10-K 1 wnr12311210k.htm 10-K WNR 12.31.12 10K
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
þ
 
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
 
For the Fiscal Year Ended December 31, 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

Item 1.
Item 1A.
Item 1B.
Item 2.
Item 3.
Item 4.
 
Item 5.
Item 6.
Item 7.
Item 7A.
Item 8.
Item 9.
Item 9A.
Item 9B.
 
Item 10.
Item 11.
Item 12.
Item 13.
Item 14.
 
Item 15.
 EX-10.25
 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;

1


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.


2


PART I
In this Annual Report on Form 10-K, all references to “Western Refining,” “the Company,” “Western,” “we,” “us,” and “our” refer to Western Refining, Inc. ("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.

7


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

13


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.

15


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.

16


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.

17


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.

18


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.

19



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.

20


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.

21


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.


22


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



23


 
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

28


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.

29


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

30


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.


32


 
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

33


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.

34


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.



35


 
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.

36


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.


37


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
)



38


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