failsafe. Any compromise of our data security or our inability to use or access these information systems at critical points in time could unfavorably impact the timely and efficient operation of our business and subject us to additional costs and liabilities.

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, 2012, 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, 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, results of operations, or cash flows.

Item 4. Mine Safety Disclosures

Not Applicable.

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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 22, 2013, we had 80 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
2012:
First quarter	$	20.07	$	13.98	$	0.04
Second quarter	22.27		17.51		0.04
Third quarter	27.97		22.11		0.08
Fourth quarter (1)	31.04		23.96		2.58
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		—

(1) Dividends for the fourth quarter 2012 included special dividends of $1.00 per common share and $1.50 per common share.

Our payment of dividends is limited under the terms of our Revolving Credit Agreement and our Senior Secured Notes, and in part, depends on our ability to satisfy certain financial covenants. Throughout 2012, our board of directors approved and we declared quarterly and special cash dividends totaling $240.7 million paid on various dates throughout the year. On January 15, 2013, our board of directors approved a first quarter 2013 cash dividend of $0.12 per share of common stock in an aggregate payment of $10.5 million that was paid on February 14, 2013. We neither declared nor paid dividends during fiscal year 2011.

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 our common stock relative to the cumulative total stockholder returns of the Standard & Poor’s ("S&P, 500") index, and a customized peer group of six companies that includes: Alon USA Energy, Inc., CVR Energy, Inc., Delek US Holdings Inc., HollyFrontier Corp., 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, 2012 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.

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COMPARISON OF 60-MONTH CUMULATIVE TOTAL RETURN

COMPARISON OF 60-MONTH CUMULATIVE TOTAL RETURN

(Tabular representation of data in graph above)

December 2007 - June 2010	Dec	Mar	Jun	Sep	Dec	Mar	Jun	Sep	Dec	Mar	Jun
	2007	2008	2008	2008	2008	2009	2009	2009	2009	2010	2010
Western Refining, Inc.	$100	$55.64	$49.20	$42.01	$32.24	$49.61	$29.33	$26.80	$19.57	$22.85	$20.90
S&P 500	100	90.55	88.08	80.71	62.99	56.05	64.98	75.12	79.65	83.94	74.34
Peer Group	100	69.69	56.92	43.56	31.31	28.83	26.76	31.27	27.54	31.50	28.70

September 2010 - December 2012	Sep	Dec	Mar	Jun	Sep	Dec	Mar	Jun	Sep	Dec
	2010	2010	2011	2011	2011	2011	2012	2012	2012	2012
Western Refining, Inc.	$21.77	$43.96	$70.42	$75.07	$51.76	$55.21	$78.37	$92.92	$109.61	$128.99
S&P 500	82.74	91.64	97.07	97.16	83.69	93.58	105.35	102.45	108.95	108.53
Peer Group	28.85	38.38	52.47	47.34	34.44	38.36	48.24	48.00	64.57	70.73

Purchases of Equity Securities by the Issuer and Affiliated Purchasers

On July 18, 2012, our board of directors authorized a share repurchase program of up to $200 million. We may repurchase shares from time-to-time through open market transactions, block trades, privately negotiated transactions, accelerated share repurchase transactions, or otherwise subject to market conditions, as well as corporate, regulatory, and other considerations. Our board of directors authorized this share repurchase program through July 31, 2013, but may discontinue the program in its discretion at any time prior to that date. During 2012, we purchased 3,324,135 shares as part of our share repurchase program at a cost of $82.3 million. As of February 22, 2013 we have not purchased any additional shares.

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The following table presents shares repurchased, by month, during 2012.

	Total number of shares purchased	Average price paid per share (1)		Total number of shares purchased as part of publicly announced plans or programs	Maximum dollar value that may yet be purchased under the program (in thousands)
July 1 - July 31	—	$	—	—	$	200,000
August 1 - August 31	—	—		—	200,000
September 1 - September 30	296,364	25.85		296,364	192,334
October 1 - October 31	2,443,102	24.65		2,443,102	132,066
November 1 - November 30	584,669	24.50		584,669	117,730
December 1 - December 31	—			—	117,730
	3,324,135			3,324,135

(1) Average price per share excludes commissions.

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Item 6. Selected Financial Data

The following tables set forth a summary of our historical financial and operating data for the periods indicated. The summary results of operations and financial position data as of and for the five years ended December 31, 2012 have been derived from the consolidated financial statements of Western Refining, Inc. and its subsidiaries.

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 consolidated financial statements and the notes thereto included in Item 8. Financial Statements and Supplementary Data.

	Year Ended December 31,
	2012			2011			2010			2009			2008
	(In thousands, except per share data)
Statement of Operations Data
Net sales	$	9,503,134		$	9,071,037		$	7,965,053		$	6,807,368		$	10,725,581
Operating costs and expenses:
Cost of products sold (exclusive of depreciation and amortization) (1)	8,054,385			7,532,423			7,155,967			5,944,128			9,735,500
Direct operating expenses (exclusive of depreciation and amortization)	483,070			463,563			444,531			486,164			532,325
Selling, general, and administrative expenses	114,628			105,768			84,175			109,697			115,913
(Gain) loss and impairments on disposal of assets, net	(1,891		)	447,166			13,038			52,788			—
Goodwill impairment loss	—			—			—			299,552			—
Maintenance turnaround expense	47,140			2,443			23,286			8,088			28,936
Depreciation and amortization	93,907			135,895			138,621			145,981			113,611
Total operating costs and expenses	8,791,239			8,687,258			7,859,618			7,046,398			10,526,285
Operating income (loss)	711,895			383,779			105,435			(239,030		)	199,296
Other income (expense):
Interest income	696			510			441			248			1,830
Interest expense and other financing costs	(81,349		)	(134,601		)	(146,549		)	(121,321		)	(102,202		)
Amortization of loan fees	(6,860		)	(8,926		)	(9,739		)	(6,870		)	(4,789		)
Write-off of unamortized loan fees	—			—			—			(9,047		)	(10,890		)
Loss on extinguishment of debt	(7,654		)	(34,336		)	—			—			—
Other, net	359			(3,898		)	7,286			(15,184		)	1,176
Income (loss) before income taxes	617,087			202,528			(43,126		)	(391,204		)	84,421
Provision for income taxes	(218,202		)	(69,861		)	26,077			40,583			(20,224		)
Net income (loss)	$	398,885		$	132,667		$	(17,049	)	$	(350,621	)	$	64,197
Basic earnings (loss) per share	$	4.42		$	1.46		$	(0.19	)	$	(4.43	)	$	0.94
Diluted earnings (loss) per share	3.71			1.34			(0.19		)	(4.43		)	0.94
Dividends declared per common share	$	2.74		$	—		$	—		$	—		$	0.06
Weighted average basic shares outstanding	89,270			88,981			88,204			79,163			67,715
Weighted average dilutive shares outstanding	111,822			109,792			88,204			79,163			67,715

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	Year Ended December 31,
	2012			2011			2010			2009			2008
	(In thousands)
Cash Flow Data
Net cash provided by (used in):
Operating activities	$	916,353		$	508,200		$	134,456		$	140,841		$	285,575
Investing activities	18,506			(72,194		)	(73,777		)	(115,361		)	(220,554		)
Financing activities	(651,721		)	(325,089		)	(75,657		)	(30,407		)	(274,769		)
Other Data
Adjusted EBITDA (2)	$	1,083,669		$	786,239		$	287,770		$	192,948		$	399,667
Capital expenditures	202,157			83,809			78,095			115,854			222,288
Balance Sheet Data (at end of period)
Cash and cash equivalents	$	453,967		$	170,829		$	59,912		$	74,890		$	79,817
Restricted cash	—			220,355			—			—			—
Working capital	559,213			544,981			272,750			311,254			314,521
Total assets	2,480,407			2,570,344			2,628,146			2,824,654			3,076,792
Total debt	499,863			803,990			1,069,531			1,116,664			1,340,500
Stockholders’ equity	909,070			819,828			675,593			688,452			811,489

(1) The net effect of commodity hedging gains and losses included in cost of products sold for the periods presented was as follows:

	Year Ended December 31,
	2012			2011			2010			2009			2008
	(In thousands)
Realized commodity hedging gains (losses), net	$	(144,448	)	$	(76,033	)	$	(9,770	)	$	(20,184	)	$	5,208
Unrealized commodity hedging gains (losses), net	(229,672		)	183,286			337			(1,510		)	6,187
Total realized and unrealized commodity hedging gains (losses), net	$	(374,120	)	$	107,253		$	(9,433	)	$	(21,694	)	$	11,395

(2) 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 certain other non-cash income and expense items. However, Adjusted EBITDA is not a recognized measurement under United States generally accepted accounting principles ("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), and certain non-cash charges that are items that may vary for different companies for reasons unrelated to overall operating performance.

Adjusted EBITDA has limitations as an analytical tool, and you should not consider it in isolation, or as a substitute for analysis of our results as reported under GAAP. Some of these limitations are:

• Adjusted EBITDA does not reflect our cash expenditures or future requirements for significant turnaround activities, capital expenditures, or contractual commitments;

• Adjusted EBITDA does not reflect the interest expense or the cash requirements necessary to service interest or principal payments on our debt;

• Adjusted EBITDA does not reflect changes in, or cash requirements for, our working capital needs; and

• Adjusted EBITDA, as we calculate it, may differ from the Adjusted EBITDA calculations of other companies in our industry, thereby limiting its usefulness as a comparative measure.

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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,
	2012		2011			2010			2009			2008
	(In thousands)
Net income (loss)	$	398,885	$	132,667		$	(17,049	)	$	(350,621	)	$	64,197
Interest expense and other financing costs	81,349		134,601			146,549			121,321			102,202
Amortization of loan fees	6,860		8,926			9,739			6,870			4,789
Provision for income taxes	218,202		69,861			(26,077		)	(40,583		)	20,224
Depreciation and amortization	93,907		135,895			138,621			145,981			113,611
Maintenance turnaround expense	47,140		2,443			23,286			8,088			28,936
Loss and impairments on disposal of assets, net (a)	—		450,796			13,038			52,788			—
Goodwill impairment loss	—		—			—			299,552			—
Loss on extinguishment of debt	7,654		34,336			—			—			—
Write-off of unamortized loan fees	—		—			—			9,047			10,890
Net change in lower of cost or market inventory reserve	—		—			—			(61,005		)	61,005
Unrealized loss (gain) on commodity hedging transactions, net (b)	229,672		(183,286		)	(337		)	1,510			(6,187		)
Adjusted EBITDA	$	1,083,669	$	786,239		$	287,770		$	192,948		$	399,667

(a) The calculation of Adjusted EBITDA for the year ended December 31, 2011 includes the add-back of net gains and losses of $450.8 million incurred from the sale of the Yorktown refining and certain pipeline assets, and to a lesser extent the impairment of Bloomfield refining assets. We have adjusted this amount to exclude a $3.6 million gain related to the sale of platinum catalyst that was previously included in the net loss from other sales transactions. We consider the sale of catalysts to be a routine transaction occurring in the normal course of business and as such, should not be added back to net income (loss) in our calculation of Adjusted EBITDA.

(b) Adjusted EBITDA has been adjusted for the impact of net non-cash unrealized gains and losses related to our commodity hedging transactions. We believe the inclusion of this component of net income provides a better representation of Adjusted EBITDA given the non-cash and potentially volatile nature of commodity hedging.

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 report. In this Item 7, all references to “Western Refining,” “the Company,” “Western,” “we,” “us,” and “our” refer to Western Refining, Inc. and its subsidiaries, 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 retail stores that sell various grades of gasoline, diesel fuel, and convenience store merchandise. We own and operate two refineries with a total crude oil throughput capacity of 153,000 barrels per day ("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 25,000 bpd. In September 2010, we temporarily suspended refining operations of a 70,000 bpd refinery on the east coast of the United States near Yorktown, Virginia. Between September 2010 and December 29, 2011, we operated a stand-alone refined product distribution terminal at Yorktown. On December 29, 2011, we completed the sale of the Yorktown refining and terminal assets. We continue to market refined products in the Mid-Atlantic region through our wholesale group. Our primary operating areas encompass west Texas, Arizona,

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Colorado, New Mexico, and the Mid-Atlantic region. 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. As of December 31, 2012, we also operated 222 retail 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 report 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. We 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 retail 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 commodity values such as refined product prices and the cost of crude oil and other feedstocks. The spread between our cost of crude oil and our sales prices for refined products is the primary factor affecting our earnings and cash flows from operations. Factors driving the movement in petroleum based commodities include supply and demand in 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; logistics constraints; 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 have improved consistently from 2010 through 2012. Another factor that impacted our annual margins when we owned and operated the Yorktown refinery was the year-to-year narrowing of heavy light crude oil differentials that began during the second quarter of 2009, continued significantly through 2010, and remained historically narrow during 2011. The Yorktown refinery was capable of processing up to 100% of its throughput capacity with heavy crude oil, and these narrow heavy light differentials had an ongoing negative impact on Yorktown's refining economics. Our refining results of operations for 2011 and 2010 reflect additional negative impact of various impairment charges and a loss on the disposal of certain refining assets. Discussion of these charges and loss follows below under Long-lived Asset Impairment Losses.

Other impacts to our overall refinery gross margins include the sale of lower value products such as residuum and propane as well as refinery production loss. Higher crude costs tend to have a narrowing effect on the margin for lower value product sales. Our refinery product yield volume is less than our total refinery throughput volume; a higher yield loss negatively impacts our gross margin. 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. Included within our consolidated cost of products sold were net realized and unrealized commodity hedging losses of $374.1 million for 2012 and net realized and unrealized commodity hedging gains of $107.3 million for 2011. The majority of this activity relates to our refining segment and the remainder relates to our wholesale segment. Our refining cost of products sold includes $350.5 million in net realized and unrealized economic hedging losses for the year ended December 31, 2012 and $103.3 million in net realized and unrealized economic hedging gains for the year ended December 31, 2011. 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 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.

Periodically we have planned maintenance turnarounds at our refineries that are expensed as incurred. We completed a scheduled maintenance turnaround at the south side of the El Paso refinery during the first quarter of 2010. We completed a 24 day refinery maintenance turnaround at our Gallup refinery during October 2012. After December 31, 2012 we began a scheduled maintenance turnaround to be completed during the first quarter of 2013 for the north side units of the El Paso refinery.

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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 ("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. We have also experienced LIFO liquidations based on decreased levels in our inventories. These LIFO liquidations resulted in an increase in cost of products sold of $4.0 million for the year ended December 31, 2012 and decreases in cost of products sold of $22.3 million and $16.9 million, respectively, for the years ended December 31, 2011 and 2010. 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. 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. These margins are equal to the sales price, net of discounts less total cost of sales and are measured on a cents per gallon ("cpg") basis. Factors that influence margins include local supply, demand, and competition.

Historically, we purchased refined products to sell through our wholesale group in the Mid-Atlantic region from various third parties. On August 31, 2012, we entered into an exclusive supply and marketing agreement with a third party covering activities related to our refined product supply, hedging, and sales in the Mid-Atlantic region. Under the supply agreement, we will receive monthly distribution amounts from the supplier equal to one-half of the amount by which our refined product sales exceeds the supplier's costs of acquiring, transporting, and hedging the refined product. To the extent our refined product sales do not exceed the refined product costs during any month, we will pay one-half of that amount to the supplier. Our payments to the supplier are limited to an aggregate annual amount of $2.0 million.

Retail. Earnings and cash flows from our retail business segment are primarily affected by the sales volumes and margins of gasoline and diesel fuel, and by the sales and margins of merchandise, sold at our retail 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 cpg basis. Fuel margins are impacted, in descending order of magnitude, by competition, local and regional supply, and demand. 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 reflect seasonal trends such that operating results for the first and fourth calendar quarters are generally lower than those for the second and third calendar quarters of each year.

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 connection with the suspension of refining operations at our Bloomfield refinery during 2009, certain additional impairment charges were recorded during the fourth quarters of 2011 and 2010. 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. We recorded additional impairment charges of $11.7 million and $9.1 million, respectively, resulting from our fourth quarters of 2011 and 2010 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 under (Gain) loss and impairments on disposal of assets, net in the Consolidated Statements of Operations for the years ended December 31, 2011 and 2010.

In September 2010, in connection with the temporary suspension of refining operations at the Yorktown facility, we performed an impairment analysis. Based on that analysis, we determined that the undiscounted forecasted cash flows exceeded the carrying amount of the Yorktown long-lived and intangible assets and thus, no impairment was recorded at that time. During the period that refining operations were suspended through the date of the sale of the 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.

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In connection with the execution of the agreements to sell the Yorktown refining and terminal assets on December 29, 2011, we recorded a loss of $465.6 million, including transaction costs of $1.2 million. This loss has been included in (Gain) 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 16" New Mexico Pipeline. 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 (Gain) 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.

Debt and Equity Transactions

During 2009, we issued $600.0 million in Senior Secured Notes consisting of both floating and fixed rate principal amount notes. Also in 2009, we issued $215.5 million of Convertible Senior Notes. The conversion rate at December 31, 2012 is 102.3750 to each $1,000 of principal amount of Convertible Senior Notes. Including original issue discounts ("OID") we reported annual interest costs related to the Senior Secured Notes and the Convertible Senior Notes at rates ranging from 13.0% to 13.8%. In December 2011, we redeemed the entire $275.0 million of floating rate notes at a premium to par of 5%.

We made regularly scheduled interest and principal payments under our Term Loan Credit Agreement ("Term Loan") through the first quarter of 2012. In addition to scheduled payments, we made non-mandatory prepayments of $30.0 million and $291.8 million during the first and second quarters of 2012, respectively, reducing the principal balance to zero.

As a result of the redemption of the Senior Secured Floating Rate Notes and the amendment of our Revolving Credit Agreement in 2011 and the retirement of our Term Loan in 2012, we recognized losses on extinguishment of debt of $34.3 million and $7.7 million, respectively. These losses are included in Loss on extinguishment of debt in the Consolidated Statements of Operations for the years ended December 31, 2012 and 2011. Collectively, the redemption of the Senior Secured Floating Rate Notes and the retirement of the Term Loan have contributed to decreases of $53.3 million in interest expense for the year ended December 31, 2012 compared to 2011.

On July 18, 2012, our board of directors authorized a share repurchase program of up to $200 million. We may repurchase shares from time-to-time through open market transactions, block trades, privately negotiated transactions, accelerated share repurchase transactions, or otherwise subject to market conditions, as well as corporate, regulatory, and other considerations. Our board of directors authorized this share repurchase program through July 31, 2013, but may discontinue the program at its discretion at any time prior to that date. During 2012, we purchased 3,324,135 shares as part of our share repurchase program at a cost of $82.3 million. As of February 22, 2013 we have not repurchased any additional shares.

See Note 13, Long-Term Debt, and Note 18, Stockholders’ Equity, in the Notes to 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 the 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 the 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 (Gain) loss and impairments on disposal of assets, net in the Consolidated Statement of Operations for the year ended December 31, 2011.

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 (Gain) loss and impairments on disposal of assets, net in our Consolidated Statements of Operations for the years ended December 31, 2011 and 2010, 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

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long-lived assets. This charge is included under other (Gain) loss and impairments on disposal of assets, net in our Consolidated Statement of Operations for the year ended December 31, 2010.

Employee Benefit Plans

As of December 31, 2012, we have distributed $25.8 million ($5.7 million in 2012, $7.2 million in 2011, and $12.8 million in 2010) from plan assets to plan participants as a result of the 2010 temporary idling of Yorktown refining operations and resultant termination of several participants of the Yorktown cash balance plan. We contributed $1.5 million and$4.4 million to the Yorktown pension plan during 2012 and 2011, respectively. 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 either 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 in 2011 and a decrease of $5.3 million in 2010). Currently, we do not plan to terminate the Yorktown retiree medical plan.

Commodity Hedging Activities, Environmental Cost Recoveries, Property Taxes, and Other

Our operating results for the years ended December 31, 2012 and 2010 included realized and unrealized net losses from our commodity hedging activities of $374.1 million and $9.4 million, respectively, and realized and unrealized net gains from our commodity hedging activities of $107.3 million for the year ended December 31, 2011. 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 the Notes to Consolidated Financial Statements included in this annual report for further discussion on our commodity hedging activities.

During 2012, we increased our annual property tax expense estimate by approximately $11.6 million resulting from revised El Paso property appraisal rolls for 2012. We believe the appraised property values to be in error and have filed a lawsuit in state district court to appeal this appraised value.

Our income tax provisions for the years ended December 31, 2012 and 2011 include the effects of a change in our valuation allowance of $2.8 million and $23.7 million, respectively, 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.

Planned Maintenance Turnaround

During the years ended December 31, 2012, 2011, and 2010, we incurred costs of $47.1 million, $2.4 million, and $23.3 million, respectively, for maintenance turnarounds. Costs incurred during 2012 and 2011 related primarily to the planned 2012 turnaround for Gallup. We began a refinery maintenance turnaround at our Gallup refinery during September 2012. That turnaround was completed during October 2012. During 2010, we incurred costs of $23.3 million in connection with a maintenance turnaround at the El Paso refinery. Our next scheduled maintenance turnaround is during the first quarter of 2013 for the north side units of the El Paso refinery. We expense the cost of maintenance turnarounds when the expense is incurred, while most of our competitors 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 that can materially impact reported results. Changes in these estimates or assumptions, or actual results that are different, could materially impact our financial condition, results of operations, and cash flows.

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 ("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 that 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 estimated fair value of the asset being tested for impairment.

Intangible Assets. 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.

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.

Certain of our environmental obligations are recorded on a discounted basis. Where the available information is sufficient to estimate the amount of liability, that estimate is used. Where the information is only sufficient to establish a range of probable liability and no point within the range is more likely than other, the lower end of the range is used. Possible recoveries

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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.

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 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, we elected not to pursue hedge accounting treatment for financial accounting purposes, generally because of the difficulty of establishing and maintaining the required documentation that would allow for hedge accounting. The swap contracts used to fix the margin on a portion of our 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.

Other Postretirement Obligations. 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 other postretirement liability and cost. 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. We measure the cost of employee services received in exchange for equity instruments, awarded under either of our long-term incentive plans, based on the grant date fair value of the award. The fair value of each awarded share is equal to the market price at closing as of the measurement date. We amortize the expense on a straight-line basis over the scheduled vesting periods of individual awards.

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 did not affect our financial position or results of operations because these requirements only affected 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 did not affect our financial position or results of operations because these requirements only affected disclosures.

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Results of Operations

A discussion and analysis of our consolidated and operating segment financial data and key operating statistics for the three years ended December 31, 2012 is presented below:

Consolidated

Fiscal Year Ended December 31, 2012 Compared to Fiscal Year Ended December 31, 2011

	Year Ended December 31,
	2012			2011			Change
	(In thousands)
Net sales (1)	$	9,503,134		$	9,071,037		$	432,097
Operating costs and expenses:
Cost of products sold (exclusive of depreciation and amortization) (1)	8,054,385			7,532,423			521,962
Direct operating expenses (exclusive of depreciation and amortization) (1)	483,070			463,563			19,507
Selling, general, and administrative expenses	114,628			105,768			8,860
(Gain) loss and impairments on disposal of assets, net	(1,891		)	447,166			(449,057		)
Maintenance turnaround expense	47,140			2,443			44,697
Depreciation and amortization	93,907			135,895			(41,988		)
Total operating costs and expenses	8,791,239			8,687,258			103,981
Operating income	711,895			383,779			328,116
Other income (expense):
Interest income	696			510			186
Interest expense and other financing costs	(81,349		)	(134,601		)	53,252
Amortization of loan fees	(6,860		)	(8,926		)	2,066
Loss on extinguishment of debt	(7,654		)	(34,336		)	26,682
Other, net	359			(3,898		)	4,257
Income before income taxes	617,087			202,528			414,559
Provision for income taxes	(218,202		)	(69,861		)	(148,341		)
Net income	$	398,885		$	132,667		$	266,218

(1) Excludes $4,909.4 million and $5,022.8 million of intercompany sales; $4,901.5 million and $5,010.9 million of intercompany cost of products sold; and $7.9 million and $11.9 million of intercompany direct operating expenses for the years ended December 31, 2012 and 2011, respectively.

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	Year Ended December 31,
	2012			2011			Change
	(In thousands, except per share data)
Key Operating Statistics
Fuel sales volume (bbls) (including intersegment sales)
Refining	67,375			69,109			(1,734		)
Wholesale	36,204			36,742			(538		)
Retail	6,934			5,486			1,448
Total fuel sales volume	110,513			111,337			(824		)
Costs and expenses (net of intersegment)
Refining	$	3,409,916		$	3,113,027		$	296,889
Wholesale	3,966,425			3,990,681			(24,256		)
Retail	1,153,241			892,278			260,963
Total operating costs	$	8,529,582		$	7,995,986		$	533,596
Economic hedging activities recognized within cost of products sold
Realized hedging loss, net	$	(144,448	)	$	(76,033	)	$	(68,415	)
Unrealized hedging gain (loss), net	(229,672		)	183,286			(412,958		)
Total hedging gain (loss), net	$	(374,120	)	$	107,253		$	(481,373	)
Operations
Weighted average basic common shares	89,270			88,981			289
Basic earnings per common share	$	4.42		$	1.46		$	2.96
Weighted average diluted common shares	111,822			109,792			2,030
Diluted earnings per share	$	3.71		$	1.34		$	2.37

Overview. The increase in net income from 2011 to 2012 was primarily due to continued strengthening in our margin environment led by significant crude oil cost advantages reflected in refining margins and improved operating results in our wholesale and retail segments. The year over year increase was also impacted by the lack of significant asset disposal losses in the current year. Offsetting a portion of the overall increase in net income were 2012 net realized and unrealized losses from economic hedging activities from our refining and wholesale segments compared to a net gain in the prior year. We discuss economic hedging gains and losses in greater detail within our Refining Segment analysis under Refinery Gross Margin.

We analyze segment margins as a function of net sales less cost of products sold (exclusive of depreciation and amortization). At a consolidated level, our margin decreased from 2011 to 2012 by $89.9 million, due largely to a decrease in our refining margins of $125.3 million, which is a reflection of unrealized commodity hedging gains and losses recorded within cost of products sold. In 2011, we reported an unrealized commodity hedging gain compared to a loss in 2012. Excluding the impact of this activity, refining margins improved over 2011 as a result of our improving crude oil cost advantage in refining. Both our wholesale and retail groups recognized margin increases of $7.9 million and $35.4 million, respectively, net of intercompany transactions that eliminate in consolidation.

Direct Operating Expenses (exclusive of depreciation and amortization). The increase in direct operating expenses from 2011 to 2012 resulted from an increase from our retail and wholesale groups of $22.3 million and $5.3 million, respectively, offset by a decrease from our refining group of $8.2 million, net of intercompany transactions that eliminate in consolidation.

Selling, General, and Administrative Expenses. The increase in selling, general, and administrative expenses from 2011 to 2012 resulted from an increase in corporate overhead and our retail group of $9.1 million and $0.8 million, respectively, offset by a decrease from our refining and wholesale groups of $0.3 million and $0.8 million, respectively. The increase of $9.1 million in corporate overhead was primarily due to increased lease expense ($2.0 million), wages ($1.8 million), charitable contributions ($1.2 million), and commitment fees ($0.9 million). The increase in lease expense was the direct result of lease buy-outs of long-term operating leases. The increase in wages was the result of annual pay raises coupled with an increase in annual incentive compensation.

(Gain) Loss and Impairments on Disposal of Assets, Net. The gain for 2012 related to sales of various assets from our refining group. The loss for 2011 was comprised of losses of $465.6 million related to the sale of the Yorktown refinery and

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terminal assets and $11.7 million related to certain abandoned Bloomfield refinery assets, offset by gains of $26.6 million from the sale of a segment of our pipeline system and $3.6 million related to the sale of catalyst no longer in use at Yorktown.

Maintenance Turnaround Expense. Turnaround costs relate primarily to the 2012 turnaround at our Gallup refinery. The Gallup turnaround began during the third quarter of 2012 and was completed in October 2012. Additionally, turnaround costs were incurred during 2012 for the planned turnaround of the north side units of the El Paso refinery during the first quarter of 2013.

Depreciation and Amortization. The decrease from 2011 to 2012 was primarily due to the disposal of the Yorktown facility in December 2011.

Operating Income. The increase from 2011 to 2012 was primarily the result of decreased losses and impairments on the disposal of assets and decreased depreciation and amortization, offset by a decrease in our margin per barrel and increased direct operating and maintenance turnaround expense.

Interest Income. Interest income remained relatively unchanged.

Interest Expense. The decrease from 2011 to 2012 was attributable to lower debt levels and lower average cost of borrowing during the year ended December 31, 2012 compared to 2011. Lower debt levels were due to the retirement of our Term Loan and resultant write-off of related loan fees.

Amortization of Loan Fees. Amortization of loan fees decreased from 2011 to 2012 due to the retirement of our Term Loan and resultant write-off of related loan fees.

Loss on extinguishment of debt. We recorded a loss on extinguishment of debt for the year ended December 31, 2012 resulting from the prepayment of our Term Loan. The loss on extinguishment of debt for the year ended December 31, 2011 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.

Other, Net. Other, net during 2011 includes amounts related to the settlement of a lawsuit.

Provision for Income Taxes. We recorded income tax expense for the year ended December 31, 2012 using an effective tax rate of 35.4% compared to the federal statutory rate of 35%. Our 2012 income tax provision includes a $2.8 million increase in our valuation allowance from December 31, 2011.

We recorded income tax expense 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 recording a valuation allowance of $23.7 million against certain net operating loss carry-forwards related to Yorktown operations.

See additional analysis under the Refining Segment, Wholesale Segment, and Retail Segment.

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Fiscal Year Ended December 31, 2011 Compared to Fiscal Year Ended December 31, 2010

	Year Ended December 31,
	2011			2010			Change
	(In thousands)
Net sales (1)	$	9,071,037		$	7,965,053		$	1,105,984
Operating costs and expenses:
Cost of products sold (exclusive of depreciation and amortization) (1)	7,532,423			7,155,967			376,456
Direct operating expenses (exclusive of depreciation and amortization) (1)	463,563			444,531			19,032
Selling, general, and administrative expenses	105,768			84,175			21,593
Loss and impairments on disposal of assets, net	447,166			13,038			434,128
Maintenance turnaround expense	2,443			23,286			(20,843		)
Depreciation and amortization	135,895			138,621			(2,726		)
Total operating costs and expenses	8,687,258			7,859,618			827,640
Operating income	383,779			105,435			278,344
Other income (expense):
Interest income	510			441			69
Interest expense and other financing costs	(134,601		)	(146,549		)	11,948
Amortization of loan fees	(8,926		)	(9,739		)	813
Loss on extinguishment of debt	(34,336		)	—			(34,336		)
Other, net	(3,898		)	7,286			(11,184		)
Income (loss) before income taxes	202,528			(43,126		)	245,654
Provision for income taxes	(69,861		)	26,077			(95,938		)
Net income (loss)	$	132,667		$	(17,049	)	$	149,716

(1) Excludes $5,022.8 million and $3,294.0 million of intercompany sales; $5,010.9 million and $3,287.5 million of intercompany cost of products sold; and $11.9 million and $6.5 million of intercompany direct operating expenses for the years ended December 31, 2011 and 2010, respectively.

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	Year Ended December 31,
	2011			2010			Change
	(In thousands, except per share data)
Key Operating Statistics
Fuel sales volume (bbls) (including intersegment sales)
Refining	69,109			90,806			(21,697		)
Wholesale	36,742			24,043			12,699
Retail	5,486			4,936			550
Total fuel sales volume	111,337			119,785			(8,448		)
Costs and expenses (net of intersegment)
Refining	$	3,113,027		$	5,033,146		$	(1,920,119	)
Wholesale	3,990,681			1,904,094			2,086,587
Retail	892,278			663,258			229,020
Total operating costs	$	7,995,986		$	7,600,498		$	395,488
Economic hedging activities recognized within cost of products sold
Realized hedging loss, net	$	(76,033	)	$	(9,770	)	$	(66,263	)
Unrealized hedging gain, net	183,286			337			182,949
Total hedging gain (loss), net	$	107,253		$	(9,433	)	$	116,686
Operations
Weighted average basic common shares	88,981			88,204			777
Basic earnings (loss) per common share	$	1.46		$	(0.19	)	$	1.65
Weighted average diluted common shares	109,792			88,204			21,588
Diluted earnings (loss) per share	$	1.34		$	(0.19	)	$	1.53

Overview. The increase in net income from 2010 to 2011 was primarily due to an improved margin environment, significant crude oil cost advantages, and net realized and unrealized economic hedging gains during 2011.

The increase from 2010 to 2011 was primarily the result of an increase in segment margins from our refining, wholesale, and retail groups of $708.5 million, $17.6 million, and $3.5 million, respectively, net of intercompany transactions that eliminate in consolidation. Our margin for 2011 reflects an increase from unrealized economic hedging gains, partially offset by decreased sales volumes.

Direct Operating Expenses (exclusive of depreciation and amortization). The increase from 2010 to 2011 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 $8.3 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.

Selling, General, and Administrative Expenses. The increase from 2010 to 2011 resulted from increased expenses in corporate overhead and our refining and retail groups of $13.6 million, $7.3 million, and $2.2 million, respectively, and a $1.5 million decrease in our wholesale group. The increase of $13.6 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). 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.

Loss and Impairments on Disposal of Assets, Net. The loss for 2011 included a $465.6 million loss related to the sale of the Yorktown refinery and terminal assets 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.

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Maintenance Turnaround Expense. Costs in 2011 were incurred for the planned 2012 turnaround at our Gallup refinery. Costs in 2010 were for a turnaround at our El Paso refinery.

Depreciation and Amortization. The majority of the decrease from 2010 to 2011 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. The increase from 2010 to 2011 was 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 remained relatively unchanged.

Interest Expense and Other Financing Costs. The decrease from 2010 to 2011 was due to our lower average cost of borrowing during 2011 compared to 2010 resulting from our early redemption of the Floating Rate Notes during 2011 and an amendment to our Term Loan Credit Agreement.

Amortization of Loan Fees. Amortization of loan fees remained relatively unchanged.

Loss on extinguishment of debt. The loss on extinguishment of debt for 2011 was the result of our early redemption of the Floating Rate Notes and an amendment to our Term Loan Credit Agreement.

Other, Net. Both periods include amounts related to the settlement of different 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 during 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 recording a full valuation of $23.7 million against certain net operating loss carry-forwards related to Yorktown operations.

We recorded an income tax benefit using an estimated effective tax rate of 60.5% for 2010, 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.

See additional analysis under the Refining Segment, Wholesale Segment, and Retail Segment.

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Refining Segment

The following tables set forth our summary and individual refining operating results and throughput and production data. All Refineries summary tables include summary operating results and 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 for the periods presented. We do not allocate corporate selling, general, and administrative expenses to the individual refineries or other related refinery operations.

Fiscal Year Ended December 31, 2012 Compared to Fiscal Year Ended December 31, 2011

All Refineries and Related Operations

	Year Ended December 31,
	2012 (6)			2011 (6)		Change
	(In thousands, except per barrel data)
Net sales (including intersegment sales)	$	8,340,178		$	8,399,698	$	(59,520	)
Operating costs and expenses:
Cost of products sold (exclusive of depreciation and amortization) (5)	7,133,308			7,059,210		74,098
Direct operating expenses (exclusive of depreciation and amortization)	320,659			329,237		(8,578		)
Selling, general, and administrative expenses	27,136			27,451		(315		)
(Gain) loss and impairments on disposal of assets, net	(1,382		)	447,166		(448,548		)
Maintenance turnaround expense	47,140			2,443		44,697
Depreciation and amortization	77,575			119,057		(41,482		)
Total operating costs and expenses	7,604,436			7,984,564		(380,128		)
Operating income	$	735,742		$	415,134	$	320,608
Key Operating Statistics
Total sales volume (bpd) (1)	184,086			189,339		(5,253		)
Total refinery production (bpd)	147,461			140,124		7,337
Total refinery throughput (bpd) (2)	149,809			142,257		7,552
Per barrel of throughput:
Refinery gross margin (3) (5)	$	22.01		$	25.82	$	(3.81	)
Refinery gross margin excluding hedging activities (3) (5)	28.40			23.83		4.57
Gross profit (3) (5)	20.60			23.52		(2.92		)
Direct operating expenses (4)	5.85			6.34		(0.49		)

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Southwest Refineries (El Paso and Gallup with Related Operations)

	Year Ended December 31,
	2012 (6)			2011 (6)			Change
	(In thousands, except per barrel data)
Net sales (including intersegment sales)	$	8,339,492		$	8,383,594		$	(44,102	)
Operating costs and expenses:
Cost of products sold (exclusive of depreciation and amortization) (5)	7,137,486			7,048,140			89,346
Direct operating expenses (exclusive of depreciation and amortization)	320,659			285,800			34,859
Selling, general, and administrative expenses	27,136			27,451			(315		)
(Gain) loss and impairments on disposal of assets, net	(1,382		)	(14,829		)	13,447
Maintenance turnaround expense	47,140			2,443			44,697
Depreciation and amortization	77,575			76,254			1,321
Total operating costs and expenses	7,608,614			7,425,259			183,355
Operating income	$	730,878		$	958,335		$	(227,457	)
Key Operating Statistics
Total sales volume (bpd) (1)	184,070			189,007			(4,937		)
Total refinery production (bpd)	147,461			140,124			7,337
Total refinery throughput (bpd) (2)	149,809			142,257			7,552
Per barrel of throughput:
Refinery gross margin (3) (5)	$	21.92		$	25.72		$	(3.80	)
Refinery gross margin excluding hedging activities (3) (5)	28.31			23.73			4.58
Gross profit (3) (5)	20.51			24.25			(3.74		)
Direct operating expenses (4)	5.85			5.50			0.35

All Refineries (El Paso and Gallup)

	Year Ended December 31,
	2012	2011	Change
Key Operating Statistics
Refinery product yields (bpd):
Gasoline	76,536	74,224	2,312
Diesel and jet fuel	61,224	57,037	4,187
Residuum	5,655	5,219	436
Other	4,046	3,644	402
Total refinery production (bpd)	147,461	140,124	7,337
Refinery throughput (bpd):
Sweet crude oil	115,345	113,347	1,998
Sour or heavy crude oil	24,792	19,876	4,916
Other feedstocks and blendstocks	9,672	9,034	638
Total refinery throughput (bpd) (2)	149,809	142,257	7,552

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El Paso Refinery

	Year Ended December 31,
	2012		2011		Change
Key Operating Statistics
Refinery product yields (bpd):
Gasoline	61,669		58,236		3,433
Diesel and jet fuel	54,600		50,211		4,389
Residuum	5,655		5,219		436
Other	3,280		2,882		398
Total refinery production (bpd)	125,204		116,548		8,656
Refinery throughput (bpd):
Sweet crude oil	94,404		91,589		2,815
Sour crude oil	24,792		19,876		4,916
Other feedstocks and blendstocks	7,734		6,680		1,054
Total refinery throughput (bpd) (2)	126,930		118,145		8,785
Total sales volume (bpd) (1)	151,352		155,196		(3,844		)
Per barrel of throughput:
Refinery gross margin (3) (5)	$	28.25	$	23.18	$	5.07
Direct operating expenses (4)	4.50		4.50		—

Gallup Refinery

	Year Ended December 31,
	2012		2011		Change
Key Operating Statistics
Refinery product yields (bpd):
Gasoline	14,867		15,988		(1,121		)
Diesel and jet fuel	6,624		6,826		(202		)
Other	766		762		4
Total refinery production (bpd)	22,257		23,576		(1,319		)
Refinery throughput (bpd):
Sweet crude oil	20,941		21,758		(817		)
Other feedstocks and blendstocks	1,938		2,354		(416		)
Total refinery throughput (bpd) (2)	22,879		24,112		(1,233		)
Total sales volume (bpd) (1)	32,718		33,811		(1,093		)
Per barrel of throughput:
Refinery gross margin (3) (5)	$	28.25	$	26.05	$	2.20
Direct operating expenses (4)	9.60		8.27		1.33

(1) Sales volume includes sales of refined products sourced primarily from our refinery production as well as refined products purchased from third parties. We 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 13.83% and 14.78% of our total consolidated sales volumes for the years ended December 31, 2012 and 2011, respectively. The majority of the purchased refined products are distributed through our wholesale refined product sales activities in the Mid-Atlantic region where we satisfy our refined product customer sales requirements through a third-party supply agreement.

(2) Total refinery throughput includes crude oil, other feedstocks, and blendstocks.

(3) 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. Net realized and net non-cash unrealized economic hedging gains and losses included in the combined refining segment gross margin are not allocated to the individual refineries. Cost of products sold does not include any depreciation or amortization. Refinery

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

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

	Year Ended December 31,
	2012		2011		Change
	(In thousands, except per barrel data)
Net sales (including intersegment sales)	$	8,340,178	$	8,399,698	$	(59,520	)
Cost of products sold (exclusive of depreciation and amortization)	7,133,308		7,059,210		74,098
Depreciation and amortization	77,575		119,057		(41,482		)
Gross profit	1,129,295		1,221,431		(92,136		)
Plus depreciation and amortization	77,575		119,057		(41,482		)
Refinery gross margin	$	1,206,870	$	1,340,488	$	(133,618	)
Refinery gross margin per refinery throughput barrel	$	22.01	$	25.82	$	(3.81	)
Gross profit per refinery throughput barrel	$	20.60	$	23.52	$	(2.92	)

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,
	2012		2011		Change
	(In thousands, except per barrel data)
Net sales (including intersegment sales)	$	8,339,492	$	8,383,594	$	(44,102	)
Cost of products sold (exclusive of depreciation and amortization)	7,137,486		7,048,140		89,346
Depreciation and amortization	77,575		76,254		1,321
Gross profit	1,124,431		1,259,200		(134,769		)
Plus depreciation and amortization	77,575		76,254		1,321
Refinery gross margin	$	1,202,006	$	1,335,454	$	(133,448	)
Refinery gross margin per refinery throughput barrel	$	21.92	$	25.72	$	(3.80	)
Gross profit per refinery throughput barrel	$	20.51	$	24.25	$	(3.74	)

(4) 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.

(5) Cost of products sold for the combined refining segment includes the net realized and net non-cash unrealized hedging activity shown in the table below. The hedging gains and losses are also included in the combined gross profit and refinery gross margin but are not included in those measures for the individual refineries.

	Year Ended December 31,
	2012			2011			Change
	(In thousands)
Realized hedging loss, net	$	(120,805	)	$	(78,995	)	$	(41,810	)
Unrealized hedging gain (loss), net	(229,672		)	182,343			(412,015		)
Total hedging gain (loss), net	$	(350,477	)	$	103,348		$	(453,825	)

(6) The difference between the total refining financial data and our Southwest refining financial data represents the sale of refined products associated with the Yorktown operations. We sold 5,707 barrels of feedstocks during 2012 and 120,783 barrels during 2011.

41

Overview. The increase in operating income from 2011 to 2012, excluding commodity hedging activities, was primarily attributable to higher refining margins influenced by the strong margin environment and crude oil discounts. We continue to realize the positive impact from the discount of WTI crude oil to Brent crude oil, and more recently the WTI Midland/Cushing discount at our El Paso refinery, discussed under Refinery Gross Margin below. The year over year increase was also impacted by the lack of significant asset disposal losses in the current year. Partially offsetting the overall increase in operating income was a greater year over year loss from economic hedging activities.

Refinery Gross Margin. Refinery gross margin is a function of net sales (including intersegment sales) less cost of products sold (exclusive of depreciation and amortization). Refinery gross margin decreased from 2011 to 2012 due to an increase in net realized and unrealized economic hedging losses and lower sales volumes. We enter into hedge contracts to manage our exposure to commodity price risks or to fix sales margins on future gasoline and distillate production. We record unrealized mark-to-market gains and losses related to our economic hedging instruments based on the difference between forward crack spreads and the fixed margins that result from our hedge contracts. We incur unrealized commodity hedging losses when forward spreads are in excess of our fixed contract margins. We recognize hedging gains and losses within cost of product sold, which directly impacts our refining gross margin. Our 2012 refining gross margin included significant net realized and unrealized commodity hedging losses compared to net hedging gains in 2011. Also, our refined product sales volume decreased from 69.1 million barrels in 2011 to 67.4 million barrels in 2012.

Excluding the impact of hedging activities, refining margin per throughput barrel increased from 2011 to 2012, consistent with strong industry trends and our cost advantaged crude supply relative to industry benchmarks. The Gulf Coast benchmark 3:2:1 crack spread improved to $28.79 in 2012 from $24.48 in 2011. We base all of our crude oil purchases on pricing tied to WTI, and our margins were positively impacted by the discount of WTI crude oil to Brent crude oil. Though it remains strong, the WTI/Brent discount has been volatile over the past two years due in part to new and proposed crude oil pipeline capacity additions in the Permian Basin and at Cushing, Oklahoma. We are uncertain as to the potential duration of this large differential. During 2012, the refining margin reflected the added advantage of the widening price differential between WTI Cushing crude oil and WTI Midland crude oil. For our El Paso refinery, this differential averaged $4.01 per barrel for 2012 compared to $0.42 for 2011. Permian Basin crude oil production continues to increase, providing additional cost-advantaged crude oil for our El Paso refinery and contributes to the discount we receive on WTI Midland crude oil. Total refinery throughput increased from 2011 to 2012 primarily due to operational efficiencies at the El Paso refinery during 2012 and the lack of significant weather-related disruptions at the El Paso refinery as occurred in 2011. The positive impact in 2012 was partially offset by the scheduled turnaround that was completed at our Gallup refinery during October 2012.

Direct Operating Expenses (exclusive of depreciation and amortization). The decrease in direct operating expenses primarily resulted from decreased energy expenses of $16.1 million due to the Yorktown sale and the decrease in price of natural gas for the El Paso and Gallup refineries. On December 29, 2011, we completed the sale of the Yorktown refining and terminal assets, therefore, certain direct operating expenses associated with the Yorktown facility that were incurred during 2011 were not incurred in 2012. Also, maintenance expenses and chemicals and catalyst expenses decreased $4.8 million and $2.3 million, respectively, that primarily related to the Yorktown sale. These decreases were partially offset by increased property tax expense of $11.6 million resulting from an increase in appraised property values for our El Paso refinery and increased outside support services of $4.0 million for inspections, outside engineering, and technical services at the El Paso refinery and the Jal storage facility.

Selling, General, and Administrative Expenses. Selling, general, and administrative expenses remained relatively unchanged from 2012 to 2011.

(Gain) Loss and Impairments on Disposal of Assets, Net. The net gain during 2012 was primarily the result of transactions relating to the sale of catalyst from our refineries. 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.

Maintenance Turnaround Expense. During the years ended December 31, 2012 and December 31, 2011, we incurred costs in connection with the planned turnaround at our Gallup refinery. The Gallup turnaround began during the third quarter of 2012 and was completed in October 2012. Additionally, turnaround costs were incurred during 2012 for the planned turnaround of the north side units of our El Paso refinery planned for the first quarter of 2013.

Depreciation and Amortization. Depreciation and amortization decreased from 2012 to 2011 due to the disposal of the Yorktown facility in December 2011.

42

Fiscal Year Ended December 31, 2011 Compared to Fiscal Year Ended December 31, 2010

All Refineries and Related Operations

	Year Ended December 31,
	2011		2010		Change
	(In thousands, except per barrel data)
Net sales (including intersegment sales)	$	8,399,698	$	8,070,119	$	329,579
Operating costs and expenses:
Cost of products sold (exclusive of depreciation and amortization) (6)	7,059,210		7,439,826		(380,616		)
Direct operating expenses (exclusive of depreciation and amortization)	329,237		335,869		(6,632		)
Selling, general, and administrative expenses	27,451		20,155		7,296
Loss and impairments on disposal of assets, net	447,166		12,832		434,334
Maintenance turnaround expense	2,443		23,286		(20,843		)
Depreciation and amortization	119,057		118,661		396
Total operating costs and expenses	7,984,564		7,950,629		33,935
Operating income	$	415,134	$	119,490	$	295,644
Key Operating Statistics
Total sales volume (bpd) (1)	189,339		248,785		(59,446		)
Total refinery production (bpd)	140,124		192,997		(52,873		)
Total refinery throughput (bpd) (2)	142,257		194,492		(52,235		)
Per barrel of throughput:
Refinery gross margin (3) (6)	$	25.82	$	8.88	$	16.94
Refinery gross margin excluding hedging activities (3) (6)	23.83		9.01		14.82
Gross profit (3) (6)	23.52		7.21		16.31
Direct operating expenses (4)	6.34		4.73		1.61

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Southwest Refineries (El Paso and Gallup with Related Operations)

	Year Ended December 31,
	2011			2010		Change
	(In thousands, except per barrel data)
Net sales (including intersegment sales)	$	8,383,594		$	6,321,322	$	2,062,272
Operating costs and expenses:
Cost of products sold (exclusive of depreciation and amortization) (6)	7,048,140			5,745,996		1,302,144
Direct operating expenses (exclusive of depreciation and amortization)	285,800			242,422		43,378
Selling, general, and administrative expenses	27,451			20,155		7,296
(Gain) loss and impairments on disposal of assets, net	(14,829		)	12,832		(27,661		)
Maintenance turnaround expense	2,443			23,286		(20,843		)
Depreciation and amortization	76,254			72,886		3,368
Total operating costs and expenses	7,425,259			6,117,577		1,307,682
Operating income	$	958,335		$	203,745	$	754,590
Key Operating Statistics
Total sales volume (bpd) (1)	189,007			189,613		(606		)
Total refinery production (bpd)	140,124			149,007		(8,883		)
Total refinery throughput (bpd) (2)	142,257			151,288		(9,031		)
Per barrel of throughput:
Refinery gross margin (3) (6)	$	25.72		$	10.42	$	15.30
Refinery gross margin excluding hedging activities (3) (6)	23.73			10.59		13.14
Gross profit (3) (6)	24.25			9.10		15.15
Direct operating expenses (4)	5.50			4.39		1.11

All Refineries

	Year Ended December 31,
	2011	2010 (5)	Change
Key Operating Statistics
Refinery Product Yields (bpd)
Gasoline	74,224	102,927	(28,703	)
Diesel and jet fuel	57,037	73,774	(16,737	)
Residuum	5,219	4,899	320
Other	3,644	7,174	(3,530	)
Liquid by-products	140,124	188,774	(48,650	)
By-products (coke)	—	4,223	(4,223	)
Total refinery production (bpd)	140,124	192,997	(52,873	)
Refinery Throughput (bpd)
Sweet crude oil	113,347	131,028	(17,681	)
Sour or heavy crude oil	19,876	44,129	(24,253	)
Other feedstocks and blendstocks	9,034	19,335	(10,301	)
Total refinery throughput (bpd) (2)	142,257	194,492	(52,235	)

44

Southwest Refineries (El Paso and Gallup)

	Year Ended December 31,
	2011	2010	Change
Key Operating Statistics
Refinery Product Yields (bpd)
Gasoline	74,224	81,953	(7,729	)
Diesel and jet fuel	57,037	58,122	(1,085	)
Residuum	5,219	4,899	320
Other	3,644	4,033	(389	)
Total refinery production (bpd)	140,124	149,007	(8,883	)
Refinery Throughput (bpd)
Sweet crude oil	113,347	125,259	(11,912	)
Sour crude oil	19,876	14,007	5,869
Other feedstocks and blendstocks	9,034	12,022	(2,988	)
Total refinery throughput (bpd) (2)	142,257	151,288	(9,031	)

El Paso Refinery

	Year Ended December 31,
	2011		2010		Change
Key Operating Statistics
Refinery product yields (bpd):
Gasoline	58,236		65,740		(7,504		)
Diesel and jet fuel	50,211		51,571		(1,360		)
Residuum	5,219		4,899		320
Other	2,882		3,245		(363		)
Total refinery production (bpd)	116,548		125,455		(8,907		)
Refinery throughput (bpd):
Sweet crude oil	91,589		104,119		(12,530		)
Sour crude oil	19,876		14,007		5,869
Other feedstocks and blendstocks	6,680		9,051		(2,371		)
Total refinery throughput (bpd) (2)	118,145		127,177		(9,032		)
Total sales volume (bpd) (1)	155,196		153,398		1,798
Per barrel of throughput:
Refinery gross margin (3) (6)	$	23.18	$	9.37	$	13.81
Direct operating expenses (4)	4.50		3.50		1.00

45

Gallup Refinery

	Year Ended December 31,
	2011		2010		Change
Key Operating Statistics
Refinery product yields (bpd):
Gasoline	15,988		16,213		(225		)
Diesel and jet fuel	6,826		6,551		275
Other	762		788		(26		)
Total refinery production (bpd)	23,576		23,552		24
Refinery throughput (bpd):
Sweet crude oil	21,758		21,140		618
Other feedstocks and blendstocks	2,354		2,971		(617		)
Total refinery throughput (bpd) (2)	24,112		24,111		1
Total sales volume (bpd) (1)	33,811		36,215		(2,404		)
Per barrel of throughput:
Refinery gross margin (3) (6)	$	26.05	$	16.82	$	9.23
Direct operating expenses (4)	8.27		6.68		1.59

Yorktown Refinery

	Year Ended December 31,
	2010 (5)
Key Operating Statistics
Refinery Product Yields (bpd):
Gasoline	28,043
Diesel and jet fuel	20,926
Other	4,199
Liquid by-products	53,168
By-products (coke)	5,647
Total refinery production (bpd)	58,815
Refinery throughput (bpd):
Sweet crude oil	7,713
Heavy crude oil	40,274
Other feedstocks and blendstocks	9,777
Total refinery throughput (bpd) (2)	57,764
Total sales volume (bpd) (1) (5)	59,172
Per barrel of throughput:
Refinery gross margin (3) (6)	$	3.49
Direct operating expenses (4)	5.93

(1) Sales volume includes sales of refined products sourced primarily from our refinery production as well as refined products purchased from third parties. We 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 14.78% and 9.89% of our total consolidated sales volumes for the years ended December 31, 2011 and 2010, respectively. The majority of the purchased refined products were distributed through our wholesale refined product sales activities in the Mid-Atlantic region where we satisfied our refined product customer sales requirements through third-party purchases since we no longer produce refined products in the region.

(2) Total refinery throughput includes crude oil, other feedstocks, and blendstocks.

46

(3) 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. Net realized and net non-cash unrealized economic hedging gains and losses included in the combined refining segment gross margin are not allocated to the individual refineries. Cost of products sold does not include any depreciation or amortization. Refinery gross margin is a non-GAAP performance measure that we believe is important to investors in evaluating our refinery performance as a general indication of the amount above our cost of products that we are able to sell refined products. Each of the components used in this calculation (net sales and cost of products sold) can be reconciled directly to our statement of operations. Our calculation of refinery gross margin may differ from similar calculations of other companies in our industry, thereby limiting its usefulness as a comparative measure.

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

	Year Ended December 31,
	2011		2010		Change
	(In thousands, except per barrel data)
Net sales (including intersegment sales)	$	8,399,698	$	8,070,119	$	329,579
Cost of products sold (exclusive of depreciation and amortization)	7,059,210		7,439,826		(380,616		)
Depreciation and amortization	119,057		118,661		396
Gross profit	1,221,431		511,632		709,799
Plus depreciation and amortization	119,057		118,661		396
Refinery gross margin	$	1,340,488	$	630,293	$	710,195
Refinery gross margin per refinery throughput barrel (4)	$	25.82	$	8.88	$	16.94
Gross profit per refinery throughput barrel (4)	$	23.52	$	7.21	$	16.31

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		Change
	(In thousands, except per barrel data)
Net sales (including intersegment sales)	$	8,383,594	$	6,321,322	$	2,062,272
Cost of products sold (exclusive of depreciation and amortization)	7,048,140		5,745,996		1,302,144
Depreciation and amortization	76,254		72,886		3,368
Gross profit	1,259,200		502,440		756,760
Plus depreciation and amortization	76,254		72,886		3,368
Refinery gross margin	$	1,335,454	$	575,326	$	760,128
Refinery gross margin per refinery throughput barrel (4)	$	25.72	$	10.42	$	15.30
Gross profit per refinery throughput barrel (4)	$	24.25	$	9.10	$	15.15

(4) 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.

(5) 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 or 2012, and we 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.

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(6) Cost of products sold for the combined refining segment includes the net realized and net non-cash unrealized hedging activity shown in the table below. The hedging gains and losses are also included in the combined gross profit and refinery gross margin but are not included in those measures for the individual refineries.

	Year Ended December 31,
	2011			2010			Change
	(In thousands)
Realized hedging loss, net	$	(78,995	)	$	(9,770	)	$	(69,225	)
Unrealized hedging gain, net	182,343			337			182,006
Total hedging gain (loss), net	$	103,348		$	(9,433	)	$	112,781

Overview. The increase in operating income from 2010 to 2011 was primarily due to higher refining margins reflective of the strong margin environment and crude oil discounts, economic hedging gains, and decreased maintenance turnaround expenses. This increase was partially offset by a net loss on disposal of assets primarily related to the sale of the Yorktown refinery.

Refinery Gross Margin. Refinery gross margin increased from 2010 to 2011 due to higher refining margins per barrel of refined products excluding the impact of hedging activities and an increase in net realized and unrealized economic hedging gains, partially offset by lower sales volumes.

Excluding the impact of hedging activities, refining margin per throughput barrel increased from 2010 to 2011, consistent with strong industry trends and our cost advantaged crude supply relative to industry benchmarks. The Gulf Coast benchmark 3:2:1 crack spread improved to $24.48 in 2011 from $8.76 in 2010. We base all of our crude oil purchases on pricing tied to WTI, and our margins were positively impacted by the discount of WTI crude oil to Brent crude oil. Beginning in early 2011, our refining margin began to reflect the logistical advantage gained by our access to and use of WTI Cushing crude oil. During 2011, we began entering into hedge contracts to fix the margin on a portion of our future gasoline and distillate production. Prior hedging activities focused on mitigating the change in value of inventory volumes only. Our 2011 refinery gross margin included significant net realized and unrealized commodity hedging gains compared to net hedging losses in 2010.

The impact of these increases were partially offset by lower sales volumes of refined products in part due to the weather-related outage at our El Paso refinery during the first quarter of 2011. Our sales volume decreased from 90.8 million barrels in 2010 (including 21.6 million barrels sold from the Yorktown refinery) to 69.0 million barrels in 2011.

Direct Operating Expenses (exclusive of depreciation and amortization). Direct operating expenses decreased from 2010 to 2011 primarily due to the $50 million impact of idling the Yorktown refinery. Also contributing to the decrease were decreased maintenance expenses of $6.3 million, including a $4.8 million insurance recovery for the weather-related outage during the first quarter of 2011 at our El Paso refinery. Partially offsetting these decreases were increased labor and repair expenses of $19.7 million and increased material and supplies expense of $8.3 million primarily related to repairs associated with the weather-related outage at our El Paso refinery during the first quarter of 2011. Additionally, there were increased personnel costs of $7.2 million related to higher incentive compensation, increased chemicals and catalyst of $6.9 million associated with increased prices for the Fluid Catalytic Cracking Unit at the El Paso refinery, and increased outside services of $4.1 million primarily due to various scoping and engineering studies performed at the El Paso refinery during 2011.

Selling, General, and Administrative Expenses. The increase in selling, general, and administrative expenses from 2010 to 2011 primarily resulted from increases in personnel costs of $6.9 million resulting from higher incentive compensation during 2011 and the reversal of the 2009 incentive bonus accrual in the first quarter of 2010.

Loss and Impairments on Disposal of Assets, Net. The net loss for 2011 was comprised of losses of $465.6 million for the disposal of the Yorktown refinery and $11.7 million related to certain Bloomfield assets offset by gains of $26.6 million from the sale of a segment of our pipeline system and $3.6 million related to the first quarter sale of platinum assets at Yorktown.

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 our Bloomfield refinery assets and recorded a non-cash impairment charge of $9.1 million.

Maintenance Turnaround Expense. During the year ended December 31, 2011, we incurred costs 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 associated with a turnaround in the first quarter of 2010 at the El Paso refinery.

Depreciation and Amortization. Depreciation and amortization remained relatively unchanged from 2010 to 2011.

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Wholesale Segment

Fiscal Year Ended December 31, 2012 Compared to Fiscal Year Ended December 31, 2011

	Year Ended December 31,
	2012			2011 (3)			Change
	(In thousands, except per gallon data)
Net sales (including intersegment sales)	$	4,860,291		$	4,753,790		$	106,501
Operating costs and expenses:
Cost of products sold (exclusive of depreciation amortization)	4,748,077			4,645,851			102,226
Direct operating expenses (exclusive of depreciation and amortization)	67,491			65,829			1,662
Selling, general, and administrative expenses	10,407			11,177			(770		)
Gain on disposal of assets, net	(509		)	—			(509		)
Depreciation and amortization	3,814			4,312			(498		)
Total operating costs and expenses	4,829,280			4,727,169			102,111
Operating income	$	31,011		$	26,621		$	4,390
Key Operating Data
Fuel gallons sold	1,520,581			1,543,173			(22,592		)
Fuel gallons sold to retail	244,906			213,137			31,769
Average fuel sales price per gallon	$	3.32		$	3.22		$	0.10
Average fuel cost per gallon	3.27			3.17			0.10
Fuel margin per gallon (2)	0.07			0.06			0.01
Lubricant gallons sold	11,492			10,823			669
Average lubricant sales price per gallon	$	11.15		$	10.85		$	0.30
Average lubricant cost per gallon	10.05			9.60			0.45
Lubricant margin (1)	9.9		%	11.5		%	(1.6		)%
Realized hedging gain (loss)	$	(23,643	)	$	2,962		$	(26,605	)
Unrealized hedging gain (loss)	—			943			(943		)

The following table reconciles fuel sales and cost of fuel sales to net sales and cost of products sold:

	Year Ended December 31,
	2012			2011			Change
	(In thousands, except per gallon data)
Net Sales
Fuel sales (including intersegment sales)	$	5,054,987		$	4,971,199		$	83,788
Excise taxes included in fuel sales	(355,957		)	(366,393		)	10,436
Lubricant sales	128,171			117,478			10,693
Other sales (including intersegment sales)	33,090			31,506			1,584
Net Sales	$	4,860,291		$	4,753,790		$	106,501
Cost of Products Sold
Fuel cost of products sold	$	4,970,965		$	4,895,302		$	75,663
Excise taxes included in fuel cost of products sold	(355,957		)	(366,393		)	10,436
Lubricant cost of products sold	115,540			103,925			11,615
Other cost of products sold	17,529			13,017			4,512
Cost of Products Sold	$	4,748,077		$	4,645,851		$	102,226
Fuel margin per gallon (2)	$	0.07		$	0.06		$	0.01

49

(1) 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 wholesale petroleum products industry to measure operating results related to lubricant sales.

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

(3) Our wholesale group began selling refined product through the Yorktown facility during January 2011 and continues to supply refined product to the region as a customer of the terminal facility that we sold in December 2011. The refined products sold through the Yorktown facility were purchased from third parties.

Overview. Operating income increased$4.4 million from 2011 to 2012. The increase was primarily due to increased fuel margins from our wholesale operations in the Southwest offset by decreased margins from our Northeast wholesale operations. Our margins in the Northeast were mainly affected by the increase in realized economic hedging losses year over year. On August 31, 2012 our wholesale segment entered into a supply and marketing agreement with a third party covering activities related to refined product supply, hedging, and sales in the Mid-Atlantic region. Under the agreement we will receive one-half of the amount our refined product sales exceed the supplier's cost of acquiring, transporting, and hedging the refined products and we will pay one-half the amount our refined product sales do not exceed the refined product costs, with an annual limit of $2.0 million.

Wholesale Gross Margin. We analyze gross margin as a function of net sales (including intersegment sales) less cost of products sold (exclusive of depreciation and amortization). Wholesale gross margin increased by $4.3 million from 2011 to 2012 primarily due to a higher percentage increase in the average sales price per gallon in comparison to the percentage increase in cost of refined product per gallon from our wholesale activity in the Southwest. Decreased fuel margins in the Northeast served to partially offset the increased Southwest margins. The Northeast margin decreased due to 2012 realized economic hedging losses compared to gains in 2011. We enter into inventory hedge contracts to protect our refined product inventory values from market volatility, and recognize hedging gains and losses within cost of products sold as these contracts settle. This has a direct impact on our calculated fuel gross margin. In addition, lubricant margin per gallon decreased year over year due to increased cost of lubricants without corresponding increases in the sales price.

Direct Operating Expenses (exclusive of depreciation and amortization). Direct operating expenses increased from 2011 to 2012 primarily due to increased insurance premium rates, addition of new property leases and increased rents for existing property leases, higher maintenance and higher materials and supplies due to equipment additions to certain transportation assets. Partially offsetting the increases was a decrease in environmental remediation expense.

Selling, General, and Administrative Expenses. Selling, general, and administrative expenses decreased from 2011 to 2012 due to a decrease in wages based on lower 2012 employee headcount and decreased bad debt expense due to improved collections.

Gain on Disposal of Asset, Net. Gain on disposal of assets for the year ended December 31, 2012 was related primarily to gains on lease buy-outs and subsequent sale of 17 fuel tanker trucks.

Depreciation and Amortization. Depreciation and amortization decreased$0.5 million from 2011 to 2012.

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Fiscal Year Ended December 31, 2011 Compared to Fiscal Year Ended December 31, 2010

	Year Ended December 31,
	2011 (3)			2010			Change
	(In thousands, except per gallon data)
Net sales (including intersegment sales)	$	4,753,790		$	2,470,586		$	2,283,204
Operating costs and expenses:
Cost of products sold (exclusive of depreciation amortization)	4,645,851			2,383,931			2,261,920
Direct operating expenses (exclusive of depreciation and amortization)	65,829			48,222			17,607
Selling, general, and administrative expenses	11,177			12,638			(1,461		)
Depreciation and amortization	4,312			5,069			(757		)
Total operating costs and expenses	4,727,169			2,449,860			2,277,309
Operating income	$	26,621		$	20,726		$	5,895
Key Operating Data
Fuel gallons sold	1,543,173			1,009,786			533,387
Fuel gallons sold to retail	213,137			186,922			26,215
Average fuel sales price per gallon	$	3.22		$	2.56		$	0.66
Average fuel cost per gallon	3.17			2.50			0.67
Fuel margin per gallon (2)	0.06			0.07			(0.01		)
Lubricant gallons sold	10,823			10,664			159
Average lubricant sales price per gallon	$	10.85		$	9.58		$	1.27
Average lubricant cost per gallon	9.60			8.48			1.12
Lubricant margin (1)	11.5		%	11.5		%	—		%
Realized hedging gain	$	2,962		$	—		$	2,962
Unrealized hedging gain	943			—			943

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			Change
	(In thousands, except per gallon data)
Net Sales
Fuel sales (including intersegment sales)	$	4,971,199		$	2,588,628		$	2,382,571
Excise taxes included in fuel sales	(366,393		)	(250,550		)	(115,843		)
Lubricant sales	117,478			102,200			15,278
Other sales (including intersegment sales)	31,506			30,308			1,198
Net Sales	$	4,753,790		$	2,470,586		$	2,283,204
Cost of Products Sold
Fuel cost of products sold	$	4,895,302		$	2,527,758		$	2,367,544
Excise taxes included in fuel cost of products sold	(366,393		)	(250,550		)	(115,843		)
Lubricant cost of products sold	103,925			90,411			13,514
Other cost of products sold	13,017			16,312			(3,295		)
Cost of Products Sold	$	4,645,851		$	2,383,931		$	2,261,920
Fuel margin per gallon (2)	$	0.06		$	0.07		$	(0.01	)

(1) 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 wholesale petroleum products industry to measure operating results related to lubricant sales.

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

(3) Our wholesale group began selling refined product through the Yorktown facility during January 2011 and continues to supply refined product to the region as a customer of the terminal facility that we sold in December 2011. The refined products sold through the 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 year ended December 31, 2011 were from 2011 wholesale activities through the Yorktown facility with no comparable activity in the prior period. Further discussion of the impact of this wholesale activity is included in the period to period comparisons below.

Overview. Operating income increased by $5.9 million primarily due to positive results from our wholesale operations in the Northeast, including the results of our hedging transactions, without comparable activity in the prior period.

Wholesale Gross Margin. We analyze gross margin as a function of net sales (including intersegment sales) less cost of products sold (exclusive of depreciation and amortization). Wholesale gross margin increased by $21.3 million from 2010 to 2011 primarily from wholesale operations in the Northeast without comparable activity in the prior year. Wholesale gross margin attributable to the Northeast operations was $11.1 million. During 2011, we entered into inventory hedge contracts to protect our refined product inventory values from market volatility, and recorded realized hedging gains and losses within cost of products sold as these contracts settled. We concluded 2011 with a net realized economic hedging gain in wholesale cost of products sold without comparable activity in 2010. 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 offset by increased cost of refined products, lubricants, and purchased fuel volume.

Direct Operating Expenses (exclusive of depreciation and amortization). Direct operating expenses increased from 2010 to 2011 primarily because we transferred activity related to our Northeast terminalling operations from refining to our wholesale segment. We recognized increased costs in wholesale including terminalling and storage fees, personnel costs, operating materials and supplies, and lease expenses.

Selling, General, and Administrative Expenses. Selling, general, and administrative expenses decreased from 2010 to 2011 primarily from decreased bad debt expense, partially offset by an increase in field and back office support personnel costs related to the Northeast operations transferred from refining to wholesale.

Depreciation and Amortization. Depreciation and amortization decreased $0.8 million from 2010 to 2011.

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Retail Segment

Fiscal Year Ended December 31, 2012 Compared to Fiscal Year Ended December 31, 2011

	Year Ended December 31,
	2012			2011			Change
	(In thousands, except per gallon data)
Net sales (including intersegment sales)	$	1,212,070		$	940,395		$	271,675
Operating costs and expenses:
Cost of products sold (exclusive of depreciation and amortization)	1,074,532			838,247			236,285
Direct operating expenses (exclusive of depreciation and amortization)	102,793			80,458			22,335
Selling, general, and administrative expenses	8,161			7,329			832
Depreciation and amortization	10,473			9,653			820
Total operating costs and expenses	1,195,959			935,687			260,272
Operating income	$	16,111		$	4,708		$	11,403
Key Operating Data
Fuel gallons sold	291,244			230,429			60,815
Average fuel sales price per gallon	$	3.56		$	3.44		$	0.12
Average fuel cost per gallon	3.36			3.27			0.09
Fuel margin per gallon (2)	0.20			0.17			0.03
Merchandise sales	$	248,023		$	204,998		$	43,025
Merchandise margin (1)	29.0		%	28.0		%	1.0		%
Operating retail outlets at period end	222			209			13

The following table reconciles fuel sales and cost of fuel sales to net sales and cost of products sold:

	Year Ended December 31,
	2012			2011			Change
	(In thousands, except per gallon data)
Net Sales
Fuel sales (including intersegment sales)	$	1,036,404		$	792,502		$	243,902
Excise taxes included in fuel sales	(111,805		)	(83,255		)	(28,550		)
Merchandise sales	248,023			204,998			43,025
Other sales	39,448			26,150			13,298
Net Sales	$	1,212,070		$	940,395		$	271,675
Cost of Products Sold
Fuel cost of products sold	$	978,979		$	753,487		$	225,492
Excise taxes included in fuel cost of products sold	(111,805		)	(83,255		)	(28,550		)
Merchandise cost of products sold	176,215			147,692			28,523
Other cost of products sold	31,143			20,323			10,820
Cost of Products Sold	$	1,074,532		$	838,247		$	236,285
Fuel margin per gallon (2)	$	0.20		$	0.17		$	0.03

(1) 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 retail industry to measure operating results related to merchandise sales.

(2) Fuel margin per gallon is a measurement calculated by dividing the difference between fuel sales and fuel cost of products sold 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.

Overview. The increase in operating income from 2011 to 2012 was primarily due to increased same store operating margins coupled with higher fuel sales volumes. The effect of the new retail outlets added during 2011 was an increase in

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operating income of $5.0 million and the effect of new retail outlets added during 2012 was a reduction of operating income by $1.0 million. During 2012, we added 13 stores to our retail network. We added 59 stores during 2011 including 37 stores added in the fourth quarter. The operating results discussed below include a full year's operations in 2012 of stores added in the latter part of 2011.

Retail Gross Margin. Retail gross margin is a function of net sales (including intersegment sales) less cost of products sold (exclusive of depreciation and amortization). The increase in retail gross margin from 2011 to 2012 was primarily due to higher realized per gallon fuel margins, increased merchandise sales and margins, and the positive result of the additional retail outlets added during 2012 and 2011. Fuel margin per gallon improved over 2011 due to small improvements in the general economy and relatively stable retail fuel sales pricing among our competition. The effect of the new retail outlets added during 2012 was an increase of retail gross margin of $4.2 million and the effect of new retail outlets added during 2011 was an increase of retail gross margin of $24.4 million.

Direct Operating Expenses (exclusive of depreciation and amortization). The increase in direct operating expenses from 2011 to 2012 was primarily due to retail outlets added in 2012 and in late 2011. The addition of the new outlets resulted in increased employee expense, credit card processing fees resulting from the increase in credit sales, property taxes, lease expense, and utilities. The new retail outlets added in 2012 required additional costs of $4.7 million and the new retail outlets added in 2011 required additional costs of $18.4 million.

Selling, General, and Administrative Expenses. The increase in selling, general, and administrative expenses from 2011 to 2012 was primarily due to increased field and back office support personnel required to support the addition of new retail outlets during 2012 and 2011.

Depreciation and Amortization. Depreciation and amortization remained relatively unchanged over 2011. The majority of the retail outlets added during 2012 and 2011 were through operating leases.

Fiscal Year Ended December 31, 2011 Compared to Fiscal Year Ended December 31, 2010

	Year Ended December 31,
	2011			2010			Change
	(In thousands, except per gallon data)
Net sales (including intersegment sales)	$	940,395		$	718,369		$	222,026
Operating costs and expenses:
Cost of products sold (exclusive of depreciation and amortization)	838,247			619,674			218,573
Direct operating expenses (exclusive of depreciation and amortization)	80,458			66,997			13,461
Selling, general, and administrative expenses	7,329			5,095			2,234
Depreciation and amortization	9,653			10,245			(592		)
Total operating costs and expenses	935,687			702,011			233,676
Operating income	$	4,708		$	16,358		$	(11,650	)
Key Operating Data
Fuel gallons sold (in thousands)	230,429			207,303			23,126
Average fuel sales price per gallon	$	3.44		$	2.81		$	0.63
Average fuel cost per gallon	3.27			2.62			0.65
Fuel margin per gallon (2)	0.17			0.19			(0.02		)
Merchandise sales	$	204,998		$	191,324		$	13,674
Merchandise margin (1)	28.0		%	28.5		%	(0.5		)%
Operating retail outlets at period end	209			150			59

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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			Change
	(In thousands, except per gallon data)
Net Sales
Fuel sales (including intersegment sales)	$	792,502		$	582,688		$	209,814
Excise taxes included in fuel revenues	(83,255		)	(79,639		)	(3,616		)
Merchandise sales	204,998			191,324			13,674
Other sales	26,150			23,996			2,154
Net Sales	$	940,395		$	718,369		$	222,026
Cost of Products Sold
Fuel cost of products sold	$	753,487		$	543,916		$	209,571
Excise taxes included in fuel cost of products sold	(83,255		)	(79,639		)	(3,616		)
Merchandise cost of products sold	147,692			136,855			10,837
Other cost of products sold	20,323			18,542			1,781
Cost of Products Sold	$	838,247		$	619,674		$	218,573
Fuel margin per gallon (2)	$	0.17		$	0.19		$	(0.02	)

(1) 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 retail industry to measure operating results related to merchandise sales.

(2) Fuel margin per gallon is a measurement calculated by dividing the difference between fuel sales and fuel cost of products sold 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.

Overview. The decrease in operating income from 2010 to 2011 was the result of increased direct operating and selling, general, and administrative costs, primarily related to the addition of new retail outlets during 2011. The effect of the new retail outlets added in 2011 was a reduction of operating income by $3.8 million. During 2011 we added 59 stores to our network including 37 in the fourth quarter.

Retail Gross Margin. Retail gross margin is a function of net sales (including intersegment sales) less cost of products sold (exclusive of depreciation and amortization). Retail gross margin increased by $3.5 million from 2010 to 2011 primarily due to the result of the additional retail outlets added to our retail network during 2011, offset by lower realized per gallon fuel margins. Absent the addition of the new retail outlets, fuel sales volumes decreased and merchandise sales and margin were depressed when compared to 2010. The effect of new retail outlets added during 2011 was an increase in retail gross margin by $7.4 million.

Direct Operating Expenses (exclusive of depreciation and amortization). The increase in direct operating expenses from 2010 to 2011 was primarily due to the addition of retail stores added during 2011 and increased same store transaction fees directly related to the increase in average customer fuel purchases driven by the increase in the per gallon sales price over 2010. The addition of the new retail outlets added to our network in 2011 required additional costs of $10.9 million that includes one-time transaction costs. These costs included professional and license fees, technology costs, and merchandise reset costs.

Selling, General, and Administrative Expenses. The increase in selling, general, and administrative expenses from 2010 to 2011, absent the 2010 reversal of the 2009 bonus accrual, was primarily due to the reclassification of cost centers allocated to direct operating expenses in 2010 and to selling, general, and administrative expenses in 2011, and from additional field and back office support personnel related to the retail outlets added during 2011.

Depreciation and Amortization. The decrease in depreciation and amortization from 2010 to 2011 was primarily the result of certain assets that we initially capitalized with three year depreciable lives being fully depreciated in 2010.

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Outlook

Our refining margins were stronger in 2012 compared to 2011. The Gulf Coast benchmark 3:2:1 crack spread improved to $28.79 in 2012 from $24.48 in 2011. Our refining margins continue to be positively impacted by the discount of WTI crude oil to Brent crude oil, as all of our crude oil purchases are based on pricing tied to WTI. However, the WTI/Brent discount has been volatile recently due to new and proposed crude oil pipeline capacity additions in the Permian Basin and at Cushing, Oklahoma. These capacity additions could reduce the WTI/Brent discount in future years. Permian Basin crude oil production continues to increase, which could provide additional cost-advantaged crude oil in the region. We expect these trends to continue in 2013. Thus far during the first quarter of 2013, we continue to experience strong refining margins. Additionally, the widening price differentials between WTI Cushing crude oil and WTI Midland crude oil contributed to our El Paso refining margins during 2012. This differential has been more volatile recently and has continued to contribute to our refining margins in early 2013. The Gulf Coast benchmark 3:2:1 crack spread for January 2013 was $25.46.

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 2012 with $454.0 million of cash and cash equivalents and $394.5 million in net availability under the Revolving Credit Agreement. As of December 31, 2012, we had no direct borrowings and $256.2 million in outstanding letters of credit under the Revolving Credit Agreement. We continually consider strategic initiatives to further improve our capital structure and deliver additional value to our shareholders. These initiatives include possible refinancings of our existing indebtedness.

On July 18, 2012, our board of directors authorized a share repurchase program of up to $200 million. We may repurchase shares from time-to-time through open market transactions, block trades, privately negotiated transactions, accelerated share repurchase transactions, or otherwise subject to market conditions, as well as corporate, regulatory, and other considerations. Our board of directors authorized this share repurchase program through July 31, 2013, but may discontinue the program at its discretion at any time prior to that date. During 2012, we purchased 3,324,135 shares as part of our share repurchase program at a cost of $82.3 million. As of February 22, 2013 we have not purchased any additional shares.

Cash Flows

Fiscal Year Ended December 31, 2012 Compared to Fiscal Year Ended December 31, 2011

	Year Ended December 31,
	2012			2011			Change
	(In thousands)
Cash flows provided by operating activities	$	916,353		$	508,200		$	408,153
Cash flows provided by (used in) investing activities	18,506			(72,194		)	90,700
Cash flows used in financing activities	(651,721		)	(325,089		)	(326,632		)
Net increase in cash and cash equivalents	$	283,138		$	110,917		$	172,221

The increase in net cash from operating activities from 2011 to 2012 was primarily the result of the following net changes between years:

•Net income ($266.2 million);

•Net unrealized commodity hedging activity ($413.0 million);

•Inventories ($35.9 million);

•Prepaid expenses ($179.6 million);

•Impairments and losses on disposal of assets ($449.1 million);

•Depreciation ($42.0 million); and

•Loss on extinguishment of debt ($26.7 million).

The changes in components making up net income and results of our commodity hedging activity occurred for reasons discussed above. The decrease in our prepaid expenses was primarily the result of improved credit terms with some of our

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crude and feedstock suppliers that reduced the amount of prepaid balances. The decrease in inventories was primarily the result of a decrease in the cost per barrel from year to year, partially offset by an increase of 84,000 barrels at the end of 2012.

Cash flows provided by operating activities for the year ended December 31, 2012 combined with $220.4 million of restricted cash were primarily used for the following:

•Fund capital expenditures ($202.2 million);

•Repayment of debt ($324.3 million);

•Payment of cash dividends ($240.7 million); and

•Purchase of treasury stock ($82.3 million).

Fiscal Year Ended December 31, 2011 Compared to Fiscal Year Ended December 31, 2010

	Year Ended December 31,
	2011			2010			Change
	(In thousands)
Cash flows provided by operating activities	$	508,200		$	134,456		$	373,744
Cash flows used in investing activities	(72,194		)	(73,777		)	1,583
Cash flows used in financing activities	(325,089		)	(75,657		)	(249,432		)
Net increase (decrease) in cash and cash equivalents	$	110,917		$	(14,978	)	$	125,895

The increase in net cash from operating activities from 2010 to 2011 was primarily the result of the following net changes between years:

•Net income ($149.7 million);

•Net unrealized commodity hedging activity ($184.5 million);

•Accounts receivable ($58.6 million);

•Inventories ($97.2 million);

•Prepaid expenses ($47.4 million);

•Other assets ($62.4 million);

•Accounts payable and accrued liabilities ($217.8 million);

•Impairments and losses on disposal of assets ($434.1 million); and

•Deferred taxes ($35.4 million).

The changes in components making up net income and results of our commodity hedging activity occurred for reasons discussed above. The increase in our accounts receivable, inventories, prepaid expenses, and accounts payable and accrued liabilities was primarily the result of significant increases in prices for gasoline, distillate, and crude oil at the end of 2011 compared to such prices at the end of 2010.

Cash flows provided by operating activities for the year ended December 31, 2011 were primarily used for the following:

•Fund capital expenditures ($83.8 million);

•Repayment of debt ($316.3 million); and

•Refinancing of debt ($7.3 million).

Working Capital

Working capital at December 31, 2012 was $559.2 million, consisting of $1,292.4 million in current assets and $733.2 million in current liabilities. 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.

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Indebtedness

Our capital structure at December 31, 2012 and 2011 was as follows:

	December 31,
	2012		2011
	(In thousands)
Debt, including current maturities:
11.25% Senior Secured Notes, due 2017, net of unamortized discount of $19,001 and $21,986 for 2012 and 2011, respectively	$	305,999	$	303,014
5.75% Senior Convertible Notes, due 2014, net of conversion feature of $22,105 and $34,999 for 2012 and 2011, respectively	193,345		180,451
Term Loan, net of unamortized discount of $2,901 in 2011, with average interest rates of 7.50% and 8.31% during 2012 and 2011, respectively	—		319,661
5.50% promissory note, due 2015	519		864
Revolving Credit Agreement	—		—
Long-term debt	499,863		803,990
Stockholders' equity	909,070		819,828
Total capitalization	$	1,408,933	$	1,623,818

We may redeem the 11.25% Senior Secured Notes, in whole or part, at our option at any time prior to June 15, 2013 at a price equal to 100% of the principal amount plus an applicable premium plus accrued and unpaid interest to the date of redemption. Beginning June 15, 2013 through June 14, 2014, we may redeem the Senior Secured Notes 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 $275.0 million Senior Secured Floating Rate Notes at a premium to par of 5%. The Senior Secured 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 Senior Secured Floating Rate Notes was 10.75%.

The Convertible Senior Notes are unsecured and pay interest semi-annually in arrears at a rate of 5.75% per annum. As of December 31, 2012, the if-converted value of the Convertible Senior Notes exceeded its principal amount by $406.3 million. The Convertible Senior Notes are presently convertible at the option of the holder. The current conversion rate is 102.3750 to each $1,000 of principal amount of Convertible Senior Notes. The Convertible Senior Notes will also be convertible in any future calendar quarter (prior to maturity) whenever the last reported sale price of our common stock exceeds 130% of the applicable conversion price in effect for the Notes on the last trading day of the immediately preceding calendar quarter 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, we may elect to satisfy our obligations upon conversion through the delivery of shares of our common stock, in cash, or a combination thereof.

On March 29, 2011, we entered into an amended and restated Term Loan Credit Agreement. To effect this amendment and restatement, we paid $3.7 million in amendment fees. As a result of this amendment, we recognized a $4.6 million loss on extinguishment of debt. In addition to our scheduled Term Loan payment of $0.8 million made during the first quarter of 2012, we made non-mandatory prepayments of $30.0 million and $291.8 million during the first and second quarters of 2012, respectively. As a result of the repayment of the Term Loan, we recognized a loss on extinguishment of debt of $7.7 million.

On September 22, 2011, we 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. The agreement also provides for letters of credit and swing line loans and provides for a quarterly commitment fee ranging from 0.375% to 0.50% per annum subject to adjustment based upon the average utilization ratio under the agreement and letter of credit fees ranging from 2.50% to 3.25% per annum, payable quarterly, 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% subject to adjustment based upon the average excess availability under the 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. Prior to September 22, 2011, the Revolving Credit Agreement included commitments of $800.0 million composed of a $145.0 million tranche maturing on May 31, 2012 and a $655.0 million tranche maturing on January 1, 2015. Interest rates ranged from 3.00% to 4.50% over LIBOR. Our subsidiaries guarantee the Revolving Credit Agreement on a joint and several basis.

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As of December 31, 2012, we had net availability under the amended and restated Revolving Credit Agreement of $394.5 million consisting of $650.7 million in gross availability and $256.2 million in outstanding letters of credit. On February 22, 2013, we had net availability under the Revolving Credit Agreement of $490.6 million consisting of $753.5 million in gross availability and $262.9 million in outstanding letters of credit.

See Note 13, Long-Term Debt, in the Notes to Consolidated Financial Statements included in this annual report for detailed information on our indebtedness.

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. We issue and cancel letters of credit on a periodic basis depending upon our needs. At December 31, 2012, there were $256.2 million of irrevocable letters of credit outstanding, primarily issued to crude oil suppliers under the Revolving Credit Agreement.

Capital Spending

Capital expenditures totaled $202.2 million for the year ended December 31, 2012, and included improvement and regulatory projects for our refining group and several smaller projects for our wholesale, retail, and corporate groups. Capital expenditures included $2.4 million of capitalized interest for 2012.

Our capital expenditure budget for 2013 is $205.8 million, of which $187.6 million is for our refining group, $5.1 million for our wholesale group, $6.6 million for our retail group, and $6.5 million for other general projects. The following table summarizes the spending allocation between sustaining, discretionary, and regulatory projects for 2013:

	2013
	(In thousands)
Sustaining	$	49,517
Discretionary	122,403
Regulatory	33,884
Total	$	205,804

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 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, such as a gathering and storage project in the Permian Basin of southeast New Mexico that we expect to complete in the second quarter of 2013, 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. The deadline for compliance with the final phase of the ultra low sulfur diesel regulations to reduce sulfur in locomotive and marine diesel was 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 $7.0 million for this expansion during 2013.

Our El Paso and Gallup refineries are required to meet Mobile Source Air Toxics ("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, 2012, we expended $63.7 million to comply with MSAT II regulations at our El Paso refinery by completing construction of a benzene saturation unit that began operating in May 2011. During 2012 we made $2.5 million in capital expenditures for our Gallup refinery to meet the 1.30 volume percent requirement.

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Based on current information, we estimate the total remaining capital expenditures necessary to address the EPA Initiative issues at El Paso would be $9.7 million for NOx emission controls on heaters and boilers and will occur in 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 Fluid Catalytic Cracking Unit ("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 $1.0 million and will occur in 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 completed the upgrade of its wastewater treatment plant by May 31, 2012. We estimated capital expenditures of approximately $38.8 million to upgrade the wastewater treatment plant at the Gallup refinery; we expended $20.8 million through 2011, $17.1 million during 2012, and expect to spend the remaining $0.9 million during 2013. 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:

	2012		2011		2010
	(In millions)
EPA Initiative projects	$	47.7	$	11.0	$	—
MSAT II gasoline	2.5		2.0		43.0
Wastewater Treatment Plant	17.0		17.0		4.0
Total	$	67.2	$	30.0	$	47.0

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:

	2013		2014		2015
	(In millions)
Air emissions - El Paso	$	11.4	$	—	$	—
Control room upgrades - El Paso and Gallup	5.7		10.5		—
Flare system - Gallup	4.8		5.2		—
Various other projects	12.0		29.0		25.0
Total	$	33.9	$	44.7	$	25.0

Contractual Obligations and Commercial Commitments

Information regarding our contractual obligations of the types described below as of December 31, 2012 is set forth in the following table:

	Payments Due by Period
	Totals		2013		2014 and 2015		2016 and 2017		2018 and Beyond
	(In thousands)
Long-term debt obligations (1)	$	721,530	$	48,952	$	294,256	$	378,322	$	—
Capital lease obligations	18,889		831		1,698		1,775		14,585
Operating lease obligations	274,448		23,981		41,981		34,216		174,270
Purchase obligations (2)	3,989,380		570,324		1,140,098		1,139,768		1,139,190
Environmental reserves (3)	8,051		2,747		4,118		214		972
Uncertain tax positions (4)	9,572		9,572		—		—		—
Other obligations (5)(6)	244,963		17,348		32,153		32,263		163,199
Total obligations	$	5,266,833	$	673,755	$	1,514,304	$	1,586,558	$	1,492,216

(1) Includes minimum principal payments and interest calculated using interest rates at December 31, 2012.

(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, 2012, multiplied by the contract volumes.

(3) As of December 31, 2012, the discounted environmental reserve included in these liabilities totaled $1.3 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.

60

(4) Includes accrued interest and penalties.

(5) Other commitments include agreements for sulfuric acid regeneration and sulfur gas processing, throughput and distribution, storage services, and professional consulting. The minimum payment commitments are included in the table.

(6) 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.

Dividends

We anticipate paying future quarterly dividends, subject to approval by our board of directors and compliance with our outstanding financing agreements. On January 15, 2013, our board of directors approved a cash dividend for the first quarter of 2013 of $0.12 per share of common stock in an aggregate payment of $10.5 million that was paid on February 14, 2013.

Off-Balance Sheet Arrangements

We have no off-balance sheet arrangements.

Item 7A. Quantitative and Qualitative Disclosure About Market Risk

Commodity price fluctuation is our primary source 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 that 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, 2012, we held approximately 5.8 million barrels of crude oil, refined product, and other inventories valued under the LIFO valuation method with an average cost of $62.57 per barrel. At December 31, 2012, the excess of the current cost of our crude oil, refined product, and other feedstock and blendstock inventories over aggregated LIFO costs was $148.3 million.

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.

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. 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.

61

The following table summarizes our economic hedging activity for the three years ended December 31, 2012:

	Year Ended December 31,
	2012			2011			2010
	(In thousands)
Economic hedging activities recognized within cost of products sold
Realized hedging gain (loss), net	$	(144,448	)	$	(76,033	)	$	(9,770	)
Unrealized hedging gain (loss), net	(229,672		)	183,286			337
Total hedging gain (loss), net	$	(374,120	)	$	107,253		$	(9,433	)
Open commodity hedging instruments (barrels)
Crude futures	588			933			(177		)
Refined product price and crack spread swaps	26,683			29,283			1,200
Total open commodity hedging instruments	27,271			30,216			1,023
Fair value of outstanding contracts
Other current assets	$	3,918		$	128,103		$	—
Other assets	228			54,208			—
Accrued liabilities	(35,901		)	(198		)	(1,173		)
Other long-term liabilities	(15,804		)	—			—
Fair value of outstanding contracts - unrealized gain (loss), net	$	(47,559	)	$	182,113		$	(1,173	)

During the three years ended December 31, 2012, we did not have any commodity derivative instruments that were designated or accounted for as hedges.

62

Item 8. Financial Statements and Supplementary Data

Management’s Report on Internal Control Over Financial Reporting

Our 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, our principal executive and principal financial officers and effected by our 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 our transactions and dispositions of the assets;

• 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 are being made only in accordance with authorizations of our management and directors; and

• Provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of our assets that could have a material effect on our 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.

Our management assessed the effectiveness of our internal control over financial reporting as of December 31, 2012. In making this assessment, our 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, our management believes that, as of December 31, 2012, our internal control over financial reporting is effective based on those criteria.

Our independent registered public accounting firm, Deloitte & Touche LLP, has issued an audit report on our internal control over financial reporting. This report appears on page 64 of this annual report.

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 internal control over financial reporting of Western Refining, Inc. and subsidiaries (the "Company") as of December 31, 2012, 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, 2012, 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, 2012 of the Company and our report dated February 28, 2013 expressed an unqualified opinion on those financial statements.

/s/ Deloitte & Touche LLP

Phoenix, AZ

February 28, 2013

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WESTERN REFINING, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

INDEX TO FINANCIAL STATEMENTS

	Page
Report of Independent Registered Public Accounting Firm	66
Consolidated Balance Sheets as of December 31, 2012 and 2011	67
Consolidated Statements of Operations for the Three Years ended December 31, 2012	68
Consolidated Statements of Comprehensive Income (Loss) for the Three Years ended December 31, 2012	69
Consolidated Statements of Changes in Stockholders’ Equity for the Three Years ended December 31, 2012	70
Consolidated Statements of Cash Flows for the Three Years ended December 31, 2012	71
Notes to Consolidated Financial Statements	72

65

WESTERN REFINING, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

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, 2012 and 2011, and the related consolidated statements of operations, comprehensive income (loss), stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2012. 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, 2012 and 2011, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2012, 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, 2012, 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 28, 2013 expressed an unqualified opinion on the Company’s internal control over financial reporting.

/s/ Deloitte & Touche LLP

Phoenix, AZ

February 28, 2013

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WESTERN REFINING, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In thousands, except share data)

	As of December 31,
	2012			2011
ASSETS
Current assets:
Cash and cash equivalents	$	453,967		$	170,829
Accounts receivable, trade, net of a reserve for doubtful accounts of $1,166 and $1,884, respectively	273,087			275,478
Inventories	409,970			405,754
Prepaid expenses	74,041			163,530
Other current assets	81,338			195,064
Total current assets	1,292,403			1,210,655
Restricted cash	—			220,355
Property, plant, and equipment, net	1,112,484			995,316
Intangible assets, net	41,624			44,352
Other assets, net	33,896			99,666
Total assets	$	2,480,407		$	2,570,344
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	439,168		$	384,523
Accrued liabilities	266,106			172,001
Deferred income tax liability, net	27,710			105,555
Current portion of long-term debt	206			3,595
Total current liabilities	733,190			665,674
Long-term liabilities:
Long-term debt, less current portion	499,657			800,395
Deferred income tax liability, net	282,339			262,492
Other liabilities	56,151			21,955
Total long-term liabilities	838,147			1,084,842
Commitments and contingencies (Note 21)
Stockholders’ equity:
Common stock, par value $0.01, 240,000,000 shares authorized; 90,960,640 and 90,001,537 shares issued, respectively	910			900
Preferred stock, par value $0.01, 10,000,000 shares authorized; no shares issued and outstanding	—			—
Additional paid-in capital	612,339			599,645
Retained earnings	400,708			242,538
Accumulated other comprehensive loss, net of tax	(1,174		)	(1,812		)
Treasury stock, 4,022,141 and 698,006 shares, respectively at cost	(103,713		)	(21,443		)
Total stockholders’ equity	909,070			819,828
Total liabilities and stockholders’ equity	$	2,480,407		$	2,570,344

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

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WESTERN REFINING, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share data)

	Year Ended December 31,
	2012			2011			2010
Net sales	$	9,503,134		$	9,071,037		$	7,965,053
Operating costs and expenses:
Cost of products sold (exclusive of depreciation and amortization)	8,054,385			7,532,423			7,155,967
Direct operating expenses (exclusive of depreciation and amortization)	483,070			463,563			444,531
Selling, general, and administrative expenses	114,628			105,768			84,175
(Gain) loss and impairments on disposal of assets, net	(1,891		)	447,166			13,038
Maintenance turnaround expense	47,140			2,443			23,286
Depreciation and amortization	93,907			135,895			138,621
Total operating costs and expenses	8,791,239			8,687,258			7,859,618
Operating income	711,895			383,779			105,435
Other income (expense):
Interest income	696			510			441
Interest expense and other financing costs	(81,349		)	(134,601		)	(146,549		)
Amortization of loan fees	(6,860		)	(8,926		)	(9,739		)
Loss on extinguishment of debt	(7,654		)	(34,336		)	—
Other, net	359			(3,898		)	7,286
Income (loss) before income taxes	617,087			202,528			(43,126		)
Provision for income taxes	(218,202		)	(69,861		)	26,077
Net income (loss)	$	398,885		$	132,667		$	(17,049	)
Net earnings (loss) per share:
Basic	$	4.42		$	1.46		$	(0.19	)
Diluted	$	3.71		$	1.34		$	(0.19	)
Weighted average common shares outstanding:
Basic	89,270			88,981			88,204
Diluted	111,822			109,792			88,204
Cash dividends declared per common share	$	2.74		$	—		$	—

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

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WESTERN REFINING, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(In thousands)

	Year Ended December 31,
	2012			2011			2010
Net income (loss)	$	398,885		$	132,667		$	(17,049	)
Other comprehensive income (loss) items:
Benefit plans:
Reclassification of (gain) loss to income	48			4			(15		)
Pension plan termination adjustment	978			1,537			3,322
Actuarial loss	(13		)	(1,211		)	(4,272		)
Other comprehensive income (loss) before tax	1,013			330			(965		)
Income tax	(375		)	(202		)	395
Other comprehensive income (loss), net of tax	638			128			(570		)
Comprehensive income (loss)	$	399,523		$	132,795		$	(17,619	)

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

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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, 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 share 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 share 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
Stock-based compensation	—	—		8,291			—			—			—		—			8,291
Restricted share and share unit vesting	959,103	10		(10		)	—			—			—		—			—
Excess tax benefit from stock-based compensation	—	—		4,413			—			—			—		—			4,413
Cash dividends declared	—	—		—			(240,715		)	—			—		—			(240,715		)
Net income	—	—		—			398,885			—			—		—			398,885
Other comprehensive loss, net of tax of $375	—	—		—			—			638			—		—			638
Treasury stock, at cost	—	—		—			—			—			(3,324,135	)	(82,270		)	(82,270		)
Balance at December 31, 2012	90,960,640	$	910	$	612,339		$	400,708		$	(1,174	)	(4,022,141	)	$	(103,713	)	$	909,070

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

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WESTERN REFINING, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

	Year Ended December 31,
	2012			2011			2010
Cash flows from operating activities:
Net income (loss)	$	398,885		$	132,667		$	(17,049	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Loss and impairments on disposal of assets, net	(1,891		)	447,166			13,038
Depreciation and amortization	93,907			135,895			138,621
Commodity hedging instrument mark-to-market net unrealized loss (gain)	229,672			(183,286		)	1,173
Reserve for doubtful accounts	1,049			2,306			3,260
Amortization of loan fees and original issue discount	22,928			27,197			25,606
Loss on extinguishment of debt	7,654			34,336			—
Stock-based compensation expense	8,291			8,173			5,857
Deferred income taxes	(57,998		)	(52,174		)	(16,778		)
Excess tax benefit from stock-based compensation	4,413			3,267			—
Changes in operating assets and liabilities:
Accounts receivable	1,342			(8,188		)	50,402
Inventories	(4,216		)	(40,081		)	57,080
Prepaid expenses	89,489			(90,139		)	(42,719		)
Other assets	(6,213		)	(22,421		)	39,972
Accounts payable and accrued liabilities	117,460			121,158			(96,651		)
Other long-term liabilities	11,581			(7,676		)	(27,356		)
Net cash provided by operating activities	916,353			508,200			134,456
Cash flows from investing activities:
Capital expenditures	(202,157		)	(83,809		)	(78,095		)
Proceeds from the sale of assets	308			231,970			4,318
Decrease (increase) in restricted cash	220,355			(220,355		)	—
Net cash provided by (used in) investing activities	18,506			(72,194		)	(73,777		)
Cash flows from financing activities:
Payments on long-term debt	(322,908		)	(302,524		)	(13,000		)
Prepayment fee on early retirement of long-term debt	(1,415		)	(13,750		)	—
Revolving credit facility, net	—			—			(50,000		)
Deferred financing costs	—			(7,281		)	(12,657		)
Proceeds from financing arrangement	—			12,322			—
Payment on financing arrangement	—			(10,589		)	—
Purchase of treasury stock	(82,270		)	—			—
Dividends paid	(240,715		)	—			—
Excess tax benefit from stock-based compensation	(4,413		)	(3,267		)	—
Net cash used in financing activities	(651,721		)	(325,089		)	(75,657		)
Net increase (decrease) in cash and cash equivalents	283,138			110,917			(14,978		)
Cash and cash equivalents at beginning of year	170,829			59,912			74,890
Cash and cash equivalents at end of year	$	453,967		$	170,829		$	59,912

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

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WESTERN REFINING, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Organization and Basis of Presentation

The "Company," "Western," "we," "us," and "our" may be used to refer to Western Refining, Inc. and, unless the context otherwise requires, our 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”).

We are an independent crude oil refiner and marketer of refined products and also operate retail stores that sell various grades of gasoline, diesel fuel, and convenience store merchandise. We own and operate two refineries: one in El Paso, Texas and one near Gallup in the Four Corners region of northern New Mexico. During September of 2010, we temporarily suspended refining operations of the Yorktown, Virginia facility and on December 29, 2011, we completed the sale of the Yorktown refining and terminal assets. Primarily, we operate in 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 Bloomfield and Albuquerque, New Mexico, as well as asphalt terminals in Phoenix and Tucson, Arizona; Albuquerque; and El Paso. As of December 31, 2012, we also operated 222 retail 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.

Our operations include three business segments: the refining group, the wholesale group, and the retail group. See Note 3, Segment Information, for further discussion of our business segments.

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. During 2009 and 2010, extreme volatility in domestic refining margins limited the effect of these seasonal trends on our results of operations. During 2012, the volatility in crude oil prices and refining margins also contributed to the variability of our results of operations for the four calendar quarters.

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 as it relates to quarterly information included in Note 25, Quarterly Financial Information.

2. Summary of Accounting Policies

Principles of Consolidation

Western Refining, Inc. was formed on September 16, 2005, as a holding company prior to our initial public offering. On May 31, 2007, we acquired 100% of shares outstanding of Giant Industries, Inc. ("Giant"). The accompanying consolidated financial statements reflect the operations of Giant and its subsidiaries. In connection with our initial public offering in January 2006, pursuant to a contribution agreement, a reorganization of entities under common control was consummated whereby we 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

We consider all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents.

Restricted Cash

Restricted cash reported in the Consolidated Balance Sheet at December 31, 2011 relates to proceeds from the sale of the Yorktown refinery and certain portions of our Southwest pipeline system that had not been expended in accordance with restrictions of our Term Loan Agreement and Senior Secured Fixed Rate Notes Indenture. As of December 31, 2012, all of the restricted cash was used to either repay amounts outstanding under the Term Loan Agreement, to fund capital expenditures, or to pay taxes due on the sale of the Yorktown refinery and portions of our Southwest pipeline system.

72

WESTERN REFINING, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

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 our customer’s financial condition. In addition, a portion of the sales at our retail stores are on credit terms generally through major credit card companies. Past due or delinquency status of our trade accounts receivable are generally based on contractual arrangements with our customers.

Uncollectible accounts receivable are charged against the reserve for doubtful accounts when all reasonable efforts to collect the amounts due have been exhausted. Reserves for doubtful accounts related to trade receivables were $1.2 million, $1.9 million, and $3.9 million for the years ended December 31, 2012, 2011, and 2010, respectively. Additions, deductions, and balances for the reserve for doubtful accounts for the three years ended December 31, 2012 are presented below:

	Year Ended December 31,
	2012			2011			2010
	(In thousands)
Balance at January 1	$	1,884		$	3,896		$	1,571
Additions	1,049			2,306			3,260
Reductions	(1,767		)	(4,318		)	(935		)
Balance at December 31	$	1,166		$	1,884		$	3,896

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. We determine 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 our refineries or from third-party purchases. Retail refined product (fuel) inventory values are determined using the FIFO inventory valuation method. Retail 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. We capitalize 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.

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Expenditures for periodic maintenance and repair costs, including major turnaround expenses, are expensed when incurred. Such expenses are reported in direct operating expenses in our 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 our refining and retail operations. We amortize our 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. 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 evaluate the remaining useful lives of our 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 that our 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 effect on our results of operations and shareholders’ equity.

Other Assets

Other assets consist primarily of commodity hedging activities receivable, loan origination fees, and various other assets that are related to our general operation 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

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 long-lived assets for recoverability, we must make estimates of projected cash flows related to the asset being evaluated, which include, but are not limited to, assumptions about the use or disposition of the asset, its estimated remaining life, and future expenditures necessary to maintain its existing service potential. In order to determine fair value, we must make certain estimates and assumptions including, among other things, an assessment of market conditions, projected volumes, margins, cash flows, investment rates, interest/equity rates, and growth rates, that could significantly impact the estimated fair value of the asset being tested for impairment.

The risk of long-lived asset impairment losses may increase to the extent that our 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 our results of operations and shareholders’ equity.

For assets to be disposed of, we report long-lived assets at the lower of carrying amount or fair value less cost to sell.

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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 our commodity hedging activities. Wholesale cost of products sold includes the cost of fuel and lubricants, transportation and distribution costs, service parts and labor, and realized gains and losses related to our commodity hedging activities. Retail cost of products sold includes costs for motor fuels and for merchandise. Motor fuel cost of products sold represents net cost for purchased fuel. Net cost of purchased fuel excludes transportation and motor fuel taxes. Merchandise cost of products sold includes merchandise purchases, net of merchandise rebates and inventory shrinkage.

Refining direct operating expenses include direct costs of labor, maintenance materials and services, chemicals and catalysts, natural gas, utilities, and other direct operating expenses. Wholesale direct operating expenses include direct costs of labor, transportation expense, maintenance materials and services, utilities, and other direct operating expenses. Retail direct operating expenses include direct costs of labor, maintenance materials and services, outside services, bank charges, rent expense, utilities, and other direct operating expenses. Direct operating expenses also include insurance expense and property taxes.

Maintenance Turnaround Expense

Refinery process units require periodic maintenance and repairs that are commonly referred to as “turnarounds.” The required frequency of the maintenance varies by unit, but generally is every two to six years depending on the processing unit involved. Turnaround costs are expensed as incurred.

Stock-Based Compensation

The cost of employee services received in exchange for an award of equity instruments granted under the Western Refining Long-Term Incentive Plan and 2010 Incentive Plan of Western Refining, Inc. is measured based on the grant date fair value of the award. 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 the shares underlying 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 us to concentrations of credit risk primarily consist of accounts receivable. We believe that our credit risk is minimized as a result of the credit quality of our customer base. No single customer accounted for more than 10% of our consolidated net sales in 2012. The carrying amounts of cash equivalents, restricted cash, accounts receivable, accounts payable, accrued liabilities, and amounts outstanding under our Revolving Credit Agreement approximate their fair values due to their short-term maturities.

We enter 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 we physically receive and deliver the crude oil under the contracts and when we enter 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, we use crude oil and refined products futures, swap contracts, or options to mitigate the change in value for a portion of our LIFO inventory volumes subject to market price fluctuations and swap contracts to fix the margin on a portion of our future gasoline and distillate production. The physical volumes are not exchanged, and these contracts are net settled with

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cash. For instruments used to mitigate the change in value of volumes subject to market prices, we elected not to pursue hedge accounting treatment for financial accounting purposes, generally because of the difficulty of establishing and maintaining the required documentation that would allow for hedge accounting. The swap contracts used to fix the margin on a portion of our future gasoline and distillate production do not qualify for hedge accounting treatment.

We do not believe that there is significant credit risk associated with our commodity hedging instruments that are transacted through counterparties meeting established credit criteria. We may be required to collateralize any mark-to-market losses on outstanding commodity hedging contracts. Generally, we do 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.

Asset Retirement Obligations

We recognize 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

We record 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. The majority of our environmental obligations are recorded on an undiscounted 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 our 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 we deem their receipt probable.

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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 we expect 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 our 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, our 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 our ability to recover our deferred tax assets, the tax provision is increased in any period in which we determine 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.

We recognize 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. We classify interest to be paid on an underpayment of income taxes and any related penalties as income tax expense.

Use of Estimates

The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

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 did not affect our financial position or results of operations because these requirements only affected 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 did not affect our financial position or results of operations because these requirements only affected disclosures.

From time to time, new accounting pronouncements are issued by the Financial Accounting Standards Board or other standard setting bodies that may have an impact on our accounting and reporting. We believe that such recently issued accounting pronouncements and other authoritative guidance for which the effective date is in the future either will not have an impact on our accounting or reporting or that such impact will not be material to our financial position, results of operations, or cash flows when implemented.

3. Segment Information

Our operations are organized into three operating segments based on manufacturing and marketing criteria and the nature of our products and services, our production processes, and our 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 the principal products follows:

Refining Group. Our refining group currently operates two refineries: one in El Paso, Texas (the “El Paso refinery”) and one near Gallup, New Mexico (the “Gallup refinery”). The refining group also operates a crude oil transportation and pipeline

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gathering system in New Mexico, an asphalt plant in El Paso, two stand-alone refined product distribution terminals, and four asphalt terminals. Our refineries make various grades of gasoline, diesel fuel, and other products from crude oil, other feedstocks, and blending components. We purchase crude oil, other feedstocks, and blending components from various third-party suppliers. We also acquire refined products through exchange agreements and from various third-party suppliers to supplement supply to our customers. We sell these products through our wholesale group, our retail stores, other independent wholesalers and retailers, commercial accounts, and sales and exchanges with major oil companies.

In September 2010, we temporarily suspended refining operations at the 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 the Yorktown refining operations. Based on that analysis, we determined that the undiscounted forecasted cash flows exceeded the carrying amount of the 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 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 that would have required a six to nine month pre-restart maintenance period at an estimated cost of approximately $65.0 million.

On November 30, 2011, we announced that we 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 environmental remediation liabilities to the buyer and an equal sharing of future net proceeds if Yorktown refining assets are sold. We retained our East Coast wholesale business and continue to market refined 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 (Gain) loss and impairments on disposal of assets, net in our 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 a section of our 16" New Mexico Pipeline for a sales price of $40.0 million. Prior to the sale of the section of the line, the 16" New Mexico Pipeline extended from southeast to northwest New Mexico. The pipeline originates near Maljamar, New Mexico, 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 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. We 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 (Gain) loss and impairments on disposal of assets, net in our Consolidated Statement of Operations for the year ended December 31, 2011.

During the fourth quarters of 2011 and 2010, we recorded impairment charges of $11.7 million and $9.1 million, respectively, resulting from changes in our plans regarding specific assets that we had previously planned to relocate from the Bloomfield facility to the Gallup refinery. Based on the operations of the Gallup refinery, we determined that all three of the assets set aside for relocation to Gallup were no longer required. Non-cash impairment losses of $11.7 million and $9.1 million related to the long-lived assets and certain intangible assets are included under (Gain) loss and impairments on disposal of assets, net in our Consolidated Statements of Operations for the years ended December 31, 2011 and 2010, respectively.

During the third quarter of 2010, we permanently closed our product distribution terminal in Flagstaff, Arizona. We completed an impairment analysis of our Flagstaff terminal long-lived assets and determined from this analysis that the assets were fully impaired. Accordingly, an impairment charge of $3.8 million related to our Flagstaff long-lived assets is included in (Gain) loss and impairments on disposal of assets, net in our Consolidated Statement of Operations for the year ended December 31, 2010.

Wholesale Group. Our wholesale group includes several lubricant and bulk petroleum distribution plants, unmanned fleet fueling operations, and a fleet of refined product and lubricant delivery trucks. Our wholesale group distributes commercial wholesale petroleum products primarily in Arizona, California, Colorado, Nevada, New Mexico, Texas, Maryland, and

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Virginia. The wholesale group purchases petroleum fuels and lubricants from our refining group and from third-party suppliers. Beginning in January 2011, wholesale operations include the distribution of refined products through the Yorktown terminal facility.

Prior to September 2012, the refined products sold by our wholesale group in the Mid-Atlantic region were purchased from various third parties. On August 31, 2012, we transferred all of our Northeast wholesale inventories to a third party and entered into an exclusive supply and marketing agreement with the third party covering activities related to our refined product supply, hedging, and sales in the Mid-Atlantic region. We accounted for the refined product inventory transfer as a product exchange with the net difference in settlement recorded in cost of products sold. Under the supply agreement, we will receive monthly distribution amounts from the supplier equal to one-half of the amount by which our refined product sales price exceeds the supplier's costs of acquiring, transporting, and hedging (including net realized and unrealized hedging gains and losses) the refined product. To the extent our refined product sales do not exceed the refined product costs during any month, we will pay one-half of that amount to the supplier. Our payments to the supplier are limited to an aggregate annual amount of $2.0 million. Further, during any month that our refined product sales price does not exceed the refined product costs by an aggregate amount of $4.0 million for the calendar year, we will not receive monthly distribution amounts from the supplier. We paid $0.7 million for amounts due to the supplier for the year ended December 31, 2012 that we recorded as a component of cost of products sold in our Consolidated Statement of Operations.

Retail Group. Our retail stores sell various grades of gasoline, diesel fuel, general merchandise, and beverage and food products to the general public. Our wholesale group supplies the majority of gasoline and diesel fuel that our retail group sells. We purchase general merchandise and beverage and food products from various third-party suppliers. During the second, third, and fourth quarters of 2011, the retail group added 59 stores, primarily under various operating leases. For the year ended December 31, 2011, the retail group results included $97.9 million in net sales from the retail stores added during the second, third, and fourth quarters of 2011. The operations of the additional retail stores did not have a significant impact on the operating income of the retail group for the year ended December 31, 2011. During the first and second quarters of 2012, the retail group added 13 stores. For the year ended December 31, 2012, the retail group results included incremental net sales of $251.5 million from the retail stores added during the second, third, and fourth quarters of 2011 and $41.1 million in net sales from the retail stores added during the first and second quarters of 2012.

At December 31, 2012, our retail group operated 222 retail locations in Arizona, Colorado, New Mexico, 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; net impact of the disposal of assets; maintenance turnaround expense; and depreciation and amortization. Cost of products sold includes net realized and unrealized gains and losses related to our commodity hedging activities and reflects current costs adjusted, where appropriate, for LIFO and LCM inventory adjustments. Intersegment revenues are reported at prices that approximate market.

Activities of our business that are not included in the three segments mentioned above are included in the "Other" category. These activities consist primarily of corporate staff operations and other items that are not specific to the normal business of any one of our three operating segments. We do not allocate certain items of other income and expense, including income taxes, to the individual segments.

The total assets of each segment consist primarily of cash and cash equivalents; inventories; net accounts receivable; net property, plant, and equipment; 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 net accounts receivable; prepaid expenses; other current assets; net deferred income tax items; net property, plant, and equipment; and other long-term assets.

Combined segment results for the year ended December 31, 2010 include the reversal of $14.7 million related to our December 2009 incentive bonus accrual. This revision of our 2009 bonus estimate reduced direct operating expenses (exclusive of depreciation and amortization) and selling, general, and administrative expense by $8.5 million and $6.2 million, respectively.

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Disclosures regarding our reportable segments with reconciliations to consolidated totals for the three years ended December 31, 2012 are presented below:

	Year Ended December 31, 2012
	Refining Group		Wholesale Group		Retail Group		Other			Consolidated
	(In thousands)
Net sales to external customers	$	4,304,000	$	4,011,148	$	1,187,986	$	—		$	9,503,134
Intersegment revenues (1)	4,036,178		849,143		24,084		—			—
Operating income (loss) before asset disposals	$	734,360	$	30,502	$	16,111	$	(70,969	)	$	710,004
Gain on disposal of assets, net	1,382		509		—		—			1,891
Operating income (loss) (2)	$	735,742	$	31,011	$	16,111	$	(70,969	)	$	711,895
Other income (expense), net										(94,808		)
Income before income taxes										$	617,087
Depreciation and amortization	$	77,575	$	3,814	$	10,473	$	2,045		$	93,907
Capital expenditures	186,489		4,255		7,774		3,639			202,157
Total assets at December 31, 2012	1,608,624		187,689		186,668		497,426			2,480,407

(1) Intersegment revenues of $4,909.4 million have been eliminated in consolidation.

(2) The effect of our economic hedging activity is included within operating income of our refining and wholesale groups as a component of cost of products sold. Refining cost of products sold includes $350.5 million in net realized and unrealized economic hedging losses and wholesale cost of products sold includes $23.6 million in net realized economic hedging losses for the year ended December 31, 2012.

	Year Ended December 31, 2011
	Refining Group			Wholesale Group		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 asset disposals	$	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) (2)	$	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) The effect of our economic hedging activity is included within operating income of our refining and wholesale groups as a component of cost of products sold. Refining cost of products sold includes $103.3 million in net realized and unrealized economic hedging gains and wholesale cost of products sold includes $3.9 million in net realized economic hedging gains for the year ended December 31, 2011.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

	Year Ended December 31, 2010
	Refining Group			Wholesale Group		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 asset disposals	$	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) (2)	$	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) The effect of our economic hedging activity is included within operating income of our refining and wholesale groups as a component of cost of products sold. Refining cost of products sold includes $9.4 million in net realized and unrealized economic hedging losses for the year ended December 31, 2010.

4. Fair Value Measurement

We utilize the market approach when measuring fair value for our financial assets and liabilities. The market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities.

The 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 that 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 cash equivalents, accounts receivable, accounts payable, and accrued liabilities approximated their fair values at December 31, 2012 and 2011 due to their short-term maturities. Certain of our commodity derivative contracts under master netting arrangements include both asset and liability positions. We have elected to offset the fair value amounts recognized for multiple similar derivative instruments executed with the same counterparty, including any related cash collateral asset or obligation under the column "Netting Adjustments" below; however, fair value amounts by hierarchy level are presented on a gross basis in the tables below.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

The following tables represent our assets and liabilities measured at fair value on a recurring basis as of December 31, 2012 and 2011, and the basis for that measurement:

	Carrying Value at December 31, 2012			Fair Value Measurement at December 31, 2012 Using											Net Fair Value at December 31, 2012
				Level 1		Level 2			Level 3			Netting Adjustments
	(In thousands)
Gross financial assets:
Current assets - commodity hedging contracts	$	5,369		$	—	$	5,369		$	—		$	(1,451	)	$	3,918
Other assets - commodity hedging contracts	1,375			—		1,360			15			(1,147		)	228
Gross financial liabilities:
Accrued liabilities - commodity hedging contracts	(37,352		)	—		(37,352		)	—			1,451			(35,901		)
Other long-term liabilities - commodity hedging contracts	(16,951		)	—		(15,289		)	(1,662		)	1,147			(15,804		)
	$	(47,559	)	$	—	$	(45,912	)	$	(1,647	)	$	—		$	(47,559	)

	Carrying Value at December 31, 2011			Fair Value Measurement at December 31, 2011 Using										Net Fair Value at December 31, 2011
				Level 1		Level 2			Level 3		Netting Adjustments
	(In thousands)
Gross financial assets:
Current assets - commodity hedging contracts	$	129,473		$	—	$	129,473		$	—	$	(1,370	)	$	128,103
Other assets - commodity hedging contracts	54,208			—		51,577			2,631		—			54,208
Gross financial liabilities:
Accrued liabilities - commodity hedging contracts	(1,568		)	—		(1,568		)	—		1,370			(198		)
Other long-term liabilities - commodity hedging contracts	—			—		—			—		—			—
	$	182,113		$	—	$	179,482		$	2,631	$	—		$	182,113

Commodity hedging contracts designated as Level 3 financial assets relate to jet fuel crack spread swaps with contract maturity dates in 2014 and 2015. We based the fair value of these instruments upon similar contracts with quoted market prices that have a strong historical correlation in pricing to the jet fuel crack spread swaps. Both historically and in observable future contracts, there has been an average differential of $0.756 per barrel greater for the jet fuel crack spread swaps to the quoted market prices for ultra-low sulfur diesel crack spread swaps. This differential was the basis for valuing the jet fuel crack spread swaps that mature in 2014 and 2015. As quoted prices for similar assets or liabilities in an active market are available, the underlying financial asset or liability will be reclassified and designated as Level 2 prior to final settlement.

Carrying amounts of commodity hedging contracts reflected as financial assets are included in both current and non-current other assets in the Consolidated Balance Sheets. Carrying amounts of commodity hedging contracts reflected as financial liabilities are included in both accrued and other long-term liabilities in the Consolidated Balance Sheets. Included in the carrying amounts of commodity hedging contracts are fair value adjustments, respective to each counterparty with whom we enter into contracts, called credit valuation adjustments ("CVA"). CVAs are intended to adjust the fair value of counterparty contracts as a function of a counterparty's credit rating and reflect the credit quality of each counterparty to arrive at contract fair values.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

The following table presents the changes in fair value of our Level 3 assets and liabilities (all related to commodity price swap contracts) for the years ended December 31, 2012 and 2011. There were not any assets or liabilities designated as Level 3 at December 31, 2010.

	December 31,
	2012			2011
	(In thousands)
Asset amount at beginning of period	$	2,631		$	—
Change in fair value of Level 3 trades open at the beginning of the period	(3,073		)	—
Fair value of trades entered into during the period	(1,205		)	2,631
Fair value reclassification from Level 3 to Level 2	—			—
Asset (liability) balance at end of period	$	(1,647	)	$	2,631

A hypothetical change of 10% to the estimated future cash flows attributable to our Level 3 commodity price swaps would result in an estimated fair value change of $0.2 million.

As of December 31, 2012 and 2011, the carrying amount and estimated fair value of our debt was as follows:

	December 31,
	2012		2011
	(In thousands)
Carrying amount	$	499,863	$	803,990
Fair value	984,831		997,693

The carrying amount of our 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.

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).

5. Inventories

Inventories were as follows:

	December 31,
	2012		2011
	(In thousands)
Refined products (1)	$	190,147	$	199,848
Crude oil and other raw materials	189,249		179,039
Lubricants	13,379		11,985
Retail store merchandise	17,195		14,882
Inventories	$	409,970	$	405,754

(1) Includes $15.1 million and $76.5 million of inventory valued using the FIFO valuation method at December 31, 2012 and 2011, respectively. The decrease in our FIFO inventories from December 31, 2011 is primarily due to the sale of our wholesale group's Mid-Atlantic refined product inventories during the third quarter of 2012 in connection with the execution of an exclusive supply and marketing agreement with a third party. See Note 3, Segment Information for further discussion.

We value our 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 our wholesale and retail groups, refined products inventories are valued under the LIFO valuation method. Lubricants and retail store merchandise are valued under the FIFO valuation method.

As of December 31, 2012 and 2011, refined products valued under the LIFO method and crude oil and other raw materials totaled 5.8 million barrels and 5.2 million barrels, respectively. At December 31, 2012, the excess of the current cost

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WESTERN REFINING, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

of these crude oil, refined product, and other feedstock and blendstock inventories over LIFO cost was $148.3 million. 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. The non-cash impact of changes in our LIFO reserves decreased our cost of products sold for the year ended December 31, 2012 by $65.4 million and increased our cost of products sold for the year ended December 31, 2011 and 2010 by $44.2 million and $47.1 million, respectively.

The net effect of inventory reductions that resulted in the liquidation of LIFO inventory levels are summarized in the table below:

	Year Ended December 31,
	2012			2011		2010
	(In thousands, except per share amount)
Increase (decrease) in operating income	$	(4,040	)	$	22,290	$	16,886
Increase (decrease) net income (loss)	(2,612		)	14,600		6,675
Increase (decrease) in earnings (loss) per diluted share	$	(0.02	)	$	0.13	$	0.08

Average LIFO cost per barrel of our refined products and crude oil and other raw materials inventories as of December 31, 2012 and 2011, was as follows:

	December 31,
	2012					2011
	Barrels	LIFO Cost		Average LIFO Cost Per Barrel		Barrels	LIFO Cost		Average LIFO Cost Per Barrel
	(In thousands, except cost per barrel)
Refined products	2,404	$	175,097	$	72.84	1,896	$	123,335	$	65.05
Crude oil and other	3,419	189,249		55.35		3,289	179,039		54.44
	5,823	$	364,346	62.57		5,185	$	302,374	58.32

6. Prepaid Expenses

Prepaid expenses were as follows:

	December 31,
	2012		2011
	(In thousands)
Prepaid crude oil and other raw materials inventories	$	47,858	$	111,521
Prepaid insurance and other	26,183		52,009
Prepaid expenses	$	74,041	$	163,530

The majority of the decrease in prepaid expenses was due to the increase in credit limits with certain vendors for the purchase of crude oil and other raw materials inventories.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

7. Other Current Assets

Other current assets were as follows:

	December 31,
	2012		2011
	(In thousands)
Margin account deposits	$	29,669	$	10,819
Material and chemical inventories	27,533		27,196
Excise and other taxes receivable	14,955		22,149
Unrealized hedging gains	3,918		128,103
Exchange and other receivables	5,263		6,797
Other current assets	$	81,338	$	195,064

8. Property, Plant, and Equipment, Net

Property, plant, and equipment, net was as follows:

	December 31,
	2012			2011
	(In thousands)
Refinery facilities and related equipment	$	1,179,418		$	1,013,169
Pipelines, terminals, and transportation equipment	76,037			75,172
Wholesale and retail facilities and related equipment	221,674			198,060
Other	23,238			22,287
	1,500,367			1,308,688
Accumulated depreciation	(451,490		)	(368,434		)
	1,048,877			940,254
Construction in progress	63,607			55,062
Property, plant, and equipment, net	$	1,112,484		$	995,316

Depreciation expense was $90.6 million, $131.3 million, and $134.3 million for the years ended December 31, 2012, 2011, and 2010, respectively. The majority of the decrease in depreciation expense from 2011 to 2012 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

A summary of intangible assets, net is presented in the table below:

	December 31, 2012							December 31, 2011
	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	$	20,427	$	(8,971	)	$	11,456	$	20,426	$	(7,384	)	$	13,042	7.3
Customer relationships	7,300		(2,278		)	5,022		7,300		(1,758		)	5,542		9.7
Rights-of-way and other	7,120		(3,401		)	3,719		8,163		(3,346		)	4,817		5.2
	34,847		(14,650		)	20,197		35,889		(12,488		)	23,401
Unamortizable assets:
Trademarks	4,800		—			4,800		4,800		—			4,800
Liquor licenses	16,627		—			16,627		16,151		—			16,151
Intangible assets, net	$	56,274	$	(14,650	)	$	41,624	$	56,840	$	(12,488	)	$	44,352

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Intangible asset amortization expense was $3.0 million, $4.2 million, and $4.0 million for the years ended December 31, 2012, 2011, and 2010, 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):

2013	$	3,039
2014	2,849
2015	2,371
2016	2,200
2017	2,259

10. Other Assets, Net

Other assets, net of amortization, were as follows:

	December 31,
	2012		2011
	(In thousands)
Unamortized loan fees	$	22,701	$	33,086
Unrealized hedging gains	228		54,208
Other	10,967		12,372
Other assets, net of amortization	$	33,896	$	99,666

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11. Accrued and Other Long-Term Liabilities

Accrued liabilities were as follows:

	December 31,
	2012		2011
	(In thousands)
Income taxes	$	72,900	$	52,795
Excise taxes	54,727		32,000
Payroll and related costs	45,989		42,111
Fair value of open commodity hedging positions, net	35,901		198
Property taxes	25,819		13,216
Professional and other	21,126		19,859
Environmental reserves	3,932		3,343
Banking fees and other financing	2,841		3,708
Interest	2,176		2,310
Short-term pension obligation	695		2,461
Accrued liabilities	$	266,106	$	172,001

During 2012, we increased our annual property tax accrual estimate for our El Paso refinery by $11.6 million resulting from an increased appraisal from the El Paso Central Appraisal District for 2012. We believe the appraised property values to be in error and have filed a lawsuit in state district court to appeal this appraised value.

Other long-term liabilities were as follows:

	December 31,
	2012		2011
	(In thousands)
Fair value of open commodity hedging positions, net	$	15,804	$	—
Capital lease obligations	10,158		3,337
Unrecognized tax benefits	9,572		—
Retiree plan obligations	6,228		5,745
Asset retirement obligations	5,088		4,736
Environmental reserves	3,904		2,428
Other	5,397		5,709
Other long-term liabilities	$	56,151	$	21,955

As of December 31, 2012, we had environmental liability accruals of $7.8 million, of which $3.9 million was in accrued liabilities. Discounted liabilities of $1.3 million have been recorded using an inflation factor of 2.7% and a discount rate of 7.1%. Environmental liabilities of $6.5 million accrued at December 31, 2012 have not been discounted. As of December 31, 2012, the unescalated, undiscounted environmental reserves related to these liabilities totaled $1.5 million, leaving $0.2 million to be accreted over time.

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The table below summarizes our environmental liability accruals:

	December 31, 2011		Increase (Decrease)			Payments			December 31, 2012
	(In thousands)
Discounted liabilities	$	4,295	$	(2,606	)	$	(397	)	$	1,292
Undiscounted liabilities	1,476		5,813			(745		)	6,544
Total environmental liabilities	$	5,771	$	3,207		$	(1,142	)	$	7,836

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

2013	$	107
2014	107
2015	107
2016	107
2017	107
2018 and thereafter	972

12. Asset Retirement Obligations

We determine the estimated fair value of our AROs 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 the total estimated retirement obligation is accrued or we settle the liability.

We have identified the following AROs:

Crude Pipelines. Our rights-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. We do not believe these rights-of-way agreements will require us to remove the underground pipe upon taking the pipeline permanently out of service. However, certain regulatory requirements may mandate that we purge out of service underground pipe at the time we take the pipelines permanently out of service.

Storage Tanks. We have 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, we have also committed to restore the leased property to its original condition.

Other. We identified certain refinery piping and heaters as a conditional ARO since we have 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 our AROs for the three years ended December 31, 2012:

	December 31,
	2012			2011			2010
	(In thousands)
Liability, beginning of period	$	4,736		$	5,485		$	5,326
Liabilities incurred	43			44			33
Liabilities settled	(33		)	(1,160		)	(229		)
Accretion expense	342			367			355
Liability, end of period	$	5,088		$	4,736		$	5,485

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13. Long-Term Debt

Long-term debt was as follows:

	December 31,
	2012			2011
	(In thousands)
11.25% Senior Secured Notes, due 2017, net of unamortized discount of $19,001 and $21,986 for 2012 and 2011, respectively	$	305,999		$	303,014
5.75% Senior Convertible Notes, due 2014, net of conversion feature of $22,105 and $34,999 for 2012 and 2011, respectively	193,345			180,451
Term Loan, net of unamortized discount of $2,901 in 2011, with average interest rates of 7.50% and 8.31% during 2012 and 2011, respectively	—			319,661
5.50% promissory note, due 2015	519			864
Revolving Credit Agreement	—			—
Long-term debt	499,863			803,990
Current portion of long-term debt	(206		)	(3,595		)
Long-term debt, net of current portion	$	499,657		$	800,395

Outstanding amounts under the Revolving Credit Agreement, if any, are included in the current portion of long-term debt.

Interest expense and other financing costs were as follows:

	Year Ended December 31,
	2012			2011			2010
	(In thousands)
Contractual interest:
11.25% Senior Secured Notes	$	36,563		$	36,563		$	36,563
Senior Secured Floating Rate Notes	—			29,152			29,973
5.75% Senior Convertible Notes	12,388			12,388			12,388
Term Loan	9,458			27,224			37,611
Revolving Credit Agreement	—			631			5,036
	58,409			105,958			121,571
Amortization of original issuance discount:
11.25% Senior Secured Notes	2,986			2,632			2,324
Senior Secured Floating Rate Notes	—			4,004			3,645
5.75% Senior Convertible Notes	12,894			11,286			9,898
Term Loan	188			349			—
	16,068			18,271			15,867
Other interest expense	9,231			12,330			13,359
Capitalized interest	(2,359		)	(1,958		)	(4,248		)
Interest expense and other financing costs	$	81,349		$	134,601		$	146,549

We amortize original issue discounts using the effective interest method over the respective term of the debt.

Senior Secured Notes. We issued two tranches of Senior Secured Notes under an indenture dated on June 12, 2009. The first tranche consisted of $325.0 million in aggregate principal amount of 11.25% Senior Secured Notes ("Fixed Rate Senior Secured Notes"). The second tranche consisted of $275.0 million Senior Secured Floating Rate Notes (together with the Fixed Rate Senior Secured Notes, the "Senior Secured Notes"). The Fixed Rate Senior Secured Notes pay interest semi-annually in cash in arrears on June 15 and December 15 of each year and will mature on June 15, 2017. We may redeem the 11.25% Senior Secured Notes, in whole or part, at our option at any time prior to June 15, 2013 at a price equal to 100% of the principal amount plus an applicable premium plus accrued and unpaid interest to the date of redemption. Beginning June 15, 2013 through June 14, 2014, we may redeem the Senior Secured Notes at a premium of 5.625%; from June 15, 2014 through June 14, 2015 at a premium of 2.813%; and at par thereafter.

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On December 21, 2011, we redeemed the Senior Secured 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 of $275.0 million. As a result of this redemption, we recorded a $29.7 million loss on extinguishment of debt including a $3.2 million write-off of unamortized loan fees in our Consolidated Statement of Operations for the year ended December 31, 2011. Prior to December 21, 2011, the Senior Secured 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 Senior Secured Floating Rate Notes as of December 21, 2011 was 10.75%. The Senior Secured Floating Rate Notes became redeemable at our option beginning on December 15, 2011 at a premium of 5.0%.

The Fixed Rate Senior Secured Notes are guaranteed by all of our domestic restricted subsidiaries in existence on the date the Notes were issued. The Fixed Rate Senior Secured Notes will also be guaranteed by all future wholly-owned domestic restricted subsidiaries and by any restricted subsidiary that guarantees any of our indebtedness under credit facilities that are secured by a lien on the collateral securing the Fixed Rate Senior Secured Notes. The Fixed Rate Senior Secured Notes are also secured on a first priority basis equally and ratably with any future other pari passu secured obligation, by the collateral that consists of our fixed assets, and on a second priority basis, equally and ratably with any future other pari passu secured obligation, by the collateral securing the Revolving Credit Agreement that consists of our cash and cash equivalents, trade accounts receivables, and inventory.

The indenture governing the Senior Secured Notes contains covenants that limit our (and most of our subsidiaries’) ability to, among other things: (i) pay dividends or make other distributions in respect of our capital stock or make other restricted payments; (ii) make certain investments; (iii) sell certain assets; (iv) incur additional 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 that 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. In 2009, we issued and sold $215.5 million in aggregate principal amount of our 5.75% Convertible Senior Notes (“Convertible Senior Notes”). The Convertible Senior Notes are unsecured and pay interest semi-annually in arrears at a rate of 5.75% per year and will mature on June 15, 2014. The discount on the Convertible Senior Notes is amortized using the effective interest method through maturity on June 15, 2014.

The initial conversion rate for the Convertible Senior Notes was 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). The Convertible Senior Notes are presently convertible at the option of the holder. The current conversion rate is 102.3750 to each $1,000 of principal amount of Convertible Senior Notes. The Convertible Senior Notes will also be convertible in any future calendar quarter (prior to maturity) whenever the last reported sale price of our common stock exceeds 130% of the applicable conversion price in effect for the Convertible Senior Notes on the last trading day of the immediate preceding calendar quarter 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, we may elect to satisfy our obligations upon conversion through the delivery of shares of our common stock, in cash, or a combination thereof. As of December 31, 2012, the if-converted value of the Convertible Senior Notes exceeded its principal amount by $406.3 million.

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 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 and recognized a $4.6 million loss on extinguishment of debt. In addition to our scheduled Term Loan payment of $0.8 million made during the first quarter of 2012, we made non-mandatory prepayments of $30.0 million and $291.8 million during the first and second quarters of 2012, respectively. As a result of the repayment of the Term Loan during the second quarter of 2012, we recognized a loss on extinguishment of debt of $7.7 million.

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

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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 Fixed Rate Notes and previously securing the Term Loan, and any future other pari passu secured obligations that 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. We are also subject to covenant requirements related to a minimum fixed charge coverage ratio, contingent on the level of availability under the Revolving Credit Agreement.

As of December 31, 2012, we had net availability under the amended and restated Revolving Credit Agreement of $394.5 million consisting of $650.7 million in gross availability and $256.2 million in outstanding letters of credit.

Guarantors of the Revolving Credit Agreement. The amended and restated Revolving Credit Agreement is 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. We issue and cancel letters of credit on a periodic basis depending upon our needs. At December 31, 2012, there were $256.2 million of irrevocable letters of credit outstanding, primarily issued to crude oil suppliers under the Revolving Credit Agreement.

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14. Income Taxes

The following is an analysis of our consolidated income tax expense (benefit) for the three years ended December 31, 2012:

	Year Ended December 31,
	2012			2011			2010
	(In thousands)
Current:
Federal	$	242,016		$	106,386		$	(7,554	)
State	34,184			13,268			(1,036		)
Total current	276,200			119,654			(8,590		)
Deferred:
Federal	(52,606		)	(48,085		)	(15,297		)
State	(5,392		)	(1,708		)	(2,190		)
Total deferred	(57,998		)	(49,793		)	(17,487		)
Provision for income taxes	$	218,202		$	69,861		$	(26,077	)

We paid income tax, net of refunds, of $237.6 million and $70.2 million and received income tax refunds, net of taxes paid of $49.8 million for the years ended December 31, 2012, 2011, and 2010, 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, 2012:

	Year Ended December 31,
	2012			2011			2010
	(In thousands)
Taxes at the federal statutory rate	$	215,980		$	70,885		$	(15,094	)
State income taxes, net of federal tax benefit (1)	15,330			(15,863		)	(5,588		)
Valuation allowance for state net operating losses	2,791			23,700			—
Domestic Activity Production deduction	(15,059		)	(8,309		)	—
Federal tax credit for increasing research activities (1)	(2,154		)	—			—
Federal tax credit for production of ultra low sulfur diesel	—			(109		)	(4,747		)
Other, net	1,314			(443		)	(648		)
Total income tax expense (benefit)	$	218,202		$	69,861		$	(26,077	)

(1) State income taxes, net of federal tax benefit, and federal tax credit for increasing research activities include $7.4 million and $2.2 million, respectively, in unrecognized tax benefits for the year ended December 31, 2012.

The effective tax rates for 2012, 2011, and 2010 were 35.4%, 34.5%, and 60.5%, respectively, as compared to the federal statutory rate of 35% in all years.

The Internal Revenue Service (the “IRS”) is presently conducting an examination of our tax years ending December 31, 2009 and 2010. That examination is in progress and no adjustments have been proposed. The IRS has completed an examination of our tax years ending December 31, 2007 and 2008. For the 2007 and 2008 years, the IRS has proposed adjustments; however, we disagree with the proposed adjustments and are pursuing our remedies at the exam level. For our tax year ending December 31, 2006, the IRS has completed an examination and has proposed adjustments. We filed final Decision Documents in Tax Court regarding the 2006 adjustments. We do not believe the results of any of these examinations, appeals, or litigation will have a material effect on our financial position, operations, or cash flows. The timing and results of final determinations on these matters remain uncertain.

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The following is a reconciliation of unrecognized tax benefits for the three years ended December 31, 2012:

	December 31,
	2012		2011		2010
	(In thousands)
Unrecognized tax benefits at beginning of year	$	—	$	—	$	—
Increases (decreases) related to current year tax positions	9,572		—		—
Increases (decreases) related to prior year tax positions	—		—		—
Decreases related to settlements with taxing authorities	—		—		—
Decreases resulting from the expiration of the statute of limitations	—		—		—
Unrecognized tax benefits at end of year	$	9,572	$	—	$	—

The unrecognized tax benefit as of December 31, 2012 of $9.6 million would affect our effective tax rate if recognized. No interest or penalties have been accrued with respect to the unrecognized tax benefit.

The tax years of 2007 through 2012 remain open to examination by the major tax jurisdictions to which we are subject (U.S. Federal, Texas, Virginia, Maryland, New Mexico, Arizona, and California).

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

	December 31,
	2012									2011
	Assets			Liabilities			Net			Assets			Liabilities			Net
	(In thousands)
Current deferred taxes:
Inventories	$	—		$	(44,138	)	$	(44,138	)	$	—		$	(39,332	)	$	(39,332	)
Stock-based compensation	2,095			—			2,095			1,841			—			1,841
Commodity hedging activities	17,847			—			17,847			—			(68,365		)	(68,365		)
Other current, net	—			(3,514		)	(3,514		)	301			—			301
Valuation allowance	—			—			—			—			—			—
Current deferred taxes	19,942			(47,652		)	(27,710		)	2,142			(107,697		)	(105,555		)
Noncurrent deferred taxes:
Property, plant, and equipment	—			(278,424		)	(278,424		)	—			(250,140		)	(250,140		)
Intangible assets	—			—			—			—			(3,853		)	(3,853		)
Postretirement obligations	2,006			—			2,006			2,604			—			2,604
Debt discount	—			(8,249		)	(8,249		)	—			(13,139		)	(13,139		)
Environmental and retirement obligations	788			—			788			1,410			—			1,410
Other noncurrent, net	1,234			—			1,234			626			—			626
Net operating loss and tax credit carryforwards	26,797			—			26,797			23,700			—			23,700
Valuation allowance	(26,491		)	—			(26,491		)	(23,700		)	—			(23,700		)
Noncurrent deferred taxes	4,334			(286,673		)	(282,339		)	4,640			(267,132		)	(262,492		)
Net deferred taxes	$	24,276		$	(334,325	)	$	(310,049	)	$	6,782		$	(374,829	)	$	(368,047	)

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At December 31, 2012, we had the following credits and net operating loss (“NOL”) carryforwards:

Type of Credit	Gross Amount			Tax Effected Amount			Expiration
	(In thousands)
State NOL carryforwards:
Colorado	$	(4,690	)	$	(217	)	2030
Virginia and Maryland	(4,141		)	(204		)	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	(96,967		)	(4,922		)	2031
Total state NOL carryforwards	(621,351		)	(26,796		)
Less valuation allowance for operating loss carryforwards	616,428			26,491
Total credits and NOL carryforwards	$	(4,923	)	$	(305	)

In assessing the realizability of deferred tax assets, we determined that a valuation allowance of $26.5 million was appropriate against the deferred tax assets relating to the NOL carryforwards for Virginia and Maryland at December 31, 2012. We have increased the valuation allowance for the NOL carryforwards by $2.8 million from December 31, 2011.

Subsequent to December 31, 2012, certain tax laws were enacted that will have an impact on taxable income for 2012; however, changes in tax law are effected in the year of enactment. As such, the impact of these changes in tax law will be reflected during 2013. None of the changes in tax law will have a material impact on our business, financial condition, results of operations, or cash flows.

15. Retirement Plans

We fully recognize the obligations associated with our single-employer defined benefit pension, retiree healthcare, and other postretirement plans in our financial statements.

Pensions

Through December 31, 2012, we had distributed $25.8 million ($5.7 million in 2012, $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. We contributed $1.5 million and $4.4 million to the Yorktown pension plan during 2012 and 2011, respectively. In connection with the sale of the Yorktown refinery during the fourth quarter of 2011, we intend to terminate the defined benefit plan covering certain previous Yorktown refinery employees. Such termination is subject to regulatory approval that may take several months. We expect to contribute $0.8 million to the Yorktown pension plan in 2013, depending upon the plan's status at the end of 2013.

In connection with the negotiation of a collective bargaining agreement covering employees of the El Paso refinery during the second quarter of 2009, we terminated the defined benefit plan covering certain El Paso refinery employees. Regulatory approval of this termination was received during the first quarter of 2010. We 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, we 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.

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The following tables set forth significant information about our 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,
	2012			2011
	(In thousands)
Benefit obligation at beginning of year	$	7,274		$	14,743
Service cost	—			—
Interest cost	141			450
Benefits paid	—			(29		)
Termination benefits paid	(5,732		)	(7,215		)
Actuarial gain	(406		)	(675		)
Plan amendments	—			—
Curtailment	—			—
Settlement	—			—
Benefit obligation at end of year	$	1,277		$	7,274
Fair value of plan assets at beginning of year	$	4,813		$	7,659
Company contribution	1,500			4,400
Actual return on plan assets	1			(2		)
Benefits paid	—			(29		)
Termination benefits paid	(5,732		)	(7,215		)
Fair value of plan assets at end of year	$	582		$	4,813
Current liabilities	$	(695	)	$	(2,461	)
Noncurrent liabilities	—			—
Unfunded status recognized in the consolidated balance sheets	$	(695	)	$	(2,461	)
Accumulated benefit obligation	$	1,277		$	7,274

	Year Ended December 31,
	2012			2011			2010
	(In thousands)
Net periodic benefit cost includes:
Service cost	$	—		$	—		$	1,802
Interest cost	141			450			1,221
Expected return on assets	(61		)	(119		)	(1,436		)
Amortization of net actuarial (gain) loss	6			—			5
Recognized settlement expense	978			1,537			4,407
Recognized curtailment gain	—			—			(1,006		)
Net periodic benefit cost	$	1,064		$	1,868		$	4,993
Pre-tax unrecognized net loss included in accumulated other comprehensive loss at beginning of year	$	1,550		$	3,641		$	3,123
Net actuarial (gain) loss	(347		)	(554		)	4,930
Recognition of loss due to settlement	(978		)	(1,537		)	(4,407		)
Amortization of net actuarial loss	(6		)	—			(5		)
Pre-tax unrecognized net loss included in accumulated other comprehensive loss at end of year	$	219		$	1,550		$	3,641

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	Year Ended December 31,
	2012 (1)		2011 (1)		2010 (1)
Weighted average assumptions used to determine benefit obligations at December 31:
Discount rate	3.79	%	3.67	%	4.63	%
Rate of compensation increase	—		—		3.50
Weighted average assumptions used to determine net periodic benefit cost:
Discount rate	3.67		4.63		5.25
Expected long-term return on assets (2)	1.90		1.90		8.50
Rate of compensation increase	—		—		3.50

(1) Weighted average assumptions used to determine the expected benefit obligation and net periodic benefit cost in 2012, 2011, and 2010 are for the Yorktown pension plan only.

(2) During 2011, all benefit plan assets for the Yorktown pension plan were moved into cash equivalents and our expected long-term rate of return on assets was lowered to 1.90%.

The following benefit payments (in thousands) are expected to be paid in the years indicated:

2013	$	861
2014	30
2015	30
2016	30
2017	30
2018-2022	140

Postretirement Obligations

The following tables set forth significant information about our retiree medical plans for certain El Paso and Yorktown employees. Unlike the pension plans, we are 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 4.32% and 4.33% at December 31, 2012 and 2011, respectively, to determine the benefit obligation, the components of the postretirement obligation were:

	As of December 31,
	2012			2011
	(In thousands)
Benefit obligation at beginning of year	$	5,965		$	4,070
Service cost	119			84
Interest cost	261			257
Benefits paid	(214		)	(211		)
Actuarial loss	361			1,765
Curtailment gain	—			—
Benefit obligation at end of year	$	6,492		$	5,965
Unfunded status	$	(6,492	)	$	(5,965	)
Current liabilities	$	(265	)	$	(220	)
Noncurrent liabilities	(6,227		)	(5,745		)
Unfunded status recognized in the consolidated balance sheets	$	(6,492	)	$	(5,965	)

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	Year Ended December 31,
	2012			2011			2010
	(In thousands)
Net periodic benefit cost includes:
Service cost	$	119		$	84		$	490
Interest cost	261			257			493
Amortization of net actuarial (gain) loss	42			4			(20		)
Net periodic benefit cost	$	422		$	345		$	963
Pre-tax unrecognized net (gain) loss included in accumulated other comprehensive gain at beginning of year	$	1,351		$	(410	)	$	(859	)
Net actuarial (gain) loss	361			1,765			(24		)
Recognition of curtailment gain	—			—			453
Amortization of net actuarial (gain) loss	(42		)	(4		)	20
Pre-tax unrecognized net (gain) loss included in accumulated other comprehensive gain at end of year	$	1,670		$	1,351		$	(410	)

The weighted average discount rates used to determine net periodic benefit costs were 4.37%, 5.64%, and 5.92% for 2012, 2011, and 2010, respectively. The following benefit payments (in thousands) are expected to be paid in the year indicated:

2013	$	270
2014	300
2015	323
2016	350
2017	383
2018-2022	1,813

The health care cost trend rate for the plan covering El Paso employees for 2012 and future years is capped at 4.00%. The health care cost trend rate for the plan covering Yorktown employees for 2012 is 7.50% 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	$	(49	)
Effect on accumulated benefit obligation	26		(567		)

(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 table presents cumulative changes in other comprehensive income related to our benefit plans included as a component of equity for the periods presented, net of income tax:

	As of December 31,
	2012			2011
	(In thousands)
Beginning of period balance	$	(1,812	)	$	(1,940	)
Current year changes	638			128
End of period balance	$	(1,174	)	$	(1,812	)

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The following tables present the fair values of the assets of our pension plans as of December 31, 2012 and 2011 by level of the fair value hierarchy. Assets categorized in Level 1 of the hierarchy are measured at fair value using a market approach based on quotations from national securities exchanges. Assets categorized in Level 2 of the hierarchy are measured at net asset value as a practical expedient for fair value. As noted above, our other postretirement benefit plans are funded on a pay-as-you-go basis and have no assets.

			Fair Value Measurement Using
	Total as of December 31, 2012		Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	(In thousands)
Cash equivalents	$	582	$	582	$	—	$	—

	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	$	—	$	—

Defined Contribution Plans

We sponsor a 401(k) defined contribution plan under which participants may contribute a percentage of their eligible compensation to various investment choices offered by the plan. We make a Safe Harbor matching contribution to the account of each participant who is covered under the collective bargaining agreement with the International Union of Operating Engineers in El Paso and has completed 12 months of service equal to 250% of the first 4% of compensation beginning February 1, 2012. During January 2012, the safe harbor matching contribution was 200% of the first 4% of compensation. In addition, participants who were covered by the settlement agreement with the International Union of Operating Engineers in El Paso received a contribution equal to 3% of the compensation paid between January 1, 2012 and January 31, 2012. For all other employees, we matched 1% up to a maximum of 4% of eligible compensation for each 1% of eligible compensation contributed provided the participant had a minimum of one year of service with Western. We expensed $5.9 million, $5.8 million, and $6.2 million in connection with this plan for the years ended December 31, 2012, 2011, and 2010, respectively.

16. Crude Oil and Refined Product Risk Management

We enter into crude oil forward contracts to facilitate the supply of crude oil to the refineries. During 2012, 2011, and 2010, we 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.

We use crude oil and refined products futures, swap contracts, or options to mitigate the change in value for a portion of our LIFO inventory volumes subject to market price fluctuations, and swap contracts to fix the margin on a portion of our 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, we elected not to pursue hedge accounting treatment for financial accounting purposes, generally because of the difficulty of establishing and maintaining the required documentation that would allow for hedge accounting. The swap contracts used to fix the margin on a portion of our 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 of the majority of the contracts for the purpose of marking to market the hedging instruments at each period end.

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The following table summarizes our economic hedging activity for the three years ended December 31, 2012:

	Year Ended December 31,
	2012			2011			2010
	(In thousands)
Economic hedging activities recognized within cost of products sold
Realized hedging gain (loss), net	$	(144,448	)	$	(76,033	)	$	(9,770	)
Unrealized hedging gain (loss), net	(229,672		)	183,286			337
Total hedging gain (loss), net	$	(374,120	)	$	107,253		$	(9,433	)
Open commodity hedging instruments (bbls)
Crude futures	588			933			$	(177	)
Refined product price and crack spread swaps	26,683			29,283			$	1,200
Total open commodity hedging instruments	27,271			30,216			1,023
Fair value of outstanding contracts, net
Other current assets	$	3,918		$	128,103		$	—
Other assets	228			54,208			—
Accrued liabilities	(35,901		)	(198		)	(1,173		)
Other long-term liabilities	(15,804		)	—			—
Fair value of outstanding contracts - unrealized gain (loss), net	$	(47,559	)	$	182,113		$	(1,173	)

Our commodity hedging activities are initiated within guidelines established by management and approved by our board of directors. Commodity hedging transactions are executed centrally on behalf of all of our 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 net gains and losses could be recorded in our results of operations. Additionally, we may be required to collateralize any mark-to-market losses on outstanding commodity hedging contracts.

As of December 31, 2012, we had the following outstanding crude oil and refined product hedging instruments that were entered into as economic hedges. Settlement prices for our unleaded gasoline crack spread swaps range from $10.96 to $23.69 per contract. Settlement prices for our distillate crack spread swaps range from $25.36 to $27.96 per contract. 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
	2013	2014	2015
Inventory positions (futures and swaps):
Crude oil and refined products — net short positions	588	—	—
Refined product positions (crack spread swaps):
Distillate — net short positions	9,108	10,200	5,025
Unleaded gasoline — net short positions	2,125	225	—

17. Stock-Based Compensation

We have 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”) that allow for restricted share awards and restricted share unit awards. As of December 31, 2012, there were 14,311 and 3,182,567 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.

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As of December 31, 2012, there were 694,622 and 440,860 restricted shares and restricted share units not vested, respectively, outstanding.

We recorded stock compensation expense of $8.3 million for the year ended December 31, 2012, of which $0.3 million was included in direct operating expenses and $8.0 million in selling, general, and administrative expenses.

The excess tax benefit related to the restricted shares that vested during the year ended December 31, 2012 was $4.1 million using a statutory blended rate of 37.80%. The aggregate fair value at the grant date of the restricted shares that vested during the year ended December 31, 2012 was $5.4 million. The related aggregate intrinsic value of these restricted shares was $16.2 million at the vesting date.

The excess tax benefit related to the restricted share units that vested during the year ended December 31, 2012 was $0.3 million using a statutory blended rate of 37.80%. The aggregate fair value at the grant date of the restricted share units that vested during the year ended December 31, 2012 was $2.2 million. The related aggregate intrinsic value of these restricted share units was $3.1 million at the vesting date.

We 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 excess 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.

We 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.

As of December 31, 2012, the aggregate fair value at grant date of outstanding restricted shares and restricted share units was $4.1 million and $8.0 million, respectively. The aggregate intrinsic value of restricted shares and restricted share units was $19.6 million and $12.4 million, respectively. The unrecognized compensation cost of outstanding restricted shares and restricted share units was $1.2 million and $5.1 million, respectively. Unrecognized compensation cost for restricted shares and restricted share units will be recognized over a weighted average period of approximately 0.38 years and 1.95 years, respectively.

The following table summarizes our restricted share unit and restricted share activity for the three years ended December 31, 2012:

	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, 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
Awards granted	269,406		19.45		—		—
Awards vested	(142,483	)	15.78		(816,620	)	6.64
Awards forfeited	(2,980	)	16.78		—		—
Nonvested at December 31, 2012	440,860		18.24		694,622		5.93

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18. Stockholders’ Equity

On January 24, 2006, we completed an initial public offering of 18,750,000 shares of our common stock at an aggregate offering price of $318.8 million. We received approximately $297.2 million in net proceeds from the initial public offering.

On June 10, 2009, we issued an additional 20,000,000 shares of our 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, we issued and sold $215.5 million in Convertible Senior Notes and recorded additional paid-in capital of $36.3 million, net of deferred income taxes of $22.6 million and transaction costs of $2.0 million related to the equity portion of this convertible debt.

Prior to 2010, we repurchased 698,006 shares of our 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. We recorded these repurchases as treasury stock.

On July 18, 2012, our board of directors authorized a share repurchase program of up to $200 million. We may repurchase shares from time-to-time through open market transactions, block trades, privately negotiated transactions, accelerated share repurchase transactions, or otherwise subject to market conditions, as well as corporate, regulatory, and other considerations. Our board of directors authorized this share repurchase program through July 31, 2013, but may discontinue the program at its discretion at any time prior to that date. During 2012, we purchased 3,324,135 shares as part of our share repurchase program at a cost of $82.3 million.

Our ability to pay dividends to our shareholders is subject to certain restrictions in our Revolving 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 and compliance with an incurrence-based test subject to 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.

19. Earnings Per Share

We follow the provisions related to the accounting treatment of certain participating securities for the purpose of determining earnings per share. These provisions address share-based payment awards that have not vested and 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, we have granted shares of restricted stock to certain employees and outside directors. 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. Accordingly, we utilize the two-class method to determine our earnings per share.

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The computation of basic and diluted earnings (loss) per share under the two-class method is presented below:

	Year Ended December 31,
	2012			2011			2010
	(In thousands, except per share data)
Basic earnings (loss) per common share:
Allocation of earnings (losses):
Net income (loss)	$	398,885		$	132,667		$	(17,049	)
Distributed earnings	(240,715		)	—			—
Income allocated to participating securities	(1,645		)	(2,673		)	—
Distributed earnings allocated to participating securities	2,504			—			—
Undistributed income (loss) available to common shareholders	$	159,029		$	129,994		$	(17,049	)
Weighted average number of common shares outstanding (1)	89,270			88,981			88,204
Basic earnings (loss) per common share:
Distributed earnings per share	$	2.67		$	—		$	—
Undistributed earnings (loss) per share	1.75			1.46			(0.19		)
Basic earnings (loss) per common share	$	4.42		$	1.46		$	(0.19	)

(1) Excludes the weighted average number of common shares outstanding associated with participating securities of 938,413, 1,829,565, and 1,704,318 shares for the years ended December 31, 2012, 2011, and 2010, respectively.

	Year Ended December 31,
	2012		2011		2010
	(In thousands, except per share data)
Diluted earnings (loss) per common share:
Net income (loss)	$	398,885	$	132,667	$	(17,049	)
Tax effected interest related to convertible debt	15,726		14,787		—
Net income (loss) available to common stockholders, assuming dilution	$	414,611	$	147,454	$	(17,049	)
Weighted average number of diluted shares outstanding	111,822		109,792		88,204
Diluted earnings (loss) per common share	$	3.71	$	1.34	$	(0.19	)

The computation of the weighted average number of diluted shares outstanding is presented below:

	Year Ended December 31,
	2012	2011	2010 (1)
	(In thousands)
Weighted average number of common shares outstanding	89,270	88,981	88,204
Common equivalent shares from Convertible Senior Notes	22,057	19,949	—
Restricted shares	495	862	—
Weighted average number of diluted shares outstanding	111,822	109,792	88,204

(1) We have excluded 179,087 restricted shares and 19,949,076 common equivalent shares of Convertible Senior Notes from the weighted average number of diluted shares outstanding as the effect of including such shares would be antidilutive.

A shareholder's interest in our common stock could become diluted as a result of vestings of restricted shares and restricted share units and the conversion of our Convertible Senior Notes into actual shares of our common stock. In calculating our fully diluted earnings per common share, we consider the impact of restricted shares and restricted share units that have not vested and common equivalent shares related to our Convertible Senior Notes. We include restricted shares and restricted share units that have not vested in our diluted earnings calculation when the trading price of our common stock equals or exceeds the per

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share or per share unit grant price. Common equivalent shares from our Convertible Senior Notes are generally included in our diluted earnings calculation when net income exceeds certain thresholds above which the effect of the shares becomes dilutive. We calculate the volume of these shares by applying the current conversion rate of 102.3750 to each $1,000 of principal amount of Convertible Senior Notes. Prior to 2012, the conversion rate was 92.5926.

The table below summarizes our cash dividends declared and paid through December 31, 2012:

	2012
	Declaration Date	Record Date	Payment Date	Dividend per common share		Total Payment (in thousands)
First quarter	January 4	January 19	February 13	$	0.04	$	3,633
Second quarter	March 29	April 19	May 14	0.04		3,633
Third quarter	July 16	July 27	August 13	0.08		7,274
Fourth quarter	October 16	October 26	November 9	0.08		7,115
Fourth quarter - special dividend	November 6	November 19	December 7	1.00		87,624
Fourth quarter - special dividend	December 11	December 21	December 28	1.50		131,436
Total						$	240,715

On January 15, 2013, our board of directors approved a cash dividend for the first quarter of 2013 of $0.12 per share of common stock in an aggregate payment of $10.5 million that was paid on February 14, 2013.

20. Cash Flows

Cash Equivalents

Cash equivalents totaling $20.0 million consisting of short-term money market deposits were included in the Consolidated Balance Sheet as of December 31, 2012. There were no cash equivalents as of December 31, 2011 included in the Consolidated Balance Sheet.

Supplemental Cash Flow Information

Supplemental disclosures of cash flow information were as follows:

	Year Ended December 31,
	2012		2011		2010
	(In thousands)
Income taxes paid (refunded)	$	237,551	$	70,171	$	(49,827	)
Interest paid, excluding amounts capitalized	68,735		121,282		135,063

Non-cash investing and financing activities were as follows:

	Year Ended December 31,
	2012		2011		2010
	(In thousands)
Increase in debt from modification of long-term debt agreement	$	—	$	8,193	$	—
Reduction of long-term debt for original issue discount	—		3,250		—
Reduction of debt proceeds to pay accrued interest	—		1,250		—
Assets acquired through capital lease obligations and promissory note	7,064		4,391		—
Debt costs incurred for modification of long-term debt agreement	—		3,693		—

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21. Contingencies

Environmental Matters

Like other petroleum refiners, our 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. Many of these regulations are becoming increasingly stringent, and the cost of compliance can be expected to increase over time. Our 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, we receive communications from various federal, state, and local governmental authorities asserting violations 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 impact on our financial condition, results of operations, or cash flows.

El Paso Refinery

Prior spills, releases and discharges of petroleum or hazardous substances have impacted the groundwater and certain solid waste management units and other areas at and adjacent to the El Paso refinery. We are currently in the remediation process, in conjunction with Chevron U.S.A., Inc. (“Chevron”), for these areas pursuant to certain agreed administrative orders with the Texas Commission on Environmental Quality (the “TCEQ”; previously known as the Texas Natural Resources Conservation Commission). Pursuant to our purchase of the north side of the El Paso refinery from Chevron, Chevron retained responsibility to remediate its solid waste management units in accordance with its Resource Conservation Recovery Act (“RCRA”) permit, which Chevron has fulfilled. Chevron also retained control of and liability for certain groundwater remediation responsibilities that are ongoing.

In May 2000, we entered into an Agreed Order with the TCEQ for remediation of the south side of the El Paso refinery property. We purchased a non-cancelable Pollution and Legal Liability and Clean-Up Cost Cap Insurance policy that 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 $20.0 million. In addition, a subsidiary of Chevron is obligated under a settlement agreement to pay 60% of any Agreed Order environmental clean-up costs that exceed the $20.0 million policy coverage. Under the policy, environmental costs outside the scope of the Agreed Order are covered up to $20.0 million and require that we pay 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 (the “EPA”) filed notice with the federal district court in El Paso that we and the EPA 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 $41.3 million, including $15.2 million for the installation of a flare gas recovery system completed in 2007 and $26.0 million for nitrogen oxides (“NOx”) emission controls on heaters and boilers through December 2012. We estimate remaining expenditures of approximately $9.7 million for the NOx emission controls on heaters and boilers during 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 2004 and 2005, the El Paso refinery applied for and was issued a Texas Flexible Permit by the TCEQ, under which the refinery continues to operate. However, there is an ongoing dispute between the EPA and the Texas Attorney General as to the validity of the state-issued permits. Although we believe our Texas Flexible Permit was federally enforceable, we applied with the TCEQ for, and received in December 2012, a permit amendment obtaining a State Implementation Plan ("SIP"), approved state air quality permit to address concerns raised by the EPA about all flexible permits. No additional capital expenditures are required by the permit amendment.

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

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permits because the EPA has disapproved the TCEQ Flexible Permits program and that our El Paso refinery may have exceeded certain emission limitations under its permit. We dispute these claims and maintain that the El Paso refinery is properly operating, and has not exceeded emissions limitations, under the validly issued TCEQ permit. We intend to defend ourselves accordingly.

In November 2012, we proposed to TCEQ to pay a penalty of up to $0.2 million to settle unresolved air enforcement issued by TCEQ to our El Paso refinery between October 2004 and April 2008. Resolution is expected to involve entering an agreed administrative order with TCEQ and payment of a penalty. We do not expect the order to require any soil or groundwater remediation or clean-up. Based on current information, we do not believe the requirements of the order will have a material effect on our business, financial condition, or results of operation.

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 (the “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, we 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, we indefinitely suspended refining operations at the Bloomfield refinery. We currently operate the site, including certain remaining tanks and equipment, as a standalone products distribution terminal and crude storage facility for our Gallup refinery. An amendment to the 2009 NMED Amendment, which became effective June 25, 2012, reflects the indefinite suspension as of 2009.

Based on current information and the 2009 NMED Amendment as amended in June 2012 to reflect the indefinite suspension of refining operations at our Bloomfield facility and to delay NOx controls on heaters, boilers, and Fluid Catalytic Cracking Unit (the "FCCU") at our Gallup refinery, we estimated $50.0 million in total capital expenditures after January 2009. We expended $11.3 million through 2011 and $37.6 million during 2012. In early 2013 we spent an additional $1.0 million to complete the project. These capital expenditures are primarily 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 our Gallup refinery. We will incur additional capital expenditures to implement one or more FCCU off-set projects to be completed by the end of 2017. 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. We paid an additional penalty of $0.4 million in July 2012 associated with the June 2012 amendment. We do not expect implementation of the requirements in the 2009 NMED Amendment, as amended in June 2012, to 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 that we investigate the extent of such releases, perform interim remediation measures, and implement corrective measures. Prior to July 2007, with the approval of the NMED and the New Mexico Oil Conservation Division, we placed into operation certain remediation measures which remain operational. As of December 31, 2012, we have expended $3.2 million and have accrued the remaining estimated costs of $4.0 million for implementing the investigation, interim measures, and the reasonably known corrective actions 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. We reached a final settlement with the agencies in August 2009 and paid a penalty of $0.7 million in October 2009. Between September 2010 and July 2012, the EPA demanded and we have paid penalties totaling $0.2 million pursuant to the settlement. 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. We estimated capital expenditures of approximately $38.8 million to upgrade the wastewater treatment plant at the Gallup refinery pursuant to the requirements of the final settlement. We expended $20.8 million through 2011, $17.1 million during 2012 on the upgrade of the wastewater treatment plant, and expect to spend the remaining $0.9 million during 2013. The final settlement deadline was modified in September 2010 to establish May 31, 2012 as the deadline for completing startup of the upgraded plant. After negotiating an extension of this deadline with the EPA, we completed startup on August 12, 2012.

Gallup 2013 Risk Management Plan General Duty Settlement. In November 2012, the EPA approached us to settle one alleged violation of the Clean Air Act Risk Management Plan 112(r) General Duty clause at our Gallup refinery. We expect to

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settle in 2013 with the potential of adding four other alleged violations to the final settlement with a total penalty of $0.2 million. The settlement will not result in any soil or groundwater remediation or clean-up costs.

Yorktown Refinery

Yorktown 1991 and 2006 Orders. In August 2006, Giant agreed to the terms of the final administrative consent order pursuant to which Giant would implement a clean-up plan for the refinery. Following the acquisition of Giant, we completed the first phase of the soil clean-up plan and negotiated revisions with the EPA for the remainder of the soil clean-up plan. Through December 2011, we expended $32.9 million related to the EPA order.

In December 2011, our subsidiaries sold the Yorktown refinery, an adjacent 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 (the "CAMU"). We have completed construction of this phase of the CAMU and have incurred substantially all costs anticipated to complete this work. We and the purchaser agreed that the purchaser would replace Giant as the respondent under the EPA order. The replacement is pending the EPA's agreement.

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. Following the sale of the refinery 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. The purchaser has replaced Giant as the respondent under the Consent Decree.

Tax Matters

See Note 14, Income Taxes, to these consolidated financial statements for additional information on tax examinations.

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. Our subsidiary, Western Refining Yorktown, Inc., 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.

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 retail store property across the street, which is owned by our subsidiary. 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 (the “BIA”) acted improperly in approving certain rights-of-way on land allotted to the individual Plaintiffs (each, an "Allottee") by the Navajo Nation, Arizona, New Mexico, and Utah (the “Navajo Nation”). The lawsuit names us and numerous other defendants (“Rights-of-Way Defendants”) and seeks imposition of a constructive trust and asserts these Rights-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 that also dismissed Plaintiffs claims. Plaintiffs are now attempting to appeal this dismissal within the Department of Interior.

Regarding the claims asserted against us referenced above, potentially applicable factual and legal issues have not been resolved, we have yet to determine if a liability is probable. We do not believe the potential settlement of any of the asserted claims discussed above would have a material affect on our financial condition, results of operations, or cash flows; however we cannot reasonably estimate the range of any loss associated with these matters. Accordingly, we have not recorded a liability for these pending lawsuits.

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Union Matters

During 2011, we successfully negotiated a collective bargaining agreement covering employees at the Gallup refinery that expires in 2014. We 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, we may not be able to prevent a strike or work stoppage in the future, and any such work stoppage could have a material affect on our business, financial condition, and results of operations. The collective bargaining agreement covering the employees at our Bloomfield refinery who were terminated in connection with the indefinite suspension of refining operations at our Bloomfield facility during November 2009 expired in March of 2012.

During 2012, we recognized a union as the bargaining representative for finished product and lube drivers and warehouse employees at one of our Albuquerque, New Mexico facilities. Negotiations related to a collective bargaining agreement are on-going related to these covered employees.

Other Matters

In late 2011, the EPA initiated enforcement proceedings against companies it believes produced invalid fuel credits known as Renewable Identification Numbers ("RINs"). We purchased RINs to satisfy a portion of our obligations under the Renewable Fuels Standard program for calendar year 2010 and had purchased some RINs the EPA considered invalid. In April 2012, we entered into an administrative settlement with the EPA that required us to pay a penalty of less than $0.1 million. We continue to purchase RINs to satisfy our obligations under the RFS program, and we understand the EPA continues to investigate invalid RINs. While we do not know if the EPA will identify other RINs we have purchased as being invalid or what actions the EPA would take, at this time we do not expect any such action would have a material effect on our financial condition, results of operations, or cash flows.

We are party to various other claims and legal actions arising in the normal course of business. We believe that the resolution of these matters will not have a material effect on our financial condition, results of operations, or cash flows.

22. Concentration of Risk

Significant Customers

We sell a variety of refined products to a diverse customer base. No single customer accounted for more than 10% of consolidated net sales in any of the three years ended December 31, 2012.

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 7.5%, 6.2%, and 8.3% of consolidated sales during the years ended December 31, 2012, 2011, and 2010, respectively.

23. Leases and Other Commitments

We have commitments under various operating leases with initial terms greater than one year for buildings, warehouses, card locks, railcars, and other facilities. These leases have terms that will expire on various dates through 2036.

We expect that in the normal course of business, these leases will be renewed or replaced by other leases. Certain of our 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, we also have long-term commitments to purchase services, such as natural gas, electricity, water, and transportation services for use by our refineries at market-based rates. We are 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 we leased to DuPont within our El Paso refinery.

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Our subsidiary is a party to a ten-year lease agreement for an administrative office building in Scottsdale, Arizona that ends in 2013. During 2008, we 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, our subsidiary entered into a ten-year lease agreement for an office space in downtown El Paso. The building will serve as our headquarters. In December 2007, our subsidiary entered into an eleven-year lease agreement for an office building in Tempe, Arizona. The building centralized our operational and administrative offices in the Phoenix area.

We entered into one capital lease agreement for a retail store during the third quarter of 2011 and three retail capital leases during the second quarter of 2012. Each capital lease has an initial term of 20 years. The current portion of the capital lease obligation of $0.1 million is included in accrued liabilities and the non-current portion of $10.2 million is included in other liabilities in the accompanying Consolidated Balance Sheet as of December 31, 2012. These capital leases were discounted using an annual rate of 7.5%. Total remaining interest related to these leases was $8.6 million at December 31, 2012.

The following table presents our annual minimum rental payments under non-cancelable operating leases that have lease terms of one year or more (in thousands):

2013	$	23,981
2014	21,994
2015	19,987
2016	18,042
2017	16,174
2018 and thereafter	174,270
	$	274,448

Total rental expense was $25.5 million, $19.1 million, and $15.7 million for the years ended December 31, 2012, 2011, and 2010, respectively. Contingent rentals and subleases were not significant in any year.

24. Related Party Transactions

Effective November 30, 2012, an entity controlled by one of our officers purchased the building and related lease agreement of certain office space that we and other commercial tenants occupy in El Paso, Texas. The lease agreement expires in May 2017. Under the terms of the lease, we make annual payments of $0.2 million. For the year ended December 31, 2012, we made rental payments under this lease to the related party of $0.02 million. We have no amounts due as of December 31, 2012 related to this lease agreement.

25. Quarterly Financial Information (Unaudited)

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. During 2012, the volatility in crude oil prices and refining margins also contributed to the variability of our results of operations for the four calendar quarters.

During the third and fourth quarters of 2012, we increased our accruals for estimated property taxes by $8.7 million and $2.9 million, respectively, related to revised property tax appraisal rolls for 2012. We believe the appraised property values to be in error and have filed a lawsuit in state district court to appeal this appraised value.

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WESTERN REFINING, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

The quarterly financial data for the years ended December 31, 2012 and 2011 is presented below.

	Year Ended December 31, 2012
	Quarter
	First			Second			Third			Fourth
	(Unaudited) (In thousands, except for share data)
Net sales	$	2,339,212		$	2,469,348		$	2,446,317		$	2,248,257
Operating costs and expenses:
Cost of products sold (exclusive of depreciation and amortization)	2,236,502			1,899,684			2,207,424			1,710,775
Direct operating expenses (exclusive of depreciation and amortization)	115,581			116,792			127,884			122,813
Selling, general, and administrative expenses	25,781			27,316			26,986			34,545
(Gain) loss and impairments on disposal of assets, net	(1,891		)	—			—			—
Maintenance turnaround expense	450			1,862			31,065			13,763
Depreciation and amortization	22,764			22,767			23,577			24,799
Total operating costs and expenses	2,399,187			2,068,421			2,416,936			1,906,695
Operating income (loss)	(59,975		)	400,927			29,381			341,562
Other income (expense):
Interest income	193			202			165			136
Interest expense and other financing costs	(24,122		)	(21,808		)	(18,000		)	(17,419		)
Amortization of loan fees	(1,807		)	(1,771		)	(1,641		)	(1,641		)
Loss on extinguishment of debt	—			(7,654		)	—			—
Other income (expense), net	1,562			(279		)	(646		)	(278		)
Income (loss) before income taxes	(84,149		)	369,617			9,259			322,360
Provision for income taxes	30,645			(131,113		)	(2,961		)	(114,773		)
Net income (loss)	$	(53,504	)	$	238,504		$	6,298		$	207,587
Basic earnings (loss) per common share	$	(0.60	)	$	2.63		$	0.07		$	2.35
Diluted earnings (loss) per common share	$	(0.60	)	$	2.19		$	0.07		$	1.92

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WESTERN REFINING, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

	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		)
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	)

110

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 our “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, 2012 (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 63 of this report.

Attestation Report of the Registered Public Accounting Firm. Included herein under the caption "Report of Independent Registered Public Accounting Firm" on page 64 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, 2012, 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.”

111

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

Plan Category	(a) Number of securities to be issued upon exercise of outstanding options, warrants,and rights (1)	(b) Weighted average exercise price of outstanding options, warrants, and rights (2)	(c) Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)
Equity compensation plans approved by security holders	440,860	—	3,196,878
Equity compensation plans not approved by security holders	—	—	—
Total	440,860	—	3,196,878

(1) Represents 440,860 shares underlying restricted share unit awards.

(2) Restricted share unit awards do not have an exercise price.

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 2012 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 Definitive Proxy Statement under the heading “Proposal 2: Ratification of Independent Auditor.”

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PART IV

Item 15. Exhibits and Financial Statement Schedules

(a) Financial Statements:

See Index to Financial Statements included in Item 8.

(b) The following exhibits are filed herewith (or incorporated by reference herein):

Number	Exhibit Title
2.1	Agreement and Plan of Merger, dated August 26, 2006, by and among Western Refining, Inc., New Acquisition Corporation and Giant Industries, Inc. (incorporated by reference to Exhibit 2.1 to the 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 13, 2009).
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, 2009).

113

Number	Exhibit Title
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, 2009).
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, 2009).
10.6	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).
10.6.1	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).
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 June 3, 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).

114

Number	Exhibit Title
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†	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).
10.9	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).
10.10	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).
10.11†	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).
10.11.1†	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).
10.11.2†	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).
10.12†	Form of Restricted Stock Grant Agreement under the Western Refining Long-Term Incentive Plan (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).
10.13†	Form of Nonqualified Stock Option Agreement under the Western Refining Long-Term Incentive Plan (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).
10.14†	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).
10.15	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).
10.15.1	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).
10.16†	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).
10.16.1†	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 13, 2009).
10.17†	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).
10.18†	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).

115

Number	Exhibit Title
10.19†	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).
10.20†	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).
10.21†	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 10.33 to the Company’s Annual Report on Form 10-K, filed with the SEC on March 8, 2011).
10.22†*	Form of Western Refining, Inc. Restricted Share Unit Award Agreement between the Company and Non-Employee Director under the 2010 Incentive Plan of Western Refining, Inc.
10.23	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).
10.24	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).
10.25†	Western Refining, Inc. Non-Employee Director Deferred Compensation Plan.
10.26†	Western Refining, Inc. Non-Employee Director Deferred Compensation Plan Adoption Agreement, dated as of January 1, 2009.
12.1*	Statements of Computation of Ratio of Earnings to Fixed Charges.
21.1*	List of Subsidiaries of the Company.
23.1*	Consent of Deloitte & Touche LLP, dated February 28, 2013.
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.

Our 2012 Annual Report is available upon request. Stockholders may obtain a copy of any exhibits to this Form 10-K at a charge of $0.10 per page. Requests should be made to: Investor Relations, Western Refining, Inc., 123 W. Mills Ave., Suite 200, El Paso, Texas 79901.

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 28, 2013
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 28, 2013
Jeff A. Stevens	(Principal Executive Officer)
/s/  Gary R. Dalke	Chief Financial Officer	February 28, 2013
Gary R. Dalke	(Principal Financial Officer)
/s/  Paul L. Foster	Executive Chairman and Director	February 28, 2013
Paul L. Foster
/s/  Scott D. Weaver	Vice President and Director	February 28, 2013
Scott D. Weaver
/s/  William R. Jewell	Chief Accounting Officer	February 28, 2013
William R. Jewell	(Principal Accounting Officer)
/s/  Carin M. Barth	Director	February 28, 2013
Carin M. Barth
/s/  Sigmund L. Cornelius	Director	February 28, 2013
Sigmund L. Cornelius
/s/  L. Frederick Francis	Director	February 28, 2013
L. Frederick Francis
/s/  Brian J. Hogan	Director	February 28, 2013
Brian J. Hogan
/s/  William D. Sanders	Director	February 28, 2013
William D. Sanders
/s/  Ralph A. Schmidt	Director	February 28, 2013
Ralph A. Schmidt

117