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, 2014
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.  o

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 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, 2014 (the last business day of the registrant’s most recently completed second fiscal quarter) was $2,860,337,605.

As of February 27, 2015, there were 95,459,798 shares outstanding, par value $0.01, of the registrant’s common stock.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the definitive proxy statement relating to the registrant’s 2015 annual meeting of stockholders are incorporated by reference into Part III of this report.

WESTERN REFINING, INC. AND SUBSIDIARIES

INDEX

PART I
Item 1.	Business	3
Item 1A.	Risk Factors	13
Item 1B.	Unresolved Staff Comments	25
Item 2.	Properties	25
Item 3.	Legal Proceedings	25
Item 4.	Mine Safety Disclosures	25
PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	26
Item 6.	Selected Financial Data	29
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	32
Item 7A.	Quantitative and Qualitative Disclosure About Market Risk	57
Item 8.	Financial Statements and Supplementary Data	59
Item 9.	Changes In and Disagreements With Accountants on Accounting and Financial Disclosure	128
Item 9A.	Controls and Procedures	128
Item 9B.	Other Information	128
PART III
Item 10.	Directors, Executive Officers and Corporate Governance	128
Item 11.	Executive Compensation	128
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	129
Item 13.	Certain Relationships and Related Transactions and Director Independence	129
Item 14.	Principal Accountant Fees and Services	129
PART IV
Item 15.	Exhibits and Financial Statement Schedules	130
Signatures		135
EX-10.19.3
EX-12.1
EX-21.1
EX-23.1
EX-31.1
EX-31.2
EX-32.1
EX-32.2
EX-101

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 including the regulation of 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, volatility of crude oil prices, additions to pipeline capacity in the Permian Basin and at Cushing, Oklahoma, expected share repurchases and dividends, volatility in pricing of Renewable Identification Numbers ("RINs"), taxes, capital expenditures, liquidity and capital resources 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,” “forecast,” “intend,” “may,” “plan,” “position,” “potential,” “predict,” “project,” “strategy,” “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 or that are affected by unknown risks or uncertainties. Consequently, no forward-looking statements can be guaranteed. In addition, our business and operations involve numerous risks and uncertainties, many that 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.

When considering these forward-looking statements, you should keep in mind the risk factors and other cautionary statements in this Form 10-K. Actual events, results and outcomes may differ materially from our expectations due to a variety of factors. Although it is not possible to predict or identify all of these factors, they include, among others, the following:

• changes in crack spreads;

• changes in the spread between WTI crude oil and West Texas Sour 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;

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

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

• availability and costs of renewable fuels for blending and RINs to meet Renewable Fuel Standards ("RFS") obligations;

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

• changes in the underlying demand for our refined products;

• instability and volatility in the financial markets, including as a result of potential disruptions caused by economic uncertainties in Europe;

• a potential economic recession in the United States and/or abroad;

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

• changes in the availability and cost of capital;

• actions of customers and competitors;

• successful integration and future performance of acquired assets, businesses or third-party product supply and processing relationships;

• actions of third-party operators, processors and transporters;

1

• changes in fuel and utility costs incurred by our refineries;

• the effect of weather-related problems on our operations;

• disruptions due to equipment interruption, pipeline disruptions or failure at our or third-party facilities;

• execution of planned capital projects, cost overruns relating to those projects and failure to realize the expected benefits from those projects;

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

• rulings, judgments or settlements in litigation, 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;

• labor relations;

• 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 I. — 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 financial condition, results of operations or cash flows 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 the forward-looking statements we make in this report related to our plans, intentions and expectations 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 (and will not) 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 common stock trades on the New York Stock Exchange ("NYSE") under the symbol “WNR.” We own certain operating assets directly; the controlling general partner interest and a 38.4% limited partner interest in Northern Tier Energy LP (“NTI”) and the controlling general partner interest, Incentive Distribution Rights ("IDRs") and a 66.2% limited partner interest in Western Refining Logistics, LP (“WNRL”). NTI and WNRL common partnership units trade on the NYSE under the symbols "NTI" and "WNRL," respectively.

We produce refined products at three refineries: one in El Paso, Texas (131,000 barrels per day, or bpd), one near Gallup, New Mexico (25,000 bpd) and NTI's refinery in St. Paul Park, Minnesota (97,800 bpd). We sell refined products in Arizona, Colorado, the Mid-Atlantic region, New Mexico, the Upper Great Plains region ,West Texas and Mexico through bulk distribution terminals and wholesale marketing networks and we sell refined products through two retail networks with a total of 484 company-owned and franchised retail sites in the U.S.

On November 12, 2013, we acquired a 38.7% limited partner interest and 100% ownership of the general partner of NTI. NTI owns and operates a 97,800 bpd refinery in St. Paul Park, Minnesota. NTI has a retail-marketing network of 254 convenience stores. NTI directly operates 165 of these stores, including 2 owned and the remainder leased, and supports 89 stores through franchise agreements. NTI's primary areas of operation include Minnesota, South Dakota and Wisconsin.

During 2013, we formed WNRL as a Delaware master limited partnership to own, operate, develop and acquire terminals, storage tanks, pipelines and other logistics assets and related businesses. WNRL completed its initial public offering (the "Offering") on October 16, 2013. At December 31, 2014, we own a 66.2% limited partner interest in WNRL and the public held a 33.8% limited partner interest. We control WNRL through our 100% ownership of the general partner of WNRL and through control of the majority of outstanding common partnership units. WNRL provides logistical services to our refineries in the Southwest and operates several lubricant and bulk petroleum distribution plants and a fleet of crude oil and refined product delivery trucks. WNRL distributes commercial wholesale petroleum products primarily in Arizona, California, Colorado, Nevada, New Mexico and Texas.

On October 15, 2014, in connection with a Contribution, Conveyance and Assumption Agreement (the "Contribution Agreement") dated September 25, 2014, we sold all of the outstanding limited liability company interests of Western Refining Wholesale, LLC ("WRW") to WNRL. The sale of WRW to WNRL was a reorganization of entities under common control. The information contained herein for our WNRL accounting predecessor (the "WNRL Predecessor") and WNRL has been retrospectively adjusted, to include the historical results of the WRW assets acquired, for periods prior to the effective date of the transaction. Our financial information includes the historical results of the WNRL Predecessor, retrospectively adjusted due to the transaction, collectively defined as our "Predecessor," for periods prior to October 16, 2013, and the results of WNRL, beginning October 16, 2013, the date WNRL commenced operations, which have also been retrospectively adjusted. We refer to this transaction as the "Wholesale Acquisition."

3

The following simplified diagram depicts the three publicly traded reporting entities in our organizational structure as of December 31, 2014:

During the fourth quarter of 2014, we changed our reportable segments due to fourth quarter changes in our organization. Our operations are currently organized into four operating segments based on manufacturing and marketing criteria and the nature of our products and services, our production processes and our types of customers. The historical segment financial data was retrospectively adjusted for the periods presented. The four business segments are: refining, NTI, WNRL and retail.

• Refining. Our refining segment owns and operates two refineries in the Southwest that process crude oil and other feedstocks primarily into gasoline, diesel fuel, jet fuel and asphalt. We market refined products to a diverse customer base including wholesale distributors and retail chains. The refining segment also sells refined products in the Mid-Atlantic region and Mexico.

• NTI. NTI owns and operates refining and transportation assets and operates and supports retail convenience stores primarily in the Upper Great Plains region of the U.S.

• WNRL. WNRL owns and operates terminal, storage, transportation and provides related services primarily to our refining segment in the Southwest. The WNRL segment also includes wholesale assets consisting of a fleet of crude oil and refined product truck transports and wholesale petroleum product operations in the Southwest region. WNRL receives its product supply from the refining segment and third-party suppliers.

• Retail. Our retail segment operates retail convenience stores and unmanned commercial fleet fueling locations located in the Southwest. The retail convenience stores 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. We sell a variety of refined products to a diverse customer base. When aggregated for all of our operating segments, consolidated net sales to Kroger Company accounted for 11.4% for the year ended December 31, 2013 that are primarily attributable to WNRL. No single customer accounted for more than 10% of consolidated net sales for the years ended December 31, 2014 and 2012.

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"). We supply refined products to the El Paso area via WNRL and other logistics assets adjacent to the El Paso refinery and to other areas including Tucson, Phoenix, Albuquerque and Juarez, Mexico through third-party pipeline systems linked to our El Paso refinery. We supply refined products to the Four Corners region and throughout Northern New Mexico from WNRL operations in Albuquerque, Bloomfield and Gallup, New Mexico. As of October 15, 2014, our refining segment also includes the operations of our refined products marketing and distribution in the Mid-Atlantic region, and we have recast historical financial and operational data of the refining segment, for all periods presented, to reflect the inclusion of the Mid-Atlantic product distribution business that we historically reported within wholesale operations.

4

Prior to August 2012, our refined products sold 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. 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.

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 WNRL and our retail group directly to third-party 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,
	2014		2013		2012
Gasoline	36.5	%	42.3	%	44.3	%
Diesel fuel	25.1		35.0		34.3
Jet fuel	8.6		13.7		13.9
Asphalt	2.9		3.2		3.5
Crude oil and other (1)	26.9		5.8		4.0
Total sales percentage by type	100.0	%	100.0	%	100.0	%

(1) Crude oil sales for the years ended December 31, 2014 and 2013 were $1,489.6 million and $51.3 million, respectively. There were no comparable sales in 2012.

Customers. We sell a variety of refined products to our diverse customer base through the WNRL wholesale business. No single third-party customer of our refining group accounted for more than 10% of our consolidated net sales during the years ended December 31, 2014, 2013 and 2012.

Other than sales of gasoline and diesel fuel for export to Juarez and other cities in Northern Mexico, our refining sales were domestic sales in the United States. The sales for export were to PMI Trading Limited, an affiliate of Petroleos Mexicanos, the Mexican state-owned oil company and accounted for approximately 5.5%, 8.5% and 7.5% of our consolidated net sales during the years ended December 31, 2014, 2013 and 2012, 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 10%, 14% and 14% of our total sales volumes during the years ended December 31, 2014, 2013 and 2012, respectively. The decrease when comparing 2014 purchases to 2013 and 2012 levels was primarily the result of lower refined product sales activities in the Mid-Atlantic region where we satisfy our refined product customer sales requirements through third-party purchases.

Competition. The refining segment operates primarily in the U.S. Southwest region including Arizona, Colorado, New Mexico, Utah and West Texas. This region is supplied by substantial refining capacity from our refineries, from other regional refineries and from non-regional refineries via interstate pipelines.

Petroleum refining and marketing is highly competitive. Our southwest refineries primarily compete with Valero Energy Corporation, 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. 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 Mid-Atlantic region, we compete with wholesale petroleum products distributors such as Shell Oil Company, BP Oil, CITGO Petroleum Corporation, Valero Energy Corporation and Exxon Mobil Corporation.

Various refined product pipelines supply our refined product distribution areas. Any expansions or additional product supplied by these third-party pipelines could put downward pressure on refined product prices in these areas.

To the extent that climate change legislation passes to impose domestic greenhouse gas restrictions, domestic refiners will be at competitive disadvantage to offshore refineries not subject to the legislation.

5

El Paso Refinery

Our El Paso refinery has a crude oil throughput capacity of 131,000 bpd with access to logistics assets including approximately 4.3 million barrels of storage capacity, a refined product terminal and an asphalt plant and terminal. The 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 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% West Texas Sour ("WTS") 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 units on property we lease to DuPont within our El Paso refinery.

Power and Natural Gas Supply. A regional electric company supplies electricity to our El Paso refinery via two separate feeders to the refinery's north and south sides. There are several uninterruptible power supply units throughout the plant to maintain computers and controls in the event of a power outage. The refinery receives its natural gas supply 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. Our El Paso refinery receives crude oil from a 450 mile crude oil pipeline owned and operated by Kinder Morgan Energy Partners, LP ("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 that gives us access to a plentiful supply of WTI and WTS crude oil from fields with long reserve lives. In 2013, we completed construction of a crude oil gathering and storage system in the Delaware Basin portion of the Permian Basin area of West Texas (the "Delaware Basin"). This system connects to the Kinder Morgan pipeline to facilitate delivery of crude oil to El Paso. This system was among the logistics assets that we contributed to WNRL upon completion of its initial public offering. 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.

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)	2014	2013	2012	2014
Crude Oil:
Sweet crude oil	96,384	93,654	94,404	75.8	%
Sour crude oil	25,113	25,195	24,792	19.7	%
Total Crude Oil	121,497	118,849	119,196	95.5	%
Other Feedstocks and Blendstocks:
Intermediates and other	3,735	4,130	4,852	2.9	%
Blendstocks	2,004	2,358	2,882	1.6	%
Total Other Feedstocks and Blendstocks	5,739	6,488	7,734	4.5	%
Total Crude Oil and Other Feedstocks and Blendstocks	127,236	125,337	126,930	100.0	%

Refined Products Transportation. We supply refined products to the El Paso area via WNRL and logistics assets including the light product distribution terminal and other truck and rail racks located at the El Paso refinery and to other areas including Tucson, Phoenix, Albuquerque and Juarez, Mexico, through third-party pipeline systems linked to our El Paso refinery. We deliver gasoline and distillate products to Tucson and Phoenix through Kinder Morgan's East Line and to Albuquerque and Juarez, Mexico, through pipelines owned by Magellan Midstream Partners, LP ("Magellan").

Both Kinder Morgan’s East Line and Magellan's 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.

6

Gallup Refinery

Our Gallup refinery, located near Gallup, New Mexico, has a crude oil throughput capacity of 25,000 bpd and access to WNRL segment logistics assets including approximately 595,000 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. The Gallup refinery sources all of its crude oil supply from regionally produced Four Corners Sweet crude oil. 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 three years ended December 31, 2014.

Power and Natural Gas 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 we source primarily from Northern New Mexico, Colorado and Utah. We receive crude oil through a pipeline gathering system owned and operated by our WNRL segment and through a third-party pipeline connected to our Gallup refinery. WNRL segment's 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 299 mile section of the TexNew Mex 16" Pipeline that extends from our crude oil station in Star Lake, New Mexico in the Four Corners area to near Maljamar, New Mexico in the Delaware Basin. During 2014, we completed a project to reactivate and reverse the crude oil line flow.

We supplement the crude oil used at our Gallup refinery with other feedstocks that currently include locally produced natural gas liquids and condensate as well as other feedstocks produced outside of the Four Corners area. WNRL owns and operates a 14-mile pipeline that connects the Gallup refinery to Western's recently purchased Wingate facility that provides additional receiving capacity for natural gas liquids consumed at the Gallup refinery.

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)	2014	2013	2012	2014
Crude Oil:
Sweet crude oil	25,130	23,635	20,941	90.5	%
Total Crude Oil	25,130	23,635	20,941	90.5	%
Other Feedstocks and Blendstocks:
Intermediates and other	867	—	684	3.1	%
Blendstocks	1,786	1,457	1,254	6.4	%
Total Other Feedstocks and Blendstocks	2,653	1,457	1,938	9.5	%
Total Crude Oil and Other Feedstocks and Blendstocks	27,783	25,092	22,879	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 owned and operated by our WNRL segment. We supply these refined products to Arizona, Colorado, New Mexico and Utah, primarily via a fleet of refined product trucks operated by WNRL and common carriers.

NTI

St. Paul Park Refinery

NTI's St. Paul Park refinery located in Southeast St. Paul Park, Minnesota, has a crude oil throughput capacity of 97,800 bpd and has the ability to process a variety of light, heavy, sweet and sour crudes into higher value refined products. The St. Paul Park refinery competes directly with Koch Industries’ Flint Hills Resources Refinery in Pine Bend, Minnesota, as well as the other refiners in the region and, to a lesser extent, major U.S. and foreign refiners.

7

NTI's refinery is an integrated refining operation that includes storage and transportation assets. NTI's transportation assets include a 17% interest in the Minnesota Pipe Line Company ("MPL"), an eight-bay light product terminal adjacent to the refinery, a seven-bay heavy product loading rack located on the refinery property, rail facilities for shipping liquefied petroleum gas (“LPG”) and asphalt and receiving butane, isobutane and ethanol and a barge dock on the Mississippi River used primarily for shipping vacuum residue and slurry. As of December 31, 2014, NTI's storage assets had an operating capacity of approximately 3.8 million barrels; comprised of 0.8 million barrels of crude oil storage and 3.0 million barrels of feedstock and product storage.

Process Summary. The St. Paul Park refinery is a cracking facility that during the year ended December 31, 2014 processed 91,840 bpd of crude oil and 1,685 bpd of other feedstocks and blendstocks. The facility processes a mix of light sweet, synthetic and heavy sour crude oils, predominately from Canada and North Dakota, into products such as gasoline, diesel, jet fuel, asphalt, kerosene, propane, LPG, propylene and sulfur.

Power and Natural Gas Supply. A regional electric company supplies electricity on a firm basis to the St. Paul Park refinery via five separate feeders to the main refinery areas. Three other utility feeders supply power to the tank farms and barge facilities and the northern turnaround and construction infrastructure. There are several uninterruptible power supply units throughout the plant and one generator to maintain computers and controls in the event of a power outage.

The refinery receives its natural gas supply via pipeline. The supply agreements are on a firm and interruptible basis. NTI purchases natural gas at market rates or under fixed-price agreements.

Raw Material Supply. The following table summarizes the historical feedstocks used by the St. Paul Park refinery. The information presented includes the results of operations of the St. Paul Park refinery beginning November 12, 2013, the date we acquired control of NTI.

	Period Ended December 31,		Percentage For Year Ended December 31,
Refinery Feedstocks (bpd)	2014	2013	2014
Refinery Throughput Crude Oil Feedstocks by Location:
Canadian	34,184	37,045	36.6	%
Domestic	57,656	37,192	61.6	%
Total Crude Oil by Location	91,840	74,237	98.20	%
Crude Oil Feedstocks by Type:
Light and intermediate	73,999	56,310	79.1	%
Heavy	17,841	17,927	19.1	%
Total Crude Oil by Type	91,840	74,237	98.2	%
Other Feedstocks and Blendstocks (1):
Natural gasoline	38	—	—	%
Butanes	798	597	0.9	%
Gasoil	351	114	0.4	%
Other	498	516	0.5	%
Total Other Feedstocks and Blendstocks	1,685	1,227	1.8	%
Total Crude Oil and Other Feedstocks and Blendstocks	93,525	75,464	100.0	%

(1) Other Feedstocks and Blendstocks includes only feedstocks and blendstocks that are used at the refinery and does not include ethanol and biodiesel. Although NTI purchases ethanol and biodiesel to supplement the fuels produced at the St. Paul Park refinery, these are not included in the table as those items are blended at the terminal adjacent to the refinery or at terminals on the Magellan pipeline system.

Of the crude oils processed at the St. Paul Park refinery for the period ended December 31, 2014, approximately 37% was Canadian crude oil and the remainder was comprised of mostly light sweet crude oil from North Dakota.

In March 2012, NTI entered into an amended and restated crude oil supply and logistics agreement (the "Crude Intermediation Agreement") with J.P. Morgan Commodities Canada Corporation (“JPM CCC”), under which JPM CCC assisted NTI in the purchase of most of the crude oil requirements of NTI's refinery. Once NTI identified types of crude oil and pricing terms that met its requirements, NTI notified JPM CCC that then for a fee provided credit, transportation and other logistical services for delivery of the crude oil to storage tanks leased by JPM CCC from NTI for the duration of the crude oil supply and logistics agreement. Title to the crude oil passed from JPM CCC to NTI when the crude oil entered NTI's refinery

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from the storage tanks leased by JPM CCC. JPM CCC announced its intention to sell the physical portions of its commodities business (that included JPM CCC) to Mercuria Energy Group Ltd. during the fourth quarter of 2014. In advance of this sale, JPM CCC and NTI mutually agreed to terminate the Crude Intermediation Agreement. Going forward, NTI expects to use existing trade credit agreements with vendors, or letters of credit under a revolving credit facility, to fund the purchase of crude oil.

The Minnesota Pipeline system has a maximum capacity of approximately 455,000 bpd and is the primary supply route for crude oil to the St. Paul Park refinery. The Minnesota Pipeline extends from Clearbrook, Minnesota to the refinery and receives crude oil from Western Canada and North Dakota through connections with various Enbridge pipelines. NTI also purchases ethanol and biodiesel, as well as conventional petroleum based blendstocks, such as natural gasoline, to supplement the fuels produced at the refinery.

Refined Products Transportation. NTI owns various storage and transportation assets, including an eight-bay light products terminal located adjacent to the St. Paul Park refinery, a seven-bay heavy products terminal located on the St. Paul Park refinery's property, storage tanks, rail loading/unloading facilities and a Mississippi river dock. The primary fuel distribution for NTI is through its light products terminal. Approximately 59% of the gasoline and diesel volumes for the year ended December 31, 2014, were sold via NTI's light products terminal to NTI operated and franchised SuperAmerica branded convenience stores, Marathon Petroleum Company LP ("Marathon") branded convenience stores and other resellers. NTI has a contract with Marathon to supply substantially all of the gasoline and diesel requirements for the independently owned and operated Marathon branded convenience stores within the region that NTI supplies. NTI also has a crude oil transportation operation in North Dakota to allow them to purchase crude oil at the wellhead in the Bakken Shale while limiting the impact of rising trucking costs for crude oil in North Dakota.

Light refined products that include gasoline and distillates, are distributed from the St. Paul Park refinery through a pipeline and terminal system owned by Magellan that has facilities throughout the Upper Great Plains. Asphalt and heavy fuel oil are transported from the refinery via truck from NTI's seven-bay heavy products terminal and via rail and barge through its rail facilities and Mississippi River barge dock and are sold to a broad customer base.

NTI's location allows them to distribute refined products throughout the Upper Great Plains of the United States. The St. Paul Park refinery produces refined products including gasoline, diesel, jet fuel and asphalt that are marketed to resellers and consumers primarily in the Petroleum Administration for Defense District ("PADD") II region. NTI sold the majority of its refinery's 2014 gasoline and diesel sales volumes in Minnesota and Wisconsin with the remainder sold primarily in Iowa, Nebraska, Oklahoma and South and North Dakota. The NTI refinery supplied a majority of the gasoline and diesel sold in the NTI operated or franchised convenience stores for the year ended December 31, 2014, as well as supplied the independently owned and operated Marathon branded stores in its marketing area.

NTI owns 17% of the outstanding common interests of MPL and a 17% interest in MPL Investments, Inc. that owns 100% of the preferred interests of MPL. MPL owns the Minnesota Pipeline, a crude oil pipeline system in Minnesota that transports crude oil to the St. Paul area and supplies NTI's crude oil input.

SuperAmerica Retail

NTI has a retail-marketing network of 258 convenience stores, as of February 27, 2015, located throughout Minnesota, Wisconsin and South Dakota. NTI operates 165 stores of which 2 are owned and the remainder leased, and supports 93 franchised stores. NTI brands all of its company-operated and franchised convenience stores as SuperAmerica. NTI also owns and operates SuperMom’s Bakery that prepares and distributes baked goods and other prepared items for sale in NTI's retail outlets and for other third parties. Substantially all of the fuel gallons sold at NTI's company owned convenience stores for the period ended December 31, 2014, was supplied by its refinery.

NTI's major retail competitors include Holiday, Kwik Trip, Marathon, Freedom Valu Centers, BP, Costco and Sam's Club. The main competitive factors affecting NTI's retail-marketing network are the location of the stores, brand identification and product price and quality.

WNRL

WNRL owns and operates terminal, storage, transportation and wholesale assets and provides related services primarily to our refineries in the Southwest. WNRL is a fee-based, Delaware master limited partnership that Western formed during 2013 to own, operate, develop and acquire logistics and related assets and businesses to include terminals, storage tanks, pipelines and other logistics assets related to the terminalling, transportation, storage and distribution of crude oil and refined products. As of December 31, 2014, Western's ownership of WNRL consisted of a 100% interest in WNRL's general partner and a 66.2% interest in a limited partnership that Western controls through the general partner.

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Concurrent with the closing of its initial public offering on October 16, 2013, WNRL entered into commercial and service agreements with Western under which it operates assets contributed by Western (the "Contributed Assets") for the purpose of generating fee-based revenues.

On October 15, 2014, Western sold all of the outstanding limited liability company interests of WRW to WNRL, in exchange for $320 million and 1,160,092 WNRL common partnership units in connection with the Contribution Agreement. WNRL entered into commercial and service agreements with Western under which it operates the assets acquired in the Wholesale Acquisition for the purpose of transporting and reselling refined products purchased from Western and transporting crude oil for Western.

Pipeline and Gathering Assets. WNRL's pipeline and gathering assets consist of approximately 300 miles of crude oil pipelines and gathering systems that serve as the primary source of crude oil for our Gallup refinery and provide access to shale crude oil production in the Delaware Basin and southern New Mexico for shipment to our El Paso refinery through the Kinder Morgan crude oil pipeline. These pipeline systems connect at various points to an aggregate of approximately 620,000 barrels of active crude oil storage located primarily in the Delaware Basin and in the Four Corners area.

Terminalling, Transportation, Asphalt and Storage Assets. WNRL's terminalling, transportation and storage infrastructure consist of on-site refined product distribution terminals at the El Paso and Gallup refineries and stand-alone refined products terminals located in Bloomfield and Albuquerque, New Mexico. The Bloomfield product distribution terminal is permitted to operate at 19,000 bpd with a total storage capacity of approximately 734,550 barrels and a truck loading rack with four loading spots. Western maintains a long-term third-party exchange agreement to supply product through a pipeline connection to the Bloomfield product distribution terminal. WNRL provides additional product deliveries to Bloomfield from its truck fleet. The Albuquerque product distribution terminal is permitted to operate at 27,500 bpd with a refined product storage capacity of approximately 170,000 barrels 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. These assets include approximately 6.9 million barrels of active shell storage capacity. These assets primarily receive, store and distribute crude oil, feedstock and refined products for Western’s Southwest refineries. WNRL also provides fee-based asphalt terminalling and processing services at an asphalt plant and terminal in El Paso and asphalt terminalling services at three stand-alone asphalt terminals in Albuquerque, Phoenix and Tucson that have a combined storage capacity of 473,000 barrels.

Wholesale Assets. WNRL's wholesale assets include several lubricant and bulk petroleum distribution plants and a fleet of crude oil and refined product trucks and lubricant delivery trucks. WNRL distributes wholesale petroleum products primarily in Arizona, California, Colorado, Nevada, New Mexico and Texas. WNRL purchases petroleum fuels and lubricants primarily from the refining segment and from third-party suppliers.

WNRL's principal wholesale customers are retail fuel distributors, our retail segment and the mining, construction, utility, manufacturing, transportation, aviation and agricultural industries. Of the wholesale segment's net sales revenues, 26.0% and 23.9%, were to our retail segment and to Kroger Company, respectively, for the year ended December 31, 2014. WNRL competes with other wholesale petroleum products distributors in the Southwest such as Pro Petroleum, Inc.; Southern Counties Fuels; Synergy Petroleum, LLC; SoCo Group, Inc.; C&R Distributing, Inc.; and Brewer Petroleum Services, Inc.

Retail Segment

Our retail group operates retail stores that sell various grades of gasoline, diesel fuel and convenience store merchandise to the general public. Retail also operates unmanned commercial fueling locations ("cardlocks") that sell various grades of gasoline and diesel fuel to contract customers' vehicle fleets. At February 27, 2015, our retail group operated 261 retail stores located in Arizona, Colorado, New Mexico and Texas and 50 cardlocks located in Arizona, California, Colorado, New Mexico and Texas. We supply the majority of our retail gasoline and diesel fuel inventories through WNRL 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, Maverik, Murphy Oil, Quik-Trip, Shay Oil, Valero Energy Corporation and 7-2-11 food stores. Large chains of retailers like Costco Wholesale Corp., Wal-Mart Stores, Inc., Kroger Company and other 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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Our retail stores operate 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 Company, Conoco, 76, Shell Oil Company, Chevron, Mobil and Texaco.

The following table summarizes the ownership and location of Western's retail stores as of February 27, 2015:

Retail Store locations	Owned	Leased	Total
Arizona	27	77	104
Colorado	10	2	12
New Mexico	74	43	117
Texas	—	28	28
	111	150	261

The following table summarizes the ownership and location of Western's cardlocks as of February 27, 2015:

Cardlock locations	Owned	Leased	Private Sites (1)	Total
Arizona	11	10	12	33
California	1	—	—	1
Colorado	1	—	—	1
New Mexico	—	2	3	5
Texas	—	10	—	10
	13	22	15	50

(1) The private site designation for cardlocks represents tanks and equipment that we own and operate on customer sites for the exclusive use of the customer.

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 23, 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 U.S. Environmental Protection Agency ("EPA") finalized Tier III regulations for gasoline sulfur content in 2014. The regulations have lowered gasoline sulfur content to 10 parts per million ("ppm") with an effective date of 2017 for our El Paso refinery and 2020 for our Gallup refinery. Meeting these regulations will require capital spending and adjustments to the operations of our refineries.

The EPA has issued Renewable Fuels Standards ("RFS") under the Energy Acts of 2005 and 2007, implementing mandates to blend increasing volumes of renewable fuels into the petroleum fuels produced at obligated refineries through the year 2022. Annually, the EPA establishes the volume of renewable fuels that our El Paso and Gallup refineries must blend into their refined petroleum fuels. Obligated refineries demonstrate compliance with the RFS through the accumulation of Renewable Identification Numbers ("RINs"), which are unique serial numbers acquired through blending renewable fuels or

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direct purchase. Our compliance strategy includes blending at our refineries, transferring RINs from blending across our refinery and terminal system and purchasing third-party RINs.

Minnesota law currently requires the use of biofuels in gasoline and diesel sold in the state for combustion in internal combustion engines. Fuels produced at the St. Paul Park refinery are currently blended with the appropriate amounts of ethanol or biodiesel to ensure that they comply with applicable federal and state renewable fuel standards. Blending renewable fuels into the finished petroleum fuels to comply with these requirements will displace an increasing volume of a refinery’s product pool.

NTI is also subject to other fuel quality requirements under federal and state law, including federal standards governing the maximum sulfur content of gasoline and diesel fuel manufactured at the St. Paul Park refinery. If NTI fails to comply with any of these fuel quality requirements, it could be subject to fines, penalties and corrective action orders. Moreover, fuel quality standards could change in the future requiring them to incur significant costs to ensure that the fuels they produce continue to comply with all applicable requirements. NTI may at some point in the future be required to make significant capital expenditures and/or incur materially increased operating costs to comply with the new standards.

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 December 31, 2014, our companies employed approximately 5,700 people including 2,950 NTI employees and approximately 550 WNRL employees in its wholesale segment. The collective bargaining agreements covering the El Paso and Gallup refinery employees expire in April 2015 and May 2020, respectively. 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 effect on our business, financial condition and results of operations. The collective bargaining agreements covering the NTI employees associated with its refining and retail operations expire in December 2016 and August 2017, respectively. Through our control of WNRL's general partner and its affiliate entities, we have seconded approximately 300 employees to WNRL as well as other employees who may provide services to WNRL from time to time.

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

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On July 5, 2014, 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 Sections 302 and 906 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 recent years, the prices of crude oil, other feedstocks and refined products have fluctuated substantially. The NYMEX WTI postings of crude oil for 2014 ranged between a $59.29 to $105.15 per barrel. In addition, the WTI/Brent discount has been volatile and we expect continued volatility in crude oil pricing and crack spreads. It is possible that this volatility in crude oil pricing and crack spreads may continue for prolonged periods of time due to numerous factors beyond our control. Prolonged periods of low crude oil prices could impact production growth of inland crude oil, which could reduce the amount of cost advantaged crude oil available and/or the discount of such crude oil and thereby impacting the profitability of our refineries. 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 and political conditions;

• domestic and foreign 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 Russia 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. that can be impacted by accidents, interruptions in transportation, inclement weather or other events affecting producers and suppliers;

• U.S. government regulations, including legislation affecting the exportation of domestic crude oil;

• 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;

• commodities speculation;

• 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, Kinder Morgan’s East Line, the Aranco pipeline and the Magellan pipeline system, all 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; 

• federal and state government regulations and taxes; 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.

The nature of our business requires us to maintain substantial quantities of crude oil and refined product inventories. Crude oil and refined products are commodities. As a result, we have no control over the changing market value of these inventories. Because our inventory of crude oil and refined product is valued at the lower of cost or market value under the “last-in, first-out” ("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

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an increase in cost of products sold of $1.1 million and $3.2 million for the years ended December 31, 2014 and 2013, respectively, and a decrease in cost of products sold of $4.0 million for the year ended December 31, 2012.

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

If the price of crude oil increases significantly or our credit profile changes, or if we or our subsidiaries are unable to access our respective credit agreements 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 and certain of our subsidiaries rely on borrowings and letters of credit under each of our respective credit agreements 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 subsidiaries’ inability to access their credit agreements or other similar arrangements may have a material effect on our liquidity and our ability to make payments to our suppliers that 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 the credit agreements 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 business, financial condition, results of operations 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 also require us to furnish cash collateral, letters of credit or other forms of performance assurance. Mark-to-market calculations that result in settlement obligations by us to the counterparties could impact our liquidity and capital resources.

Compliance with and changes in tax laws could adversely affect our performance.

We are subject to tax liabilities, including federal, state and transactional taxes such as excise, sales/use, payroll, franchise, withholding and ad valorem taxes. New tax laws and regulations and changes in existing tax laws and regulations are continuously being enacted or proposed that could result in increased expenditures for tax liabilities in the future. Certain of these liabilities are subject to periodic audits by the respective taxing authority that could increase our tax liabilities. Subsequent changes to our tax liabilities as a result of these audits may also subject us to interest and penalties.

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

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 and our subsidiaries will be able to borrow funds under certain credit agreements in amounts sufficient to enable us and our subsidiaries 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 and our subsidiaries may be unable to comply with the financial covenants set forth in our and their respective credit facilities. If we or our subsidiaries fail to satisfy these covenants, we and our subsidiaries could be prohibited from borrowing for our working capital needs and issuing letters of credit that would hinder our ability to purchase sufficient quantities of crude oil to operate our refineries at planned rates. To the extent that we

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and our subsidiaries are unable to generate sufficient cash flows from operations, or if we and our subsidiaries are unable to borrow or issue letters of credit under certain credit agreements, we and our subsidiaries 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, 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 credit agreements and our indentures. See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations; Liquidity and Capital Resources; Working Capital and Indebtedness.

Covenants and events of default in our and our subsidiaries’ debt instruments could limit our ability to undertake certain types of transactions and adversely affect our liquidity.

Our and our subsidiaries’ credit agreements and indentures contain covenants and events of default that may limit our financial flexibility and ability to undertake certain types of transactions. For instance, we and our subsidiaries 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.

Debt instruments of our and our subsidiaries are subject to financial covenants. Our ability and that of our subsidiaries to comply with these covenants will depend on factors outside our control, including refined product margins. We cannot assure you that we and our subsidiaries will satisfy these covenants. If we fail to satisfy the covenants set forth in these facilities or an event of default occurs under the applicable facility, the maturity of the debt instruments could be accelerated or we could be prohibited from borrowing for our working capital needs and issuing letters of credit. A similar result could occur if our subsidiaries fail to satisfy the covenants applicable to them in their respective debt instruments. If our and our subsidiaries' obligations under the debt instruments 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 or our subsidiaries cannot borrow or issue letters of credit under our respective credit agreements, 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. Equipment, even if properly maintained, may require significant capital expenditures and expenses to keep it operating at optimum efficiency. 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 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

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associated with new equipment, redesigned older equipment or repaired equipment could lead to lower revenues or higher costs or otherwise have a material adverse effect on our business, financial condition, results of operations and cash flows.

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. Failure to identify and manage these risks could result in explosions, fires, refinery or pipeline releases of crude oil or refined products or other incidents resulting in personal injury, loss of life, environmental damage, property damage, legal liability, loss of revenue and substantial fines by government authorities. 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 Du Pont 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, we may experience unplanned downtime at our El Paso or Gallup refineries due to weather, interruptions to our electrical supply or other causes. In any of these situations, undamaged refinery processing units may be dependent on or interact with damaged process units and, accordingly, may also be 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, our Gallup refinery in New Mexico and the St. Paul Park refinery in Minnesota. 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 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 that are subject to such severe weather risks. Crude oil supplies for the St. Paul Park refinery are from the Bakken Shale of North Dakota and from Western Canada. As a result, the St. Paul Park refinery may be disproportionately exposed to the impact of delays or interruptions of supply from that region caused by natural disasters or adverse weather conditions. An interruption to our supply of feedstocks for the El Paso or the St. Paul Park refineries could have a material adverse effect on our business, financial condition, results of operations and cash flows.

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, convenience stores 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

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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 and increased vehicle fuel economy, 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 may incur in the future, substantial costs to comply with the EPA’s low sulfur and low benzene rules. Our strategy for complying with low sulfur gasoline and low benzene 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 regulations, in part, require refiners to add annually increasing amounts of renewable fuels to their petroleum products or purchase credits, known as RINs. Annually, the EPA establishes a volume of renewable fuels that obligated refineries must blend into their refined petroleum fuels. In the RFS, the obligated volume increases over time until 2022. Blending renewable fuels into refined petroleum fuels may displace an increasing volume of a refinery’s product pool. Our El Paso and Gallup refineries and the St. Paul Park refinery are subject to the RFS. We currently purchase RINS for some fuel categories on the open market, as well as waiver credits for cellulosic biofuels from the EPA, in order to comply with the RFS. Recently, due in part to the nation’s gasoline supply approaching the “blend wall” (the 10% ethanol limit prescribed by most automobile warranties), the price of RINs has been extremely volatile with the price dramatically increasing in recognition of the decrease in RINs availability. While we cannot predict the future prices of RINs, the costs to obtain the necessary number of RINs could be material. If we are unable to pass the costs of compliance with the RFS onto our customers, if sufficient RINs are unavailable for purchase or we have to pay a significantly higher price for RINs, or if we are otherwise unable to meet the RFS mandates, our business, financial condition, results of operations and cash flows could be materially adversely affected.

Certain states have renewable fuel mandates that further displace volume of a refinery's product pool. Minnesota law currently requires that all diesel sold in the state for combustion in internal combustion engines, with limited exceptions, must contain at least 5% biodiesel. Under the statute, the minimum biodiesel percentage will increase to 10% between April 1 and September 30 of every year beginning as of July 1, 2014. Pending certification by state agencies that certain statutory preconditions are satisfied, the minimum will increase to 20% between April 1 and September 30 of every year beginning as of

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May 1, 2018. Minnesota law also currently requires, with limited exceptions, that all gasoline sold or offered for sale in the state must contain the maximum amount of ethanol allowed under federal law for use in all gasoline powered motor vehicles. Federal law currently allows a maximum of 15% ethanol for cars and light trucks manufactured since 2001, and 10% ethanol for all other vehicles.

The EPA required that fuel and fuel additive manufacturers take certain steps before introducing gasoline containing 15% ethanol (“E15”) into the market, including developing and obtaining EPA approval of a plan to minimize the potential for E15 to be used in vehicles and engines not covered by the partial waiver. The EPA has taken several recent actions to authorize the introduction of E15 into the market, including approving, on June 15, 2012, the first plans to minimize the potential for E15 to be used in vehicles and engines not covered by the partial waiver. Existing laws and regulations could change, and the minimum volumes of renewable fuels that must be blended with refined petroleum fuels may increase. Increasing the volume of renewable fuels that must be blended into its products displaces an increasing volume of its refinery’s product pool, potentially resulting in lower earnings.

Various states have proposed and/or enacted low carbon fuel standards (“LCFS”) intended to reduce carbon intensity in transportation fuels.  In addition, in 2010 the EPA issued social cost of carbon (“SCC”) estimates used by the EPA and other federal agencies in regulatory cost-benefit analyses to take into account alleged broad economic consequences associated with emissions of GHGs. These estimates were increased in 2013.  While the impacts of LCFS and higher SCC in future regulations is not known at this time, either of these may result in increased costs to our operations.

We could incur significant costs to comply with greenhouse gas emissions regulation or legislation.

The EPA has 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, in certain circumstances, 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. In addition, Minnesota is a participant in the Midwest Greenhouse Gas Reduction Accord, a non-binding resolution that could lead to the creation of a regional GHG cap-and-trade program if the Minnesota legislature and the legislatures of other participating states enact implementing legislation. To the extent these EPA and other rules and regulations are enacted, our operating costs, including capital expenditures, may increase and additional operating restrictions could be imposed on our business, which could have a material adverse effect on our business, financial condition, results of operations and cash flows. Finally, some scientists have concluded that increasing concentrations of greenhouse gases in the earth’s atmosphere may produce climate changes that may have significant physical effects, such as increased frequency and severity of storms, droughts, floods and other climatic events, which if any such event were to occur, it may have a material adverse effect on our business.

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

The domestic economy, economic slowdowns and the scarcity of credit can lead to lack of consumer confidence, increased market volatility and widespread reduction of business activity generally in the United States and abroad. An economic downturn may adversely affect the liquidity, businesses and/or financial conditions of our customers that has resulted, and may result, not only in decreased demand for our products, but also increased delinquencies in our accounts receivable. Disruptions in the financial markets could also lead to a reduction in available trade credit due to counterparties’ liquidity concerns. If we or our subsidiaries are unable to obtain borrowings or letters of credit under our debt instruments, 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 is our largest refinery and is dependent on a pipeline owned by 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.

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. Certain rights-of-way necessary for our crude oil pipeline system to deliver crude oil to our Gallup refinery must be renewed periodically.

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NTI’s St. Paul Park refinery receives all of its crude oil and delivers a portion of its refined products through pipelines. NTI distributes a portion of its transportation fuels through pipelines owned and operated by Magellan, including the Aranco Pipeline that Magellan leases from NTI. In addition, NTI is dependent on the Minnesota Pipeline system that is the supply route for crude oil and has transported all of the crude oil used at the refinery. Because NTI only has a minority equity interest in the pipeline, it does not have significant influence over or control of the performance of the pipeline.

Certain of the pipelines we utilize are subject to common carrier regulatory obligations applicable to interstate oil pipelines that require that capacity must be prorated among shippers in an equitable manner in accordance with the tariff then in effect in the event there are nominations in excess of capacity. Nominations by new shippers or increased nominations by existing shippers may reduce the capacity available to us. Any extended, non-excused downtime at our refineries could, under certain circumstances, cause us to lose line space on the refined products pipelines used by such refinery, if we cannot otherwise utilize our pipeline allocations.

As a result, 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, blended stocks or refined products is disrupted because of accidents, weather interruption, 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.

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, availability of equipment, facilities, personnel or services, plant closures for scheduled maintenance, or transportation problems, 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.

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. 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, health and safety and/or our and our subsidiaries’ permits and licenses relating to the sale of alcohol and tobacco products. 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, marketing and retail industries 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.

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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 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.

Newer or upgraded refineries will often be more efficient than some of our refineries that may put us at a competitive disadvantage. While we have taken measures to maintain and upgrade units in our refineries by installing new equipment and repairing equipment to improve our operations, these actions involve significant uncertainties, since upgraded equipment may not perform at expected throughput levels, the yield and product quality of new equipment may differ from design specifications and modifications may be needed to correct equipment that does not perform as expected. 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 an adverse effect on our business, financial condition, results of operations and cash flows. Over time, our refineries may become obsolete or be unable to compete because of the construction of new, more efficient facilities by our competitors.

Our retail operations compete with numerous convenience stores, gasoline service stations, supermarket chains, drug stores, fast food operations and other retail outlets. Increasingly, national high-volume grocery and dry-goods retailers are entering the gasoline retailing business. Because of their diversity, integration of operations and greater resources, these companies may be better able to withstand volatile market conditions or levels of low or no profitability. Additionally, our convenience stores could lose market share, relating to both gasoline and merchandise, to these and other retailers that could adversely affect our business, results of operations and cash flows. Our convenience stores compete in large part based on their ability to offer convenience to customers. Consequently, changes in traffic patterns, the type and number and location of competing stores and promotional pricing or discounts by our competitors could result in the loss of customers and reduced sales and profitability at affected stores.

If we and our subsidiaries are unable to make and integrate acquisitions or complete or manage divestitures on economically acceptable terms, our future growth would be limited, and any acquisitions we and our subsidiaries may make may cause our actual growth or results of operations to differ adversely compared with our expectations.

A portion of our strategy to grow our business is dependent on our ability to make selective acquisitions. We actively seek to acquire assets such as refineries, pipelines, terminals and retail fuel and convenience stores that complement our existing assets and/or broaden our geographic presence. For example, in November 2013, we completed the NTI acquisition that now consists of the 97,800 bpd St. Paul Park refinery, 165 convenience stores and 89 franchised convenience stores. In addition, during 2013 we formed WNRL to develop and acquire terminals, storage tanks, pipelines and other logistics assets. WNRL’s acquisition strategy is based, in large part, on its expectation of ongoing divestitures of gathering, transportation and storage assets by industry participants, including Western. Any acquisition involves potential risks, including, among other things:

• we may not be able to identify attractive acquisition candidates or negotiate acceptable purchase contracts or we are outbid by competitors;

• during the acquisition process, we may fail to or be unable to discover some of the liabilities of companies or businesses that we acquire;

• we may not be able to obtain financing for these acquisitions on economically acceptable terms;

• we may have mistaken assumptions about the overall costs of equity or debt;

• as a public company, we are subject to reporting obligations, internal controls and other accounting requirements with respect to any business we acquire, which may prevent or negatively affect the valuation of some acquisitions we might otherwise deem favorable or increase our acquisition costs;

• we may have mistaken assumptions about revenues and costs, including synergies;

• we may fail to successfully integrate or manage acquired businesses or assets;

• any acquisition may cause the diversion of management’s attention from other business concerns;

• any acquisition may involve unforeseen difficulties operating in new product areas or new geographic areas; and

• we may have customer or key employee losses at the acquired businesses.

We and our subsidiaries may also not be able to complete any divestitures on acceptable terms to us or at all. Further, as divestitures may reduce our and our subsidiaries’ direct control over certain aspects of our business, any failure to maintain good relations with divested businesses may adversely impact our results of operations or performance.

There can be no assurance that any acquisition, including our NTI acquisition in 2013 or any future or pending acquisition, will be successfully integrated into our operations. Furthermore, our capitalization and results of operations may change significantly as a result of any such acquisitions. The occurrence of any of these factors could adversely affect our growth strategy and cause our actual growth or results of operations to differ adversely compared with our expectations.

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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 various liability claims regarding damages caused by our products. Any liability claims 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 27, 2015, we employed approximately 5,700 people, with collective bargaining agreements covering about 430 of those employees. As of December 31, 2014, NTI employed 2,950 people, including 486 employees associated with its refining operations and 2,326 employees associated with its retail operations. NTI is party to collective bargaining agreements covering approximately 190 of the 486 employees associated with its refining operations and 22 of 2,399 associated with its retail operations. WNRL employs approximately 550 employees in its wholesale segment. During 2011, we successfully renegotiated a collective bargaining agreement covering employees at our Gallup refinery that expires in 2020. We also successfully negotiated a new collective bargaining agreement covering employees at our El Paso refinery, renewing the collective bargaining agreement to expire in April of 2015. We also have collective bargaining agreement that expires in December 2016 associated with the operations of the St. Paul Park refining operations and another collective bargaining agreement associated with NTI’s retail operations that expires in August 2017. While our El Paso and Gallup collective bargaining agreements and the NTI 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 cause disruptions in our business and 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. In addition, unseasonably cool weather in summer months and/or unseasonably warm weather in winter months in the regions where we sell our refined products can impact the demand for gasoline and diesel.

Seasonal fluctuations in traffic also affect sales of motor fuels and merchandise in our retail fuel and convenience stores. As a result, the operating results of our retail business are generally lower for the first quarter of the year. Weather conditions in

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our operating area also have a significant effect on our retail operating results. Customers are more likely to purchase higher profit margin items at our retail fuel and convenience stores, such as fast foods, fountain drinks and other beverages and more gasoline during the spring and summer months, thereby typically generating higher revenues and gross margins for us in these periods. Unfavorable weather conditions during these months and a resulting lack of the expected seasonal upswings in traffic and sales could have a material adverse effect on our business, financial condition, results of operations and cash flows.

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.

WNRL and NTI are dependent upon the earnings and cash flow generated by their respective operations in order to meet their debt service obligations and to allow each of them to make cash distributions to us. The operating and financial restrictions and covenants in their respective debt instruments and any future financing agreements could restrict each of their, and our, ability to finance future operations or capital needs or to expand or pursue business activities, which may in turn limit their ability to make cash distributions to us and our ability to make cash distributions to stockholders. For example, WNRL’s revolving credit facility and the indenture governing its senior notes contain restrictions on its ability to, among other things, make certain cash distributions, incur certain indebtedness, create certain liens, make certain investments, and merge or sell all or substantially all of its assets. NTI’s asset-based revolving credit facility and the indenture governing its 7.125% senior secured notes due 2020 also contain restrictive covenants.

To the extent the ability of our subsidiaries to distribute dividends or other payments to us could be limited in any way, our ability to grow, pursue business opportunities or make acquisitions that could be beneficial to our business, or otherwise fund and conduct our business could be materially limited.

In addition, our ability to pay dividends to our stockholders is subject to certain restrictions in our debt instruments and such restrictions 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, and Scott Weaver, our Vice President and Assistant Secretary and a current director, own approximately 25.1% of our common stock as of February 27, 2015. 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.

Loss of any of our key personnel could negatively impact our ability to manage our business and continue our growth.

Our future performance depends to a significant degree upon the continued contributions of our senior management team, including our executive officers and key technical employees. 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 companies. We may not be able to locate or employ such qualified personnel on acceptable terms, or at all.

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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 technology infrastructure and maintain and rely upon certain critical information systems for the effective operation of our businesses. These information systems include data network and telecommunications, internet access and our websites and various computer hardware equipment and software applications. 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 and emergency recovery processes to address the outlined risks. However, security measures for information systems cannot be guaranteed. Breaches to our networks could lead to such information being accessed, publicly disclosed, lost or stolen, and could result in legal claims or proceedings, liability under laws that protect the privacy of customer information, disrupt the services we provide and damage our reputation, any of which could have a material adverse effect on our business, financial condition, results of operations and cash flows. 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.

We have exposure to concentrations of credit risk related to the ability of our counterparties to meet their contractual payment obligations and the potential non-performance of counterparties to deliver contracted commodities or services at the contracted price.

We and our subsidiaries are exposed to credit risk of counterparties with whom we do business. Adverse economic conditions or financial difficulties experienced by these counterparties could impair the ability of these counterparties to pay for our and our subsidiaries’ services or fulfill their contractual obligations, including performance and payment of damages. We and our subsidiaries depend on these counterparties to remit payments and perform services timely. Counterparties could fail or delay the performance of their contractual obligations for a number of reasons, including the effect of regulations on their operations. Any delay or default in payment or performance of contractual obligations and an adverse change in our counterparties’ business, results of operations or financial condition could adversely affect their respective ability to perform each of these obligations that could consequently have a material adverse effect on our business, results of operations or liquidity.

Our operations could be disrupted if our information systems fail, causing increased expenses and loss of sales.

Our business is highly dependent on financial, accounting and other data processing systems and other communications and information systems, including our enterprise resource planning tools and credit and debit card sales at our retail stores and within our wholesale group. We process a large number of transactions and transmit confidential credit and debit card information securely over public networks on a daily basis and rely upon the proper functioning of computer systems. If a key system was to fail or experience unscheduled downtime for any reason, even if only for a short period, our operations and financial results could be affected adversely. 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 security breach could expose us to risks of data loss, litigation and liability and could seriously disrupt our operations and any resulting negative publicity could significantly harm our reputation. Our formal disaster recovery plan may not prevent delays or other complications that could arise from an information systems failure. Further, our business interruption insurance may not compensate us adequately for losses that may occur.

Our pipeline interests are subject to federal and/or state rate regulation that could reduce its profitability.

Certain of our pipelines, are subject to regulation by multiple governmental agencies, and compliance with such regulation increases our cost of doing business and affects our profitability.

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Kinder Morgan's East Line, the Plains pipeline to Albuquerque and the Minnesota Pipeline, used by NTI, are common carrier pipelines providing interstate transportation service that is subject to regulation by FERC under the Interstate Commerce Act (the “ICA”). The ICA requires that tariff rates for interstate petroleum pipelines transportation service be just and reasonable and that the rates and terms of service of such pipelines not be unduly discriminatory or unduly preferential. Because NTI currently does not operate the Minnesota Pipeline or control the board of managers of the Minnesota Pipe Line Company, NTI does not control how the Minnesota Pipeline’s tariff is applied.

FERC can also impose conditions it considers appropriate, impose penalties limit or set rates retroactively, declare pipeline-related facilities to be common carrier facilities and require that common carrier access be provided or otherwise alter the terms of service and/or rates of such facilities. Rate regulation or a successful challenge to the rates we charge, including on our regulated pipelines could adversely affect the pipeline revenue we generate. Conversely, reduced rates on our regulated pipelines would reduce the rates for transportation of crude oil into our refineries.

Two of our subsidiaries act as the general partner of two publicly traded master limited partnerships that may involve a greater exposure to legal liability than our historic business operations.

Northern Tier Energy GP, LLC and Western Refining Logistics GP, LLC act as the general partners of NTI and WNRL, two publicly traded master limited partnerships, respectively. Our control of the general partner of NTI and WNRL may increase the possibility of claims of breach of fiduciary duties, including claims of conflicts of interest related to WNRL. Any liability resulting from such claims could have a material adverse effect on our future business, financial condition, results of operations and cash flows.

The adoption of financial reform legislation in the United States among other jurisdictions, and the implementing regulations issued thereunder, could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price and other risks associated with our business.

We use derivative instruments to manage our commodity price risk. The United States Congress adopted comprehensive financial reform legislation in 2010 that establishes federal oversight and regulation of the market for certain derivatives, termed “swaps” and “security-based swaps,” and entities, such as ours, that participate in that market. The Dodd-Frank Act was signed into law by the President on July 21, 2010. Many of the provisions of the Dodd-Frank Act require implementing regulations by agencies including the Commodity Futures Trading Commission (the “CFTC”) and the SEC. While the SEC’s implementing regulations governing security-based swaps have largely not yet been adopted, the CFTC has implemented the majority of its rules governing swaps, including many commodity swaps.

Of particular importance to us, the CFTC has the authority, under certain findings, to establish position limits for certain futures, options on futures and swap contracts. Certain bona fide hedging transactions or positions would be exempt from these position limits. In 2011, the CFTC adopted position limit rules that were subsequently vacated by the U.S. District Court for the District of Columbia. In November 2013, the CFTC re-proposed position limit rules. The timing of adoption and implementation of these proposed rules and their applicability to and impact on our ability to cost-effectively hedge our commodity risks remain unclear.

The financial reform legislation may also require us to comply with margin requirements and with certain clearing and trade-execution requirements in connection with our derivatives activities. While there are exceptions from the clearing and trade execution requirements that have been implemented to date for commercial end users of swaps like us, whether we choose to use these exceptions for all transactions remains uncertain at this time. The Dodd-Frank Act and its implementing regulations have also required some of the counterparties to our swaps to register with the CFTC and become subject to substantial regulation. These requirements and others, such as those related to trade execution and margin, could significantly increase the cost of derivatives contracts (including through requirements to clear swaps and to post collateral for both cleared and uncleared swaps, each of which could adversely affect our available liquidity), materially alter the terms of derivatives contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Our revenues could also be adversely affected if a consequence of the legislation and regulations is to lower commodity prices.

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Our retail business is vulnerable to risks including changes in consumer preferences and economic conditions, competitive environment, supplier concentration, franchising operations and other trends and factors that could harm our business, financial condition, results of operations or cash flows.

Our retail business is subject to changes in consumer preferences, national, regional and local economic conditions, demographic trends and consumer confidence in the economy. Factors such as traffic patterns, weather conditions, local demographics and the number and locations of competing retail service stations and convenience stores also affect the performance of our retail stores. NTI's retail operations in the Upper Great Plains region depend on one principal supplier for a substantial portion of its merchandise inventory. NTI franchises some of its retail stores and as a result, NTI's retail operations partly depend on the retail store franchisees who are independent business operators that could take actions that harm NTI's brand, reputation or goodwill. Adverse changes in any of these trends or factors could reduce our retail customer traffic or sales, or impose limits on our pricing that could adversely affect our business, financial condition, results of operations and cash flows.

Our business depends on the protection of our intellectual property and may suffer if we are unable to adequately protect such intellectual property.

We rely on patent laws, trademark and trade secret protection to protect our intellectual property rights. However, the steps we take to protect our intellectual property rights may be inadequate. There are events that are outside of our control that pose a threat to our intellectual property rights as well as to our products and services. For example, some or all of our and our subsidiaries’ current and future trademarks, service marks and trade dress may not be enforceable, even if registered, against any prior users of similar intellectual property or our competitors who seek to use similar intellectual property in areas where we and our subsidiaries operate or intend to conduct operations. Also, the efforts we have taken to protect our proprietary rights may not be sufficient or effective. Any impairment of our intellectual property rights could harm our business and our ability to compete. Also, protecting our intellectual property rights is costly and time consuming. Any increase in the unauthorized use of our intellectual property could make it more expensive to do business and harm our operating results. In addition, we could encounter claims from prior users of similar intellectual property in areas where we or our subsidiaries operate or intend to conduct operations that could result in additional expenditures and divert our management’s time and attention from our operations. Conversely, competing businesses could infringe on our intellectual property that would necessarily require us to defend our intellectual property possibly at a significant cost to us. Any of these consequences could cause a material adverse effect on our business, financial condition, results of operations and cash flows.

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, 2014, 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 25, Leases and Other Commitments, in the Notes to Consolidated Financial Statements included elsewhere in this annual report.

Item 3. Legal Proceedings

In the ordinary conduct of our business, we are subject to periodic lawsuits, investigations and claims, including environmental claims and employee related matters. Although we cannot predict with certainty the ultimate resolution of lawsuits, investigations and claims asserted against us, we do not believe that any currently pending legal proceeding or proceedings to which we are a party will have a material adverse effect on our business, financial condition, results of operations or cash flows.

Item 4. Mine Safety Disclosures

Not Applicable.

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PART II

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

Market Information

Our common stock is listed on the NYSE under the symbol “WNR.” As of February 27, 2015, we had 49 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
2014:
First quarter	$	43.00	$	35.58	$	0.26
Second quarter	45.00		36.49		0.26
Third quarter	48.36		37.61		0.26
Fourth quarter (1)	46.89		35.29		2.30
2013:
First quarter	$	38.82	$	26.94	$	0.12
Second quarter	34.99		26.89		0.12
Third quarter	31.45		26.51		0.18
Fourth quarter	42.41		29.73		0.22

(1) Dividends for the fourth quarter of 2014 included a special dividend of $2.00 per common share.

Our payment of dividends is limited under the terms of our Western Revolving Credit Agreement, our Senior Unsecured Notes and our Term Loan Credit Agreement, and in part, depends on our ability to satisfy certain financial covenants. Also, as a holding company, we rely on dividends or advances from our subsidiaries to fund any dividends. The ability of our subsidiaries including NTI and WNRL to pay us dividends is restricted by covenants in their respective debt instruments and any future financing agreements. Throughout 2014, our board of directors approved and we declared quarterly cash dividends totaling $293.7 million paid on various dates throughout the year. On February 6, 2015, our board of directors approved a cash dividend for the first quarter of 2015 of $0.30 per share of common stock in an aggregate payment of approximately $28.6 million that will be paid on March 6, 2015 to holders of record on February 20, 2015.

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, 2009. The index on December 31, 2014, and its relative performance are tracked through this date. The stock price performance included in this graph is not necessarily indicative of future stock price performance.

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COMPARISON OF 5 YEAR CUMULATIVE TOTAL RETURN

COMPARISON OF 5 YEAR CUMULATIVE TOTAL RETURN

(Tabular representation of data in graph above)

	Dec	Dec	Dec	Dec	Dec	Dec
	2009	2010	2011	2012	2013	2014
Western Refining, Inc.	$100.00	$224.63	$282.17	$662.98	$1,017.93	$976.31
S&P 500	100.00	115.06	117.49	136.30	180.44	205.14
Peer Group	100.00	142.83	148.73	282.21	394.94	393.67

Purchases of Equity Securities by the Issuer and Affiliated Purchasers

As of December 31, 2014, our board of directors authorized four separate share repurchase programs of up to $200 million, per program, of our outstanding common stock. Our board of directors approved share repurchase programs in January of 2014 (the "January 2014 Program") and November of 2014 (the "November 2014 Program"). We used the full authorized amount of $200 million of the January 2014 Program during 2014. As of December 31, 2014, we had $140.8 million remaining in authorized expenditures under the November 2014 Program. Through December 31, 2014, we have purchased approximately 17.9 million shares of our common stock under the share repurchase programs.

Between March 26, 2014, and June 16, 2014, in connection with the settlement of conversions of the Western Convertible Notes, we utilized 12.1 million shares of treasury stock, consisting of treasury shares acquired prior to the share repurchase programs and shares purchased under the programs through June 10, 2014, to satisfy a portion of these conversions. See Note 15, Long-Term Debt in the Notes to Consolidated Financial Statements included in this annual report for detailed information on the settlement of conversions of the Western Convertible Notes.

Subject to market conditions as well as corporate, regulatory and other considerations, we will repurchase shares from time-to-time through open market transactions, block trades, privately negotiated transactions or otherwise. Our board of directors may discontinue the share repurchase program at any time.

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The following table presents shares repurchased, by month, during 2014.

	Total number of shares purchased as part of publicly announced plans or programs (1)	Average price paid per share (2)		Maximum dollar value of shares that may yet be purchased under the programs (In thousands) (3)
January 1 - January 31	—	$	—	$	264,889
February 1 - February 28	—	—		264,889
March 1 - March 31	—	—		264,889
April 1 - April 30	—	—		200,000
May 1 - May 31	12,519	38.96		199,512
June 1 - June 30	467,843	38.11		181,675
July 1 - July 31	1,081,620	39.51		138,923
August 1 - August 31	11,562	39.98		138,460
September 1 - September 30	—	—		138,460
October 1 - October 31	2,478,288	40.33		38,460
November 1 - November 30	722,756	41.87		208,187
December 1 - December 31	1,694,325	39.77		140,778
Total	6,468,913	$	40.05

(1) We do not actively repurchase shares of our common stock outside of our publicly announced repurchase programs.

(2) Average price per share excludes commissions of $0.02 per share.

(3) From January 1 through April 30, 2014, both the April 2013 Program and the January 2014 Program were active under their respective board authorization terms. We made no purchases under the April 2013 Program between January 1, 2014, and its expiration on April 30, 2014. In November 2014, the board authorized the November 2014 Program for $200 million and, during November, both the January 2014 Program and the November 2014 Program were active. We exhausted the remaining balance available under the January 2014 Program in December of 2014.

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Item 6. Selected Financial Data

The following tables set forth a summary of our historical financial and operating data for the periods indicated. The summary results of operations and financial position data as of and for the five years ended December 31, 2014, have been derived from the consolidated financial statements of Western Refining, Inc. and its subsidiaries. The information presented includes the results of operations of NTI beginning November 12, 2013, the date of acquisition. The information presented also includes the financial results for WNRL from October 16, 2013 forward. In addition to the impact of the non-controlling interest in net income of NTI and WNRL, refinery margins have decreased due to additional fees paid by Western to WNRL for logistics services and refining direct operating expenses have decreased for the costs associated with WNRL that are no longer included in refining direct operating costs. Consequently, our results of operations for 2013 are not fully comparable with prior or future periods.

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,
	2014		2013		2012		2011		2010
	(In thousands, except per share data)
Statement of Operations Data
Net sales	$	15,153,573	$	10,086,070	$	9,503,134	$	9,071,037	$	7,965,053
Total operating costs and expenses (1)	14,057,060		9,514,197		8,791,239		8,687,258		7,859,618
Operating income	1,096,513		571,873		711,895		383,779		105,435
Net income (loss)	710,072		299,554		398,885		132,667		(17,049		)
Less net income attributed to non-controlling interest (3)	150,146		23,560		—		—		—
Net income (loss) attributable to Western Refining, Inc.	$	559,926	$	275,994	$	398,885	$	132,667	$	(17,049	)
Basic earnings (loss) per share	$	6.17	$	3.35	$	4.42	$	1.46	$	(0.19	)
Diluted earnings (loss) per share	5.61		2.79		3.71		1.34		(0.19		)
Dividends declared per common share	$	3.08	$	0.64	$	2.74	$	—	$	—
Weighted average basic shares outstanding	90,708		82,248		89,270		88,981		88,204
Weighted average dilutive shares outstanding	101,190		104,904		111,822		109,792		88,204

	Year Ended December 31,
	2014		2013		2012		2011		2010
	(In thousands)
Other Data
Adjusted EBITDA (2)	$	1,231,443	$	754,839	$	1,083,669	$	786,239	$	287,770
Balance Sheet Data (at end of period)
Cash and cash equivalents	$	431,159	$	468,070	$	453,967	$	170,829	$	59,912
Restricted cash	167,009		—		—		220,355		—
Working capital	754,762		448,667		559,213		544,981		272,750
Total assets	5,682,558		5,512,965		2,480,407		2,570,344		2,628,146
Total debt and lease financing obligations	1,548,026		1,411,517		499,863		803,990		1,069,531
Total equity	2,787,644		2,570,587		909,070		819,828		675,593

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(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,
	2014		2013			2012			2011			2010
	(In thousands)
Realized commodity hedging gain (loss), net	$	95,331	$	15,868		$	(144,448	)	$	(76,033	)	$	(9,770	)
Unrealized commodity hedging gain (loss), net	194,423		(16,898		)	(229,672		)	183,286			337
Total realized and unrealized commodity hedging gain (loss), net	$	289,754	$	(1,030	)	$	(374,120	)	$	107,253		$	(9,433	)

(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.

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.

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The following table reconciles net income (loss) to Adjusted EBITDA for the periods presented:

	Year Ended December 31,
	2014			2013			2012		2011			2010
	(In thousands)
Net income (loss) attributable to Western Refining, Inc.	$	559,926		$	275,994		$	398,885	$	132,667		$	(17,049	)
Net income attributed to non-controlling interest	150,146			23,560			—		—			—
Interest expense and other financing costs	89,276			68,040			81,349		134,601			146,549
Amortization of loan fees	7,786			6,541			6,860		8,926			9,739
Provision for income taxes	292,604			153,925			218,202		69,861			(26,077		)
Depreciation and amortization	190,566			117,848			93,907		135,895			138,621
Maintenance turnaround expense	48,469			50,249			47,140		2,443			23,286
Loss (gain) and impairments on disposal of assets, net (a)	8,530			(4,989		)	—		450,796			13,038
Loss on extinguishment of debt	9			46,773			7,654		34,336			—
Net change in lower of cost or market inventory reserve	78,554			—			—		—			—
Unrealized loss (gain) on commodity hedging transactions, net (b)	(194,423		)	16,898			229,672		(183,286		)	(337		)
Adjusted EBITDA	$	1,231,443		$	754,839		$	1,083,669	$	786,239		$	287,770

(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.

(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.

(3) Net income attributed to non-controlling interest for the years ended December 31, 2014 and 2013, consisted of income from NTI of $131.9 million and $20.6 million, respectively. Net income attributed to non-controlling interest for the years ended December 31, 2014 and 2013, consisted of income from WNRL of $18.2 million and $3.0 million, respectively.

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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

See Part I — Item 1. Business included in this annual report for detailed information on our business.

Major Influences on Results of Operations

Summary of 2014 Developments

• We averaged total throughput of 127,236 bpd at the El Paso refinery for the year ended December 31, 2014, a 1.5%increase from 2013.

• We averaged total throughput of 27,783 bpd at the Gallup refinery for the year ended December 31, 2014, a 10.7%increase from 2013.

• We completed a turnaround of the south side units of the El Paso refinery during the first quarter of 2014.

• We retired the Western Convertible Notes through the issuance of 22,759,243 shares of our common stock in exchange thereof.

• We sold all of the outstanding limited liability company interests of WRW to WNRL on October 15, 2014, in exchange for consideration of $320 million in cash and the issuance of approximately 1.16 million common units representing limited partner interests in WNRL.

• We purchased 6,468,913 shares under our share repurchase programs at an average price of $40.05 per share.

• We declared and paid dividends per share of $3.08 per common share in an aggregate payment of $293.7 million, including a special dividend during the fourth quarter of $2.00 per common share.

• NTI averaged total throughput of 93,525 bpd at the St. Paul Park refinery for the year ended December 31, 2014, a 13.7%increase from 2013.

• NTI terminated its Crude Intermediation Agreement with JPM CCC, funding the purchase of related crude oil inventories through issuance in a private placement of an additional $75.0 million in principal value of its 2020 Secured Notes.

• NTI recorded a lower of cost or market adjustment on its crude oil, finished product and retail LIFO inventory values of $73.7 million as of December 31, 2014.

• WNRL completed the Wholesale Acquisition, using $269.0 million borrowed under the WNRL Revolving Credit Facility, on October 15, 2014, to partially fund the purchase.

2014 Operating and Financial Highlights

Net income attributable to Western was $559.9 million, or $5.61 per diluted share for the year ended December 31, 2014 compared to $276.0 million, or $2.79 per diluted share for the year ended December 31, 2013. The increase was primarily due to the inclusion of a full year of financial results from NTI, which generated net income of $88.8 million for the year ended December 31, 2014 compared to $13.6 million representing the period from November 12, 2013 through December 31, 2013. Also contributing to the increase in 2014 net income were our consolidated realized and unrealized net gains on commodity hedging activities compared to a small net loss in the prior year.

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Our operating income increased$524.6 million from December 31, 2013 to December 31, 2014 as shown by segment in the following table:

	Year Ended December 31,
	2014			2013			Change
	(In thousands)
Refining	$	836,952		$	636,333		$	200,619
NTI	241,229			37,358			203,871
WNRL	74,502			(41,527		)	116,029
Retail	20,763			14,854			5,909
Corporate	(76,933		)	(75,145		)	(1,788		)
Total operating income	$	1,096,513		$	571,873		$	524,640

The information presented includes the results of operations of NTI beginning November 12, 2013, the consummation date of the purchase transactions. Additionally, the information presented includes the financial results for WNRL from the period beginning October 16, 2013.

The WNRL financial and operational data presented include the historical results of all assets acquired from Western in the Wholesale Acquisition. This acquisition from Western was a transfer of assets between entities under common control. The information contained herein for the WNRL Predecessor and WNRL has been retrospectively adjusted, to include the historical results of the WRW assets acquired, for periods prior to the effective date of the Wholesale Acquisition. Our financial information includes the historical results of the Predecessor for periods prior to October 16, 2013, and the results of WNRL, beginning October 16, 2013, the date WNRL commenced operations, which have also been retrospectively adjusted.

Overview of Segments

Refining. The following items have a significant impact on our overall refinery gross margin, results of operations and

cash flows:

• fluctuations in petroleum based commodity values such as refined product prices and the cost of crude oil and other feedstocks resulting from changes in supply and demand;

• product yield volumes are less than total refinery throughput volume, resulting in yield loss and lower refinery gross margin;

• the impact of our economic hedging activity;

• fluctuations in our direct operating expenses, especially the cost of natural gas and the cost of electricity;

• planned maintenance turnarounds, generally significant in both downtime and cost, are expensed as incurred;

• seasonal fluctuations in demand for refined products; and

• unplanned downtime of our refineries generally leads to increased maintenance costs and a temporary increase in working capital investment.

Key factors affecting petroleum based commodities' values include: supply and demand for crude oil, gasoline and other refined products; changes in domestic and foreign economies; weather conditions; domestic and foreign political affairs; crude oil and refined petroleum product production levels; logistics constraints; availability of imports; marketing of competitive fuels; price differentials between heavy and sour crude oils and light sweet crude oils; and government regulation. Our economic hedging activity can also have a significant impact on our refining margins. We engage in hedging activity 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.

Excise and other taxes collected from customers and remitted to governmental authorities are not included in revenues. In addition to the crude oil that we purchase to supply our refinery production, we also purchase crude oil quantities that are transported to different locations and sold to third parties. We record these sales on a gross basis with the sales price recorded as revenues and our corresponding purchase price within cost of products sold. Consolidated cost of products sold for the year ended December 31, 2014 includes $289.8 million of realized and non-cash unrealized net gains from our economic hedging activities, of which $280.2 million related to refining. The non-cash unrealized net gains included in the consolidated total were $194.4 million, including $197.2 million related to Western's refining segment, offset by an unrealized loss of $2.8 million related to NTI for the year ended December 31, 2014.

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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.

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. We occasionally experience unplanned downtime due to circumstances outside of our control. Certain of these outages qualify for reimbursement as business interruption losses, and we record these reimbursements as revenues. Net sales for the years ended December 31, 2014 and 2013, include $5.8 million and $22.2 million, respectively, in business interruption recoveries related to processing outages that occurred during the first and fourth quarters of 2011 at the El Paso refinery. Net sales for the year ended December 31, 2012, also include $4.0 million in business interruption recoveries related to the 2011 first quarter processing outage at our El Paso refinery.

Under an exclusive supply agreement with a third party, we receive monthly distribution amounts from the supplier equal to one-half of the amount by which our refined product sales in the Mid-Atlantic exceeds the supplier's costs of acquiring, transporting and hedging the refined product related to such sales. To the extent our refined product sales do not exceed the refined product costs during any month, we 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.

NTI. NTI's gross margins, results of operations and cash flows are primarily affected by the following:

• Fluctuations in petroleum based commodity values such as refined product prices and the cost of crude oil and other feedstocks resulting from changes in supply and demand;

• product yield volumes are less than total refinery throughput volume, resulting in yield loss and lower refinery gross margin;

• adjustments to reflect the lower of cost or market value of crude oil, finished product and retail LIFO inventory values;

• fluctuations in its direct operating expenses, especially related to the cost of natural gas and the cost of electricity;

• planned maintenance turnarounds, generally significant in both downtime and cost, are expensed as incurred;

• seasonal fluctuations in demand for refined products; and

• unplanned downtime of its refineries generally leads to increased maintenance costs and a temporary increase in working capital investment.

Seasonal demand for gasoline is generally higher during the summer months than during the winter months due to seasonal increases in highway traffic. Decreased demand during the winter months can lower gasoline prices and margins. As a result, NTI's operating results for the first and fourth calendar quarters are generally lower than those for the second and third calendar quarters of each year.

WNRL. As WNRL's logistics operations primarily support the operations of Western, its results of operations and cash flows are indirectly affected by operational items that affect Western. WNRL's terminal throughput volumes depend primarily on the volume of refined and other products produced at Western’s refineries that, in turn, is ultimately dependent on supply and demand for refined product, crude oil and other feedstocks and Western’s response to changes in demand and supply.

Earnings and cash flows from WNRL's wholesale business are primarily affected by the sales volumes and margins of gasoline, diesel fuel and lubricants sold and transportation revenues from crude oil trucking and delivery. 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.

Retail. Earnings and cash flows from our retail business 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 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. Earnings and cash flows from our cardlock business are primarily affected by the sales volumes and margins of gasoline and diesel fuel sold. These margins are equal to

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the sales price, net of discounts less the delivered cost of the fuel and motor fuel taxes and are measured on a cpg basis. Factors that influence margins include local supply, demand and competition.

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.

WNRL

During 2013, we formed WNRL, a fee-based growth-oriented master limited partnership, to own, operate, develop and acquire terminals, storage tanks, pipelines and other logistics assets. On October 16, 2013, WNRL completed the offering of 15,812,500 common units representing limited partner interests to the public at a price of $22.00 per unit that included a 2,062,500 common partnership unit over-allotment option exercised by the underwriters. Western retained certain assets that are related to the operations of Western Refining Logistics, LP Predecessor, which is WNRL's predecessor as defined for accounting purposes. The retained assets include Western’s NGL storage facility in Jal, New Mexico and portions of the TexNew Mex 16” Pipeline extending from the crude oil station in Star Lake, New Mexico in the Four Corners area to near Maljamar, New Mexico in the Delaware Basin.

On October 15, 2014, in connection with a Contribution, Conveyance and Assumption Agreement dated September 25, 2014, we sold substantially all of our wholesale business to WNRL.

We are WNRL's primary customer for its terminalling and storage activities and we record the fees we pay to WNRL for its services within cost of products sold. Prior to WNRL's operations, we did not operate our logistics assets for the purpose of generating revenue, therefore, there is no comparable activity prior to WNRL's commencement of operations on October 16, 2013.

As of December 31, 2014, we own a 66.2% limited partner interest in WNRL and the public owns a 33.8% limited partner interest.

See Note 29, Western Refining Logistics, LP, in the Notes to Consolidated Financial Statements included in this annual report for more detailed information.

NTI Acquisition

On November 12, 2013 Western purchased all of NTH’s interests in NT InterHoldCo LLC, a wholly-owned subsidiary of Northern Tier Holdings LLC that holds all of the membership interests in Northern Tier Energy GP LLC, the general partner of Northern Tier Energy LP, and 35,622,500 common units representing a 38.7% limited partner interest in Northern Tier Energy LP for a purchase price of $775 million. Our 2013 results of operations include the period from November 12, 2013 through December 31, 2013. See Note 30, Acquisitions, in the Notes to Consolidated Financial Statements included in this annual report for more detailed information.

Debt Transactions

The following debt transactions occurred during the years ended December 31, 2014, 2013 and 2012:

• We made non-mandatory prepayments under our term loan maturing in 2017 during the first and second quarter of 2012 reducing the principal value to zero.

• We redeemed or otherwise purchased and canceled all outstanding 11.25% Senior Secured Notes during the first and second quarters of 2013.

• We entered into an indenture for the issuance of $350.0 million in aggregate principal amount of 6.25% Senior Unsecured Notes due 2021 on March 25, 2013.

• We amended and restated our Western revolving credit facility on April 11, 2013, receiving $900.0 million in commitments maturing in 2018.

• WNRL entered into a senior secured revolving credit facility on October 16, 2013, receiving $300.0 million in commitments maturing in 2018.

• We entered into a term loan credit agreement on November 12, 2013, that provides for loans of $550.0 million, matures on November 12, 2020 and provides for quarterly principal payments equal to 0.25% of the aggregate principal amount of term loans (as adjusted by any application of debt prepayment, to the extent applicable) with the remaining balance then outstanding due on the maturity date.

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• We delivered an aggregate of 22,759,243 shares of common stock on various dates between March 26, 2014, and June 16, 2014, to noteholders to satisfy the conversion of aggregate principal amount of 5.75% Convertible Senior Unsecured Notes based on conversion rates.

• NTI amended and restated its senior secured Revolving Credit Facility on September 29, 2014, increasing the aggregate principal amount available prior to the amendment from $300.0 million to $500.0 million.

• NTI increased the principal amount of the 2020 Secured Notes in September 2014 through issuance of a private placement of an additional $75.0 million in principal value at a premium of $4.2 million.

• We amended and restated our Western revolving credit facility on October 2, 2014 receiving $900.0 million in commitments maturing in 2019.

• WNRL borrowed $269.0 million under the WNRL 2019 Revolving Credit Facility on October 15, 2014, to partially fund the purchase of substantially all of Western's wholesale business.

As a result of the long-term debt redemptions described above, we recognized insignificant losses on extinguishment of debt in 2014 and $46.8 million and $7.7 million for the years ended December 31, 2013 and 2012, respectively. These losses are included in Loss on extinguishment of debt in the Consolidated Statements of Operations.

See Note 15, Long-Term Debt, in the Notes to Consolidated Financial Statements included in this annual report for more detailed information regarding our debt transactions.

Equity Transactions

See Part I — Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities included in this annual report and Note 20, Equity, in the Notes to Consolidated Financial Statements included in this annual report for detailed information regarding our share repurchase programs and the issuance of common stock to satisfy conversions of our Convertible Senior Unsecured Notes.

Employee Benefit Plans

See Note 17, Retirement Plans, in the Notes to Consolidated Financial Statements included in this annual report for detailed information regarding our employee benefit plans.

Commodity Hedging Activities, Property Taxes and Other

Our operating results for the years ended December 31, 2014 included realized and unrealized net gains from our commodity hedging activities of $289.8 million and realized and unrealized net losses from our commodity hedging activities of $1.0 million and $374.1 million for the years ended December 31, 2013 and 2012, respectively. For the period following our acquisition of NTI through December 31, 2013 and the year ended December 31, 2014, NTI operations included $12.4 million in realized commodity hedging gains and $1.8 million in realized commodity hedging losses, respectively, that are included in the consolidated net activity noted above. See Note 18, 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 the fourth quarter of 2014, market prices of feedstocks and refined products decreased significantly. We reduced the carrying value of our inventory by $78.6 million in order to state the value at market prices which were lower than our cost at December 31, 2014. Refined products inventory includes a lower of cost or market non-cash adjustment of $41.7 million and crude oil and other raw materials inventory includes a lower of cost or market non-cash adjustment of $36.9 million at December 31, 2014.

During the latter half of 2012, we increased our annual property tax accrual estimate by $11.6 million resulting from increased 2012 appraisal values. In 2013 we reduced our accrual for property tax expense as appraisal values for certain of our properties were re-evaluated and reduced. There were no significant changes in appraisal values of our properties during 2014.

Our income tax provisions include the effects of a decrease in our valuation allowance of $2.9 million and $2.8 million for the years ended December 31, 2014 and 2013, respectively, and an increase of $23.7 million for the year ended December 31, 2012 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.

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Planned Maintenance Turnaround

During the years ended December 31, 2014, 2013 and 2012, we incurred costs of $48.5 million, $50.2 million and $47.1 million, respectively, for maintenance turnarounds. In the first quarter of 2014, we completed a scheduled maintenance turnaround for the south side units of the El Paso refinery. In the first quarter of 2013, we completed a scheduled maintenance turnaround for the north side units of the El Paso refinery. We also incurred turnaround expense during 2013 in preparation for a planned 2014 turnaround for the south side units at the El Paso refinery. Costs incurred during 2012 and 2011 related primarily to the planned 2012 turnaround for the Gallup refinery. We began a refinery maintenance turnaround at our Gallup refinery during September 2012 that was completed during October 2012. We expense the cost of maintenance turnarounds when the expense is incurred, while most of our competitors capitalize and amortize maintenance turnarounds.

Critical Accounting Policies and Estimates

We prepare our financial statements in conformity with U.S. GAAP. See Note 2, Summary of Accounting Policies to our Consolidated Financial Statements for 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 for refining inventories. Costs include both direct and indirect expenditures incurred in bringing an item or product to its existing condition and location, but not unusual/non-recurring costs or research and development costs. Ending inventory costs in excess of market value are written down to net realizable market values and charged to cost of products sold in the period recorded. In subsequent periods, a new LCM determination is made based upon current circumstances. We determine market value inventory adjustments by evaluating crude oil, refined products and other inventories on an aggregate basis by geographic region.

Retail refined product, lubricants and related inventories are determined using the first-in, first-out ("FIFO") inventory valuation method. Refined product inventories originate from either our refineries or from third-party purchases. Retail merchandise inventory value is determined under the retail inventory method.

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 that 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.

Goodwill. At December 31, 2014 and 2013, we had goodwill of $1,289.4 million and $1,297.0 million, respectively, relating to the NTI acquisition that was completed on November 12, 2013. Goodwill represents the excess of the purchase price (cost) over the fair value of the net assets acquired and is carried at cost. We do not amortize goodwill for financial reporting purposes. We test goodwill for impairment at the reporting unit level. The reporting unit or units used to evaluate and measure goodwill for impairment are determined primarily from the manner in which the business is managed.

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Our policy is to test goodwill for impairment annually at June 30, or more frequently if indications of impairment exist. The testing of our goodwill for impairment is based on the estimated fair value of our reporting units that is determined based on consideration given to discounted expected future cash flows using a weighted-average cost of capital rate. An assumed terminal value is used to project future cash flows beyond base years. In addition, various market-based methods including market capitalization and earnings before interest, taxes, depreciation and amortization ("EBITDA") multiples are considered. The estimates and assumptions used in determining fair value of a reporting unit require considerable judgment and are based on historical experience, financial forecasts and industry trends and conditions. The discounted cash flow model is sensitive to changes in future cash flow forecasts and the discount rate used. The market capitalization model is sensitive to changes in traded partnership unit price. The EBITDA model is sensitive to changes in recent historical results of operations within the refining industry. We compare and contrast the results of the various valuation models to determine if impairment exists at the end of a reporting period. Any declines in the market capitalization of NTI after December 31, 2014, could be an early indication that goodwill may become impaired in the future.

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 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. Moreover, 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.

Recent Accounting Pronouncements

From time to time, new accounting pronouncements are issued by the Financial Accounting Standards Board or other standard setting bodies that may have an impact on our accounting and reporting. We believe that recently issued accounting pronouncements and other authoritative guidance for which the effective date is in the future either will not have a significant impact on our accounting or reporting or that such impact will not be material to our financial position, results of operations and cash flows when implemented. For further discussion on the impact of recent accounting pronouncements, see Note 2, Summary of Accounting Policies, in the Notes to Consolidated Financial Statements included in this annual report.

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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, 2014, is presented below:

Consolidated

	Year Ended December 31,
	2014 (2)			2013 (2)			2012
	(In thousands, except per share data)
Statement of Operations Data:
Net sales (1)	$	15,153,573		$	10,086,070		$	9,503,134
Operating costs and expenses:
Cost of products sold (exclusive of depreciation and amortization) (1)	12,719,963			8,690,222			8,054,385
Direct operating expenses (exclusive of depreciation and amortization) (1)	850,634			523,836			483,070
Selling, general and administrative expenses	226,020			137,031			114,628
Affiliate severance costs	12,878			—			—
Loss (gain) and impairments on disposal of assets, net	8,530			(4,989		)	(1,891		)
Maintenance turnaround expense	48,469			50,249			47,140
Depreciation and amortization	190,566			117,848			93,907
Total operating costs and expenses	14,057,060			9,514,197			8,791,239
Operating income	1,096,513			571,873			711,895
Other income (expense):
Interest income	1,188			746			696
Interest expense and other financing costs	(89,276		)	(68,040		)	(81,349		)
Amortization of loan fees	(7,786		)	(6,541		)	(6,860		)
Loss on extinguishment of debt	(9		)	(46,773		)	(7,654		)
Other, net	2,046			2,214			359
Income before income taxes	1,002,676			453,479			617,087
Provision for income taxes	(292,604		)	(153,925		)	(218,202		)
Net income	710,072			299,554			398,885
Less net income attributed to non-controlling interest (3)	150,146			23,560			—
Net income attributable to Western Refining, Inc.	$	559,926		$	275,994		$	398,885
Basic earnings per share	$	6.17		$	3.35		$	4.42
Diluted earnings per share	5.61			2.79			3.71
Dividends declared per common share	$	3.08		$	0.64		$	2.74
Weighted average basic shares outstanding	90,708			82,248			89,270
Weighted average dilutive shares outstanding	101,190			104,904			111,822

(1) The information presented excludes $4,390.7 million, $4,277.8 million and $4,909.4 million of intercompany sales, $4,374.1 million, $4,265.0 million and $4,901.5 million of intercompany cost of products sold; and $16.6 million, $12.8 million and $7.9 million of intercompany direct operating expenses for the years ended December 31, 2014, 2013 and 2012.

(2) The information presented includes the results of operations of NTI beginning November 12, 2013, the consummation date of the purchase transactions. Additionally, the WNRL financial and operational data presented include the historical results of all assets acquired from Western in the Wholesale Acquisition. This acquisition from Western was a transfer of assets between entities under common control. Accordingly, the financial information for the WNRL Predecessor and WNRL has been retrospectively adjusted, to include the historical results of the WRW assets acquired, for periods prior to the effective date of the transaction. Our financial information includes the historical results of the Predecessor for periods prior to October 16, 2013, and the results of WNRL, beginning October 16, 2013, the date WNRL commenced operations, which have also been retrospectively adjusted.

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(3) Net income attributable to non-controlling interest for the years ended December 31, 2014 and 2013, consisted of net income from NTI of $131.9 million and $20.6 million, respectively, and net income from WNRL of $18.2 million and $3.0 million, respectively.

Gross Margin

Gross margin is a function of net sales less cost of products sold (exclusive of depreciation and amortization). Our consolidated margins increased from 2013 through 2014 by 74.3%. Our margin increase was a reflection of the overall industry wide improvement in refining margins year over year. Our increase in margins was also impacted, in part, by the results of our commodity hedging activities in our refining segment. Total Gross Margin in our other segments increased from 2013 through 2014, in part due to the acquisition of NTI and regional margin environments in the locale of our non-refining operations.

Our consolidated margins decreased from 2012 through 2013 by 3.7%. Our margin decrease was a reflection of the overall industry wide decline in refining margins. Our decrease in margins was offset in part by the results of our commodity hedging activities. Our other segments’ total margins increased from 2012 through 2013, in part due to the acquisition of NTI.

Direct Operating Expenses

The increase in direct operating expenses was primarily due to direct operating expenses associated with NTI ($298.1 million) which was acquired during November 2013 and higher direct operating expenses in our refining segment ($52.5 million).

The increase in direct operating expenses from 2012 to 2013 was primarily due to NTI that had direct operating expenses of $35.1 million with no comparable data in prior periods.

Selling, General and Administrative Expenses

The increase in selling, general and administrative expenses from 2013 to 2014 was primarily due to selling, general and administrative expenses associated with NTI ($91.5 million) which was acquired during November 2013.

The increase in selling, general and administrative expenses from 2012 to 2013 was primarily due to NTI that had selling, general and administrative expenses ($11.7 million) with no comparable data in prior periods.

Affiliate Severance Costs

The severance costs are related to severance payments related to Western's acquisition of NTI's general partner.

Maintenance Turnaround Expenses

During the years ended December 31, 2014 and 2013, we incurred turnaround expenses for a turnaround of the south and north side units of the El Paso refinery, respectively. During the year ended December 31, 2012, we incurred turnaround expenses in connection with the turnaround of our Gallup Refinery.

Depreciation and Amortization

The increase in depreciation and amortization from 2013 to 2014 was primarily due to depreciation associated with the NTI assets acquired during November 2013 ($91.5 million). There was also additional depreciation resulting from assets capitalized during the first quarter of 2013 and 2014, respectively, for the north and south side units of the El Paso refinery and additional depreciation associated with our logistics assets related to the ongoing expansion of our Delaware Basin logistics system. 

The increase from 2012 to 2013 was primarily due to additional depreciation at our Gallup refinery ($4.8 million), resulting from additional assets capitalized during the third and fourth quarters of 2012, and at our El Paso refinery ($2.9 million), related to first quarter of 2013 capital additions. Also, there was additional depreciation associated with WNRL logistics assets due to the ongoing expansion of our Delaware Basin logistics system. We also incurred depreciation associated with the NTI assets acquired during November 2013 ($10.7 million).

Other Income (Expense)

The increase in interest expense from prior periods was attributable to higher debt levels resulting from the issuance of senior unsecured notes on March 25, 2013, a term loan agreement entered into on November 12, 2013, additional interest related to the NTI Senior Secured Notes and WNRL's Revolving Credit Facility, partially offset by the retirement of our Convertible Senior Unsecured Notes.

The loss on extinguishment of debt recorded for the year ended December 31, 2013, was attributable to the tender offer for our Senior Secured Notes. The loss on extinguishment of debt for the year ended December 31, 2012, was the result of the prepayment of our Term Loan.

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Segment Results

The following tables set forth our consolidating historical financial data for the periods presented below. During the fourth quarter of 2014, we changed our reportable segments due to recent changes in our organization and the corresponding changes in the business assessment needs of our chief operating decision maker. Our operations are now organized into four operating segments based on manufacturing and marketing criteria and the nature of our products and services, our production processes and our types of customers. These segments are refining, NTI, WNRL and retail. See Note 3, Segment Information, in the Notes to Consolidated Financial Statements included in this annual report for more detailed information. The historical financial data was retrospectively adjusted for the periods presented.

	Year Ended December 31,
	2014		2013		2012
	(In thousands)
Consolidated Gross Margin by Segment
Refining	$	1,293,802	$	1,024,656	$	1,203,105
NTI	720,145		94,882		—
WNRL	256,969		127,411		95,833
Retail	162,271		148,352		149,262
Other	423		547		549
Consolidated gross margin	$	2,433,610	$	1,395,848	$	1,448,749
Consolidated Direct Operating Expenses by Segment
Refining	$	289,983	$	241,276	$	260,793
NTI	298,104		35,123		—
WNRL	142,398		135,307		115,374
Retail	118,468		111,320		105,980
Other	1,681		810		923
Consolidated direct operating expenses	$	850,634	$	523,836	$	483,070
Consolidated Depreciation and Amortization
Refining	$	81,726	$	75,346	$	65,955
NTI	76,544		10,740		—
WNRL	17,372		15,970		14,315
Retail	11,733		12,382		11,233
Other	3,191		3,410		2,404
Consolidated depreciation and amortization	$	190,566	$	117,848	$	93,907

See additional analysis under the refining, NTI, WNRL and retail segments.

41

Refining

	Year Ended
	December 31,
	2014		2013			2012
	(In thousands, except per barrel data)
Statement of Operations Data:
Net sales (including intersegment sales) (1)	$	9,485,734	$	8,866,162		$	9,500,558
Operating costs and expenses:
Cost of products sold (exclusive of depreciation and amortization) (2)	8,175,332		7,828,695			8,289,580
Direct operating expenses (exclusive of depreciation and amortization)	306,583		254,087			268,666
Selling, general and administrative expenses	28,470		26,451			24,330
Loss (gain) and impairments on disposal of assets, net	8,202		(4,999		)	(1,382		)
Maintenance turnaround expense	48,469		50,249			47,140
Depreciation and amortization	81,726		75,346			65,955
Total operating costs and expenses	8,648,782		8,229,829			8,694,289
Operating income	$	836,952	$	636,333		$	806,269
Key Operating Statistics:
Total sales volume (bpd) (1) (3)	217,640		176,653			184,086
Total refinery production (bpd)	152,942		147,793			147,461
Total refinery throughput (bpd) (4)	155,019		150,429			149,809
Per barrel of throughput:
Refinery gross margin (2) (5)	$	23.11	$	18.89		$	22.01
Direct operating expenses (6)	5.42		5.69			5.85
Mid-Atlantic sales volume (bbls)	8,588		9,734			9,301
Mid-Atlantic margin per barrel	$	0.32	$	0.47		$	0.86

El Paso and Gallup Refineries

	Year Ended
	December 31,
	2014	2013	2012
Key Operating Statistics
Refinery product yields (bpd):
Gasoline	79,279	78,568	76,536
Diesel and jet fuel	63,359	59,580	61,224
Residuum	5,121	5,445	5,655
Other	5,183	4,200	4,046
Total refinery production (bpd)	152,942	147,793	147,461
Refinery throughput (bpd):
Sweet crude oil	121,514	117,289	115,345
Sour or heavy crude oil	25,113	25,195	24,792
Other feedstocks and blendstocks	8,392	7,945	9,672
Total refinery throughput (bpd) (4)	155,019	150,429	149,809

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El Paso Refinery

	Year Ended
	December 31,
	2014		2013		2012
Key Operating Statistics
Refinery product yields (bpd):
Gasoline	62,252		61,893		61,669
Diesel and jet fuel	54,501		52,600		54,600
Residuum	5,121		5,445		5,655
Other	3,740		3,442		3,280
Total refinery production (bpd)	125,614		123,380		125,204
Refinery throughput (bpd):
Sweet crude oil	96,384		93,654		94,404
Sour crude oil	25,113		25,195		24,792
Other feedstocks and blendstocks	5,739		6,488		7,734
Total refinery throughput (bpd) (4)	127,236		125,337		126,930
Total sales volume (bpd) (3)	139,216		141,894		151,352
Per barrel of throughput:
Refinery gross margin (2) (5)	$	18.34	$	18.74	$	28.25
Direct operating expenses (6)	4.37		4.30		4.50

Gallup Refinery

	Year Ended
	December 31,
	2014		2013		2012
Key Operating Statistics
Refinery product yields (bpd):
Gasoline	17,027		16,675		14,867
Diesel and jet fuel	8,858		6,980		6,624
Other	1,443		758		766
Total refinery production (bpd)	27,328		24,413		22,257
Refinery throughput (bpd):
Sweet crude oil	25,130		23,635		20,941
Other feedstocks and blendstocks	2,653		1,457		1,938
Total refinery throughput (bpd) (4)	27,783		25,092		22,879
Total sales volume (bpd) (3)	34,300		34,759		32,718
Per barrel of throughput:
Refinery gross margin (2) (5)	$	16.55	$	18.94	$	28.25
Direct operating expenses (6)	8.40		10.13		9.60

(1) Refining net sales for the year ended December 31, 2014, include $1,489.6 million representing a period average of 44,124 bpd in crude oil sales to third parties without comparable activity in 2013 or 2012. The majority of the crude oil sales resulted from the purchase of barrels in excess of what was required for production purposes in the El Paso and Gallup refineries.

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

	Year Ended
	December 31,
	2014		2013			2012
	(In thousands)
Realized hedging gain (loss), net	$	82,937	$	17,714		$	(120,805	)
Unrealized hedging gain (loss), net	197,223		(16,898		)	(229,672		)
Total hedging gain (loss), net	$	280,160	$	816		$	(350,477	)

(3) Sales volume includes sales of refined products sourced primarily from our refinery production as well as refined products purchased from third parties. We purchase additional refined products from third parties to supplement supply to our customers. These products are similar to the products that we currently manufacture and represented 9.84%, 14.44% and 13.83% of our total consolidated sales volumes for the years ended December 31, 2014, 2013 and 2012, respectively. The majority of the purchased refined products are distributed through our refined product sales activities in the Mid-Atlantic region where we satisfy our refined product customer sales requirements through a third-party supply agreement.

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

(5) Refinery gross margin is a per barrel measurement calculated by dividing the difference between net sales and cost of products sold by our refineries’ total throughput volumes for the respective periods presented. Net realized and net non-cash unrealized economic hedging gains and losses included in the combined refining segment gross margin are not allocated to the individual refineries. Cost of products sold does not include any depreciation or amortization. Refinery gross margin is a non-GAAP performance measure that we believe is important to investors in evaluating our refinery performance as a general indication of the amount above our cost of products that we are able to sell refined products. Each of the components used in this calculation (net sales and cost of products sold) can be reconciled directly to our statement of operations. Our calculation of refinery gross margin may differ from similar calculations of other companies in our industry, thereby limiting its usefulness as a comparative measure. Refinery gross margin in the current year is not entirely comparable to the prior year as a result of a full year of fees paid by our refining segment to WNRL compared to 2013 fees paid only for the period after the Offering through December 31, 2013.

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

	Year Ended
	December 31,
	2014		2013		2012
Net sales (including intersegment sales)	$	8,496,576	$	7,693,829	$	8,339,492
Cost of products sold (exclusive of depreciation and amortization)	7,188,928		6,656,778		7,133,308
Depreciation and amortization	81,726		85,712		77,575
Gross profit	1,225,922		951,339		1,128,609
Plus depreciation and amortization	81,726		85,712		77,575
Refinery gross margin	$	1,307,648	$	1,037,051	$	1,206,184
Refinery gross margin per refinery throughput barrel	$	23.11	$	18.89	$	22.01
Gross profit per refinery throughput barrel	$	21.67	$	17.33	$	20.60

(6) Refinery direct operating expenses per throughput barrel is calculated by dividing direct operating expenses by total throughput volumes for the respective periods presented. Direct operating expenses do not include any depreciation or amortization.

Gross Margin

Refinery gross margin is a function of net sales (including intersegment sales) less cost of products sold (exclusive of depreciation and amortization). Refinery gross margin increased from 2013 to 2014 due primarily to a higher net gain on hedging activities. Excluding the impact of our hedging activities, refining margin per throughput barrel declined slightly from 2013 to 2014, reflective of lower refining industry margins. The Gulf Coast benchmark 3:2:1 crack spread decreased from $19.97 in 2013 to $15.81 in 2014. The Gulf Coast crack spread was negatively impacted by the lower discount of WTI crude

44

oil to Brent crude oil, which declined from $10.67 per barrel in 2013 to $5.66 in 2014. However, during 2014, refining margins at our El Paso refinery benefited from the positive impact of the discount of WTI Midland crude oil to WTI Cushing crude oil (the "WTI Midland/Cushing differential"). The WTI Midland/Cushing differential averaged $6.92 per barrel for 2014 compared to $2.63 in 2013. This discount has been volatile and fluctuates based on local crude oil production, crude oil outflow at Cushing and regional refining throughput volumes.

Refinery gross margin decreased from 2012 to 2013 due primarily to a lower refining industry margin environment, partially offset by the difference in the results of our hedging activities in 2013 compared to 2012. The Gulf Coast benchmark 3:2:1 crack spread decreased from $28.79 in 2012 to $19.97 in 2013, which was negatively impacted by the lower discount of WTI crude oil to Brent crude oil during 2013. The WTI/Brent discount decreased from a per barrel average of $17.48 to $10.67 year over year. Additionally, the decreased WTI Midland/Cushing discount in 2013 negatively impacted the refining margin at our El Paso refinery. The WTI Midland/Cushing discount averaged $2.63 per barrel for 2013 compared to $4.06 in 2012.

Historical refining margin data is presented below.

During 2014, we recognized a net realized and unrealized gain from economic hedging activities of $280.2 million compared to a gain of $0.8 million in 2013 and a loss of $350.5 million in 2012. We enter into hedge contracts to manage our exposure to commodity price risks or to fix sales margins on future gasoline and distillate production. Unrealized mark-to-market gains and losses related to our economic hedging instruments are the result of differences between forward crack spreads and the fixed margins from our hedge contracts. We incur unrealized commodity hedging losses when forward spreads are in excess of our fixed contract margins. Hedging gains or losses are included within cost of product sold, directly impacting our refining gross margin. We also recognized the negative margin impact of the higher cost of purchased RINs. RINs costs were $28.2 million, $30.5 million and $4.0 million for the year ended December 31, 2014, 2013 and 2012, respectively.

Total refinery throughput increased from 2012 to 2013, and from 2013 to 2014 primarily due to Gallup refinery operational efficiencies gained from the October 2012 turnaround in both successive years. Gallup's increase in throughput was partially offset by lower El Paso throughput due to a scheduled turnaround of the north and south side units during the first quarter of 2013 and 2014, respectively. Also, our refined product sales volume was 79.4 million, 64.5 million and 67.4 million barrels in December 31, 2014, 2013 and 2012, respectively.

Direct Operating Expenses

The increase in direct operating expenses from 2013 to 2014 is primarily due to higher maintenance expense at our El Paso refinery ($16.7 million), property tax expense due to a 2013 refund of a 2012 property tax expense resulting from a corrected property appraisal ($10.8 million), energy expenses due to an increase in price and volume of natural gas ($8.4 million) and outside support services ($4.1 million).

The decrease in direct operating expenses from 2012 through 2013 was primarily due to lower property tax expense ($19.9 million) resulting from a corrected property appraisal for 2013 taxes and the refund of property taxes in 2013 paid for 2012, lower maintenance expenses ($13.7 million) and employee expenses ($2.8 million).

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Maintenance Turnaround Expenses

During the year ended December 31, 2014 we incurred turnaround expenses of $48.5 million for a turnaround of the south side units of the El Paso refinery, compared to 2013 turnaround expenses of $50.2 million, mainly related to turnaround activity at the north side units at El Paso. During the year ended December 31, 2012 we incurred $47.1 million in turnaround expenses in connection with the turnaround of our Gallup Refinery.

Depreciation and Amortization

Depreciation and amortization increased from 2013 to 2014 due to additional depreciation at our El Paso refinery primarily resulting from assets capitalized during the first quarter of 2013 and 2014 in El Paso.

Depreciation and amortization increased from 2012 to 2013 due to additional depreciation at our Gallup refinery ($4.8 million) and El Paso refinery ($2.9 million) primarily resulting from assets capitalized during the third and fourth quarters of 2012 in Gallup and the first quarter of 2013 in El Paso.

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NTI

The following table sets forth the summary operating results for NTI. The selected historical financial data for the 2013 period presented below represents the financial results from the period beginning November 12, 2013, through the period ended December 31, 2013. There is no comparable activity in periods prior to 2013.

	Period Ended December 31,
	2014			2013
	(In thousands, except key operating statistics)
Statement of Operations Data:
Net sales	$	5,159,657		$	686,824
Operating costs and expenses:
Cost of products sold (exclusive of depreciation and amortization) (1)	4,439,512			591,942
Direct operating expenses (exclusive of depreciation and amortization)	298,104			35,123
Selling, general and administrative expenses	91,482			11,651
Affiliate severance costs	12,878			—
Loss (gain) and impairments on disposal of assets, net	(92		)	10
Depreciation and amortization	76,544			10,740
Total operating costs and expenses	4,918,428			649,466
Operating income	$	241,229		$	37,358
Key Operating Statistics:
Total sales volume (bpd)	98,016			84,028
Total refinery production (bpd)	93,838			82,758
Total refinery throughput (bpd) (2)	93,525			82,261
Per barrel of throughput:
Refinery gross margin (1) (3)	$	15.91		$	18.06
Direct operating expenses (4)	4.77			5.05
Retail fuel gallons sold (in thousands)	306,777			40,031
Retail fuel margin per gallon (5)	$	0.22		$	0.17
Merchandise sales	349,145			27,958
Merchandise margin (6)	25.9		%	25.0		%
Company-operated retail outlets at period end	165			164
Franchised retail outlets at period end	89			75

(1) Cost of products sold for NTI includes the net realized and net non-cash unrealized hedging activity shown in the table below. The hedging losses are also included in the combined gross profit and refinery gross margin.

	Period Ended December 31,
	2014			2013
	(In thousands)
Realized hedging loss (gain), net	$	12,394		$	(1,846	)
Unrealized hedging gain, net	(2,800		)	—
Total hedging loss (gain), net	$	9,594		$	(1,846	)

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

(3) Refinery gross margin is a per barrel measurement calculated by dividing the difference between net sales and cost of products sold by our refinery's total throughput volumes for the respective period presented. The net realized and net non‑cash unrealized economic hedging losses included in NTI's gross margin are not allocated to the refinery. Cost of products sold does not include any depreciation or amortization. Refinery net sales and cost of products sold, respectively, include $1,194.7 million related to crude oil sales in 2014 and $118.5 million related to crude oil sales in 2013. Refinery gross margin is a non-GAAP performance measure that we believe is important to investors in evaluating our refinery

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

The following table reconciles gross profit for the St. Paul Park refinery to gross margin for the St. Paul Park refinery for the period presented:

	Period Ended December 31,
	2014		2013
	(In thousands, except per barrel data)
Net sales (including intersegment sales)	$	5,097,634	$	633,201
Cost of products sold (exclusive of depreciation and amortization)	4,554,658		557,453
Depreciation and amortization	67,538		9,485
Gross profit	475,438		66,263
Plus depreciation and amortization	67,538		9,485
Refinery gross margin	$	542,976	$	75,748
Refinery gross margin per refinery throughput barrel	$	15.91	$	18.06
Gross profit per refinery throughput barrel	$	13.93	$	15.79

(4) NTI's direct operating expenses per throughput barrel is calculated by dividing direct operating expenses by total throughput volumes for the respective periods presented. Direct operating expenses do not include any depreciation or amortization.

(5) Retail fuel margin per gallon is a measurement calculated by dividing the difference between retail fuel sales and retail fuel cost of products sold by the number of retail gallons sold. Retail fuel margin per gallon is a measure frequently used in the retail industry to measure operating results related to retail fuel sales.

(6) Merchandise margin is a measurement calculated by dividing the difference between merchandise sales and merchandise cost of products sold by merchandise sales. Merchandise margin is a measure frequently used in the retail industry to measure operating results related to merchandise sales.

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WNRL

The WNRL financial and operational data presented include the historical results of all assets acquired from Western in the Wholesale Acquisition. This acquisition from Western was a transfer of assets between entities under common control. Accordingly, the financial information for the WNRL Predecessor and WNRL has been retrospectively adjusted, to include the historical results of the WRW assets acquired, for periods prior to the effective date of the transaction. Our financial information includes the historical results of the Predecessor for periods prior to October 16, 2013, and the results of WNRL, beginning October 16, 2013, the date WNRL commenced operations, which have also been retrospectively adjusted.

	Year Ended
	December 31,
	2014		2013			2012
	(In thousands)
Statement of Operations Data:
Net sales, net of excise taxes	$	3,501,888	$	3,407,128		$	3,474,920
Operating costs and expenses:
Cost of products sold, net of excise taxes	3,244,919		3,279,717			3,379,087
Direct operating expenses	142,398		135,307			115,374
General and administrative expenses	22,540		17,661			17,141
Loss (gain) and impairments on disposal of assets, net	157		—			(509		)
Depreciation and amortization	17,372		15,970			14,315
Total operating costs and expenses	3,427,386		3,448,655			3,525,408
Operating income (loss)	$	74,502	$	(41,527	)	$	(50,488	)

	Year Ended
	December 31,
	2014		2013		2012
	(In thousands, except per gallon/barrel data)
Key Operating Statistics:
Pipeline and gathering (bpd):
Mainline movements:
Permian/Delaware Basin system	24,644		3,258		—
Four Corners system (1)	37,485		38,091		33,629
Gathering (truck offloading):
Permian/Delaware Basin system	24,166		10,169		1,838
Four Corners system	11,550		8,814		6,105
Terminalling, transportation and storage (bpd):
Shipments into and out of storage (includes asphalt)	381,371		367,208		354,886
Wholesale:
Fuel gallons sold	1,147,860		1,073,538		1,064,255
Fuel gallons sold to retail (included in fuel gallons sold, above)	268,148		254,907		244,906
Fuel margin per gallon (2)	$	0.022	$	0.026	$	0.026
Lubricant gallons sold	12,082		11,793		11,492
Lubricant margin per gallon (3)	$	0.86	$	0.89	$	0.80
Crude oil trucking volume (bpd)	36,314		12,603		8,284
Average crude oil revenue per barrel	$	2.90	$	2.24	$	2.32

(1) Some barrels of crude oil movements to Western’s Gallup refinery are transported on more than one of our mainlines. Mainline movements for the Four Corners system include each barrel transported on each mainline.

49

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

(3) Lubricant margin per gallon is a measurement calculated by dividing the difference between lubricant sales, net of transportation charges, and lubricant cost of products sold by lubricant sales. Lubricant margin is a measure frequently used in the petroleum products wholesale industry to measure operating results related to lubricant sales.

Gross Margin

WNRL gross margin is a function of net sales, net of excise taxes, less cost of products sold, net of excise taxes. WNRL's logistic gross margin increased by $129.6 million from 2013 to 2014 and $31.6 million from 2012 to 2013 primarily due to the formation of WNRL on October 16, 2013. WNRL recognizes revenue for crude oil pipeline transportation and for crude oil and refined petroleum product terminalling and storage based on contractual rates and agreements. WNRL derived a substantial portion of its revenue from service revenues charged to Western. Prior to the Offering, Western did not charge or record revenue for intercompany gathering, pipeline transportation, terminalling and storage services.

WNRL's wholesale gross margin increased from 2013 to 2014 primarily due to truck freight revenue from crude oil gathering activity in the Permian Basin.

WNRL's wholesale gross margin increased from 2012 to 2013 primarily due to higher fuel volumes. In addition, lubricant margins per gallon increased year over year due to the increased sales price of lubricants without a corresponding increase in cost.

Direct Operating Expenses

WNRL's direct operating expenses increased from 2013 through 2014 primarily due to increased employee expense ($7.4 million), higher maintenance and higher materials and supplies due to equipment additions to certain transportation assets ($3.1 million) and addition of new property leases and increased rents for existing property leases ($1.6 million). Partially offsetting the increases was a decrease in WNRL logistics maintenance expense ($6.3 million).

Direct operating expenses expenses increased from 2012 through 2013 primarily due to increased WNRL logistics maintenance expense ($8.4 million).

WNRL's logistics maintenance costs are generally cyclical in nature. WNRL's terminal facilities are subject to recurring maintenance for normal wear and related maintenance costs are generally consistent from period to period. Routine service cycle for tank inspections and maintenance at WNRL's storage facilities is generally every 10 years. Pipelines are also subject to routine periodic inspections. When WNRL changes the service use of a storage tank, maintenance costs will generally be greater due to increased costs of tank cleaning and hazardous material disposal. The cost of WNRL's maintenance is dependent upon the level of repairs deemed necessary as a result of the inspection of the specified asset.

General and Administrative Expenses

General and administrative expenses increased from 2013 to 2014 primarily due to increased corporate overhead related to the Wholesale Acquisition ($5.8 million).

The increase in general and administrative expenses from 2012 to 2013 resulted from higher back office expense principally due to filling of positions during the later part of 2012 that were vacated in early 2012 when administrative functions were consolidated to a single location. This increase was partially offset by reduced facility costs from maintaining a single location in 2013 versus two locations in 2012.

Depreciation and Amortization

The increase in depreciation and amortization from 2013 through 2014 was primarily due to the ongoing expansion of WNRL's Delaware Basin logistics system and the addition of crude oil tanker trailers during the latter half of 2013 and 2014.

The increase in depreciation and amortization from 2012 through 2013 was primarily due to the ongoing expansion of WNRL's Delaware Basin logistics system.

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Retail

	Year Ended
	December 31,
	2014			2013			2012
	(In thousands, except per gallon data)
Statement of Operations Data:
Net sales (including intersegment sales)	$	1,395,903		$	1,402,564		$	1,435,947
Operating costs and expenses:
Cost of products sold (exclusive of depreciation and amortization)	1,233,632			1,254,212			1,286,685
Direct operating expenses (exclusive of depreciation and amortization)	118,468			111,320			105,980
Selling, general and administrative expenses	11,461			9,796			9,450
Gain on disposal of assets, net	(154		)	—			—
Depreciation and amortization	11,733			12,382			11,233
Total operating costs and expenses	1,375,140			1,387,710			1,413,348
Operating income	$	20,763		$	14,854		$	22,599
Key Operating Statistics:
Retail fuel gallons sold	309,884			302,759			291,244
Average retail fuel sales price per gallon, net of excise taxes	$	3.31		$	3.41		$	3.56
Average retail fuel cost per gallon, net of excise taxes	3.11			3.23			3.36
Retail fuel margin per gallon (1)	0.20			0.18			0.20
Merchandise sales	$	266,677		$	253,096		$	248,023
Merchandise margin (2)	28.8		%	28.8		%	29.0		%
Operating retail outlets at period end	230			228			222
Cardlock gallons sold	67,420			67,803			65,695
Cardlock margin per gallon	$	0.178		$	0.153		$	0.178
Operating cardlocks at period end	50			53			55

	Year Ended
	December 31,
	2014		2013		2012
	(In thousands, except per gallon data)
Net Sales
Retail fuel sales, net of excise taxes	$	903,948	$	914,463	$	924,599
Merchandise sales	266,677		253,096		248,023
Cardlock sales	214,714		225,466		223,877
Other sales	10,564		9,539		39,448
Net sales	$	1,395,903	$	1,402,564	$	1,435,947
Cost of Products Sold
Retail fuel cost of products sold, net of excise taxes	$	840,811	$	858,574	$	867,174
Merchandise cost of products sold	189,957		180,284		176,215
Cardlock cost of products sold	202,489		215,082		212,153
Other cost of products sold	375		272		31,143
Cost of products sold	$	1,233,632	$	1,254,212	$	1,286,685
Retail fuel margin per gallon (1)	$	0.20	$	0.18	$	0.20

(1) Retail fuel margin per gallon is a measurement calculated by dividing the difference between retail fuel sales and cost of retail fuel sales for our retail segment by the number of gallons sold. Retail fuel margin per gallon is a measure frequently used in the convenience store industry to measure operating results related to retail fuel sales.

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(2) Merchandise margin is a measurement calculated by dividing the difference between merchandise sales and merchandise cost of products sold by merchandise sales. Merchandise margin is a measure frequently used in the convenience store industry to measure operating results related to merchandise sales.

Gross Margin

Retail gross margin is a function of net sales (including intersegment sales) less cost of products sold (exclusive of depreciation and amortization). The increase in retail gross margin from 2013 to 2014 was primarily the result of a 2.4%increase in fuel volumes from 2013 to 2014 and an increase of 5.4% in merchandise gross margin from 2013 to 2014. Contributing to the increase in gross margin was the retail outlets added from 2013 to 2014. The number of stores increased from 228 in 2013 to 230 in 2014.

The decrease in retail gross margin from 2012 to 2013 was primarily the result of a decrease in both retail fuel margin per gallon and cardlock fuel margin per gallon. This decrease was partially offset by a 4.0%increase in fuel volumes from 2012 to 2013. The increase in fuel volumes was primarily due to retail outlets added during 2013 and retail outlets added mid-year 2012. The number of stores increased from 222 in 2012 to 228 in 2013.

Direct Operating Expenses

The increase in direct operating expenses from 2013 to 2014 was primarily due to expenses generated by retail outlets added mid-November 2013 and during 2014. The addition of the new outlets resulted in increased employee expense, credit card processing fees resulting from an increase in credit sales, property taxes, lease expense and utilities.

The increase in direct operating expenses from 2012 to 2013 was primarily due to $2.3 million of 2013 expenses generated by retail outlets added during 2012 and $0.6 million of 2013 expenses generated by retail outlets added during the fourth quarter of 2013. The addition of the new outlets resulted in increased employee expense, credit card processing fees resulting from the increase in credit sales, property taxes, lease expense and utilities.

Selling, General and Administrative Expenses

The increase in selling, general and administrative expenses from 2013 to 2014 was primarily due to increased outside support services resulting from outsourcing store audit services starting in May 2014.

The increase in selling, general and administrative expenses from 2012 to 2013 was primarily due to increased field and back office support personnel required to support the addition of new retail outlets during 2012.

Depreciation and Amortization

Depreciation and amortization remained relatively consistent from 2012 through 2014. The majority of the retail outlets added from 2012 through 2014 were through operating leases and were therefore not depreciated. The slight increase in depreciation and amortization from 2012 to 2013 was primarily due to accelerated depreciation of certain assets.

Outlook

Our refining margins, excluding hedging activities, were weaker in 2014 compared to 2013. The Gulf Coast benchmark 3:2:1 crack spread declined from an average of $19.97 in 2013 to an average of $15.81 in 2014. Western's and NTI's refining margins in recent years have benefited from the price relationship between WTI crude oil and Brent crude oil. Western and NTI both base their crude oil purchases on pricing tied to WTI, and during 2014 the discount of WTI crude oil to Brent crude oil declined to an average of $5.66 for the year ended December 31, 2014, compared to $10.67 in 2013. However, the WTI/Brent discount has been volatile recently due to continued strong growth of inland crude production and new and proposed crude oil pipeline capacity additions in the Permian Basin and in Cushing, Oklahoma. The WTI/Brent discount year-to-date through February 27, 2015 has averaged $3.88. The Gulf Coast benchmark 3:2:1 crack spread year-to-date through February 27, 2015 has averaged $14.70. Additionally, the WTI Midland/Cushing discount of $6.92 per barrel benefited our El Paso refining margins in 2014 compared to $2.63 in 2013. The growth of gathering activity on our Delaware Basin Logistics System has increased our deliveries of cost advantaged crude oil to our El Paso refinery. NTI’s location also allows them direct access, via the Minnesota Pipeline, to cost-advantaged crude oil from the Bakken Shale in North Dakota and other Canadian crude oils that may price at substantial discounts to WTI. We expect continued volatility in crude oil pricing differentials and crack spreads given the significant recent drop in Brent and WTI crude oil prices.

During 2013 and 2014 we experienced significant volatility in the pricing of ethanol RINs as refiners essentially achieved full utilization of ethanol in gasoline blends. We expect this volatility to continue as the industry strives to meet Renewable Fuel Standards obligations which have not yet been finalized for 2014 as of February 27, 2015.

On February 11, 2015 WNRL entered into an indenture under which it issued $300.0 million in aggregate principal amount of 7.5% Senior Notes (the "Notes") due 2023. The Partnership will pay interest on the Notes semi-annually in cash in arrears on February 15 and August 15 of each year, beginning on August 15, 2015. The Notes will mature on February 15,

52

2023. WNRL used the proceeds from the notes to repay the $269.0 million balance due under the WNRL Revolving Credit Facility on February 11, 2015.

Liquidity and Capital Resources

Our primary sources of liquidity are from cash from operations, cash on hand and Western Revolving Credit Facility availability. To a lesser extent, we also generate liquidity from the issuance of securities.

As of December 31, 2014, we had cash and cash equivalents of $431.2 million including NTI cash of $87.9 million and WNRL cash of $54.3 million, non-current restricted cash of $167.0 million and had no direct borrowings under the Western and NTI revolving credit facilities. The $167.0 million of restricted cash relates to net proceeds from the sale of Western wholesale assets to WNRL. Western, NTI and WNRL had net availability under their revolving credit facilities of $405.0 million, $296.2 million and $31.0 million, respectively. As a result, Western had $694.0 million in total liquidity as of December 31, 2014, defined as Western’s cash and cash equivalents plus net availability under the Western Revolving Credit Facility. On October 15, 2014 WNRL borrowed $269.0 million under the WNRL Revolving Credit Facility to partially fund the Wholesale Acquisition. On September 22, 2014, through a private placement, NTI increased its aggregate principal amount of its 7.125% senior secured notes by $75.0 million, generating cash proceeds of $79.2 million including a premium of $4.2 million. NTI used the cash proceeds to fund the purchase of crude oil inventories in connection with the termination of an intermediation agreement with JPM CCC. See Note 15, Long-Term Debt in the Notes to Consolidated Financial Statements included in this annual report for detailed information regarding our financing.

See Part I — Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities included in this annual report and Note 20, Equity, in the Notes to Consolidated Financial Statements included in this annual report for detailed information regarding our share repurchase programs.

Cash Flows

The following table sets forth our cash flows for the periods indicated:

	Year Ended December 31,
	2014			2013			2012
	(In thousands)
Cash flows provided by operating activities	$	737,633		$	441,153		$	916,353
Cash flows provided by (used in) investing activities	(380,864		)	(895,885		)	18,506
Cash flows provided by (used in) financing activities	(393,680		)	468,835			(651,721		)
Net increase in cash and cash equivalents	$	(36,911	)	$	14,103		$	283,138

The increase in net cash from operating activities from 2013 to 2014 was primarily the result of the increase in net income and the results of our commodity hedging activity as discussed above offset by changes in our working capital as disclosed in our Consolidated Statements of Cash Flows for the years ended December 31, 2014 and 2013. The change in working capital was an increase of $482.6 million and was primarily due to increases in cash, inventories and accounts payable and accrued liabilities and decreases in prepaid expenses. The increase in inventories was primarily due to the termination of a crude oil intermediation agreement with JPM CCC and purchase of the related crude oil inventories at NTI. The decrease in prepaid expenses was primarily due to the timing of prepayments for crude oil to certain of our suppliers. The change in accounts payable and accrued liabilities was a matter of timing primarily due to accruals related to the El Paso refinery turnaround during the first quarter of 2014. The changes in deferred income taxes resulted primarily from the change in our net unrealized hedging activity between periods.

Cash flows provided by operating activities for the year ended December 31, 2014, combined with $269.0 million from borrowings under WNRL's Revolving Credit Facility and $79.2 million from the issuance of long-term debt were primarily used for the following investing and financing activities:

•Payment of cash dividends ($293.7 million);

•Purchase of treasury stock ($259.2 million);

•Fund capital expenditures ($223.3 million); and

•Repayment of debt ($6.1 million).

The increase in net cash from operating activities from 2012 to 2013 was primarily the result of the increase in net income and the results of our commodity hedging activity as discussed above offset by changes in our working capital as disclosed in our Consolidated Statements of Cash Flows for the years ended December 31, 2013 and 2012. The changes in components making up net income and results of our commodity hedging activity occurred for reasons discussed above. The

53

decrease in prepaid expenses was primarily due to the timing of prepayments for crude oil to certain of our suppliers. The changes in deferred income taxes resulted primarily from the change in our net unrealized hedging activity between periods. The change in accounts payable and accrued liabilities was a matter of timing primarily due to accruals related to the El Paso refinery turnaround during the first quarter of 2013. Major contributors to cash flows from financing and investing activities include the net cash used to acquire NTI of $698.8 million and net proceeds generated from the WNRL Offering of $323.1 million, respectively.

Cash flows provided by operating activities for the year ended December 31, 2013 combined with $900.0 million from the issuance of long-term debt were primarily used for the following investing and financing activities:

•Fund capital expenditures ($205.7 million);

•Repayment of debt ($349.8 million);

•Debt retirement fees ($24.4 million);

•Repayment of revolving credit facility ($50.0 million);

•Payment of cash dividends ($52.5 million); and

•Purchase of treasury stock ($252.8 million).

Working Capital

Total working capital at December 31, 2014 was $754.8 million, consisting of $1,768.5 million in current assets and $1,013.7 million in current liabilities. Working capital at December 31, 2013 was $448.7 million, consisting of $1,847.7 million in current assets and $1,399.0 million in current liabilities. Our working capital at December 31, 2014 and 2013 was as follows:

	December 31,
	2014		2013
	(In thousands)
Western	$	501,034	$	234,291
NTI	203,647		107,223
WNRL	50,081		107,153
Total	$	754,762	$	448,667

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Indebtedness

Our capital structure at December 31, 2014 and 2013 was as follows:

	December 31,
	2014		2013
	(In thousands)
Debt, including current maturities:
Western obligations:
Revolving Credit Facility	$	—	$	—
Term Loan Credit Facility due 2020	544,500		550,000
6.25% Senior Unsecured Notes due 2021	350,000		350,000
5.75% Convertible Senior Unsecured Notes, due 2014, net of conversion feature of $7,362 for 2013	—		207,925
5.50% promissory note due 2015	—		313
Total Western obligations	894,500		1,108,238
NTI obligations:
7.125% Senior Secured Notes, due November 2020	357,037		278,369
Revolving Credit Facility	—		—
Total NTI obligations	357,037		278,369
WNRL obligations:
Revolving Credit Facility	269,000		—
Total WNRL obligations	269,000		—
Long-term debt	1,520,537		1,386,607
Equity	2,787,644		2,570,587
Total capitalization	$	4,308,181	$	3,957,194

On February 11, 2015 WNRL entered into an indenture under which it issued $300.0 million in aggregate principal amount of 7.5% Senior Notes (the "Notes") due 2023. The Partnership will pay interest on the Notes semi-annually in cash in arrears on February 15 and August 15 of each year, beginning on August 15, 2015. The Notes will mature on February 15, 2023. WNRL used the proceeds from the notes to repay the $269.0 million balance due under the WNRL Revolving Credit Facility on February 11, 2015.

See Note 15, Long-Term Debt in the Notes to Consolidated Financial Statements included in this annual report for detailed information regarding our indebtedness.

Capital Spending

Capital expenditures totaled $223.3 million for the year ended December 31, 2014 and included improvement and regulatory projects for our refining group, WNRL and several smaller projects for our retail and corporate groups. Capital expenditures included $2.3 million of capitalized interest for 2014.

The following table summarizes the spending allocation between sustaining, discretionary and regulatory projects for 2015:

	Western (1)		NTI		WNRL (2)		Totals
	(In thousands)
Sustaining	$	45,874	$	26,500	$	11,010	$	83,384
Discretionary	162,129		35,000		31,769		228,898
Regulatory	42,152		8,500		1,387		52,039
Total	$	250,155	$	70,000	$	44,166	$	364,321

(1) Western's capital expenditure budget for 2015 is $250.2 million, of which $230.3 million is for our refining segment, $16.5 million for our retail segment and $3.3 million for other general projects.

(2) WNRL's 2015 budget was approved for up to $31.8 million is discretionary growth projects.

55

Sustaining Projects. Sustaining maintenance capital expenditures are those related to minor replacement of assets, refurbishing and replacement of components, fire protection, process safety management and other recurring and safety related capital expenditures.

Discretionary Projects. Discretionary capital expenditures are those primarily related to the economic returns and growth. Our discretionary projects include crude oil logistics projects, such as the new 70 miles of pipeline project in the Permian Basin of Southeast New Mexico that we expect to complete in the first quarter of 2015, as well as improvements on existing pipeline in San Juan Basin in Northwest New Mexico also projected to be completed in the first quarter of 2015. WNRL’s discretionary projects include improvement projects at the on-site refined product distribution terminals at the El Paso and Gallup refineries and the continued expansion of the Mason Station pipeline system.

Regulatory Projects. Regulatory projects are undertaken to comply with various regulatory requirements, including those related to environmental, health and safety matters. Our low sulfur fuel and low benzene gasoline projects are regulatory investments affected primarily by fuels regulations. The deadline for compliance with the final phase of the ultra low sulfur diesel regulations to reduce sulfur in locomotive and marine diesel was June 2012 and affects our El Paso refinery only. EPA regulation allows 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 utilization of our expanded El Paso diesel hydrotreater. We completed the following regulatory projects in 2013: EPA Initiative projects at our El Paso refinery, low benzene gasoline project at our Gallup refinery, upgraded wastewater treatment plant project at our Gallup refinery and expansion of our El Paso diesel hydrotreater.

Our capital spending on regulatory projects has decreased since 2012 due primarily to the completion of EPA initiative projects and other upgrades at our El Paso and Gallup refineries. The actual capital expenditures for the regulatory projects described above for the past three years are summarized in the table below:

	2014		2013		2012
	(In millions)
EPA Initiative projects	$	—	$	3.8	$	47.7
Low benzene gasoline	—		0.1		2.5
Wastewater Treatment Plant	—		0.7		17.0
DHT expansion in El Paso	0.5		2.6		1.3
Flare JA upgrades - El Paso and Gallup	1.3		—		—
Total	$	1.8	$	7.2	$	68.5

In 2012, the EPA finalized revisions to New Source Performance Standards ("NSPS") Subpart Ja that affected flares. Flares subject to the revised subpart have three years to comply. The revised subpart impacts the way flares at our refineries are designed and/or operated. We are planning capital projects at our refineries related to flare compliance with NSPS Subpart Ja that are expected to be implemented by 2015.

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

	2015		2016		2017
	(In millions)
Control room upgrades - El Paso and Gallup	$	19.5	$	2.5	$	—
Flare upgrades - El Paso and Gallup	6.8		—		—
Low sulfur gasoline - El Paso	2.5		2.0		—
Various other projects	5.7		4.3		5.0
Total	$	34.5	$	8.8	$	5.0

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Contractual Obligations and Commercial Commitments

Information regarding our contractual obligations of the types described below as of December 31, 2014, is set forth in the following table:

	Payments Due by Period
	Totals		2015		2016 and 2017		2018 and 2019		2020 and Beyond
	(In thousands)
Long-term debt obligations (1)	$	1,084,586	$	80,773	$	160,900	$	417,301	$	425,612
Capital lease obligations	44,000		2,589		5,098		5,004		31,309
Operating lease obligations	503,076		47,835		90,008		77,016		288,217
Purchase obligations (2)	2,178,050		528,690		1,057,380		591,980		—
Environmental reserves (3)	20,161		2,904		8,325		764		8,168
Uncertain tax positions (4)	12,000		12,000		—		—		—
Other obligations (5)(6)	519,429		16,571		32,613		161,952		308,293
Total obligations (7)	$	4,361,302	$	691,362	$	1,354,324	$	1,254,017	$	1,061,599

(1) Includes minimum principal payments and interest calculated using interest rates at December 31, 2014.

(2) Purchase obligations include agreements to buy crude oil and other raw materials. Amounts included in the table were calculated using the pricing at December 31, 2014 multiplied by the contract volumes.

(3) Our environmental liabilities are discussed in Note 23, Contingencies, in the Notes to Consolidated Financial Statements included elsewhere in this annual report.

(4) Includes accrued interest and penalties.

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

(6) We are obligated to make future expenditures related to our pension and postretirement obligations. These payments are not fixed and cannot be reasonably determined beyond 2019. As a result, our obligations beyond 2019 related to these plans are not included in the table. Our pension and postretirement obligations are discussed in Note 17, Retirement Plans, in the Notes to Consolidated Financial Statements included elsewhere in this annual report.

(7) Total contractual obligations include $755.9 million related to NTI including long-term debt, operating leases and environmental reserves.

Dividends and Distributions

We anticipate paying future quarterly dividends, subject to the board of directors' approval and compliance with the restrictions in our outstanding financing agreements. See Note 21, Earnings per Share in the Notes to Consolidated Financial Statements included in this annual report for detailed information regarding our dividends. See Note 30, Acquisitions and Note 29, Western Refining Logistics, LP for distribution information for NTI and WNRL, respectively.

Off-Balance Sheet Arrangements

We have no off-balance sheet arrangements.

Item 7A. Quantitative and Qualitative Disclosure About Market Risk

Commodity price fluctuation is our primary source of market risk.

Commodity Price Risk

We are exposed to market risks related to the volatility of crude oil and refined product prices, as well as volatility in the price of natural gas used in our refinery operations. Our financial results can be affected significantly by fluctuations in these prices that depend on many factors, including demand for crude oil, gasoline and other refined products; changes in the economy; worldwide and domestic production levels; worldwide inventory levels; and governmental regulatory initiatives. Our risk management strategy identifies circumstances in which we may utilize the commodity futures market to manage risk associated with these price fluctuations or to fix sales margins on future gasoline and distillate production.

In order to manage the uncertainty relating to inventory price volatility, we have generally applied a policy of maintaining inventories at or below a targeted operating level. In the past, circumstances have occurred, such as turnaround schedules or

57

shifts in market demand, that have resulted in variances between our actual inventory level and our desired target level. We may utilize the commodity futures market to manage these anticipated inventory variances.

We maintain inventories of crude oil, other feedstocks and blendstocks and refined products with values that are subject to wide fluctuations in market prices affected by worldwide economic conditions, regional and global inventory levels and seasonal conditions.

At December 31, 2014, we and our affiliates held approximately 9.3 million barrels of crude oil, refined product and other inventories valued under the LIFO valuation method with an average cost of $68.81 per barrel. At December 31, 2014, the excess of the current cost of our crude oil, refined product and other feedstock and blendstock inventories over aggregated LIFO costs was $28.4 million.

At December 31, 2013, we and our affiliates held approximately 6.8 million barrels of crude oil, refined product and other inventories valued under the LIFO valuation method with an average cost of $70.05 per barrel. At December 31, 2013, the excess of the current cost of our crude oil, refined product and other feedstock and blendstock inventories over aggregated LIFO costs was $193.6 million.

All commodity futures contracts, price swaps and options are recorded at fair value and any changes in fair value between periods are recorded under cost of products sold in our Consolidated Statements of Operations.

We selectively utilize commodity hedging instruments to manage our price exposure to our LIFO inventory positions or to fix margins on certain future sales volumes. The commodity hedging instruments may take the form of futures contracts, price and crack spread swaps or options, and are entered into with counterparties that we believe to be creditworthy. We elected not to pursue hedge accounting treatment for financial accounting purposes on instruments used to manage price exposure to inventory positions. The financial instruments used to fix margins on future sales volumes do not qualify for hedge accounting. Therefore, changes in the fair value of these hedging instruments are included in income in the period of change. Net gains or losses associated with these transactions are reflected within cost of products sold at the end of each period.

The following tables summarize our economic hedging activity recognized within cost of products sold for the three years ended December 31, 2014, and open commodity hedging positions as of December 31, 2014, and December 31, 2013:

	Year Ended December 31,
	2014		2013			2012
	(In thousands)
Economic hedging activities recognized within cost of products sold
Realized hedging gain (loss), net	$	95,331	$	15,868		$	(144,448	)
Unrealized hedging gain (loss), net	194,423		(16,898		)	(229,672		)
Total hedging gain (loss), net	$	289,754	$	(1,030	)	$	(374,120	)

	December 31, 2014			December 31, 2013
	(In thousands)
Open commodity hedging instruments (bbls)
Crude futures	(864		)	(768		)
Refined product price and crack spread swaps	(8,781		)	(25,721		)
Total open commodity hedging instruments	(9,645		)	(26,489		)
Fair value of outstanding contracts, net
Other current assets	$	79,722		$	8,791
Other assets	56,533			7
Accrued liabilities	(4,889		)	(17,386		)
Other long-term liabilities	(1,400		)	(55,869		)
Fair value of outstanding contracts - unrealized gain (loss), net	$	129,966		$	(64,457	)

During the three years ended December 31, 2014, we did not have any commodity derivative instruments that were designated or accounted for as hedges.

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Item 8. Financial Statements and Supplementary Data

Management’s Report on Internal Control Over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting. Internal control over financial reporting is defined in Rule 13a-15(f) or 15d-15(f) promulgated under the Securities Exchange Act of 1934 as a process designed by, or under the supervision of, our principal executive and principal financial officers and effected by our board of directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles and includes those policies and procedures that:

• Pertain to the maintenance of records that in reasonable detail accurately and fairly reflect our transactions and dispositions of the assets;

• Provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and the receipts and expenditures are being made only in accordance with authorizations of our management and directors; and

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

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Our management assessed the effectiveness of our internal control over financial reporting as of December 31, 2014, for Western Refining, Inc. and its subsidiaries. In making this assessment, our management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) in the 2013 Internal Control-Integrated Framework. Based on its assessment, our management believes that, as of December 31, 2014, our internal control over financial reporting is effective based on those criteria.

Our independent registered public accounting firm, Deloitte & Touche LLP, has issued an audit report on our internal control over financial reporting. This report appears on page 60 of this annual report.

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Report of Independent Registered Public Accounting Firm

The Board of Directors and Shareholders of

Western Refining, Inc.

El Paso, Texas

We have audited the internal control over financial reporting of Western Refining, Inc. and subsidiaries (the "Company") as of December 31, 2014, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying “Management's Report on Internal Control Over Financial Reporting”. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company's internal control over financial reporting is a process designed by, or under the supervision of, the company's principal executive and principal financial officers, or persons performing similar functions, and effected by the company's board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2014, based on the criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended December 31, 2014 of the Company and our report dated March 2, 2015 expressed an unqualified opinion on those financial statements.

/s/ DELOITTE & TOUCHE LLP

Phoenix, Arizona

March 2, 2015

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INDEX TO FINANCIAL STATEMENTS

	Page
Report of Independent Registered Public Accounting Firm	62
Consolidated Balance Sheets as of December 31, 2014 and 2013	63
Consolidated Statements of Operations for the Three Years ended December 31, 2014	64
Consolidated Statements of Comprehensive Income for the Three Years ended December 31, 2014	65
Consolidated Statements of Changes in Equity for the Three Years ended December 31, 2014	66
Consolidated Statements of Cash Flows for the Three Years ended December 31, 2014	67
Notes to Consolidated Financial Statements	68

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Report of Independent Registered Public Accounting Firm

The Board of Directors and Shareholders of

Western Refining, Inc.

El Paso, Texas

We have audited the accompanying consolidated balance sheets of Western Refining, Inc. and subsidiaries (the “Company”) as of December 31, 2014 and 2013, and the related consolidated statements of operations, comprehensive income, changes in equity, and cash flows for each of the three years in the period ended December 31, 2014. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Western Refining, Inc., and subsidiaries at December 31, 2014 and 2013, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2014, in conformity with accounting principles generally accepted in the United States of America.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2014, based on the criteria established in Internal Control-Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 2, 2015 expressed an unqualified opinion on the Company’s internal control over financial reporting.

/s/ DELOITTE & TOUCHE LLP

Phoenix, Arizona

March 2, 2015

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WESTERN REFINING, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In thousands, except share data)

	As of December 31,
	2014			2013
ASSETS
Current assets:
Cash and cash equivalents	$	431,159		$	468,070
Accounts receivable, trade, net of a reserve for doubtful accounts of $484 and $906, respectively	467,527			599,930
Inventories	629,237			557,388
Prepaid expenses	88,415			112,137
Other current assets	152,125			110,211
Total current assets	1,768,463			1,847,736
Restricted cash	167,009			—
Equity method investment	96,080			101,560
Property, plant and equipment, net	2,153,189			2,125,029
Goodwill	1,289,443			1,297,043
Intangible assets, net	85,952			78,098
Other assets, net	122,422			63,499
Total assets	$	5,682,558		$	5,512,965
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	681,803		$	879,019
Accrued liabilities	268,449			275,915
Deferred income tax liability, net	57,949			30,493
Current portion of long-term debt	5,500			213,642
Total current liabilities	1,013,701			1,399,069
Long-term liabilities:
Long-term debt, less current portion	1,515,037			1,172,965
Lease financing obligation	27,489			24,910
Deferred income tax liability, net	296,860			252,489
Other liabilities	41,827			92,945
Total long-term liabilities	1,881,213			1,543,309
Commitments and contingencies
Equity:
Western shareholders' equity:
Common stock, par value $0.01, 240,000,000 shares authorized; 102,642,540 and 91,827,731 shares issued, respectively	1,026			918
Preferred stock, par value $0.01, 10,000,000 shares authorized; no shares issued and outstanding	—			—
Additional paid-in capital	487,748			625,825
Retained earnings	890,393			624,213
Accumulated other comprehensive loss, net of tax	(1,291		)	(350		)
Treasury stock, 6,441,883 and 12,102,169 shares, respectively at cost	(258,168		)	(356,554		)
Total Western shareholders' equity	1,119,708			894,052
Non-controlling interest	1,667,936			1,676,535
Total equity	2,787,644			2,570,587
Total liabilities and equity	$	5,682,558		$	5,512,965

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

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WESTERN REFINING, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share data)

	Year Ended December 31,
	2014			2013			2012
Net sales	$	15,153,573		$	10,086,070		$	9,503,134
Operating costs and expenses:
Cost of products sold (exclusive of depreciation and amortization)	12,719,963			8,690,222			8,054,385
Direct operating expenses (exclusive of depreciation and amortization)	850,634			523,836			483,070
Selling, general and administrative expenses	226,020			137,031			114,628
Affiliate severance costs	12,878			—			—
Loss (gain) and impairments on disposal of assets, net	8,530			(4,989		)	(1,891		)
Maintenance turnaround expense	48,469			50,249			47,140
Depreciation and amortization	190,566			117,848			93,907
Total operating costs and expenses	14,057,060			9,514,197			8,791,239
Operating income	1,096,513			571,873			711,895
Other income (expense):
Interest income	1,188			746			696
Interest expense and other financing costs	(89,276		)	(68,040		)	(81,349		)
Amortization of loan fees	(7,786		)	(6,541		)	(6,860		)
Loss on extinguishment of debt	(9		)	(46,773		)	(7,654		)
Other, net	2,046			2,214			359
Income before income taxes	1,002,676			453,479			617,087
Provision for income taxes	(292,604		)	(153,925		)	(218,202		)
Net income	710,072			299,554			398,885
Less net income attributed to non-controlling interest	150,146			23,560			—
Net income attributable to Western Refining, Inc.	$	559,926		$	275,994		$	398,885
Net earnings per share:
Basic	$	6.17		$	3.35		$	4.42
Diluted	$	5.61		$	2.79		$	3.71
Weighted average common shares outstanding:
Basic	90,708			82,248			89,270
Diluted	101,190			104,904			111,822

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

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WESTERN REFINING, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(In thousands)

	Year Ended December 31,
	2014			2013			2012
Net income	$	710,072		$	299,554		$	398,885
Other comprehensive income items:
Benefit plans:
Amortization of net prior service cost	161			—			—
Reclassification of loss to income	21			47			48
Pension plan termination adjustment	—			217			978
Actuarial gain (loss)	(2,157		)	1,195			(13		)
Other comprehensive income before tax	(1,975		)	1,459			1,013
Income tax	295			(418		)	(375		)
Other comprehensive income, net of tax	(1,680		)	1,041			638
Comprehensive income	708,392			300,595			399,523
Less comprehensive income attributed to non-controlling interest	149,407			23,777			—
Comprehensive income attributable to Western Refining, Inc.	$	558,985		$	276,818		$	399,523

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

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WESTERN REFINING, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

(In thousands, except share data)

										Accumulated
	Common Stock									Other
				Additional						Comprehensive								Non-
	Shares	Par		Paid-In			Retained			Loss,			Treasury Stock					Controlling
	Issued	Value		Capital			Earnings			Net of Tax			Shares		Cost			Interest			Total
Balance at December 31, 2011	90,001,537	$	900	$	599,645		$	242,538		$	(1,812	)	(698,006	)	$	(21,443	)	$	—		$	819,828
Stock-based compensation	—	—		8,291			—			—			—		—			—			8,291
Restricted share and share unit vesting	959,103	10		(10		)	—			—			—		—			—			—
Excess tax benefit from stock-based compensation	—	—		4,413			—			—			—		—			—			4,413
Cash dividends declared of $2.74 per share	—	—		—			(240,715		)	—			—		—			—			(240,715		)
Net income	—	—		—			398,885			—			—		—			—			398,885
Other comprehensive loss, net of tax benefit of $375	—	—		—			—			638			—		—			—			638
Treasury stock, at cost	—	—		—			—			—			(3,324,135	)	(82,270		)	—			(82,270		)
Balance at December 31, 2012	90,960,640	910		612,339			400,708			(1,174		)	(4,022,141	)	(103,713		)	—			909,070
Net proceeds from issuance of common units - WNRL	—	—		—			—			—			—		—			323,146			323,146
Stock-based compensation	—	—		5,489			—			—			—		—			484			5,973
Restricted share and share unit vesting	867,091	8		(8		)	—			—			—		—			—			—
Excess tax benefit from stock-based compensation	—	—		8,362			—			—			—		—			—			8,362
Cash dividends declared of $0.64 per share	—	—		—			(52,489		)	—			—		—			—			(52,489		)
Net income	—	—		—			275,994			—			—		—			23,560			299,554
Other comprehensive loss, net of tax of $418	—	—		—			—			824			—		—			217			1,041
Convertible debt redemption	—	—		(357		)	—			—			—		—			—			(357		)
Acquisition of non-controlling interest in NTI	—	—		—			—			—			—		—			1,357,703			1,357,703
Distribution to non-controlling interest holders	—	—		—			—			—			—		—			(28,575		)	(28,575		)
Treasury stock, at cost	—	—		—			—			—			(8,080,028	)	(252,841		)	—			(252,841		)
Balance at December 31, 2013	91,827,731	918		625,825			624,213			(350		)	(12,102,169	)	(356,554		)	1,676,535			2,570,587
Stock-based compensation	—	—		4,338			—			—			—		—			15,565			19,903
Offering costs	—	—		—			—			—			—		—			66			66
Restricted share and share unit vesting	184,765	2		(2		)	—			—			—		—			—			—
Excess tax benefit from stock-based compensation	—	—		1,144			—			—			—		—			—			1,144
Cash dividends declared of $3.08 per share	—	—		—			(293,746		)	—			—		—			—			(293,746		)
Net income	—	—		—			559,926			—			—		—			150,146			710,072
Other comprehensive income, net of tax of $295	—	—		—			—			(941		)	—		—			(739		)	(1,680		)
Convertible debt redemption	10,630,044	106		(143,557		)	—			—			12,129,199		357,608			—			214,157
Distribution to non-controlling interest holders	—	—		—			—			—			—		—			(173,637		)	(173,637		)
Treasury stock, at cost	—	—		—			—			—			(6,468,913	)	(259,222		)	—			(259,222		)
Balance at December 31, 2014	102,642,540	$	1,026	$	487,748		$	890,393		$	(1,291	)	(6,441,883	)	$	(258,168	)	$	1,667,936		$	2,787,644

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

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WESTERN REFINING, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

	Year Ended December 31,
	2014			2013			2012
Cash flows from operating activities:
Net income	$	710,072		$	299,554		$	398,885
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	190,566			117,848			93,907
Changes in fair value - commodity hedging instruments	(194,423		)	16,899			229,672
Reserve for doubtful accounts	296			1,015			1,049
Amortization of loan fees and original issue discount	14,496			21,975			22,928
Loss on extinguishment of debt	9			46,773			7,654
Stock-based compensation expense	19,903			5,973			8,291
Deferred income taxes	71,827			(64,347		)	(57,998		)
Excess tax benefit from stock-based compensation	(1,144		)	(8,362		)	4,413
Income from equity method investment	(2,238		)	—			—
Loss (gain) and impairment on disposal of assets, net	8,530			(4,989		)	(1,891		)
Changes in operating assets and liabilities:
Accounts receivable	132,107			(129,531		)	1,342
Inventories	(71,849		)	37,803			(4,216		)
Prepaid expenses	23,722			(23,342		)	89,489
Other assets	22,312			(4,020		)	(6,213		)
Accounts payable and accrued liabilities	(190,209		)	126,120			117,460
Other long-term liabilities	3,656			1,784			11,581
Net cash provided by operating activities	737,633			441,153			916,353
Cash flows from investing activities:
Capital expenditures	(223,271		)	(205,677		)	(202,157		)
Proceeds from the sale of assets	1,936			7,475			308
Return of capital on equity method investment	7,480			1,140			—
Northern Tier Energy acquisition, net of cash acquired	—			(698,823		)	—
Decrease (increase) in restricted cash	(167,009		)	—			220,355
Net cash provided by (used in) investing activities	(380,864		)	(895,885		)	18,506
Cash flows from financing activities:
Additions to long-term debt	79,311			900,000			—
Payments on long-term debt	(6,072		)	(325,369		)	(322,908		)
Borrowings on revolving credit facility	269,000			—			—
Repayments of revolving credit facility	—			(50,000		)	—
Distribution to non-controlling interest holders	(173,637		)	(28,575		)	—
Debt retirement fees	—			(24,396		)	(1,415		)
Deferred financing costs	(9,649		)	(28,646		)	—
Purchase of treasury stock	(259,222		)	(252,841		)	(82,270		)
Dividends paid	(293,746		)	(52,489		)	(240,715		)
Convertible debt redemption	(809		)	(357		)	—
Net proceeds from issuance of WNRL common units	—			323,146			—
Excess tax benefit from stock-based compensation	1,144			8,362			(4,413		)
Net cash provided by (used in) financing activities	(393,680		)	468,835			(651,721		)
Net increase (decrease) in cash and cash equivalents	(36,911		)	14,103			283,138
Cash and cash equivalents at beginning of year	468,070			453,967			170,829
Cash and cash equivalents at end of year	$	431,159		$	468,070		$	453,967

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

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WESTERN REFINING, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Organization and Basis of Presentation

"Western," "we," "us," "our," and the "Company" refer to Western Refining, Inc. and, unless the context otherwise requires, our subsidiaries. Western Refining, Inc. was formed on September 16, 2005, as a holding company prior to our initial public offering and is incorporated in Delaware.

We produce refined products at three refineries: one in El Paso, Texas (131,000 barrels per day, or bpd), one near Gallup, New Mexico (25,000 bpd) and NTI's refinery in St. Paul Park, Minnesota (97,800 bpd). We sell refined products in Arizona, Colorado, the Mid-Atlantic region, New Mexico, the Upper Great Plains region and West Texas through bulk distribution terminals and wholesale marketing networks and we sell refined products through two retail networks with a total of 484 company-owned and franchised retail sites in the U.S.

On November 12, 2013, we acquired a 38.7% limited partner interest, and 100% of the general partner of NTI. NTI owns and operates a 97,800 bpd refinery in St. Paul Park, Minnesota. NTI has a retail-marketing network of 254 convenience stores. NTI directly operates 165 of these stores, including 2 owned and the remainder leased, and supports 89 stores through franchise agreements. NTI's primary areas of operation include Minnesota, South Dakota and Wisconsin.

During 2013, we formed WNRL as a Delaware master limited partnership to own, operate, develop and acquire terminals, storage tanks, pipelines and other logistics assets and related businesses. WNRL completed its initial public offering (the "Offering") on October 16, 2013. At December 31, 2014, we own a 66.2% limited partner interest in WNRL and the public held a 33.8% limited partner interest. We control WNRL through our 100% ownership of the general partner of WNRL and through control of the majority of outstanding common partnership units.

On October 15, 2014, in connection with a Contribution, Conveyance and Assumption Agreement (the "Contribution Agreement") dated September 25, 2014, we sold all of the outstanding limited liability company interests of Western Refining Wholesale, LLC ("WRW") to WNRL. The sale of WRW to WNRL was a reorganization of entities under common control. We have recast historical financial and operational data of WNRL, for all periods presented, to reflect the purchase and consolidation of WRW into WNRL. We refer to this transaction as the "Wholesale Acquisition." See Note 29, Western Refining Logistics, LP, for additional information on this transaction.

During the fourth quarter of 2014, we changed our reportable segments due to recent changes in our organization. Our operations include four business segments: refining, NTI, WNRL and retail. See Note 3, Segment Information, for further discussion of our business segments.

Demand for gasoline is generally higher during the summer months than during the winter months. As a result, our operating results for the first and fourth calendar quarters are generally lower than those for the second and third calendar quarters of each year. During 2014, the volatility in crude oil prices and refining margins also contributed to the variability of our results of operations for the four calendar quarters.

The accompanying consolidated financial statements have been prepared in accordance with U.S. generally accepted accounting principles (“GAAP”) for financial information and with the instructions to Form 10-K and Article 10 of Regulation S-X as it relates to quarterly information included in Note 28, Quarterly Financial Information.

2. Summary of Accounting Policies

Principles of Consolidation

The accompanying consolidated financial statements include the accounts of Western and our subsidiaries. All intercompany accounts and transactions have been eliminated for all periods presented.

Our consolidated financial statements include NTI and WNRL, neither wholly-owned. As the general partner of NTI and WNRL, we have the sole ability to direct the activities of NTI and WNRL that most significantly impact their respective economic performance.

NTI is an independent crude oil refiner and marketer of refined products and also operates retail convenience stores that sell various grades of gasoline, diesel fuel and convenience store merchandise in the Upper Great Plains region. NTI also owns and operates various storage and transportation assets, including a light products terminal, a heavy products terminal, storage tanks, rail loading/unloading facilities and a Mississippi River dock. NTI also owns a 17% interest in Minnesota Pipe Line Company, LLC ("MPL") that owns and operates the Minnesota Pipeline and a 455,000 bpd crude oil pipeline system that transports crude oil from the Enbridge pipeline hub at Clearbrook, Minnesota to NTI's St. Paul Park refinery. NTI's operations are separate from those of Western.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

WNRL gathers, transports and stores crude oil and refined product through their pipeline and gathering assets and terminalling, transportation, asphalt and storage assets. We are WNRL's primary customer and are also considered to be WNRL's primary beneficiary for accounting purposes.

We have non-controlling interests for NTI and WNRL of $327.6 million and $1,340.3 million, respectively, in our Consolidated Balance Sheet as of December 31, 2014.

Cash Equivalents

We consider all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents. Cash equivalents are stated at cost, which approximates market value. See Note 4, Fair Value Measurement for further information.

Restricted Cash

Restricted cash reported in our Consolidated Balance Sheet at December 31, 2014 relates to net proceeds from the sale of Western wholesale assets to WNRL. This cash is restricted through October 14, 2015 and must be used to either fund capital projects or to repay amounts outstanding under the Western 2020 Term Loan Credit Facility.

Accounts Receivable

Accounts receivable are due from a diverse customer base including companies in the petroleum industry, railroads, airlines and the federal government and is stated at the original invoice amount net of an allowance for uncollectible accounts as determined by historical experience and adjusted for economic uncertainties or known trends. Credit is extended based on an evaluation of our customer’s financial condition. In addition, a portion of the sales at our retail stores are on credit terms generally through major credit card companies. Past due or delinquency status of our trade accounts receivable are generally based on contractual arrangements with our customers.

Uncollectible accounts receivable are charged against the reserve for doubtful accounts when all reasonable efforts to collect the amounts due have been exhausted. Reserves for doubtful accounts related to trade receivables were $0.5 million, $0.9 million and $1.2 million for the years ended December 31, 2014, 2013 and 2012, respectively. Additions, deductions and balances for the reserve for doubtful accounts for the three years ended December 31, 2014, are presented below:

	Year Ended December 31,
	2014			2013			2012
	(In thousands)
Balance at January 1	$	906		$	1,166		$	1,884
Additions (1)	3,095			1,015			1,049
Reductions	(3,517		)	(1,275		)	(1,767		)
Balance at December 31	$	484		$	906		$	1,166

(1) Includes $0.2 million of additions to reserve for doubtful accounts for NTI as of December 31, 2013.

Inventories

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

WNRL's wholesale refined product, lubricants and related inventories are determined using the first-in, first-out ("FIFO") inventory valuation method. Refined product inventories originate from either our refineries or from third-party purchases. Retail refined product (fuel) inventory values are determined using the FIFO inventory valuation method. Retail merchandise inventory value is determined under the retail inventory method.

Equity Method Investment

NTI's common equity interest in MPL is accounted for using the equity method of accounting. Equity income from MPL represents our proportionate share of net income available to common equity owners generated by MPL.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

The equity method investment is assessed for impairment whenever changes in facts or circumstances indicate a loss in value has occurred. When the loss is deemed to be other than temporary, the carrying value of the equity method investment is written down to fair value, and the amount of the write-down is included in net income. See Note 8, Equity Method Investment for further disclosures.

MPL Investments Inc. ("MPLI") owns all of the preferred membership units of MPL. NTI's 17% interest in MPLI provides NTI no significant influence over MPLI and is accounted for as a cost method investment. The investment in MPLI was carried at a cost of $7.9 million and $7.9 million as of December 31, 2014 and 2013, respectively, and is included in other non-current assets in our Consolidated Balance Sheets.

Property, Plant and Equipment

Property, plant and equipment are stated at cost. We capitalize interest on expenditures for capital projects in process greater than one year and greater than $5 million until such projects are ready for their intended use.

Depreciation is provided on the straight-line method at rates based upon the estimated useful lives of the various classes of depreciable assets. The lives used in computing depreciation for such assets are as follows:

Refinery facilities and related equipment	3	—	25	years
Pipelines, terminals and transportation equipment	5	—	20	years
Wholesale facilities and related equipment	3	—	20	years
Retail facilities and related equipment	3	—	30	years
Other	3	—	10	years

Leasehold improvements are depreciated on the straight-line method over the shorter of the lease term or the improvement’s estimated useful life.

Expenditures for periodic maintenance and repair costs, including major turnaround expenses, are expensed when incurred. Such expenses are reported in direct operating expenses in our Consolidated Statements of Operations.

Goodwill

Goodwill represents the excess of the purchase price (cost) over the fair value of the net assets acquired and is carried at cost. We do not amortize goodwill for financial reporting purposes. We test goodwill for impairment at the reporting unit level. The reporting unit or units used to evaluate and measure goodwill for impairment are determined primarily from the manner in which the business is managed.

Our policy is to test goodwill for impairment annually at June 30, or more frequently if indications of impairment exist. The testing of our goodwill for impairment is based on the estimated fair value of our reporting units that is determined based on consideration given to discounted expected future cash flows using a weighted-average cost of capital rate. An assumed terminal value is used to project future cash flows beyond base years. In addition, various market-based methods including market capitalization and earnings before interest, taxes, depreciation and amortization ("EBITDA") multiples are considered. The estimates and assumptions used in determining fair value of a reporting unit require considerable judgment and are based on historical experience, financial forecasts and industry trends and conditions. The discounted cash flow model is sensitive to changes in future cash flow forecasts and the discount rate used. The market capitalization model is sensitive to changes in traded partnership unit price. The EBITDA model is sensitive to changes in recent historical results of operations within the refining industry. We compare and contrast the results of the various valuation models to determine if impairment exists at the end of a reporting period. Any declines in the market capitalization of NTI after December 31, 2014, could be an early indication that goodwill may become impaired in the future.

See Note 10, Goodwill for further disclosures.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Intangible Assets

Intangible assets, net, consist of both amortizable intangible assets, net of accumulated amortization, and intangible assets with indefinite lives. These intangible assets are primarily comprised of licenses, permits and rights-of-way related to our refining and retail operations. We amortize our intangible assets, such as rights-of-way, licenses and permits over their estimated economic useful lives, unless the economic useful lives of the assets are indefinite. If an intangible asset’s economic useful life is determined to be indefinite, then that asset is not amortized. We consider factors such as the asset’s history, our plans for that asset and the market for products associated with the asset when the intangible asset is acquired. We consider these same factors when reviewing the economic useful lives of our existing intangible assets as well. We evaluate the remaining useful lives of our intangible assets with indefinite lives at least annually at June 30. If events or circumstances no longer support an indefinite useful life, the intangible asset is tested for impairment and prospectively amortized over its remaining useful life.

Both amortizable intangible assets and intangible assets with indefinite lives must be tested for recoverability whenever events or changes in circumstances indicate that the carrying amount of those assets may not be recoverable. Amortizable intangible assets are not recoverable if their carrying amount exceeds the sum of the undiscounted cash flows expected to result from their use and eventual disposition. If an amortizable intangible asset is not recoverable, an impairment loss is recognized in an amount that its carrying amount exceeds its fair value generally based on discounted estimated net cash flows.

In order to test amortizable intangible assets for recoverability, management must make estimates of projected cash flows related to the asset being evaluated 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.

The risk of intangible asset impairment losses may increase to the extent that our results of operations or cash flows decline. Impairment losses may result in a material, non-cash write-down of intangible assets. Furthermore, impairment losses could have a material effect on our results of operations and shareholders’ equity.

Other Assets

Other assets consist primarily of commodity hedging activities receivable, loan origination fees and various other assets that are related to our general operation and are stated at cost. Amortization of loan origination fees is provided on a straight‑line basis over the term of the agreement that approximates the effective interest method.

Impairment of Long-Lived Assets

We review the carrying values of our long-lived assets for possible impairment whenever events or changes in circumstances indicate that the carrying amount of assets to be held and used may not be recoverable. A long-lived asset is not recoverable if its carrying amount exceeds the sum of the undiscounted cash flows expected to result from its use and eventual disposition. If a long-lived asset is not recoverable, an impairment loss is recognized in an amount that its carrying amount exceeds its fair value.

In order to test long-lived assets for recoverability, we must make estimates of projected cash flows related to the asset being evaluated 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 volumes, margins, cash flows, investment rates, interest/equity rates and growth rates that could significantly impact the estimated fair value of the asset being tested for impairment.

The risk of long-lived asset impairment losses may increase to the extent that our results of operations or cash flows decline. Impairment losses may result in a material, non-cash write-down of long-lived assets or intangible assets. Furthermore, impairment losses could have a material effect on our results of operations and shareholders’ equity.

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Revenue Recognition

We record sales revenues for refined products and crude oil upon delivery to customers; the point at which title is transferred, the customer has the assumed risk of loss and when payment has been received or collection is reasonably assured. Transportation, shipping and handling costs incurred are included in cost of products sold. Excise and other taxes collected from customers and remitted to governmental authorities are not included in revenues. In addition to the crude oil that we purchase to supply our refinery production, we also purchase crude oil quantities that are transported to different locations and sold to third parties. We record these sales on a gross basis with the sales price recorded as revenues and our corresponding purchase price within cost of products sold.

We enter into certain purchase and sale arrangements with the same counterparty that are deemed to be made in contemplation of one another. We combine these transactions and, as a result, revenues and cost of sales are not recognized in connection with these arrangements. We also enter into refined product exchange transactions to fulfill sales contracts with our customers by accessing refined products in markets where we do not operate our own refineries. These refined product exchanges are accounted for as exchanges of non-monetary assets, and no revenues are recorded on these transactions.

Cost Classifications

Refining cost of products sold includes cost of crude oil, other feedstocks and blendstocks, the costs of purchased refined products, transportation and distribution costs and realized and unrealized gains and losses related to our commodity hedging activities. WNRL's wholesale cost of products sold includes the cost of fuel and lubricants, transportation and distribution costs, service parts and labor and realized gains and losses related to our commodity hedging activities. Retail cost of products sold includes costs for motor fuels and for merchandise. Motor fuel cost of products sold represents net cost for purchased fuel. Net cost of purchased fuel excludes transportation and motor fuel taxes. Merchandise cost of products sold includes merchandise purchases, net of merchandise rebates and inventory shrinkage.

Refining direct operating expenses include direct costs of labor, maintenance materials and services, chemicals and catalysts, natural gas, utilities and other direct operating expenses. WNRL's wholesale direct operating expenses include direct costs of labor, transportation expense, maintenance materials and services, utilities and other direct operating expenses. Retail direct operating expenses include direct costs of labor, maintenance materials and services, outside services, bank charges, rent expense, utilities and other direct operating expenses. WNRL logistics operating and maintenance expenses include direct costs of labor, maintenance materials and services, natural gas, additives, utilities, insurance expense, property taxes and other direct operating expenses. NTI's direct operating expenses include employee and contract labor, maintenance and energy expenses consisting primarily of natural gas and electricity.

Maintenance Turnaround Expense

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

Stock-Based Compensation

The cost of employee services received in exchange for an award of equity instruments granted under the Western Refining 2006 Long-Term Incentive Plan and 2010 Incentive Plan of Western Refining, Inc. is measured based on the grant date fair value of the award. Awards may be in the form of restricted shares or restricted share units. The fair value of each restricted share or restricted share unit awarded was measured based on the market price of a share at closing as of the measurement date and is amortized on a straight-line basis over the respective vesting periods.

Recipients of restricted shares have voting and dividend rights on these shares from the date of grant.

Recipients of restricted share units do not have voting or dividend rights on the shares underlying these units until the units have vested, and if applicable, the underlying shares have been issued. Upon vesting, the recipient will be entitled to receive, at the Compensation Committee’s election, the number of shares underlying the restricted share units, a cash payment equal to the share value at the vesting date or a combination of both.

WNRL's general partner provides unit-based compensation to officers, non-employee directors and employees of its general partner or its affiliates. The fair value of WNRL's phantom units are measured based on the fair market value of the underlying common unit on the date of grant based on the closing price of the common units on the grant date. The estimated fair value of the phantom units is amortized over the vesting period using the straight-line method. Awards vest over a one or three year service period. The phantom unit awards may be settled in common units, cash or a combination of both at the option

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of the compensation committee of WNRL's board of directors. Expenses related to unit-based compensation are included in general and administrative expenses.

NTI recognizes compensation expense for equity-based awards issued under it 2012 Long-Term Incentive Plan ("NTI LTIP") over the requisite service period. Equity-based compensation costs are measured at the date of grant, based on the fair value of the award. The NTI LTIP permits the award of unit options, restricted units, phantom units, unit appreciation rights and other awards that derive their value from the market price of NTI LP’s common units. The restricted units are contingent upon NTI's achievement of a “cash available for distribution” target (as defined in the award agreement). The number of units ultimately issued under these grants can fluctuate above or below the target units (as defined in the award agreement) depending on actual cash available for distribution during the period.

Financial Instruments and Fair Value

Financial instruments that potentially subject us to concentrations of credit risk primarily consist of accounts receivable. We believe that our credit risk is minimized as a result of the credit quality of our customer base. Our financial instruments include cash equivalents, restricted cash, accounts receivable, accounts payable, accrued liabilities, debt, capital lease obligations and commodity derivative contracts. The estimated fair values of these financial instruments approximate their carrying amounts, except for certain debt as discussed in Note 4, Fair Value Measurement.

We enter into crude oil forward contracts to facilitate the supply of crude oil to the refinery. These contracts qualify for the normal purchases and normal sales exception because we physically receive and deliver the crude oil under the contracts and when we enter into these contracts, the quantities are expected to be used or sold over a reasonable period of time in the normal course of business. These transactions are reflected in cost of products sold in the period that delivery of the crude oil takes place.

In addition, we use crude oil and refined products futures, swap contracts, or options to mitigate the change in value for a portion of our LIFO inventory volumes subject to market price fluctuations and swap contracts to fix the margin on a portion of our future gasoline and distillate production. The physical volumes are not exchanged, and these contracts are net settled with cash. For instruments used to mitigate the change in value of volumes subject to market prices, we elected not to pursue hedge accounting treatment for financial accounting purposes, generally because of the difficulty of establishing and maintaining the required documentation that would allow for hedge accounting. The swap contracts used to fix the margin on a portion of our future gasoline and distillate production do not qualify for hedge accounting treatment.

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

See Note 4, Fair Value Measurement; Note 17, Retirement Plans and Note 18, Crude Oil and Refined Product Risk Management for further fair value disclosures.

Pension and Other Postretirement Obligations

Pension and other postretirement plan expenses and liabilities are determined on an actuarial basis and are affected by the market value of plan assets, estimates of the expected return on plan assets and assumed discount rates and demographic data.

Pension and other postretirement plan expenses and liabilities are determined based on actuarial valuations. Inherent in these valuations are key assumptions including discount rates, future compensation increases, expected return on plan assets, health care cost trends and demographic data. Changes in our actuarial assumptions are primarily influenced by factors outside of our control and can have a significant effect on our pension and other postretirement liabilities and costs. A defined benefit postretirement plan sponsor must (a) recognize in its statement of financial position an asset for a plan’s overfunded status or liability for the plan’s underfunded status, (b) measure the plan’s assets and obligations that determine its funded status as of the end of the employer’s fiscal year and (c) recognize, as a component of other comprehensive income, the changes in the funded status of the plan that arise during the year, but are not recognized as components of net periodic benefit cost. See Note 17, Retirement Plans.

Asset Retirement Obligations

We recognize the fair value of a liability for an asset retirement obligation (“ARO”) in the period that it is incurred if a reasonable estimate of fair value can be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. The increase in the ARO due to the passage of time is recorded as an operating expense (accretion expense). See Note 14, Asset Retirement Obligations.

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Environmental and Other Loss Contingencies

We record liabilities for loss contingencies, including environmental remediation costs when such losses are probable and can be reasonably estimated. Loss contingency accruals, including those for environmental remediation are subject to revision as further information develops or circumstances change and such accruals can take into account the legal liability of other parties. Where the available information is sufficient to estimate the amount of liability, that estimate is used. Where the information is only sufficient to establish a range of probable liability and no point within the range is more likely than another, the lower end of the range is used. See Note 23, Contingencies.

Liabilities for future remediation costs are recorded when environmental remedial efforts are probable and the costs can be reasonably estimated, generally on an undiscounted basis. Environmental liabilities acquired in a business combination may be discounted dependent upon specific circumstances related to each environmental liability acquired. The majority of our environmental obligations are recorded on an undiscounted basis. The timing and magnitude of these accruals generally are based on the completion of investigations or other studies or a commitment to a formal plan of action. Current regulations are applied in determining environmental liabilities and are based on best estimates of probable undiscounted future costs over the estimated period of time expected to complete the remediation activities using currently available technology as well as our internal environmental policies. Environmental liabilities are difficult to assess and estimate due to uncertainties related to the magnitude of possible remediation and the timing of such remediation. Such estimates are subject to change due to many factors, including the identification of new sites requiring remediation, changes in environmental laws and regulations and their interpretation, additional information related to the extent and nature of remediation efforts and potential improvements in remediation technologies. Amounts recorded for environmental liabilities are not reduced by possible recoveries from third parties. Recoveries of environmental remediation costs from other parties are recorded as assets when we deem their receipt probable.

Income Taxes

Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized to reflect temporary differences between the basis of assets and liabilities for financial reporting purposes and income tax purposes. Generally, deferred tax assets represent future income tax reductions while deferred tax liabilities represent income taxes that we expect to pay in the future. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The ultimate realization of our deferred tax assets depends upon generating sufficient future taxable income during the periods that the temporary differences become deductible or before any net operating loss and tax credit carryforwards expire. If recovery of deferred tax assets is not likely, our provision for taxes is increased by recording a valuation allowance against the deferred tax assets that management estimates will not ultimately be recoverable. As changes occur in management's assessments regarding our ability to recover our deferred tax assets, the tax provision is increased in any period that we determine that the recovery is not probable. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date.

We recognize the benefit of a tax position if that position will more likely than not be sustained in an audit, based on the technical merits of the position. If the tax position meets the more likely than not recognition threshold, the tax effect is recognized at the largest amount of the benefit that has greater than a fifty percent likelihood of being realized upon ultimate settlement. Liabilities created for unrecognized tax benefits are presented as a separate liability and are not combined with deferred tax liabilities or assets. We classify interest to be paid on an underpayment of income taxes and any related penalties as income tax expense.

We consolidate 100% of the activity of NTI and WNRL due to our ownership of the respective general partners. NTI and WNRL are both publicly held master limited partnerships, neither of which is taxable for federal income tax. We record income taxes on the portion of income or loss attributable to our respective ownership of NTI and WNRL.

Use of Estimates

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

We applied acquisition accounting for the purchase of NTI, with Western as the accounting acquirer. In accordance with the acquisition method of accounting, the price we paid for NTI has been allocated to the assets acquired and liabilities assumed based upon their estimated fair values at the date of the acquisition. The excess of the purchase price over fair value of the net assets acquired represents goodwill that was allocated at the reporting unit level.

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We performed our purchase price allocation for the acquisition of NTI on November 12, 2013. The estimated fair values of the assets acquired and liabilities assumed were based on the valuation of an independent appraisal as well as management’s evaluations of those assets and liabilities. See Note 30, Acquisitions, for a summary of the purchase price allocation.

Reclassifications

Certain reclassifications have been made to the prior year financial information in order to conform to our current presentation. Reclassifications have been made in Note 3, Segment Information, Note 9, Property, Plant and Equipment, Net, Note 11, Intangible Assets, Net, Note 15, Long-Term Debt and Note 17, Retirement Plans.

Recent Accounting Pronouncements

Recent changes in the Accounting Standards Codification ("ASC") related to the accounting and reporting requirements for disposals when such disposal represents a strategic shift that will have a significant impact on the entity’s operations and financial results are effective January 1, 2015. Among other new disclosure requirements, an entity will be required to make certain disclosures for individually material disposal transactions that do not meet the definition of a discontinued operation. These new requirements will be applied prospectively. Early adoption is permitted provided the disposal was not previously disclosed. Our adoption of these changes is not expected to have a material impact on our financial position, results of operations or cash flows.

The ASC accounting provisions covering the recognition and reporting of revenues were amended to remove inconsistencies in revenue requirements and to provide a more complete framework for addressing revenue issues across a broad range of industries and transaction types. The revised standard’s core principle is that a company should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. These provisions are effective January 1, 2017, and are to be applied retrospectively, with early adoption not permitted. We do not expect the adoption of this guidance to materially affect our financial position, results of operations or cash flows.

New provisions under the ASC that require management of an entity to evaluate whether there is substantial doubt about the entity’s ability to continue as a going concern and to provide related footnote disclosures will become effective for annual periods beginning after December 15, 2016, and interim periods thereafter with early application permitted. The changed requirements are intended to reduce diversity in the timing and content of footnote disclosures. We do not expect the adoption of these new provisions to materially affect our financial position, results of operations or cash flows as they only affect future disclosures.

New provisions under the ASC that cover reporting entities required to evaluate whether certain legal entities should be consolidated will become effective for interim and annual periods beginning on or after December 15, 2015. We do not expect the adoption of these new provisions to materially affect our financial position, results of operations or cash flows.

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

3. Segment Information

During the fourth quarter of 2014, we changed our reportable segments due to recent changes in our organization. Our operations are now organized into four operating segments based on manufacturing and marketing criteria and the nature of our products and services, our production processes and our types of customers. These segments are refining, NTI, WNRL and retail. The historical segment financial data was retrospectively adjusted for the periods presented. See Note 24, Concentration of Risk, for a discussion on significant customers. A description of each segment and the principal products follows:

Refining. We report the operations of two refineries in our refining segment: one in El Paso, Texas (the "El Paso refinery") with a 131,000 barrel per day (bpd) capacity and one near Gallup, New Mexico (the "Gallup refinery") with a 25,000 bpd capacity. Our refineries make various grades of gasoline, diesel fuel and other products from crude oil, other feedstocks and blending components. We purchase crude oil, other feedstocks and blending components from various third-party suppliers. We also acquire refined products through exchange agreements and from various third-party suppliers to supplement supply to our customers. We sell these products through WNRL's wholesale business and our retail segment, other independent wholesalers and retailers, commercial accounts and sales and exchanges with major oil companies. Net sales for the years ended December 31, 2014, 2013 and 2012, include $5.8 million, $22.2 million and $4.0 million, respectively, in business

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interruption recoveries related to processing outages that occurred during the first and fourth quarters of 2011 at our El Paso refinery.

We have 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. We recorded $0.1 million and $2.3 million in assets at December 31, 2014, and 2013, respectively, related to this supply agreement in our Consolidated Balance Sheets. The revenues and costs recorded under the supply agreement included $34.6 million and $0.5 million in net hedging gains for the year ended December 31, 2014, and 2012, respectively and $3.9 million in net hedging losses for the year ended December 31, 2013.

NTI. Through our acquisition of Northern Tier Energy GP LLC, NTI's general partner, Western acquired control of NTI during November 2013. NTI is an independent crude oil refiner and marketer of refined products with one97,800 bpd refinery and also operates a network of retail convenience stores selling various grades of gasoline, diesel fuel and convenience store merchandise in the Upper Great Plains region. NTI's operations are separate from those of Western. As of December 31, 2014, NTI included the operations of 165 retail convenience stores and supported 89 franchised retail convenience stores. These convenience stores are located primarily in Minnesota and Wisconsin. NTI's refinery supplies the majority of the gasoline and diesel sold through these convenience stores. NTI's results of operations for the year ended December 31, 2014, includes severance payments totaling $12.9 million related to Western's acquisition of NTI's general partner. See Note 30, Acquisitions, for additional information on this transaction.

WNRL. WNRL owns and operates terminal, storage, transportation and wholesale assets and provides related services primarily to our refining segment in the Southwest. WNRL was formed in 2013 to own, operate, develop and acquire logistics assets and related businesses. WNRL's assets consist of pipeline and gathering assets, terminalling, transportation and storage assets and wholesale assets in the Southwestern portion of the U.S., including approximately 300 miles of pipelines and approximately 8.0 million barrels of active storage capacity, as well as other assets. The majority of WNRL's assets are integral to the operations of Western's refineries located in El Paso, Texas and near Gallup, New Mexico. WNRL began its operations in October 2013. WNRL's accounting predecessor's operations were historically included in our refining segment's operations and were not considered to be a separate reporting segment prior to October 2013. WNRL's wholesale business includes the operations of several lubricant and bulk petroleum distribution plants and a fleet of refined product and lubricant delivery trucks. WNRL distributes commercial wholesale petroleum products primarily in Arizona, California, Colorado, Nevada, New Mexico and Texas. WNRL purchases petroleum fuels and lubricants from our refining segment and from third-party suppliers.

In the Wholesale Acquisition, WNRL purchased substantially all of Western’s southwest wholesale assets including assets and related inventories of WRW's lubricant distributions, southwest bulk petroleum fuels distribution, and crude oil and products transportation businesses. See Note 29, Western Refining Logistics, LP, for additional information on this transaction.

The WNRL financial and operational data presented include the historical results of all assets acquired from Western in the Wholesale Acquisition. This acquisition from Western was a transfer of assets between entities under common control. Accordingly, the financial information for the WNRL's accounting predecessor (the "WNRL Predecessor") and WNRL has been retrospectively adjusted, to include the historical results of the WRW assets acquired, for periods prior to the effective date of the transaction. Our financial information includes the historical results of the WNRL Predecessor, retrospectively adjusted due to the transaction, collectively defined as our "Predecessor," and the results of WNRL, beginning October 16, 2013, the date WNRL commenced operations, which have also been retrospectively adjusted.

Retail. Our retail segment sells various grades of gasoline, diesel fuel, convenience store merchandise and beverage and food products to the general public through retail convenience stores and various grades of gasoline and diesel fuel to commercial vehicle fleets through cardlocks. WNRL supplies the majority of gasoline and diesel fuel that our retail segment sells. We purchase general merchandise and beverage and food products from various third-party suppliers. At December 31, 2014, the retail segment operated 230 service stations and convenience stores or kiosks located in Arizona, Colorado, New Mexico and Texas compared to 228 and 222 service stations and convenience stores or kiosks at December 31, 2013 and 2012, respectively. The additional stores were added primarily under various operating leases. The operations of the additional retail stores did not have a significant impact on the operating income of the retail group in the year of addition. At December 31, 2014, the retail segment operated 50 cardlocks located in Arizona, California and New Mexico compared to 53 and 55 cardlocks at December 31, 2013 and 2012, respectively.

Segment Accounting Principles. Operating income for each segment consists of net revenues less cost of products sold; direct operating expenses; selling, general and administrative expenses; net impact of the disposal of assets; maintenance turnaround expense and depreciation and amortization. Cost of products sold includes net realized and unrealized gains and losses related to our commodity hedging activities and reflects current costs adjusted, where appropriate, for LIFO and LCM inventory adjustments. Intersegment revenues are reported at prices that approximate market.

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

The total assets of each segment consist primarily of cash and cash equivalents; inventories; net accounts receivable; net property, plant and equipment and other assets directly associated with the individual segment’s operations. Included in the total assets of the corporate operations are cash and cash equivalents; various net accounts receivable; prepaid expenses; other current assets; net deferred income tax items; net property, plant and equipment and other long-term assets.

Disclosures regarding our reportable segments with reconciliations to consolidated totals for the three years ended December 31, 2014, are presented below:

	Year Ended December 31, 2014
	Refining		NTI		WNRL (3)		Retail		Other			Consolidated
	(In thousands)
Net sales to external customers	$	6,151,208	$	5,134,618	$	2,490,313	$	1,376,328	$	1,106		$	15,153,573
Intersegment revenues (1)	3,334,526		25,039		1,011,575		19,575		—			—
Operating income (loss) (2)	$	836,952	$	241,229	$	74,502	$	20,763	$	(76,933	)	$	1,096,513
Other income (expense), net												(93,837		)
Income before income taxes												$	1,002,676
Depreciation and amortization	$	81,726	$	76,544	$	17,372	$	11,733	$	3,191		$	190,566
Capital expenditures	140,905		44,895		22,325		13,285		1,861			223,271
Goodwill at December 31, 2014	—		1,289,443		—		—		—			1,289,443
Total assets at December 31, 2014	1,719,989		2,235,614		327,962		224,271		1,174,722			5,682,558

(1) Intersegment revenues of $4,390.7 million have been eliminated in consolidation.

(2) The effect of our economic hedging activity is included within operating income of our refining and NTI segments as a component of cost of products sold. Refining and NTI cost of products sold include $280.2 million in net realized and unrealized economic hedging gains and $9.6 million in realized and unrealized economic hedging gains, respectively, for the year ended December 31, 2014.

(3) WNRL's financial data includes the Predecessor's historical financial results for the year ended December 31, 2014.

	Year Ended December 31, 2013
	Refining		NTI (3)		WNRL (4)			Retail		Other			Consolidated
	(In thousands)
Net sales to external customers	$	5,491,954	$	686,824	$	2,524,595		$	1,381,495	$	1,202		$	10,086,070
Intersegment revenues (1)	3,374,208		—		882,533			21,069		—			—
Operating income (loss) (2)	$	636,333	$	37,358	$	(41,527	)	$	14,854	$	(75,145	)	$	571,873
Other income (expense), net													(118,394		)
Income before income taxes													$	453,479
Depreciation and amortization	$	75,346	$	10,740	$	15,970		$	12,382	$	3,410		$	117,848
Capital expenditures	112,064		7,884		72,398			8,234		5,097			205,677
Goodwill at December 31, 2013	—		1,297,043		—			—		—			1,297,043
Total assets at December 31, 2013	1,682,656		2,109,407		384,317			207,008		1,129,577			5,512,965

(1) Intersegment revenues of $4,277.8 million have been eliminated in consolidation.

(2) The effect of our economic hedging activity is included within operating income of our refining segment as a component of cost of products sold. Refining cost of products sold includes $0.8 million in net realized and unrealized economic hedging gains for the year ended December 31, 2013.

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(3) The financial data for NTI represents the financial results for the period beginning November 12, 2013, through December 31, 2013.

(4) WNRL's financial data includes the Predecessor's historical financial results for the year ended December 31, 2013.

	Year Ended December 31, 2012
	Refining		WNRL (3)			Retail		Other			Consolidated
	(In thousands)
Net sales to external customers	$	5,467,547	$	2,622,610		$	1,411,863	$	1,114		$	9,503,134
Intersegment revenues (1)	4,033,011		852,310			24,084		—			—
Operating income (loss) (2)	$	806,269	$	(50,488	)	$	22,599	$	(66,485	)	$	711,895
Other income (expense), net											(94,808		)
Income before income taxes											$	617,087
Depreciation and amortization	$	65,955	$	14,315		$	11,233	$	2,404		$	93,907
Capital expenditures	160,764		28,076			9,678		3,639			202,157
Total assets at December 31, 2012	1,643,603		134,749			203,176		498,879			2,480,407

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

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

(3) WNRL's financial data includes the Predecessor's historical financial results for the year ended December 31, 2012.

4. Fair Value Measurement

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

The fair value hierarchy consists of the following three levels:

Level 1 Inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities.

Level 2 Inputs are quoted prices for similar assets or liabilities in an active market, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable and market-corroborated inputs that are derived principally from or corroborated by observable market data.

Level 3 Inputs are derived from valuation techniques that one or more significant inputs or value drivers are unobservable and cannot be corroborated by market data or other entity-specific inputs.

The carrying amounts of cash and cash equivalents and customer deposits included in accrued liabilities, all of which we consider Level 1 assets and liabilities, approximated their fair values at December 31, 2014, and December 31, 2013, due to their short-term maturities. Our fair value assessment incorporates a variety of considerations, including the short-term duration of the instruments and an evaluation of counterparty credit risk. Cash equivalents totaling $70.0 million and $45.0 million consisting of short-term money market deposits and commercial paper were included in the Consolidated Balance Sheets as of December 31, 2014 and 2013, respectively.

We maintain cash deposits with various counterparties in support of our hedging and trading activities. These deposits are required by counterparties as collateral and cannot be offset against the fair value of open contracts except in the event of default. Certain of our commodity derivative contracts under master netting arrangements include both asset and liability positions. We have elected to offset the fair value amounts recognized for multiple similar derivative instruments executed with the same counterparty under the column "Netting Adjustments" below, however, fair value amounts by hierarchy level are presented on a gross basis in the tables below. See Note 18, Crude Oil and Refined Product Risk Management, for further discussion of master netting arrangements.

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The following tables represent our assets and liabilities measured at fair value on a recurring basis as of December 31, 2014 and 2013, and the basis for that measurement:

	Carrying Value at December 31, 2014			Fair Value Measurement at December 31, 2014 Using							Netting Adjustments			Net Fair Value at December 31, 2014
				Level 1		Level 2			Level 3
	(In thousands)
Gross financial assets:
Current assets - commodity hedging contracts	$	86,659		$	—	$	86,329		$	330	$	(6,937	)	$	79,722
Other assets - commodity hedging contracts	58,182			—		58,182			—		(1,649		)	56,533
Gross financial liabilities:
Accrued liabilities - commodity hedging contracts	(11,826		)	—		(11,826		)	—		6,937			(4,889		)
Other long-term liabilities - commodity hedging contracts	(3,049		)	—		(3,049		)	—		1,649			(1,400		)
	$	129,966		$	—	$	129,636		$	330	$	—		$	129,966

	Carrying Value at December 31, 2013			Fair Value Measurement at December 31, 2013 Using								Netting Adjustments			Net Fair Value at December 31, 2013
				Level 1		Level 2			Level 3
	(In thousands)
Gross financial assets:
Current assets - commodity hedging contracts	$	14,344		$	—	$	14,082		$	262		$	(5,553	)	$	8,791
Other assets - commodity hedging contracts	183			—		183			—			(176		)	7
Gross financial liabilities:
Accrued liabilities - commodity hedging contracts	(22,939		)	—		(22,215		)	(724		)	5,553			(17,386		)
Other long-term liabilities - commodity hedging contracts	(56,045		)	—		(54,572		)	(1,473		)	176			(55,869		)
	$	(64,457	)	$	—	$	(62,522	)	$	(1,935	)	$	—		$	(64,457	)

Commodity hedging contracts designated as Level 3 financial assets are jet fuel crack spread swaps. Ultra-low sulfur diesel ("ULSD") pricing has had a strong historical correlation to jet fuel crack spread swaps. We estimate the fair value of our Level 3 instruments based on the differential between quoted market settlement prices on ULSD futures and quoted market settlement prices on jet fuel futures for settlement dates corresponding to each of our outstanding Level 3 jet fuel crack spread swaps. As quoted prices for similar assets or liabilities in an active market are available, we reclassify the underlying financial asset or liability and designate as Level 2 prior to final settlement.

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

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The following table presents the changes in fair value of our Level 3 assets and liabilities, excluding goodwill (all related to commodity price swap contracts) for the years ended December 31, 2014 and 2013.

	December 31,
	2014			2013
	(In thousands)
Liability balance at beginning of period	$	(1,935	)	$	(1,647	)
Change in fair value of Level 3 trades open at the beginning of the period	3,240			(753		)
Fair value of trades entered into during the period	(1,437		)	359
Fair value reclassification from Level 3 to Level 2	462			106
Asset (liability) balance at end of period	$	330		$	(1,935	)

Based on a hypothetical change of 10% to the estimated future cash flows attributable to our Level 3 commodity price swaps, the resulting estimated fair value change would be insignificant.

As of December 31, 2014 and 2013, the carrying amount and estimated fair value of our debt was as follows:

	December 31,
	2014		2013
	(In thousands)
Western obligations:
Carrying amount	$	894,500	$	1,108,238
Fair value	878,360		1,865,015
NTI obligations:
Carrying amount	$	357,037	$	278,369
Fair value	351,313		291,060
WNRL obligations:
Carrying amount	$	269,000	$	—
Fair value	269,000		—

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

There have been no transfers between assets or liabilities whose fair value is determined through the use of quoted prices in active markets (Level 1) and those determined through the use of significant other observable inputs (Level 2).

5. Inventories

Inventories were as follows:

	December 31,
	2014		2013
	(In thousands)
Refined products (1) (3)	$	257,476	$	275,865
Crude oil and other raw materials (2) (3)	318,565		227,187
Lubricants	14,265		16,032
Retail store merchandise	38,931		38,304
Inventories	$	629,237	$	557,388

(1) Includes $18.2 million and $24.1 million of inventory valued using the FIFO valuation method at December 31, 2014 and 2013, respectively.

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(2) During the third quarter of 2014, NTI terminated a crude oil intermediation agreement and subsequently purchased the entire crude oil inventory previously available to NTI under the intermediation agreement.

(3) During the fourth quarter of 2014, market prices of feedstocks and refined products decreased significantly. We reduced the carrying value of our inventory by $78.6 million in order to state the value at market prices which were lower than our cost at December 31, 2014. Refined products inventory includes a lower of cost or market non-cash adjustment of $41.7 million and crude oil and other raw materials inventory includes a lower of cost or market non-cash adjustment of $36.9 million at December 31, 2014.

We value our refinery inventories of crude oil, other raw materials and asphalt inventories at the lower of cost or market under the LIFO valuation method. Other than refined products inventories held by WNRL and our retail segment, refined products inventories are valued under the LIFO valuation method. WNRL's wholesale refined product, lubricants and related inventories are determined using the FIFO inventory valuation method. Retail refined product inventory values are determined using the FIFO inventory valuation method. Retail merchandise inventory value is determined under the retail inventory method.

As of December 31, 2014 and 2013, refined products valued under the LIFO method and crude oil and other raw materials totaled 9.3 million barrels and 6.8 million barrels, respectively. At December 31, 2014, the excess of the current cost of our crude oil, refined product and other feedstock and blendstock inventories over LIFO cost was $28.4 million. At December 31, 2013, the excess of the current cost of these crude oil, refined product and other feedstock and blendstock inventories over LIFO cost was $193.6 million. The non-cash impact of changes in our LIFO reserves decreased our cost of products sold for the years ended December 31, 2014 and 2012, by $222.0 million and $45.3 million, respectively, and increased our cost of products sold for the year ended December 31, 2013, by $65.4 million.

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

	Year Ended December 31,
	2014		2013		2012
	(In thousands, except per share amount)
Increase (decrease) in operating income	$	1,097	$	3,207	$	(4,040	)
Increase (decrease) net income	777		2,119		(2,612		)
Increase (decrease) in earnings per diluted share	$	0.01	$	0.02	$	(0.02	)

Average LIFO cost per barrel of our refined products and crude oil and other raw materials inventories as of December 31, 2014 and 2013, was as follows:

	December 31,
	2014					2013
	Barrels	LIFO Cost		Average LIFO Cost Per Barrel		Barrels	LIFO Cost		Average LIFO Cost Per Barrel
	(In thousands, except cost per barrel)
Refined products	3,707	$	283,333	$	76.43	3,320	$	251,763	$	75.83
Crude oil and other	5,577	355,470		63.74		3,517	227,187		64.60
	9,284	$	638,803	68.81		6,837	$	478,950	70.05

6. Prepaid Expenses

Prepaid expenses were as follows:

	December 31,
	2014		2013
	(In thousands)
Prepaid crude oil and other raw materials inventories	$	55,223	$	76,544
Prepaid insurance and other	33,192		35,593
Prepaid expenses	$	88,415	$	112,137

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7. Other Current Assets

Other current assets were as follows:

	December 31,
	2014		2013
	(In thousands)
Unrealized hedging gains	$	79,722	$	8,791
Material and chemical inventories	49,433		45,427
Excise and other taxes receivable	17,461		27,337
Margin account deposits	—		19,457
Exchange and other receivables	5,509		9,199
Other current assets	$	152,125	$	110,211

8. Equity Method Investment

NTI owns a 17% common equity interest in MPL. The carrying value of this equity method investment was $96.1 million and $101.6 million at December 31, 2014 and 2013, respectively.

Summarized financial information for MPL for the years ended December 31, 2014 and 2013 and as of December 31, 2014 and 2013, was as follows:

	Year Ended December 31,
	2014		2013
	(In thousands)
Net income	$	22,821	$	9,524
Net income attributable to MPL unitholders	13,168		8,174

	December 31, 2014		December 31, 2013
	(In thousands)
Current assets	$	9,578	$	26,061
Noncurrent assets	450,662		462,891
Total assets	$	460,240	$	488,952
Current liabilities	$	21,887	$	19,767
Noncurrent liabilities	—		—
Total liabilities	$	21,887	$	19,767
Equity	$	438,353	$	469,185

As of December 31, 2014 and 2013, respectively, the carrying amount of the equity method investment was $21.6 million and $21.8 million higher than the underlying net assets of the investee. We are amortizing this difference over the remaining life of MPL’s primary asset (the fixed asset life of the pipeline). There is no market for the common units of MPL and, accordingly, no quoted market price is available.

Distributions received from MPL were $7.5 million and $2.6 million, respectively, for the years ended December 31, 2014 and 2013. Equity income from MPL was $2.2 million and $1.4 million, respectively, for the years ended December 31, 2014 and 2013, and has been included in other, net in the accompanying Consolidated Statement of Operations.

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9. Property, Plant and Equipment, Net

Property, plant and equipment, net was as follows:

	December 31,
	2014			2013
	(In thousands)
Refinery facilities and related equipment	$	2,217,013		$	2,135,295
Pipelines, terminals and transportation equipment	369,080			274,561
Retail facilities and related equipment	288,338			263,009
Wholesale facilities and related equipment	57,158			54,426
Corporate	48,871			46,362
	2,980,460			2,773,653
Accumulated depreciation	(827,271		)	(648,624		)
Property, plant and equipment, net	$	2,153,189		$	2,125,029

Depreciation expense was $187.1 million, $114.7 million and $90.6 million for the years ended December 31, 2014, 2013 and 2012, respectively. Depreciation expense for the years ended December 31, 2014 and 2013, included $76.5 million and $10.7 million, respectively, of depreciation and amortization related to NTI.

10. Goodwill

At December 31, 2014 and 2013, we had goodwill of $1,289 million and $1,297.0 million, respectively, relating to the NTI acquisition that was completed on November 12, 2013. Declines in NTI's market capitalization could be an early indication that goodwill may become impaired in the future.

We test goodwill for impairment annually or more frequently if indications of impairment exist. Our testing for impairment of goodwill is based on the estimated fair value of the related reporting units that is determined based on consideration given to discounted expected future cash flows using a weighted-average cost of capital rate. An assumed terminal value is used to project future cash flows beyond base years. Various market-based methods including market capitalization, EBITDA multiples and refining complexity barrels are considered. The estimates and assumptions used in determining fair value of each reporting unit require considerable judgment and are based on historical experience, financial forecasts and industry trends and conditions. The discounted cash flow model is sensitive to changes in future cash flow forecasts and the discount rate used. The market capitalization model is sensitive to changes in NTI's traded unit price. The EBITDA and complexity barrel models are sensitive to changes in recent historical results of operations within the refining industry. We compare and contrast the results of the various valuation models to determine if impairment exists.

11. Intangible Assets, Net

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

	December 31, 2014							December 31, 2013							Weighted Average Amortization Period (Years)
	Gross Carrying Value		Accumulated Amortization			Net Carrying Value		Gross Carrying Value		Accumulated Amortization			Net Carrying Value
	(In thousands)
Amortizable assets:
Licenses and permits	$	20,427	$	(12,148	)	$	8,279	$	20,427	$	(10,558	)	$	9,869	5.3
Customer relationships	7,551		(3,366		)	4,185		7,551		(2,810		)	4,741		7.5
Rights-of-way and other	7,878		(3,613		)	4,265		5,922		(2,916		)	3,006		4.1
	35,856		(19,127		)	16,729		33,900		(16,284		)	17,616
Unamortizable assets:
Franchise rights and trademarks	50,500		—			50,500		42,900		—			42,900
Liquor licenses	18,723		—			18,723		17,582		—			17,582
Intangible assets, net	$	105,079	$	(19,127	)	$	85,952	$	94,382	$	(16,284	)	$	78,098

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Intangible asset amortization expense was $2.8 million, $2.8 million and $3.0 million for the years ended December 31, 2014, 2013 and 2012, respectively, based upon estimates of useful lives ranging from 1 to 23 years. Estimated amortization expense for the next five fiscal years is as follows (in thousands):

2015	$	2,696
2016	2,620
2017	2,679
2018	2,678
2019	2,011

12. Other Assets, Net

Other assets, net of amortization, were as follows:

	December 31,
	2014		2013
	(In thousands)
Unrealized hedging gains	$	56,533	$	7
Unamortized loan fees	40,383		40,320
Cost method investment	7,884		7,925
Other	17,622		15,247
Other assets, net of amortization	$	122,422	$	63,499

13. Accrued and Other Long-Term Liabilities

Accrued liabilities were as follows:

	December 31,
	2014		2013
	(In thousands)
Payroll and related costs	$	70,949	$	66,177
Excise taxes	58,556		58,313
Income taxes	48,170		57,316
Professional and other	32,237		36,503
Property taxes	17,567		16,258
Margin and other customer deposits	17,142		9,662
Interest	9,251		8,579
Fair value of open commodity hedging positions, net	4,889		17,386
Environmental reserves	8,377		3,605
Banking fees and other financing	1,311		2,116
Accrued liabilities	$	268,449	$	275,915

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Other long-term liabilities were as follows:

	December 31,
	2014		2013
	(In thousands)
Unrecognized tax benefits	$	12,000	$	11,106
Environmental reserves	10,086		6,587
Retiree plan obligations and other	10,802		12,056
Asset retirement obligations	7,539		7,327
Fair value of open commodity hedging positions, net	1,400		55,869
Other long-term liabilities	$	41,827	$	92,945

The table below summarizes changes in our environmental liability accruals:

	December 31, 2013		Increase (Decrease)		Payments			December 31, 2014
	(In thousands)
Discounted liabilities	$	—	$	4,169	$	(1,267	)	$	2,902
Undiscounted liabilities	10,192		6,620		(1,251		)	15,561
Total environmental liabilities	$	10,192	$	10,789	$	(2,518	)	$	18,463

See Note 23, Contingencies for further information regarding our environmental liabilities.

14. Asset Retirement Obligations

We determine the estimated fair value of our AROs based on the estimated current cost escalated by an inflation rate and discounted at a credit adjusted risk free rate. This liability is capitalized as part of the cost of the related asset and amortized using the straight-line method. The liability accretes until we have accrued the total estimated retirement obligation or we settle the liability.

We have identified the following AROs:

Crude Pipelines. Our rights-of-way agreements generally require that pipeline properties be returned to their original condition when the agreements are no longer in effect. This means that the pipeline surface facilities must be dismantled and removed and certain site reclamation performed. We do not believe these rights-of-way agreements will require us to remove the underground pipe upon taking the pipeline permanently out of service. However, certain regulatory requirements may mandate that we purge out of service underground pipe at the time we take the pipelines permanently out of service.

Storage Tanks. We have a legal obligation under applicable law to remove or close in place certain underground and aboveground storage tanks, both on owned property and leased property, once they are taken out of service. Under some lease arrangements, we have also committed to restore the leased property to its original condition.

Other. We have certain refinery piping and heaters as a conditional ARO since we have the legal obligation to properly remove or dispose of materials that contain asbestos that surround certain refinery piping and heaters.

The following table reconciles the beginning and ending aggregate carrying amount of our AROs for the three years ended December 31, 2014:

	December 31,
	2014			2013			2012
	(In thousands)
Liability, beginning of period	$	7,327		$	5,088		$	4,736
Liabilities incurred	17			11			43
Liabilities acquired	—			1,786			—
Liabilities settled	(313		)	(145		)	(33		)
Accretion expense	508			587			342
Liability, end of period	$	7,539		$	7,327		$	5,088

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NTI's ARO liability excludes $0.1 million of ARO classified as other accrued liabilities for both December 31, 2014 and 2013, respectively.

15. Long-Term Debt

Long-term debt was as follows:

	December 31,
	2014			2013
	(In thousands)
Western obligations:
Revolving Credit Facility due 2019	$	—		$	—
Term Loan Credit Facility due 2020	544,500			550,000
6.25% Senior Unsecured Notes due 2021	350,000			350,000
5.75% Convertible Senior Unsecured Notes, due 2014, net of conversion feature of $7,362 for 2013	—			207,925
5.50% promissory note due 2015	—			313
Total Western obligations	894,500			1,108,238
NTI obligations:
Revolving Credit Facility due 2018	—			—
7.125% Senior Secured Notes due 2020, net of unamortized premium of $7,037 and $3,369, respectively	357,037			278,369
Total NTI obligations	357,037			278,369
WNRL obligations:
Revolving Credit Facility due 2018	269,000			—
Total WNRL obligations	269,000			—
Long-term debt	1,520,537			1,386,607
Current portion of long-term debt	(5,500		)	(213,642		)
Long-term debt, net of current portion	$	1,515,037		$	1,172,965

As of December 31, 2014, annual long-term debt maturities through 2017 are $5.5 million. In 2018 and 2019, long-term debt maturities are $274.5 million and $5.5 million, respectively. Thereafter, total long-term debt maturities are $1,217.0 million.

Interest expense and other financing costs were as follows:

	Year Ended December 31,
	2014			2013			2012
	(In thousands)
Contractual interest:
Western obligations	$	51,114		$	42,768		$	58,409
NTI obligations	20,342			4,883			—
WNRL obligations	1,096			—			—
	72,552			47,651			58,409
Amortization of original issuance discount	7,352			15,502			16,068
Other interest expense	11,717			6,835			9,231
Capitalized interest	(2,345		)	(1,948		)	(2,359		)
Interest expense and other financing costs	$	89,276		$	68,040		$	81,349

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

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Western Obligations

Our payment of dividends is limited under the terms of the Western 2019 Revolving Credit Facility our Senior Unsecured Notes and the Western 2020 Term Loan Credit Facility, and in part, depends on our ability to satisfy certain financial covenants. Note guarantors will be released if they cease to a Restricted Subsidiary in a transaction permitted under the terms of the indenture, including through the disposition of capital stock of the guarantor.

Revolving Credit Facility

On April 11, 2013, we entered into the Second Amended and Restated Revolving Credit Agreement ("Western 2018 Revolving Credit Facility"). Lenders under the Western 2018 Revolving Credit Facility extended $900.0 million in commitments that mature on April 11, 2018 and incorporate a borrowing base tied to eligible accounts receivable and inventory. The Western 2018 Revolving Credit Facility also provides for letters of credit and swing line loans and provides for a quarterly commitment fee ranging from 0.25% to 0.50% per annum subject to adjustment based upon the average utilization ratio and letter of credit fees ranging from 1.75% to 2.25% per annum, payable quarterly, subject to adjustment based upon the average excess availability. Borrowings can be either base rate loans plus a margin ranging from 0.75% to 1.25% or LIBOR loans plus a margin ranging from 1.75% to 2.25%, in each case subject to adjustment based upon the average excess availability under the Western 2018 Revolving Credit Facility. The majority of Western's restricted subsidiaries fully and unconditionally guarantee the Western Revolving Credit Facility on a joint and several basis. The Western 2018 Revolving Credit Facility is secured by our cash and cash equivalents, accounts receivable and inventory.

On October 2, 2014, we entered into the Third Amended and Restated Revolving Credit Agreement ("Western 2019 Revolving Credit Facility"). Lenders committed $900.0 million, all of which will mature on October 2, 2019. The commitments under the Western 2019 Revolving Credit Facility may be increased in the future to $1.4 billion, subject to certain conditions (including the agreement of financial institutions, in their sole discretion, to provide such additional commitments). The amended terms of the agreement include revised borrowing rates. Borrowings can be either base rate loans plus a margin ranging from 0.50% to 1.00% or LIBOR loans plus a margin ranging from 1.50% to 2.00%, subject to adjustment based upon the average excess availability. The Western 2019 Revolving Credit Facility also provides for a quarterly commitment fee ranging from 0.250% to 0.375% per annum, subject to adjustment based upon the average utilization ratio, and letter of credit fees ranging from 1.50% to 2.00% per annum payable quarterly, subject to adjustment based upon the average excess availability. Borrowing availability under the Western 2019 Revolving Credit Facility is tied to the amount of our and our restricted subsidiaries' eligible accounts receivable and inventory. The Western 2019 Revolving Credit Facility is guaranteed, on a joint and several basis, by certain of our subsidiaries and will be guaranteed by certain newly acquired or formed subsidiaries, subject to certain limited exceptions. The Western 2019 Revolving Credit Facility is secured by our cash and cash equivalents, accounts receivable and inventory, but not our fixed assets. The Western 2019 Revolving Credit Facility contains certain covenants, including but not limited to, limitations on debt, investments, and dividends and the maintenance of a minimum fixed charge coverage ratio in certain circumstances.

As of December 31, 2014, we had no direct borrowings under the Revolving Credit Agreement, and we had net availability under the Western 2019 Revolving Credit Facility of $405.0 million consisting of $520.0 million in gross availability and $115.0 million in outstanding letters of credit.

Term Loan Credit Agreement

On November 12, 2013, we entered into a term loan credit agreement (the "Western 2020 Term Loan Credit Facility"). The Western 2020 Term Loan Credit Facility provides for loans of $550.0 million, matures on November 12, 2020 and provides for quarterly principal payments equal to 0.25% of the initial aggregate principal amount of term loans (as adjusted by any application of debt prepayment, to the extent applicable) with the remaining balance then outstanding due on the maturity date. The Western 2020 Term Loan Credit Facility bears interest at a rate based either on the base rate (as defined in the Western 2020 Term Loan Credit Facility) plus 2.50% or the Eurodollar Rate (as defined in the Western 2020 Term Loan Credit Facility) plus 3.50% (with a Euro dollar rate floor of 1.00%). The Western 2020 Term Loan Credit Facility is secured by both the El Paso and Gallup refineries and is fully and unconditionally guaranteed on a joint and several basis by substantially all of Western's material subsidiaries. The Western 2020 Term Loan Credit Facility contains customary restrictive covenants including limitations of debt, investments and dividends, and does not contain any financial maintenance covenants.

11.25% Senior Secured Notes

During the first and second quarters of 2013, we redeemed or otherwise purchased and canceled all outstanding Western Senior Secured Notes for $349.4 million, including $24.4 million in redemption fees, resulting in a loss on extinguishment of debt of $46.7 million including the write-off of $4.2 million of unamortized loan fees.

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6.25% Senior Unsecured Notes

On March 25, 2013, we entered into an indenture (the "Western 2021 Indenture") for the issuance of $350.0 million in aggregate principal amount of 6.25% Senior Unsecured Notes due 2021 (the "Western 2021 Senior Unsecured Notes"). The Western 2021 Senior Unsecured Notes are guaranteed on a senior unsecured basis by each of our wholly-owned domestic restricted subsidiaries that guarantee any of our indebtedness under our (a) Western 2019 Revolving Credit Facility or (b) any other Credit Facilities (as each such term is defined in the Western 2021 Indenture), or any capital markets debt, in the case of clause (b), in a principal amount of at least $150.0 million. The Western 2021 Senior Unsecured Notes and guarantees are our and each guarantor's general obligations and rank equally and ratably with all of our existing and future senior indebtedness and senior to our and the guarantors' subordinated indebtedness. The Western 2021 Senior Unsecured Notes are effectively subordinated in right of payment to all secured indebtedness (including secured indebtedness under the Western 2019 Revolving Credit Facility) to the extent of the value of the collateral securing such indebtedness. We pay interest on the Western 2021 Senior Unsecured Notes semi-annually in arrears on April 1 and October 1 of each year. The Western 2021 Senior Unsecured Notes mature on April 1, 2021.

The Western 2021 Indenture contains covenants that limit our ability to, among other things: pay dividends or make other distributions in respect of our capital stock or make other restricted payments; make certain investments; sell certain assets; incur additional debt or issue certain preferred shares; create liens on certain assets to secure debt; consolidate, merge, sell or otherwise dispose of all or substantially all of our assets; restrict dividends or other payments from restricted subsidiaries; and enter into certain transactions with our affiliates. The Western 2021 Indenture also provides for events of default that if any of them occurs would permit or require the principal, premium, if any, and interest on all the then outstanding Western 2021 Senior Unsecured Notes to be due and payable immediately.

5.75% Convertible Senior Unsecured Notes

On March 7, 2014, we provided notice to the Trustee and the holders (the “Noteholders”) of our 5.75% Convertible Senior Unsecured Notes (the "Western Convertible Notes") informing the Trustee and the Noteholders of our election, with respect to all conversions requested by Noteholders in accordance with the terms of the indenture received by the conversion agent on or after March 20, 2014, to settle conversions of the Western Convertible Notes through the issuance of shares of our common stock. On various dates between March 26, 2014, and June 2, 2014, we delivered an aggregate of 9,155 shares of common stock to Noteholders to satisfy the conversion of $87,000 aggregate principal amount of Western Convertible Notes based on conversion rates, dependent on conversion date, of 105.2394 or 105.8731 shares of common stock for each $1,000 of principal amount of Western Convertible Notes converted. On June 16, 2014, we delivered 22,750,088 shares of common stock to Noteholders, to satisfy the conversion of $214,881,000 aggregate principal amount of Western Convertible Notes, based on a conversion rate of 105.8731 shares of common stock for each $1,000 of principal amount of Western Convertible Notes converted.

In addition to these conversions, we paid cash for the remainder of the outstanding amount of the Western Convertible Notes with a nominal loss on extinguishment of debt.

NTI Obligations

NTI’s creditors have no recourse to Western or WNRL assets. Western or WNRL creditors have no recourse to the assets of NTI or its consolidated subsidiaries.

Revolving Credit Facility

On September 29, 2014, NTI entered into the Amended and Restated Revolving Credit Agreement (the "NTI Revolving Credit Facility"), increasing the aggregate principal amount available prior to the amendment and restatement from $300.0 million to $500.0 million. The NTI Revolving Credit Facility, which matures on September 29, 2019, incorporates a borrowing base tied to eligible accounts receivable and inventory and provides for up to $500.0 million for the issuance of letters of credit (of which, as of December 31, 2014, $308.3 million is committed) and up to $45.0 million for swing line loans. The NTI Revolving Credit Facility may be increased up to a maximum aggregate principal amount of $750.0 million, subject to certain conditions (including the agreement of financial institutions, in their sole discretion, to provide such additional commitments). Obligations under the NTI Revolving Credit Facility are secured by substantially all of NTI’s assets. Indebtedness under the NTI Revolving Credit Facility is recourse to Northern Tier Energy GP LLC, its general partner, and is guaranteed by NTI and certain of its subsidiaries. Borrowings under the NTI Revolving Credit Facility bear interest at either (a) a base rate plus an applicable margin (ranging between 0.50% and 1.00%) or (b) a LIBOR rate plus an applicable margin (ranging between 1.50% and 2.00%), in each case subject to adjustment based upon the average historical excess availability. In addition to paying interest on outstanding borrowings, NTI is also required to pay a quarterly commitment fee ranging from 0.250% to 0.375% subject to adjustment based upon the average utilization ration and letter of credit fees ranging from 1.50%

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to 2.00% subject to adjustment based upon the average historical excess availability. The NTI Revolving Credit Facility contains certain covenants, including but not limited to, limitations on debt, investments and dividends and the maintenance of a minimum fixed charge coverage ratio in certain circumstances. NTI incurred financing costs of $3.0 million associated with the amended and restated NTI Revolving Credit Facility.

As of December 31, 2014, the availability under the NTI Revolving Credit Facility was $296.2 million. This availability is net of $12.1 million in outstanding letters of credit. There were no borrowings under the NTI Revolving Credit Facility at December 31, 2014.

7.125% Secured Notes

On November 8, 2012, Northern Tier Energy LLC, its wholly owned subsidiary ("NTI LLC"), and Northern Tier Finance Corporation (together with NTI LLC, the "NTI 2020 Notes Issuers"), issued $275.0 million in aggregate principal amount of 7.125% senior secured notes due 2020 (the "NTI 2020 Secured Notes").

NTI increased the principal amount of the 2020 Secured Notes in September 2014 through issuance of a private placement of an additional $75.0 million in principal value at a premium of $4.2 million. This offering was issued under the same indenture as the existing 2020 Secured Notes and the new notes issued have the same terms as the existing notes. The offering generated cash proceeds of $79.2 million including an issuance premium of $4.2 million. NTI incurred financing costs of $2.5 million associated with this offering. The issuance premium will be amortized to interest expense over the remaining life of the notes.

The obligations under the NTI 2020 Secured Notes are fully and unconditionally guaranteed, jointly and severally, on a senior unsecured basis by Northern Tier Energy LP and on a senior secured basis by (i) all of NTI LLC’s restricted subsidiaries that borrow, or guarantee obligations, under the NTI Revolving Credit Facility or any other indebtedness of NTI LLC or another subsidiary of NTI LLC that guarantees the NTI 2020 Secured Notes and (ii) all other material wholly owned domestic subsidiaries of NTI LLC. The indenture governing the NTI 2020 Secured Notes contains covenants that limit or restrict dividends or other payments from restricted subsidiaries. Indebtedness under the NTI 2020 Secured Notes is guaranteed by NTI and certain of their subsidiaries.

WNRL Obligations

Revolving Credit Facility

On October 16, 2013, WNRL entered into a $300.0 million senior secured revolving credit facility ("WNRL Revolving Credit Facility"). WNRL has the ability to increase the total commitment of the revolving credit facility by up to $200.0 million for a total facility size of up to $500.0 million, subject to receiving increased commitments from lenders and to the satisfaction of certain conditions. The WNRL Revolving Credit Facility includes a $25.0 million sub-limit for standby letters of credit and a $10.0 million sub-limit for swing line loans. Obligations under the WNRL Revolving Credit Facility and certain cash management and hedging obligations are guaranteed by all of WNRL's subsidiaries and, with certain exceptions, will be guaranteed by any formed or acquired subsidiaries. Obligations under the WNRL Revolving Credit Facility are secured by a first priority lien on substantially all of WNRL's and its subsidiaries' significant assets. The WNRL Revolving Credit Facility will mature on October 16, 2018. Borrowings under the WNRL Revolving Credit Facility bear interest at either a base rate plus an applicable margin ranging from 0.75% to 1.75%, or at LIBOR plus an applicable margin ranging from 1.75% to 2.75%. The applicable margin will vary based upon WNRL's Consolidated Total Leverage Ratio, as defined in the WNRL Revolving Credit Facility. On October 15, 2014, to partially fund the purchase of certain assets from Western, WNRL borrowed $269.0 million under the WNRL Revolving Credit Facility.

As of December 31, 2014, the availability under the WNRL Revolving Credit Facility was $31.0 million. This availability is net of $269.0 million direct borrowings and there are no outstanding letters of credit under the WNRL Revolving Credit Facility at December 31, 2014.

The WNRL Credit Facility contains covenants that limit or restrict WNRL's ability to make cash distributions. WNRL is required to maintain certain financial ratios that are tested on a quarterly basis for the immediately preceding four quarter period.

7.5% Senior Notes

On February 11, 2015, WNRL entered into an indenture (the “WNRL Indenture”) among the Partnership, WNRL Finance Corp., a Delaware corporation and wholly-owned subsidiary of the Partnership (“Finance Corp.” and together with the Partnership, the “Issuers”), the Guarantors named therein and U.S. Bank National Association, as trustee (the “Trustee”) under which the Issuers issued $300.0 million in aggregate principal amount of 7.5% Senior Notes due 2023. The Partnership will pay

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interest on the 7.5% Senior Notes semi-annually in cash in arrears on February 15 and August 15 of each year, beginning on August 15, 2015. The Notes will mature on February 15, 2023. WNRL used the proceeds from the notes to repay the full balance due under the WNRL Revolving Credit Facility on February 11, 2015.

The WNRL Indenture contains covenants that limit WNRL’s and its restricted subsidiaries’ ability to, among other things: (i) incur, assume or guarantee additional indebtedness or issue preferred units, (ii) create liens to secure indebtedness, (iii) pay distributions on equity securities, repurchase equity securities or redeem subordinated indebtedness, (iv) make investments, (v) restrict distributions, loans or other asset transfers from the Partnership’s restricted subsidiaries, (vi) consolidate with or merge with or into, or sell substantially all of the Partnership’s properties to, another person, (vii) sell or otherwise dispose of assets, including equity interests in subsidiaries and (viii) enter into transactions with affiliates. These covenants are subject to a number of important limitations and exceptions. The WNRL Indenture also provides for events of default, which, if any of them occurs, would permit or require the principal, premium, if any, and interest on all the then outstanding Notes to be due and payable immediately.

16. Income Taxes

The following is an analysis of our consolidated income tax expense for the three years ended December 31, 2014:

	Year Ended December 31,
	2014		2013			2012
	(In thousands)
Current:
Federal	$	187,320	$	193,719		$	242,016
State	32,581		25,578			34,184
Total current	219,901		219,297			276,200
Deferred:
Federal	63,182		(62,954		)	(52,606		)
State	9,521		(2,418		)	(5,392		)
Total deferred	72,703		(65,372		)	(57,998		)
Provision for income taxes	$	292,604	$	153,925		$	218,202

We paid income tax, net of refunds, of $228.0 million, $223.6 million and $237.6 million for the years ended December 31, 2014, 2013 and 2012, respectively.

The following is a reconciliation of total income tax expense to income taxes computed by applying the 35% statutory federal income tax rate to income before income taxes for the three years ended December 31, 2014:

	Year Ended December 31,
	2014			2013			2012
	(In thousands)
Taxes at the federal statutory rate	$	350,937		$	158,718		$	215,980
State income taxes, net of federal tax benefit (1)	31,477			17,666			15,330
Valuation allowance for state net operating losses	(2,887		)	(2,776		)	2,791
Domestic Activity Production deduction	(11,900		)	(12,763		)	(15,059		)
Non-controlling interest	(50,044		)	(8,383		)	—
Federal tax credit for production of ultra low sulfur diesel	(15,486		)	—			—
Federal tax credit for increasing research activities (1)	(4,522		)	(999		)	(2,154		)
Other, net	(4,971		)	2,462			1,314
Total income tax expense	$	292,604		$	153,925		$	218,202

(1) The federal tax credit for increasing research activities includes $4.5 million, $1.0 million and $2.2 million in unrecognized tax benefits for the years ended December 31, 2014, 2013 and 2012, respectively. State income taxes, net of federal tax benefit, include $0.8 million and $4.8 million in unrecognized tax benefits for the years ended December 31, 2014 and 2012, respectively.

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The effective tax rates for 2014, 2013 and 2012 were 29.2%, 33.9% and 35.4%, respectively, as compared to the federal statutory rate of 35% in all years.

The Internal Revenue Service (the "IRS") has finalized examinations of our tax years ending December 31, 2007, 2008, 2009, 2010 and 2011. Due to statutory requirements, the tax years ending December 31, 2007 and 2008 required a review by the U.S. Joint Committee of Taxation prior to finalizing the audits. Western was notified in the third quarter that this review was completed and recorded a benefit relating to tax credits.

The following is a reconciliation of unrecognized tax benefits for the three years ended December 31, 2014:

	December 31,
	2014			2013		2012
	(In thousands)
Unrecognized tax benefits at beginning of year	$	10,571		$	9,572	$	—
Increases related to current year tax positions	1,500			999		9,572
Increases related to prior year tax positions	3,845			—		—
Decreases related to prior year tax positions	(2,154		)	—		—
Decreases resulting from the expiration of the statute of limitations	—			—		—
Unrecognized tax benefits at end of year	$	13,762		$	10,571	$	9,572

The unrecognized tax benefit as of December 31, 2014 of $13.8 million would affect our effective tax rate if recognized. We have accrued interest or penalties of $0.8 million with respect to the unrecognized tax benefit.

The tax years of 2008 through 2015 remain open to examination by the major tax jurisdictions to which we are subject (U.S. Federal, Texas, Virginia, Maryland, New Mexico, Arizona and California).

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

	December 31,
	2014									2013
	Assets			Liabilities			Net			Assets			Liabilities			Net
	(In thousands)
Current deferred taxes:
Inventories	$	—		$	(41,713	)	$	(41,713	)	$	—		$	(40,287	)	$	(40,287	)
Stock-based compensation	1,468			—			1,468			1,445			—			1,445
Commodity hedging activities	—			(29,572		)	(29,572		)	3,334			—			3,334
Debt discount	—			—			—			—			(2,820		)	(2,820		)
Other current, net	11,868			—			11,868			7,835			—			7,835
Current deferred taxes	13,336			(71,285		)	(57,949		)	12,614			(43,107		)	(30,493		)
Non-current deferred taxes:
Property, plant and equipment	—			(298,100		)	(298,100		)	—			(273,767		)	(273,767		)
Investment in WNRL	81,453			—			81,453			38,938			—			38,938
Investment in NTI	—			(64,013		)	(64,013		)	—			(44,127		)	(44,127		)
Postretirement obligations	3,175			—			3,175			1,072			—			1,072
Commodity hedging activities	—			(21,278		)	(21,278		)	21,395			—			21,395
Environmental and retirement obligations	3,489			—			3,489			2,736			—			2,736
Other non-current, net	—			(1,586		)	(1,586		)	1,036			—			1,036
Net operating loss and tax credit carryforwards	20,828			—			20,828			23,943			—			23,943
Valuation allowance	(20,828		)	—			(20,828		)	(23,715		)	—			(23,715		)
Non-current deferred taxes	88,117			(384,977		)	(296,860		)	65,405			(317,894		)	(252,489		)
Net deferred taxes	$	101,453		$	(456,262	)	$	(354,809	)	$	78,019		$	(361,001	)	$	(282,982	)

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At December 31, 2014, we had the following credits and net operating loss (“NOL”) carryforwards:

Type of Credit	Gross Amount			Tax Effected Amount			Expiration
	(In thousands)
State NOL carryforwards:
Virginia and Maryland	(7,297		)	(345		)	2023
Virginia and Maryland	(17,814		)	(757		)	2024
Virginia and Maryland	(521		)	(22		)	2026
Virginia and Maryland	(32,333		)	(1,374		)	2027
Virginia and Maryland	(58,866		)	(2,501		)	2028
Virginia and Maryland	(101,824		)	(4,326		)	2029
Virginia and Maryland	(137,313		)	(5,834		)	2030
Virginia and Maryland	(134,183		)	(5,669		)	2031
Total state NOL carryforwards	(490,151		)	(20,828		)
Less valuation allowance for operating loss carryforwards	490,151			20,828
Total credits and NOL carryforwards	$	—		$	—

In assessing the realizability of deferred tax assets, we determined that a valuation allowance of $20.8 million was appropriate against the deferred tax assets relating to the NOL carryforwards for Virginia and Maryland at December 31, 2014. We have decreased the valuation allowance for the NOL carryforwards by $2.9 million from December 31, 2013.

17. Retirement Plans

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

Pensions

Through December 31, 2013, we had distributed $25.7 million ($0.02 million in 2013, $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 idling of Yorktown refining operations in 2010 and resultant termination of several participants of the Yorktown cash balance plan. We received regulatory approval to terminate the defined benefit plan covering certain previous Yorktown refinery employees and did so during the second quarter of 2013. We recorded a termination loss of $1.8 million, including $0.6 million reclassified from other comprehensive income during 2013.

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

	As of December 31,
	2013
	(In thousands)
Benefit obligation at beginning of year	$	1,277
Interest cost	10
Termination benefits paid	(16		)
Actuarial loss	559
Settlement	(1,830		)
Benefit obligation at end of year	$	—
Fair value of plan assets at beginning of year	$	582
Company contribution	1,265
Actual return on plan assets	(1		)
Termination benefits paid	(16		)
Settlement	(1,830		)
Fair value of plan assets at end of year	$	—
Current liabilities	$	—
Noncurrent liabilities	—
Unfunded status recognized in the consolidated balance sheet	$	—
Accumulated benefit obligation	$	—

	Year Ended December 31,
	2013			2012
	(In thousands)
Net periodic benefit cost includes:
Interest cost	$	10		$	141
Expected return on assets	(3		)	(61		)
Amortization of net actuarial loss	2			6
Recognized settlement expense	—			978
Net periodic benefit cost	$	9		$	1,064
Pre-tax unrecognized net loss included in accumulated other comprehensive loss at beginning of year	$	219		$	1,550
Net actuarial loss (gain)	563			(347		)
Recognition of loss due to settlement	(780		)	(978		)
Amortization of net actuarial loss	(2		)	(6		)
Pre-tax unrecognized net loss included in accumulated other comprehensive loss at end of year	$	—		$	219

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	Year Ended December 31,
	2013		2012
Weighted average assumptions used to determine benefit obligations at December 31:
Discount rate	3.79	%	3.79	%
Rate of compensation increase	—		—
Weighted average assumptions used to determine net periodic benefit cost:
Discount rate	3.79		3.67
Expected long-term return on assets	1.90		1.90
Rate of compensation increase	—		—

NTI

NTI sponsors a defined benefit cash balance pension plan (the “Cash Balance Plan”) for eligible employees. Employer contributions are made to the cash account of the participants equal to 5.0% of eligible compensation. Participants’ cash accounts also receive interest credits each year based upon the average thirty year United States Treasury bond rate published in September preceding the respective plan year. Participants become fully vested in their accounts after three years of service.

NTI also sponsors a plan to provide retirees with health care benefits prior to age 65 (the “Retiree Medical Plan”) for eligible employees. Eligible employees may participate in the health care benefits after retirement subject to cost-sharing features. To be eligible for the Retiree Medical Plan, employees must have completed at least 10 years of service and be between the ages of 55 and 65 years old.

The following tables set forth significant information about the Cash Balance Plan and the Retiree Medical Plan (the "Plans"). The reconciliation of the benefit obligation, plan assets, funded status and significant assumptions are based upon an annual measurement date of December 31, 2014:

	Cash Balance Plan						Retiree Medical Plan
	As of December 31,
	2014			2013			2014			2013
	(In thousands)
Benefit obligation at beginning of period	$	4,560		$	2,332		$	2,113		$	2,384
Service cost	2,054			1,914			231			288
Interest cost	327			169			116			106
Actuarial (gain) loss	612			295			675			(648		)
Plan participants' contributions	—			—			18			8
Benefits paid	(588		)	(150		)	(55		)	(25		)
Benefit obligation at end of period	$	6,965		$	4,560		$	3,098		$	2,113
Fair value of plan assets at beginning of period	$	4,566		$	2,101		$	—		$	—
Employer contribution	200			2,500			37			17
Actual return on plan assets	141			115			—			—
Benefits paid	(588		)	(150		)	(55		)	(25		)
Plan participants' contributions	—			—			18			8
Fair value of plan assets at end of period	$	4,319		$	4,566		$	—		$	—
Non-current asset	$	—		$	6		$	—		$	—
Current liabilities	—			—			69			—
Non-current liabilities	2,646			—			3,029			2,113
Unfunded status recognized in the consolidated balance sheets	$	2,646		$	(6	)	$	3,098		$	2,113
Accumulated benefit obligation	$	6,965		$	4,560		$	3,098		$	2,113

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	Cash Balance Plan						Retiree Medical Plan
	As of December 31,
	2014			2013			2014			2013
	(In thousands)
Net periodic benefit cost includes:
Service cost	$	2,054		$	1,914		$	231		$	288
Interest cost	327			169			116			106
Expected return on assets	(218		)	(115		)	—			—
Recognized net actuarial loss	—			40			—			—
Amortization of prior service cost	25			—			137			161
Net periodic benefit cost	$	2,188		$	2,008		$	484		$	555
Changes recognized in other comprehensive income:
Prior service cost addition (amortization)	$	(24	)	$	—		$	(137	)	$	—
Net actuarial loss (gain)	687			(354		)	675			—
Pre-tax unrecognized net loss included in accumulated other comprehensive income at end of period	$	663		$	(354	)	$	538		$	—

	Cash Balance Plan				Retiree Medical Plan
	As of December 31,
	2014		2013		2014		2013
Weighted average assumptions used to determine benefit obligations at December 31:
Discount rate	4.00	%	5.00	%	4.00	%	5.00	%
Rate of compensation increase	3.00		4.00		N/A		N/A
Weighted average assumptions used to determine net periodic benefit cost:
Discount rate	5.00		4.00		5.00		4.00
Expected long-term return on assets	4.75		4.25		N/A		N/A
Rate of compensation increase	4.00		4.00		N/A		N/A

The health care cost trend rate for the Retiree Medical Plan for 2014 is 7.50% trending to 5.00% in five years. The assumptions used in the determination of our obligations and benefit cost are based upon management’s best estimates as of the annual measurement date. The discount rate utilized was based upon bond portfolio curves over a duration similar to the Cash Balance Plan’s and Retiree Medical Plan’s respective expected future cash flows as of the measurement date. The expected long-term rate of return on plan assets is the weighted average rate of earnings expected of the funds invested or to be invested based upon the targeted investment strategy for the plan. The assumed average rate of compensation increase is the average annual compensation increase expected over the remaining employment periods for the participating employees.

Employer contributions to the Cash Balance Plan of $0.2 million and $2.5 million were made during the period ended December 31, 2014 and 2013, respectively. These contributions were invested into equity and bond mutual funds and money market funds that are deemed Level 1 assets as described in Note 4, Fair Value Measurement. NTI expects funding requirements of approximately $5.1 million during the year ended December 31, 2015.

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

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	Cash Balance Plan		Retiree Medical Plan
2015	$	269	$	70
2016	356		88
2017	485		110
2018	622		114
2019	774		137
2020-2024	6,493		991

Postretirement Obligations

The following tables set forth significant information about our retiree medical plans for certain El Paso and Yorktown employees. Unlike the pension plans, we are not required to fund the retiree medical plans on an annual basis. Based on an annual measurement date of December 31, and discount rates of 4.09% and 4.88% at December 31, 2014 and 2013, respectively, to determine the benefit obligation, the components of the postretirement obligation were:

	As of December 31,
	2014			2013
	(In thousands)
Benefit obligation at beginning of year	$	5,793		$	6,492
Service cost	92			115
Interest cost	264			254
Benefits paid	(206		)	(216		)
Actuarial (gain) loss	792			(852		)
Benefit obligation at end of year	$	6,735		$	5,793
Unfunded status	$	(6,735	)	$	(5,793	)
Current liabilities	$	(300	)	$	(286	)
Non-current liabilities	(6,435		)	(5,507		)
Unfunded status recognized in the consolidated balance sheets	$	(6,735	)	$	(5,793	)

	Year Ended December 31,
	2014			2013			2012
	(In thousands)
Net periodic benefit cost includes:
Service cost	$	92		$	115		$	119
Interest cost	264			254			261
Amortization of net actuarial loss	20			34			42
Net periodic benefit cost	$	376		$	403		$	422
Pre-tax unrecognized net loss included in accumulated other comprehensive gain at beginning of year	$	784		$	1,670		$	1,351
Net actuarial (gain) loss	792			(852		)	361
Amortization of net actuarial loss	(20		)	(34		)	(42		)
Pre-tax unrecognized net loss included in accumulated other comprehensive gain at end of year	$	1,556		$	784		$	1,670

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The weighted average discount rates used to determine net periodic benefit costs were 4.88%, 4.14% and 4.37% for 2014, 2013 and 2012, respectively. The following benefit payments (in thousands) are expected to be paid in the year indicated:

2015	$	306
2016	331
2017	360
2018	360
2019	346
2020 - 2024	1,536

The health care cost trend rate for the plan covering El Paso employees for 2014 and future years is capped at 4.00%. The health care cost trend rate for the plan covering Yorktown employees for 2014 is 4.50% trending to 4.50% in 2015. A 1%-point change in the assumed health care cost trend rate for both plans will have the following effect:

	1%-points
	Increase (1)		Decrease
	(In thousands)
Effect on total service cost and interest cost	$	1	$	(40	)
Effect on accumulated benefit obligation	14		(592		)

(1) There is no impact for a 1%-point increase in the El Paso plan because the plan covers up to a 4% increase per year. Any increase in health care costs in excess of 4% is absorbed by the participant.

The following table presents cumulative changes in other comprehensive income related to our benefit plans included as a component of equity for the periods presented, net of income tax. The related expenses are included in direct operating expenses in the Consolidated Statements of Operations.

	Year Ended December 31,
	2014			2013			2012
	(In thousands)
Beginning of period balance	$	(350	)	$	(1,174	)	$	(1,812	)
Amortization of net prior service cost	63			—			—
Reclassification of loss to income	21			47			48
Pension plan termination adjustment	—			217			978
Actuarial gain (loss)	(1,320		)	978			(13		)
Income tax	295			(418		)	(375		)
End of period balance	$	(1,291	)	$	(350	)	$	(1,174	)

Defined Contribution Plans

We sponsor a 401(k) defined contribution plan under which participants may contribute a percentage of their eligible compensation to various investment choices offered by the plan. We make a Safe Harbor matching contribution to the account of each participant who is covered under the collective bargaining agreement with the International Union of Operating Engineers in El Paso and has completed 12 months of service equal to 250% of the first 4% of compensation beginning February 1, 2012. During January 2012, the safe harbor matching contribution was 200% of the first 4% of compensation. In addition, participants who were covered by the settlement agreement with the International Union of Operating Engineers in El Paso received a contribution equal to 3% of the compensation paid between January 1, 2012, and January 31, 2012. For all other employees, we matched 1% up to a maximum of 4% of eligible compensation for each 1% of eligible compensation contributed provided the participant had a minimum of one year of service with Western. We expensed $9.1 million, $8.5 million and $5.9 million in connection with this plan for the years ended December 31, 2014, 2013 and 2012, respectively.

NTI sponsors two qualified defined contribution plans (collectively, the “NTI Retirement Savings Plans”) for eligible employees. Eligibility is based upon a minimum age requirement and a minimum level of service. Participants may make contributions for a percentage of their annual compensation subject to Internal Revenue Service limits. For certain participant groups, NTI provides a matching contribution at the rate of 100% of up to 6.0% of a participant’s contribution and a non-

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matching contribution of 3.0% of eligible compensation. For other participant groups, NTI provides a non-elective fixed annual contribution of 3.5% of eligible compensation. Total contributions to the NTI Retirement Savings Plans were $7.1 million and $6.1 million for the year ended December 31, 2014 and 2013, respectively.

18. Crude Oil and Refined Product Risk Management

We enter into crude oil forward contracts to facilitate the supply of crude oil to our refineries. During 2014, 2013 and 2012, we entered into net forward, fixed-price contracts to physically receive and deliver crude oil that qualify as normal purchases and normal sales and are exempt from derivative reporting requirements.

We use crude oil and refined products futures, swap contracts or options to mitigate the change in value for a portion of our LIFO inventory volumes subject to market price fluctuations, and swap contracts to fix the margin on a portion of our future gasoline and distillate production. The physical volumes are not exchanged, and these contracts are net settled with cash. For instruments used to mitigate the change in value of volumes subject to market prices, we elected not to pursue hedge accounting treatment for financial accounting purposes, generally because of the difficulty of establishing and maintaining the required documentation that would allow for hedge accounting. The swap contracts used to fix the margin on a portion of our future gasoline and distillate production do not qualify for hedge accounting treatment.

The fair value of these contracts is reflected in the Consolidated Balance Sheets and the related net gain or loss is recorded within cost of products sold in the Consolidated Statements of Operations. Quoted prices for similar assets or liabilities in active markets (Level 2) are considered to determine the fair values of the majority of the contracts for the purpose of marking to market the hedging instruments at each period end.

The following tables summarize our economic hedging activity recognized within cost of products sold for the three years ended December 31, 2014, and open commodity hedging positions as of December 31, 2014, and December 31, 2013:

	Year Ended December 31,
	2014		2013			2012
	(In thousands)
Economic hedging activities recognized within cost of products sold:
Realized hedging gain (loss), net	$	95,331	$	15,868		$	(144,448	)
Unrealized hedging gain (loss), net	194,423		(16,898		)	(229,672		)
Total hedging gain (loss), net	$	289,754	$	(1,030	)	$	(374,120	)

	December 31, 2014			December 31, 2013
	(In thousands)
Open commodity hedging instruments (bbls):
Crude futures	(864		)	(768		)
Refined product price and crack spread swaps	(8,781		)	(25,721		)
Total open commodity hedging instruments	(9,645		)	(26,489		)
Fair value of outstanding contracts, net:
Other current assets	$	79,722		$	8,791
Other assets	56,533			7
Accrued liabilities	(4,889		)	(17,386		)
Other long-term liabilities	(1,400		)	(55,869		)
Fair value of outstanding contracts - unrealized gain (loss), net	$	129,966		$	(64,457	)

Offsetting Assets and Liabilities

Western's derivative financial instruments are subject to master netting arrangements to manage counterparty credit risk associated with derivatives; however, Western does not offset the fair value amounts recorded for derivative instruments under these agreements in the Consolidated Balance Sheets. We have posted cash margin with various counterparties to support

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hedging and trading activities. The cash margin posted is required by counterparties as collateral deposits and cannot be offset against the fair value of open contracts except in the event of default.

The following table presents offsetting information regarding Western's derivative instruments as of December 31, 2014, and December 31, 2013:

	Gross Amounts of Recognized Assets (Liabilities)			Gross Amounts Offset in the Consolidated Balance Sheet			Net Amounts of Assets (Liabilities) Presented in the Consolidated Balance Sheet
As of December 31, 2014
	(In thousands)
Gross financial assets:
Current assets - commodity hedging contracts	$	86,659		$	(6,937	)	$	79,722
Other assets - commodity hedging contracts	58,182			(1,649		)	56,533
Gross financial liabilities:
Accrued liabilities - commodity hedging contracts	(11,826		)	6,937			(4,889		)
Other long-term liabilities - commodity hedging contracts	(3,049		)	1,649			(1,400		)
	$	129,966		$	—		$	129,966

	Gross Amounts of Recognized Assets (Liabilities)			Gross Amounts Offset in the Consolidated Balance Sheet			Net Amounts of Assets (Liabilities) Presented in the Consolidated Balance Sheet
As of December 31, 2013
	(In thousands)
Gross financial assets:
Current assets - commodity hedging contracts	$	14,344		$	(5,553	)	$	8,791
Other assets - commodity hedging contracts	183			(176		)	7
Gross financial liabilities:
Accrued liabilities - commodity hedging contracts	(22,939		)	5,553			(17,386		)
Other long-term liabilities - commodity hedging contracts	(56,045		)	176			(55,869		)
	$	(64,457	)	$	—		$	(64,457	)

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Our commodity hedging activities are initiated within guidelines established by management and approved by our board of directors. Commodity hedging transactions are executed centrally on behalf of all of our operating segments to minimize transaction costs, monitor consolidated net exposures and to allow for increased responsiveness to changes in market factors. Due to mark-to-market accounting during the term of the various commodity hedging contracts, significant unrealized, non‑cash net gains and losses could be recorded in our results of operations. Additionally, we may be required to collateralize any mark-to-market losses on outstanding commodity hedging contracts.

As of December 31, 2014, we had the following outstanding crude oil and refined product hedging instruments that were entered into as economic hedges. Settlement prices for our unleaded gasoline crack spread swaps range from $5.05 to $5.05 per contract. Settlement prices for our distillate crack spread swaps range from $17.26 to $19.10 per contract. The information presents the notional volume of outstanding contracts by type of instrument and year of maturity (volumes in thousands of barrels):

	Notional Contract Volumes by Year of Maturity
	2015		2016		2017
Inventory positions (futures and swaps):
Crude oil and refined products - net short positions	(864	)	—		—
Natural gas - net long positions	3,432		1,658		—
Refined product positions (crack spread swaps):
Distillate - net short positions	(7,691	)	(5,430	)	(825	)
Unleaded gasoline - net long positions	75		—		—

19. Stock-Based Compensation

The Western Refining 2006 Long-Term Incentive Plan (the “2006 LTIP”) and the 2010 Incentive Plan of Western Refining, Inc. (the “2010 Incentive Plan”) allow for restricted share awards and restricted share unit awards. As of December 31, 2014, there were 14,311 and 2,879,953 shares of common stock reserved for future grants under the 2006 LTIP and the 2010 Incentive Plan, respectively. Awards granted under both plans vest over a scheduled vesting period of either one, three or five years and their market value at the date of the grant is amortized over the restricted period on a straight-line basis.

As of December 31, 2014, there were 380,695 restricted share units outstanding. The final vesting for remaining

restricted share awards occurred during the first quarter of 2014.

The components of stock compensation expense were as follows:

	Year Ended December 31,
	2014		2013		2012
	(In thousands)
Direct operating expenses	$	—	$	61	$	310
Selling, general and administrative expenses	4,338		5,428		7,981
Total stock compensation expense	$	4,338	$	5,489	$	8,291

As of December 31, 2014, the aggregate fair value at grant date of outstanding restricted share units was $11.5 million. The aggregate intrinsic value of restricted share units was $14.4 million. The unrecognized compensation cost of outstanding restricted share units was $7.7 million. Unrecognized compensation cost for restricted share units will be recognized over a weighted average period of approximately 3.30 years.

The excess tax benefit related to the restricted share units and restricted shares that vested during the year ended December 31, 2014 was $1.1 million and $0.03 million, respectively, using a statutory blended rate of 38.3%. The aggregate fair value at the grant date of the restricted share units and restricted shares that vested during the year ended December 31, 2014 was $4.2 million and $0.1 million, respectively. The related aggregate intrinsic value of these restricted share units and restricted shares was $7.1 million and $0.1 million, respectively, at the vesting date.

The excess tax benefit related to the restricted share units and restricted shares that vested during the year ended December 31, 2013 was $0.9 million and $7.5 million, respectively, using a statutory blended rate of 37.8%. The aggregate fair value at the grant date of the restricted share units and restricted shares that vested during the year ended December 31, 2013

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was $3.2 million and $4.1 million, respectively. The related aggregate intrinsic value of these restricted share units and restricted shares was $5.6 million and $23.8 million, respectively, at the vesting date.

The excess tax benefit related to the restricted share units and restricted shares that vested during the year ended December 31, 2012 was $0.3 million and $4.1 million, respectively, using a statutory blended rate of 37.8%. The aggregate fair value at the grant date of the restricted share units and restricted shares that vested during the year ended December 31, 2012 was $2.2 million and $5.4 million, respectively. The related aggregate intrinsic value of these restricted shares was $3.1 million and $16.2 million, respectively, at the vesting date.

The following table summarizes our restricted share unit and restricted share activity for the three years ended December 31, 2014:

	Restricted Share Units				Restricted Shares
	Number of Units		Weighted Average Grant Date Fair Value		Number of Shares		Weighted Average Grant Date Fair Value
Not vested at December 31, 2011	316,917		$	16.09	1,511,242		$	6.29
Awards granted	269,406		19.45		—		—
Awards vested	(142,483	)	15.78		(816,620	)	6.64
Awards forfeited	(2,980	)	16.78		—		—
Not vested at December 31, 2012	440,860		18.24		694,622		5.93
Awards granted	178,338		34.37		—		—
Awards vested	(176,311	)	18.16		(690,780	)	5.87
Awards forfeited	—		—		—		—
Not vested at December 31, 2013	442,887		24.79		3,842		16.78
Awards granted	124,276		39.08		—		—
Awards vested	(180,923	)	23.29		(3,842	)	16.78
Awards forfeited	(5,545	)	26.69		—		—
Not vested at December 31, 2014	380,695		30.14		—		—

NTI 2012 Long-Term Incentive Plan

Approximately 8.1 million NTI common units are reserved for issuance under the NTI LTIP. NTI has awarded both restricted units and phantom units under the NTI LTIP. As of December 31, 2014, approximately 0.7 million units were outstanding under the NTI LTIP consisting of 0.4 million restricted units and 0.3 million phantom units. NTI recognizes the expense on these awards ratably from the grant date until all units become unrestricted. For restricted common unit awards outstanding at December 31, 2014, the forfeiture rates on NTI LTIP awards ranged from zero to 30%, depending on the employee classification and the length of the award's vesting period. For phantom common unit awards outstanding at December 31, 2014, the forfeiture rates on NTI LTIP awards ranged from 5% to 20%, depending on the employee classification.

NTI incurred $14.0 million and $0.4 million of unit-based compensation expense for the years ended December 31, 2014 and 2013, respectively.

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A summary of the LTIP unit activity is set forth below:

	Restricted Units				Phantom Units
	Number of Units		Weighted Average Grant Date Fair Value		Number of Units		Weighted Average Grant Date Fair Value
Not vested at November 12, 2013	323,392		$	26.99	—		$	—
Awards granted	1,000		24.60		—		—
Awards vested	(17,873	)	26.38		—		—
Awards forfeited	—		—		—		—
Not vested at December 31, 2013	306,519		27.02		—		—
Awards granted	486,893		24.31		351,470		26.99
Awards vested	(390,109	)	25.99		(923	)	27.01
Awards forfeited	(7,194	)	25.21		(12,854	)	27.01
Not vested at December 31, 2014	396,109		24.73		337,693		26.99

As of December 31, 2014 and 2013, the total unrecognized compensation cost for NTI LTIP units was $12.1 million and $6.1 million, respectively. NTI's restricted and phantom units are expected to be recognized over a weighted-average period of approximately 1.3 and 2.0 years, respectively. NTI's phantom units had an aggregate grant date fair value of $15.1 million and contain both time-based vesting and performance based vesting conditions expected to mature at the end of three years following at the issuance date.

Western Refining Logistics, LP 2013 Long-Term Incentive Plan

The Western Refining Logistics, LP 2013 Long-Term Incentive Plan (the "WNRL LTIP") was adopted by the Western Refining GP, LLC board of directors in connection with the completion of its initial public offering. The WNRL LTIP provides for grants of phantom units and distribution equivalent rights ("DERs"). As of December 31, 2014, there were 4.2 million phantom units reserved for future grants under the WNRL LTIP.

The fair value of the phantom units is determined based on the closing price of WNRL common units on the grant date. The estimated fair value of the phantom units is amortized on a straight-line basis over the scheduled vesting periods of individual awards. WNRL incurred unit-based compensation expense of $1.6 million for the year ended December 31, 2014 and a nominal amount for the year ended December 31, 2013.

The fair value at grant date of non-vested phantom units outstanding as of December 31, 2014, was $7.9 million. The aggregate intrinsic value of phantom units was $8.5 million. Total unrecognized compensation cost related to our non-vested phantom units totaled $6.6 million as of December 31, 2014, that is expected to be recognized over a weighted-average period of approximately 4.16 years.

A summary of WNRL's unit award activity for the year ended December 31, 2014, is set forth below:

	Number of Phantom Units		Weighted Average Grant Date Fair Value
Not vested at December 31, 2012	—		$	—
Awards granted	10,908		22.00
Awards vested	—		—
Awards forfeited	—		—
Not vested at December 31, 2013	10,908		22.00
Awards granted	293,810		28.52
Awards vested	(10,908	)	22.00
Awards forfeited	(13,559	)	33.02
Not vested at December 31, 2014	280,251		28.30

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20. Equity

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

On June 10, 2009, we issued an additional 20,000,000 shares of our common stock, par value $0.01 per share at an aggregate offering price of $180.0 million. The net proceeds of this issuance were $170.4 million, net of underwriting discounts of $9.0 million and $0.6 million in issuance costs related to this offering. In addition, during June and July 2009, we issued and sold $215.5 million in Convertible Senior Notes and recorded additional paid-in capital of $36.3 million, net of deferred income taxes of $22.6 million and transaction costs of $2.0 million related to the equity portion of this convertible debt.

Prior to 2010, we repurchased 698,006 shares of our common stock to cover payroll withholding taxes for certain employees pursuant to the vesting of restricted shares awarded under the Western Refining Long-Term Incentive Plan. The aggregate cost paid for these shares was $21.4 million. We recorded these repurchases as treasury stock.

Since 2012, our board of directors has approved four separate share repurchase programs authorizing us to repurchase up to $200 million, per program, of our outstanding common stock. Our board of directors approved our current share repurchase program in November of 2014 (the "November 2014 Program") which will expire in November of 2015.

Subject to market conditions as well as corporate, regulatory and other considerations, we will repurchase shares from time-to-time through open market transactions, block trades, privately negotiated transactions or otherwise. Our board of directors may discontinue the share repurchase program at any time.

The following table summarizes our share repurchase activity for the four share repurchase programs:

	July 2012 Program			April 2013 Program			January 2014 Program			November 2014 Program
	Number of shares purchased	Cost of share purchases (In thousands)		Number of shares purchased	Cost of share purchases (In thousands)		Number of shares purchased	Cost of share purchases (In thousands)		Number of shares purchased	Cost of share purchases (In thousands)
Shares purchased at December 31, 2011	—	$	—	—	$	—	—	$	—	—	$	—
Shares purchased during 2012	3,324,135	82,270		—	—		—	—		—	—
Shares purchased at December 31, 2012	3,324,135	82,270		—	—		—	—		—	—
Shares purchased during 2013	3,462,230	117,730		4,617,798	135,111		—	—		—	—
Shares purchased at December 31, 2013	6,786,365	200,000		4,617,798	135,111		—	—		—	—
Shares purchased during 2014 (1)	—	—		—	—		4,976,039	200,000		1,492,874	59,222
Shares purchased at December 31, 2014	6,786,365	$	200,000	4,617,798	$	135,111	4,976,039	$	200,000	1,492,874	$	59,222

(1) The shares purchased during 2014 included 27,030 shares that we subsequently used to settle conversions of the Convertible Notes.

As of December 31, 2014, we had $140.8 million remaining in authorized expenditures under the November 2014 Program. Through December 31, 2014, we have purchased 17.9 million shares of our common stock under our share repurchase programs. As of February 27, 2015, we had $115.8 million remaining in authorized expenditures under the November 2014 Program.

Our ability to pay dividends to our shareholders is subject to certain restrictions in our Revolving Credit Agreement, Term Loan Credit Agreement and the indenture governing our Senior Unsecured Notes, including pro forma compliance with a fixed charge coverage ratio test and an excess availability test under our Revolving Credit Agreement and compliance with an incurrence-based test subject to a formula-based maximum under the indenture governing our Senior Unsecured 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.

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21. Earnings per Share

We follow the provisions related to the accounting treatment of certain participating securities for the purpose of determining earnings per share. These provisions address share-based payment awards that have not vested and that contain nonforfeitable rights to dividend equivalents and state that they are participating securities and should be included in the computation of earnings per share pursuant to the two-class method. As discussed in Note 19, Stock-Based Compensation, we granted shares of restricted stock to certain employees and outside directors. Although ownership of these shares did not transfer to the recipients until the shares vested, recipients had voting and nonforfeitable dividend rights on these shares from the date of grant. Accordingly, we utilize the two-class method to determine our earnings per share. The final vesting for remaining restricted stock awards occurred during the first quarter of 2014.

Diluted earnings per common share includes the effects of potentially dilutive shares that consist of unvested restricted share units. These awards are non-participating securities due to the forfeitable nature of their associated dividend equivalent rights, prior to vesting, and we do not consider the restricted share units in the two-class method when calculating earnings per share.

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

	Year Ended December 31,
	2014			2013			2012
	(In thousands, except per share data)
Basic earnings per common share:
Allocation of earnings:
Net income attributable to Western Refining, Inc.	$	559,926		$	275,994		$	398,885
Distributed earnings	(293,746		)	(52,489		)	(240,715		)
Income allocated to participating securities	(3		)	(814		)	(1,645		)
Distributed earnings allocated to participating securities	3			191			2,504
Undistributed income available to Western Refining, Inc.	$	266,180		$	222,882		$	159,029
Weighted average number of common shares outstanding (1)	90,708			82,248			89,270
Basic earnings per common share:
Distributed earnings per share	$	3.24		$	0.64		$	2.67
Undistributed earnings per share	2.93			2.71			1.75
Basic earnings per common share	$	6.17		$	3.35		$	4.42

(1) Excludes the weighted average number of common shares outstanding associated with participating securities of 1 thousand, 300 thousand and 938 thousand shares for the years ended December 31, 2014, 2013 and 2012, respectively.

	Year Ended December 31,
	2014		2013		2012
	(In thousands, except per share data)
Diluted earnings per common share:
Net income attributable to Western Refining, Inc.	$	559,926	$	275,994	$	398,885
Tax effected interest related to convertible debt	8,010		16,864		15,726
Net income available to Western Refining, Inc., assuming dilution	$	567,936	$	292,858	$	414,611
Weighted average number of diluted shares outstanding	101,190		104,904		111,822
Diluted earnings per common share	$	5.61	$	2.79	$	3.71

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

	Year Ended December 31,
	2014	2013	2012
	(In thousands)
Weighted average number of common shares outstanding	90,708	82,248	89,270
Common equivalent shares from Convertible Senior Notes	10,349	22,500	22,057
Restricted shares and share units	133	156	495
Weighted average number of diluted shares outstanding	101,190	104,904	111,822

A shareholder's interest in our common stock could become diluted as a result of vestings of restricted share units and, prior to the settlement of the Western Convertible Notes during the second quarter of 2014 (see Note 15, Long-Term Debt for further discussion), conversion of the Western Convertible Notes through issuance of shares of our common stock. In calculating our fully diluted earnings per common share, we consider the impact of restricted share units that have not vested and common equivalent shares related to the Western Convertible Notes. We include unvested restricted share units in our diluted earnings calculation when the trading price of our common stock equals or exceeds the per share or per share unit grant price. Common equivalent shares from the Western Convertible Notes are generally included in our diluted earnings calculation when net income exceeds certain thresholds above which the effect of the shares becomes dilutive. The Western Convertible Notes were converted into actual shares of our common stock during the first six months of 2014.

The table below summarizes our 2014 cash dividend declarations, payments and scheduled payments through December 31, 2014:

	2014
	Declaration Date	Record Date	Payment Date	Dividend per common share		Total Payment (in thousands)
First quarter	January 28	February 12	February 27	$	0.26	$	20,730
Second quarter	April 21	May 6	May 21	0.26		20,745
Third quarter	July 15	July 30	August 14	0.26		26,292
Fourth quarter	October 14	October 29	November 13	0.30		29,584
Fourth quarter - special dividend	November 4	November 18	December 1	2.00		196,395
Total						$	293,746

On February 6, 2015, our board of directors approved a cash dividend for the first quarter of 2015 of $0.30 per share of common stock in an aggregate payment of $28.6 million that will be paid on March 6, 2015 to holders of record on February 20, 2015.

Total dividends declared were $3.08, $0.64 and $2.74 per common share, including those declared related to participating securities, for the years ended December 31, 2014, 2013 and 2012.

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22. Cash Flows

Supplemental disclosures of cash flow information were as follows:

	Year Ended December 31,
	2014		2013		2012
	(In thousands)
Income taxes paid	$	227,953	$	223,594	$	237,551
Interest paid, excluding amounts capitalized	83,943		48,751		68,735

Non-cash investing and financing activities were as follows:

	Year Ended December 31,
	2014		2013		2012
	(In thousands)
Issuance of common shares for redemption of Western Convertible Notes	$	357,608	$	—	$	—
Accrued capital expenditures	9,189		—		—
Assets acquired through capital lease obligations and promissory note	—		—		7,064

23. Contingencies

Environmental Matters

Similar to other petroleum refiners, our operations are subject to extensive and periodically changing federal and state environmental regulations governing air emissions, wastewater discharges and solid and hazardous waste management activities. Many of these regulations are becoming increasingly stringent and the cost of compliance can be expected to increase over time. Our policy is to accrue environmental and clean-up related costs of a non-capital nature when it is probable that a liability has been incurred and the amount can be reasonably estimated. Such estimates may be subject to revision in the future as regulations and other conditions change.

Periodically, we receive communications from various federal, state and local governmental authorities asserting violations of environmental laws and/or regulations. These governmental entities may also propose or assess fines or require corrective action for these asserted violations. We intend to respond in a timely manner to all such communications and to take appropriate corrective action. We do not anticipate that any such matters currently asserted will have a material impact on our financial condition, results of operations or cash flows. As of December 31, 2014, and 2013, we had consolidated environmental accruals of $18.5 million and $10.2 million, respectively.

El Paso Refinery

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

In May 2000, we entered into an Agreed Order with the TCEQ for remediation of the south side of the El Paso refinery property. We purchased a non-cancelable Pollution and Legal Liability and Clean-Up Cost Cap Insurance policy that covers environmental clean-up costs related to contamination that occurred prior to December 31, 1999, including the costs of the Agreed Order activities. The insurance provider assumed responsibility for all environmental clean-up costs related to the Agreed Order up to $20.0 million, of which approximately $7.2 million remained as of December 31, 2014. In addition, a subsidiary of Chevron is obligated under a settlement agreement to pay 60% of any Agreed Order environmental clean-up costs that exceed the $20.0 million policy coverage.

On June 30, 2011, the U.S. Environmental Protection Agency (the “EPA”) filed notice with the federal district court in El Paso that we and the EPA entered into a proposed Consent Decree under the Petroleum Refinery Enforcement Initiative (“EPA Initiative”). On September 2, 2011, the court entered the Consent Decree. Under the EPA Initiative, the EPA is investigating

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industry-wide non-compliance with certain Clean Air Act rules. The EPA Initiative has resulted in many refiners entering into similar consent decrees typically requiring penalties and substantial capital expenditures for additional air pollution control equipment. The Consent Decree does not require any soil or groundwater remediation or clean-up.

We have completed our capital expenditures to address the Consent Decree issues totaling $43.2 million, including $15.2 million for the installation of a flare gas recovery system completed in 2007 and $28.0 million for nitrogen oxides (“NOx”) emission controls on heaters and boilers completed in 2013. Under the terms of the Consent Decree, we paid a civil penalty of $1.5 million in September 2011.

In April 2014, we entered two Agreed Orders with the TCEQ to settle unresolved air enforcement at our El Paso refinery between 2004 and April 2008. We paid $0.2 million in penalties in May 2014 that included funding a Supplemental Environmental Project benefiting El Paso County. The orders do not require any soil or groundwater remediation or clean-up or capital expenditures.

Four Corners Refineries

Four Corners 2005 Consent Agreements. In July 2005, as part of the EPA Initiative, Giant Industries, Inc., our wholly-owned subsidiary, reached an administrative settlement with the New Mexico Environment Department (the "NMED") and the EPA in the form of consent agreements that resolved certain alleged violations of air quality regulations at the Gallup and Bloomfield refineries in the Four Corners area of New Mexico. In January 2009 and June 2012, we and the NMED agreed to amendments of the 2005 administrative settlement (the "2005 NMED Amended Agreement") that altered certain deadlines and allowed for alternative air pollution controls.

We incurred $50.8 million in total capital expenditures between 2009 and 2013 to address the requirements of the 2005 NMED Amended Agreement. These capital expenditures were primarily for installation of emission controls on the heaters, boilers and FCCU and for reducing sulfur in fuel gas to reduce emissions of sulfur dioxide, NOx and particulate matter from our Gallup refinery. We will incur additional capital expenditures to implement one or more FCCU offset projects to be completed by the end of 2017. In 2014, we incurred $1.9 million to implement an FCC offset project. We paid penalties between 2009 and 2012 totaling $2.7 million. Implementation of the requirements in the 2005 NMED Amended Agreement will not result in any soil or groundwater remediation or clean-up costs.

Bloomfield 2007 NMED Remediation Order. In July 2007, we received a final administrative compliance order from the NMED alleging that releases of contaminants and hazardous substances that have occurred at the Bloomfield refinery over the course of its operation prior to June 1, 2007, have resulted in soil and groundwater contamination. Among other things, the order requires that we investigate the extent of such releases, perform interim remediation measures and implement corrective measures. Prior to July 2007, with the approval of the NMED and the New Mexico Oil Conservation Division, we placed into operation certain remediation measures that remain operational. As of December 31, 2014, we have expended $4.0 million and have accrued the remaining estimated costs of $4.0 million for implementing the investigation, interim measures and the reasonably known corrective actions of the order.

Gallup 2007 Resource Conservational Recovery Act (“RCRA”) Inspection. In September 2007, the Gallup refinery was inspected jointly by the EPA and the NMED to determine compliance with the EPA’s hazardous waste regulations promulgated pursuant to the RCRA. We reached a final settlement with the agencies in August 2009 and paid a penalty of $0.7 million in October 2009 for violations alleged following the inspection. Between September 2010 and July 2012, the EPA demanded and we paid penalties totaling $0.2 million in accordance with the settlement. Implementation of the requirements in the final settlement will not result in any additional soil or groundwater remediation or clean-up costs not otherwise required. We incurred a total of $38.6 million in capital expenditures between 2010 and 2013 to upgrade the wastewater treatment plant at the Gallup refinery in accordance with the requirements, and there are no further capital requirements, under the final settlement.

Gallup 2013 Risk Management Plan General Duty Settlement. In July 2013, we entered a final settlement with the EPA for five alleged violations of the Clean Air Act Risk Management Plan 112(r) General Duty clause at our Gallup refinery and paid a total penalty of $0.2 million. No capital expenditures are required under the settlement.

Gallup 2014 Environment Protection Division of NMED Settlement. In March 2014, we received a revised notice of violation and offer of settlement from the NMED Air Quality Bureau for alleged violations of the Clean Air Act. We agreed to settle and paid a penalty of $0.1 million in May 2014. No capital expenditures are required under the settlement.

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NTI

At December 31, 2014, and 2013, liabilities for remediation by NTI totaled $8.7 million and $1.5 million. These liabilities consist of $2.9 million and $1.5 million are recorded on a discounted basis as of December 31, 2014 and 2013, respectively. These discounted liabilities are expected to be settled over at least the next 23 years. At December 31, 2014, the estimated future cash flows to settle these discounted liabilities totaled $3.5 million and are discounted at a rate of 2.55%. Receivables for recoverable costs from the state, under programs to assist companies in clean-up efforts related to underground storage tanks at retail marketing outlets, and others were $0.2 million and $0.1 million at December 31, 2014, and 2013, respectively.

On June 3, 2014, SPPR was issued a National Pollutant Discharge Elimination Permit/State Disposal System Permit by the Minnesota Pollution Control Agency ("MPCA") relating to its upgraded wastewater treatment plant at its St. Paul Park refinery. This permit required the refinery to conduct additional testing of its remaining lagoon. The testing was completed in the fourth quarter of 2014, following NTI's review of the test results and additional discussions with MPCA, NTI now regards the likelihood of future remediation and closure costs related to the lagoon as probable. At December 31, 2014, NTI estimates the remediation and closure costs to be approximately $5.8 million subject to further engineering and methodology studies. Some of this cost cost may be recoverable from Marathon Petroleum under an agreement entered into in connection with NTI's December 2010 acquisition of the St. Paul Park refinery, among other assets, from Marathon. However, at December 31, 2014 it is unclear how much, if any, of NTI's future costs may be eligible for reimbursement by Marathon, and as such, NTI has not recognized any receivable for this matter.

Tax Matters

See Note 16, Income Taxes, to these consolidated financial statements for additional information on tax examinations.

Union Matters

During 2014, we successfully negotiated a collective bargaining agreement covering employees at the Gallup refinery that expires in 2020. We also successfully negotiated a new collective bargaining agreement covering employees at the El Paso refinery, renewing the collective bargaining agreement that was set to expire in April 2012. The new collective bargaining agreement covering the El Paso refinery employees expires in April 2015. While all of the collective bargaining agreements contain “no strike” provisions, those provisions are not effective in the event that an agreement expires. Accordingly, we may not be able to prevent a strike or work stoppage in the future, and any such work stoppage could have a material adverse effect on our business, financial condition and results of operations.

NTI's refining business has 190 employees associated with its operations that are covered by a collective bargaining agreement that expires in December 2016. NTI's retail business has 22 employees associated with its operations that are covered by a collective bargaining agreement that expires in August 2017. In August 2012, NTI locked out the unionized drivers at the Supermom’s Bakery for six days when the parties were unable to come to terms on a new union contract.

Other Matters

The EPA has issued Renewable Fuels Standards ("RFS"), that require us and other refiners to blend renewable fuels into the refined products produced at our refineries. Annually, the EPA is required to establish a volume of renewable fuels that refineries must blend into their refined petroleum fuels. However, the EPA has not established the final renewable blending volume level for 2014 or 2015. To the extent we are unable to blend at the rate necessary to satisfy the EPA mandated volume, we purchase Renewable Identification Numbers ("RINs"). The purchase price for RINs is volatile and may vary significantly from period to period. Historically, the cost of purchased RINs has not had a significant impact on our operating results. We anticipate 2014 and 2015 will be consistent with this history. The net cost of meeting our renewable volume obligations, including sales and purchases of RINs, was $28.2 million, $30.5 million and $4.0 million for the year ended December 31, 2014, 2013 and 2012, respectively.

In addition, the EPA has investigated and brought enforcement actions against companies it believes produced invalid RINs. We may have purchased RINs the EPA will determine are invalid. Previously, we have entered into settlements with the EPA, and paid penalties totaling less than $0.1 million, regarding RINs we purchased that the EPA ultimately determined were invalid. We expect to enter another settlement with the EPA in 2015 and pay a penalty of less than $0.01 million. While we do not know if the EPA will determine that other RINs we have purchased are invalid, at this time we do not expect any settlements we would enter into with the EPA would have a material effect on our financial condition, results of operations or cash flows.

In August 2014, the TCEQ offered an expedited settlement with a proposed penalty of $0.2 million related to enforcement issued to our retail segment. After negotiations, TCEQ issued a revised settlement with a penalty of less than $0.1 million. We

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have agreed to the settlement and have paid the penalty. The settlement is pending final approval by the TCEQ Commissioners. The settlement requires no capital expenditures or soil or groundwater remediation or clean-up.

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

24. Concentration of Risk

Significant Customers

We sell a variety of refined products to a diverse customer base. Our total sales to Kroger Company accounted for 11.4% of consolidated net sales for the year ended December 31, 2013. No single customer accounted for more than 10% of consolidated net sales for the years ended December 31, 2014 and 2012.

Sales by Product

All sales were domestic sales in the United States, except for sales of gasoline and diesel fuel for export into Mexico. The sales for export were to PMI Trading Limited, an affiliate of Petroleos Mexicanos, the Mexican state-owned oil company, and accounted for approximately 5.5%, 8.5% and 7.5% of consolidated sales during the years ended December 31, 2014, 2013 and 2012, respectively.

25. Leases and Other Commitments

We have commitments under various operating leases with initial terms greater than one year for retail convenience stores, office space, warehouses, card locks, railcars and other facilities; some of which have renewal options and rent escalation clauses. These leases have terms that will expire on various dates through 2036. We expect that in the normal course of business, these leases will be renewed or replaced by other leases. Certain of our lease agreements provide for the fair value purchase of the leased asset at the end of the lease. Rent expense for operating leases that provide for periodic rent escalations or rent holidays over the term of the lease and for renewal periods that are reasonably assured at the inception of the lease is recognized on a straight-line basis over the term of the lease.

In the normal course of business, we also have long-term commitments to purchase services, such as natural gas, electricity, water and transportation services for use by our refineries at market-based rates. We are also party to various refined product and crude oil supply and exchange agreements.

Under a sulfuric acid regeneration and sulfur gas processing agreement with E.I. du Pont de Nemours ("DuPont"), DuPont constructed and operates two sulfuric acid regeneration units on property we leased to DuPont within our El Paso refinery. Our annual estimated cost for processing sulfuric acid and sulfur gas under this agreement is $15.7 million through March of 2028.

Our subsidiary is a party to a ten-year lease agreement for an administrative office building in Scottsdale, Arizona that ended in 2013. During 2008, we entered into an agreement to sublease a portion of this property for $0.3 million annually from February 15, 2009, through October 31, 2013. The rental payments for this property have been included as part of our estimated rental payments in the table below.

In November 2007, our subsidiary entered into a ten-year lease agreement for an office space in downtown El Paso. The building serves as our headquarters. In December 2007, our subsidiary entered into an eleven-year lease agreement for an office building in Tempe, Arizona. The building centralized our operational and administrative offices in the Phoenix area.

We are party to twenty capital leases, with initial terms of 20 years, expiring in 2017 through 2034. The current portion of our capital lease obligation of $0.6 million and $0.6 million is included in accrued liabilities and the non-current portion of $27.5 million and $24.9 million is included in lease financing obligations in the accompanying Consolidated Balance Sheets as of December 31, 2014 and 2013, respectively. These capital leases were discounted using annual rates of 3.24% to 10.51%. Total remaining interest related to these leases was $21.6 million and $20.1 million at December 31, 2014, and 2013, respectively. Annual payments net of interest for the next five years are approximately $2.6 million annually with the remaining $31.3 million due through 2034. Of the twenty capital leases, twelve are NTI obligations with annual lease payments net of interest that average $0.9 million annually through the end of 2018 with the remaining $6.4 million due through 2033. There is no recourse to Western on the NTI capital leases. The remaining eight capital leases are held by our retail segment and make up the balance of the annual payments for the periods noted above.

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

2015	$	47,835
2016	46,624
2017	43,384
2018	40,087
2019	36,929
2020 and thereafter	288,217
	$	503,076

Total rental expense was $53.7 million, $23.6 million and $25.5 million for the years ended December 31, 2014, 2013 and 2012, respectively. Contingent rentals and subleases were not significant in any year.

26. Related Party Transactions

Effective November 30, 2012, an entity controlled by one of our officers purchased the building and related lease agreement of certain office space that we and other commercial tenants occupy in El Paso, Texas. The lease agreement expires in May 2017. Under the terms of the lease, we make annual payments of $0.2 million. For the years ended December 31, 2014, 2013 and 2012, we made rental payments under this lease to the related party of $0.2 million, $0.2 million and $0.02 million, respectively. We have no amounts due as of December 31, 2014, related to this lease agreement.

Beginning on September 30, 2014, NTI began paying MPL for transportation services at published tariff rates. During the year ended December 31, 2014, NTI incurred $12.6 million in crude transportation costs with MPL. As of December 31, 2014, NTI owed MPL $2.1 million. Prior to September 30, 2014, NTI had a crude oil supply and logistics agreement with a third party and had no direct supply transactions with MPL prior to this date.

27. Condensed Consolidating Financial Information

Separate condensed consolidating financial information of Western Refining, Inc. (the “Parent”), subsidiary guarantors and non-guarantors are presented below. At December 31, 2014, the Parent and certain subsidiary guarantors have fully and unconditionally guaranteed our Western 2021 Unsecured Notes on a joint and several basis. As a result of these guarantee arrangements, we are required to present the following condensed consolidating financial information that should be read in conjunction with the accompanying consolidated financial statements and notes thereto.

NTI, WNRL and Navajo Convenient Stores Co., LLC ("Navajo") are subsidiaries that have not guaranteed our Unsecured Notes. NTI was not a subsidiary of the Parent during the year ended December 31, 2012 because it was purchased on November 12, 2013. Separate condensed financial statements for Navajo were not disclosed in prior years because Navajo was considered a minor subsidiary and is not material to the consolidated financial statements.

Due to the change in the guarantor structure resulting from the Wholesale Acquisition, we have revised the condensed consolidating financial information for all periods presented. See Note 29, Western Refining Logistics, LP, for additional information on this transaction.

NTI and WNRL are publicly held master limited partnerships. As of December 31, 2014, we owned a 66.2% limited partnership interest in WNRL and a 38.4% limited partnership interest in NTI, and the non-financial general partner interests of both entities. We are the primary beneficiary of WNRL's earnings and cash flows. We exercise control of both NTI and WNRL through our 100% ownership of the respective general partners. Accordingly, NTI and WNRL are consolidated with the other accounts of Western.

NTI has 7.125% Secured Notes and a secured ABL facility. With the exception of the assets of Northern Tier Energy GP LLC, creditors have no recourse to our assets. Any recourse to NTI’s general partner would be limited to the extent of Northern Tier Energy GP LLC’s assets that other than its investment in NTI are not significant. Furthermore, our creditors have no recourse to the assets of NTI and its consolidated subsidiaries. See Note 15, Long-Term Debt, for a description of NTI’s debt obligations.

Our transactions with WNRL including fees paid under our pipeline, terminalling and services agreements with WNRL are eliminated and have no significant impact on our consolidated financial statements. Through December 31, 2014, there have

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been no significant intercompany accounts or transactions between Western and NTI. All intercompany accounts and transactions with NTI and WNRL are eliminated in our consolidated financial statements.

Western is WNRL’s primary customer. WNRL generates revenues by charging fees and tariffs for transporting crude oil through its pipelines and refined and other products through its terminals and pipelines and for providing storage in its storage tanks and at its terminals. We do not provide financial or equity support through any liquidity arrangements and/or debt guarantees to WNRL.

WNRL has a senior secured revolving credit agreement. With the exception of the assets of Western Refining Logistic GP, LLC, creditors have no recourse to our assets. Any recourse to WNRL’s general partner would be limited to the extent of Western Refining Logistic GP, LLC’s assets that other than its investment in WNRL are not significant. Furthermore, our creditors have no recourse to the assets of WNRL and its consolidated subsidiaries. See Note 15, Long-Term Debt, for a description of WNRL’s debt obligations.

NTI and WNRL have risks associated with their respective operations. NTI’s risks, while similar to ours because it experiences similar industry dynamics, are not associated with our operations. WNRL’s risks are directly associated with our operations. If we suffer significant decreases in our throughput or fail to meet desired shipping or throughput levels for an extended period of time, WNRL revenues would be reduced and WNRL could suffer substantial losses.

In the event that NTI or WNRL incur a loss, our operating results will reflect NTI's or WNRL’s loss, net of intercompany eliminations, to the extent of our ownership interests in NTI and WNRL at that point in time.

The following condensed consolidating financial information is provided as an alternative to providing separate financial statements for guarantor subsidiaries. Separate financial statements of Western’s subsidiary guarantors are not included because the guarantees are full and unconditional and these subsidiary guarantors are 100% owned and jointly and severally liable for the Parent’s outstanding debt. The information is presented using the equity method of accounting for investments in subsidiaries.

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CONDENSED CONSOLIDATING BALANCE SHEETS

As of December 31, 2014

(In thousands)

	Parent		Guarantor Subsidiaries		Non-Guarantors		Eliminations			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	21	$	288,986	$	142,152	$	—		$	431,159
Accounts receivable, trade, net of a reserve for doubtful accounts	—		178,786		288,741		—			467,527
Accounts receivable, affiliate	5,035		1,710,015		2,045		(1,717,095		)	—
Inventories	—		379,563		249,674		—			629,237
Prepaid expenses	—		69,580		18,835		—			88,415
Other current assets	—		128,564		23,561		—			152,125
Deferred income tax asset, net	—		—		—		—			—
Total current assets	5,056		2,755,494		725,008		(1,717,095		)	1,768,463
Restricted cash	—		167,009		—		—			167,009
Equity method investment	—		—		96,080		—			96,080
Property, plant and equipment, net	—		1,092,667		1,060,522		—			2,153,189
Goodwill	—		—		1,289,443		—			1,289,443
Intangible assets, net	—		35,974		49,978		—			85,952
Investment in subsidiaries	3,637,607		—		—		(3,637,607		)	—
Other assets, net	33,463		67,652		21,307		—			122,422
Total assets	$	3,676,126	$	4,118,796	$	3,242,338	$	(5,354,702	)	$	5,682,558
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable, trade	$	—	$	354,223	$	327,580	$	—		$	681,803
Accounts payable, affiliate	1,656,412		—		60,683		(1,717,095		)	—
Accrued liabilities	5,506		179,926		83,017		—			268,449
Current deferred income tax liability, net	—		57,949		—		—			57,949
Current portion of long-term debt	5,500		—		—		—			5,500
Total current liabilities	1,667,418		592,098		471,280		(1,717,095		)	1,013,701
Long-term liabilities:
Long-term debt, less current portion	889,000		—		626,037		—			1,515,037
Lease financing obligation	—		18,860		8,629		—			27,489
Deferred income tax liability, net	—		259,581		37,279		—			296,860
Deficit in subsidiaries	—		354,686		—		(354,686		)	—
Other liabilities	—		36,530		5,297		—			41,827
Total long-term liabilities	889,000		669,657		677,242		(354,686		)	1,881,213
Equity:
Equity - Western	1,119,708		2,857,041		425,880		(3,282,921		)	1,119,708
Equity - Non-controlling interest	—		—		1,667,936		—			1,667,936
Total equity	1,119,708		2,857,041		2,093,816		(3,282,921		)	2,787,644
Total liabilities and equity	$	3,676,126	$	4,118,796	$	3,242,338	$	(5,354,702	)	$	5,682,558

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CONDENSED CONSOLIDATING BALANCE SHEETS

As of December 31, 2013

(In thousands)

	Parent		Guarantor Subsidiaries		Non-Guarantors		Eliminations			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	21	$	296,905	$	171,144	$	—		$	468,070
Accounts receivable, trade, net of a reserve for doubtful accounts	—		262,681		337,249		—			599,930
Accounts receivable, affiliate	—		1,114,179		2,601		(1,116,780		)	—
Inventories	—		383,210		174,178		—			557,388
Prepaid expenses	—		84,010		28,127		—			112,137
Other current assets	—		91,485		18,726		—			110,211
Total current assets	21		2,232,470		732,025		(1,116,780		)	1,847,736
Equity method investment	—		—		101,560		—			101,560
Property, plant and equipment, net	—		1,032,213		1,092,816		—			2,125,029
Goodwill	—		—		1,297,043		—			1,297,043
Intangible assets, net	—		35,157		42,941		—			78,098
Investment in subsidiaries	3,104,201		40,314		—		(3,144,515		)	—
Other assets, net	20,591		27,819		15,089		—			63,499
Total assets	$	3,124,813	$	3,367,973	$	3,281,474	$	(4,261,295	)	$	5,512,965
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable, trade	$	—	$	516,950	$	362,069	$	—		$	879,019
Accounts payable, affiliate	1,116,780		—		—		(1,116,780		)	—
Accrued liabilities	6,056		186,252		83,607		—			275,915
Current deferred income tax liability, net	—		30,398		95		—			30,493
Current portion of long-term debt	213,425		—		217		—			213,642
Total current liabilities	1,336,261		733,600		445,988		(1,116,780		)	1,399,069
Long-term liabilities:
Long-term debt, less current portion	894,500		—		278,465		—			1,172,965
Lease financing obligation	—		16,462		8,448		—			24,910
Deferred income tax liability, net	—		215,209		37,280		—			252,489
Deficit in subsidiaries	—		—		—		—			—
Other liabilities	—		87,229		5,716		—			92,945
Total long-term liabilities	894,500		318,900		329,909		—			1,543,309
Equity:
Equity - Western	894,052		2,315,473		829,042		(3,144,515		)	894,052
Equity - Non-controlling interest	—		—		1,676,535		—			1,676,535
Total equity	894,052		2,315,473		2,505,577		(3,144,515		)	2,570,587
Total liabilities and equity	$	3,124,813	$	3,367,973	$	3,281,474	$	(4,261,295	)	$	5,512,965

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CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS AND COMPREHENSIVE INCOME

For the Year Ended December 31, 2014

(In thousands)

	Parent			Guarantor Subsidiaries			Non-Guarantors			Eliminations			Consolidated
Net sales	$	—		$	11,004,242		$	8,749,303		$	(4,599,972	)	$	15,153,573
Operating costs and expenses:
Cost of products sold (exclusive of depreciation and amortization)	—			9,531,146			7,772,189			(4,583,372		)	12,719,963
Direct operating expenses (exclusive of depreciation and amortization)	—			426,732			440,502			(16,600		)	850,634
Selling, general and administrative expenses	186			114,168			111,666			—			226,020
Affiliate severance costs	—			—			12,878			—			12,878
Loss on disposal of assets, net	—			8,465			65			—			8,530
Maintenance turnaround expense	—			48,469			—			—			48,469
Depreciation and amortization	—			96,650			93,916			—			190,566
Total operating costs and expenses	186			10,225,630			8,431,216			(4,599,972		)	14,057,060
Operating income (loss)	(186		)	778,612			318,087			—			1,096,513
Other income (expense):
Equity in earnings (loss) of subsidiaries	630,407			55,944			—			(686,351		)	—
Interest income	—			795			393			—			1,188
Interest expense and other financing costs	(63,023		)	(1,044		)	(25,209		)	—			(89,276		)
Amortization of loan fees	(7,263		)	—			(523		)	—			(7,786		)
Loss on extinguishment of debt	(9		)	—			—			—			(9		)
Other, net	—			(594		)	2,640			—			2,046
Income (loss) before income taxes	559,926			833,713			295,388			(686,351		)	1,002,676
Provision for income taxes	—			(292,145		)	(459		)	—			(292,604		)
Net income (loss)	559,926			541,568			294,929			(686,351		)	710,072
Less net income attributed to non-controlling interest	—			—			150,146			—			150,146
Net income (loss) attributable to Western Refining, Inc.	$	559,926		$	541,568		$	144,783		$	(686,351	)	$	559,926
Comprehensive income attributable to Western Refining, Inc.	$	559,926		$	541,091		$	144,319		$	(686,351	)	$	558,985

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CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS AND COMPREHENSIVE INCOME

For the Year Ended December 31, 2013

(In thousands)

	Parent			Guarantor Subsidiaries			Non-Guarantors			Eliminations			Consolidated
Net sales	$	—		$	10,387,943		$	4,351,217		$	(4,653,090	)	$	10,086,070
Operating costs and expenses:
Cost of products sold (exclusive of depreciation and amortization)	—			9,201,577			4,128,924			(4,640,279		)	8,690,222
Direct operating expenses (exclusive of depreciation and amortization)	—			366,217			170,430			(12,811		)	523,836
Selling, general and administrative expenses	185			110,738			26,108			—			137,031
Loss (gain) and impairments on disposal of assets, net	—			(4,999		)	10			—			(4,989		)
Maintenance turnaround expense	—			50,249			—			—			50,249
Depreciation and amortization	—			91,138			26,710			—			117,848
Total operating costs and expenses	185			9,814,920			4,352,182			(4,653,090		)	9,514,197
Operating income (loss)	(185		)	573,023			(965		)	—			571,873
Other income (expense):
Equity in earnings (loss) of subsidiaries	391,526			(41,546		)	—			(349,980		)	—
Interest income	—			697			49			—			746
Interest expense and other financing costs	(62,142		)	(802		)	(5,096		)	—			(68,040		)
Amortization of loan fees	(6,432		)	—			(109		)	—			(6,541		)
Loss on extinguishment of debt	(46,773		)	—			—			—			(46,773		)
Other, net	—			392			1,822			—			2,214
Income (loss) before income taxes	275,994			531,764			(4,299		)	(349,980		)	453,479
Provision for income taxes	—			(153,830		)	(95		)	—			(153,925		)
Net income (loss)	275,994			377,934			(4,394		)	(349,980		)	299,554
Less net income attributed to non-controlling interest	—			—			23,560			—			23,560
Net income (loss) attributable to Western Refining, Inc.	$	275,994		$	377,934		$	(27,954	)	$	(349,980	)	$	275,994
Comprehensive income attributable to Western Refining, Inc.	$	275,994		$	378,621		$	(27,817	)	$	(349,980	)	$	276,818

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS AND COMPREHENSIVE INCOME

For the Year Ended December 31, 2012

(In thousands)

	Parent			Guarantor Subsidiaries			Non-Guarantors			Eliminations			Consolidated
Net sales	$	—		$	11,049,424		$	3,734,428		$	(5,280,718	)	$	9,503,134
Operating costs and expenses:
Cost of products sold (exclusive of depreciation and amortization)	—			9,688,635			3,638,595			(5,272,845		)	8,054,385
Direct operating expenses (exclusive of depreciation and amortization)	—			375,569			115,374			(7,873		)	483,070
Selling, general and administrative expenses	92			100,853			13,683			—			114,628
Gain on disposal of assets, net	—			(1,382		)	(509		)	—			(1,891		)
Maintenance turnaround expense	—			47,140			—			—			47,140
Depreciation and amortization	—			79,592			14,315			—			93,907
Total operating costs and expenses	92			10,290,407			3,781,458			(5,280,718		)	8,791,239
Operating income (loss)	(92		)	759,017			(47,030		)	—			711,895
Other income (expense):
Equity in earnings (loss) of subsidiaries	494,185			(46,756		)	—			(447,429		)	—
Interest income	—			674			22			—			696
Interest expense and other financing costs	(80,694		)	(615		)	(40		)	—			(81,349		)
Amortization of loan fees	(6,860		)	—			—			—			(6,860		)
Loss on extinguishment of debt	(7,654		)	—			—			—			(7,654		)
Other, net	—			67			292			—			359
Income (loss) before income taxes	398,885			712,387			(46,756		)	(447,429		)	617,087
Provision for income taxes	—			(218,202		)	—			—			(218,202		)
Net income (loss)	$	398,885		$	494,185		$	(46,756	)	$	(447,429	)	$	398,885
Comprehensive income (loss) attributable to Western Refining, Inc.	$	398,885		$	494,823		$	(46,756	)	$	(447,429	)	$	399,523

116

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

For the Year Ended December 31, 2014

(In thousands)

	Parent			Guarantor Subsidiaries			Non-Guarantors			Eliminations			Consolidated
Cash flows from operating activities:
Net cash provided by (used in) operating activities	$	(54,846	)	$	517,756		$	406,303		$	(131,580	)	$	737,633
Cash flows from investing activities:
Capital expenditures	—			(156,051		)	(67,220		)	—			(223,271		)
Return of capital from equity method investment	—			—			7,480			—			7,480
Contributions to affiliate	—			(618,564		)	(93,546		)	712,110			—
Proceeds from the sale of assets	—			1,259			677			—			1,936
Net increase in restricted cash	—			(167,009		)	—			—			(167,009		)
Net cash provided by (used in) investing activities	—			(940,365		)	(152,609		)	712,110			(380,864		)
Cash flows from financing activities:
Additions to long-term debt	—			—			79,311			—			79,311
Payments on long-term debt	(5,759		)	—			(313		)	—			(6,072		)
Borrowings on revolving credit facility	—			—			269,000			—			269,000
Contributions from affiliate	618,564			93,546			—			(712,110		)	—
Distribution to non-controlling interest holders	—			—			(173,637		)	—			(173,637		)
Deferred financing costs	(4,182		)	—			(5,467		)	—			(9,649		)
Distribution to affiliate	—			—			(131,580		)	131,580			—
Purchases of treasury stock	(259,222		)	—			—			—			(259,222		)
Dividends paid	(293,746		)	—			—			—			(293,746		)
Convertible debt redemption	(809		)	—			—			—			(809		)
Distribution to Western Refining, Inc.	—			320,000			(320,000		)	—			—
Excess tax benefit from stock-based compensation	—			1,144			—			—			1,144
Net cash provided by (used in) financing activities	54,846			414,690			(282,686		)	(580,530		)	(393,680		)
Net decrease in cash and cash equivalents	—			(7,919		)	(28,992		)	—			(36,911		)
Cash and cash equivalents at beginning of year	21			296,905			171,144			—			468,070
Cash and cash equivalents at end of year	$	21		$	288,986		$	142,152		$	—		$	431,159

117

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

For the Year Ended December 31, 2013

(In thousands)

	Parent			Guarantor Subsidiaries			Non-Guarantors			Eliminations			Consolidated
Cash flows from operating activities:
Net cash provided by (used in) operating activities	$	541,154		$	(152,532	)	$	52,531		$	—		$	441,153
Cash flows from investing activities:
Capital expenditures	—			(125,395		)	(80,282		)	—			(205,677		)
Proceeds from the sale of assets	—			7,439			36			—			7,475
Return of capital from equity method investment	—			—			1,140			—			1,140
Northern Tier Energy acquisition, net of cash acquired	(775,000		)	—			76,177			—			(698,823		)
Contributions to affiliate	—			(139,794		)	—			139,794			—
Net cash provided by (used in) investing activities	(775,000		)	(257,750		)	(2,929		)	139,794			(895,885		)
Cash flows from financing activities:
Additions to long-term debt	900,000			—			—			—			900,000
Payments on long-term debt	(325,163		)	—			(206		)	—			(325,369		)
Repayments of revolving credit facility	—			—			(50,000		)	—			(50,000		)
Distribution to non-controlling interest holders	—			—			(28,575		)	—			(28,575		)
Debt retirement fees	(24,396		)	—			—			—			(24,396		)
Deferred financing costs	(26,030		)	—			(2,616		)	—			(28,646		)
Contributions from affiliate	15,122			—			124,672			(139,794		)	—
Purchases of treasury stock	(252,841		)	—			—			—			(252,841		)
Dividends paid	(52,489		)	—			—			—			(52,489		)
Convertible debt redemption	(357		)	—			—			—			(357		)
Net proceeds from issuance of WNRL common units	—			—			323,146			—			323,146
Distribution to Western Refining, Inc.	—			244,884			(244,884		)	—			—
Excess tax benefit from stock-based compensation	—			8,362			—			—			8,362
Net cash provided by (used in) financing activities	233,846			253,246			121,537			(139,794		)	468,835
Net increase (decrease) in cash and cash equivalents	—			(157,036		)	171,139			—			14,103
Cash and cash equivalents at beginning of year	21			453,941			5			—			453,967
Cash and cash equivalents at end of year	$	21		$	296,905		$	171,144		$	—		$	468,070

118

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

For the Year Ended December 31, 2012

(In thousands)

	Parent			Guarantor Subsidiaries			Non-Guarantors			Eliminations			Consolidated
Cash flows from operating activities:
Net cash provided by (used in) operating activities	$	633,621		$	342,592		$	(59,860	)	$	—		$	916,353
Cash flows from investing activities:
Capital expenditures	—			(174,081		)	(28,076		)	—			(202,157		)
Proceeds from the sale of assets	—			17			291			—			308
Contributions to affiliate	—			(101,333		)	—			101,333			—
Net decrease in restricted cash	—			220,355			—			—			220,355
Net cash provided by (used in) investing activities	—			(55,042		)	(27,785		)	101,333			18,506
Cash flows from financing activities:
Payments on long-term debt	(322,563		)	—			(345		)	—			(322,908		)
Debt retirement fees	(1,415		)	—			—			—			(1,415		)
Contributions from affiliate	13,342			—			87,991			(101,333		)	—
Purchases of treasury stock	(82,270		)	—			—			—			(82,270		)
Dividends paid	(240,715		)	—			—			—			(240,715		)
Excess tax benefit from stock-based compensation	—			(4,413		)	—			—			(4,413		)
Net cash provided by (used in) financing activities	(633,621		)	(4,413		)	87,646			(101,333		)	(651,721		)
Net increase in cash and cash equivalents	—			283,137			1			—			283,138
Cash and cash equivalents at beginning of year	21			170,804			4			—			170,829
Cash and cash equivalents at end of year	$	21		$	453,941		$	5		$	—		$	453,967

119

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

We restated the Condensed Consolidating Balance Sheet as of December 31, 2013, to correct immaterial errors in the presentation of the non-guarantors' investment in NTI, the Parent’s and the Guarantor Subsidiaries' Investment in Subsidiaries and the Parent’s and the Guarantor Subsidiaries' Equity. We previously presented $775.0 million as investment in NTI in the Investment in Subsidiaries line item in the non-guarantor column of the Condensed Consolidating Balance Sheets as of December 31, 2013. We have reclassified this amount into the Equity - Western line item in the non-guarantor column. We have also corrected the Parent’s equity in the earnings of subsidiaries by changing the previously reported Investment in Subsidiaries and Equity - Western in the Parent column. We made similar changes in the Guarantor Subsidiaries column by changing previously reported amounts.

The effect of presenting the equity method of accounting for investments in subsidiaries also resulted in corrections to the Condensed Consolidating Statement of Operations and Comprehensive Income for the years ended December 31, 2013 and 2012. We have corrected the Parent’s and Guarantor Subsidiaries Equity in Earnings of Subsidiaries for the years ended December 31, 2013 and 2012. We adjusted all of these amounts in the eliminations column.

The condensed consolidating statements of cash flows for the years ended December 31, 2013 and 2012 have been restated to correct the presentation of transactions between the Parent, the Guarantor Subsidiaries and the Non-Guarantors as described above. As there were no changes in the classification between operating, investing and financing, there is no impact on the consolidated statement of cash flows for the years ended December 31, 2013 and 2012.

These errors did not have an impact on the consolidated balance sheet, income statement or statement of cash flows as of December 31, 2013 or 2012, and we believe these corrections are not material to our previously issued annual or interim consolidated financial statements.

Due to the change in the guarantor structure resulting from the Wholesale Acquisition, we have revised the condensed consolidating financial information for all periods presented. See Note 29, Western Refining Logistics, LP, for additional information on this transaction.

The application of these adjustments to the prior year condensed consolidating financial information are summarized as follows:

CONDENSED CONSOLIDATING BALANCE SHEETS

As of December 31, 2013

(In thousands)

	As Previously Reported			Adjustment			Revised and Restated
Parent	$	1,854,645		$	1,249,556		$	3,104,201
Guarantor subsidiaries	431,642			(391,328		)	40,314
Non-guarantor subsidiaries	(775,000		)	775,000			—
Eliminations	(1,511,287		)	(1,633,228		)	(3,144,515		)
Investment in subsidiaries	$	—		$	—		$	—
Parent	$	(383,451	)	$	1,277,503		$	894,052
Guarantor subsidiaries	3,052,289			(736,816		)	2,315,473
Non-guarantor subsidiaries	1,597,464			908,113			2,505,577
Eliminations	(1,695,715		)	(1,448,800		)	(3,144,515		)
Total equity	$	2,570,587		$	—		$	2,570,587

120

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS AND COMPREHENSIVE INCOME

For the Year Ended December 31, 2013

(In thousands)

	As Previously Reported			Adjustment			Revised and Restated
Parent	$	—		$	391,526		$	391,526
Guarantor subsidiaries	—			(41,546		)	(41,546		)
Non-guarantor subsidiaries	—			—			—
Eliminations	—			(349,980		)	(349,980		)
Equity in earnings (loss) of subsidiaries	$	—		$	—		$	—
Parent	(62,939		)	338,933			275,994
Guarantor subsidiaries	319,769			58,165			377,934
Non-guarantor subsidiaries	19,164			(47,118		)	(27,954		)
Eliminations	—			(349,980		)	(349,980		)
Net income (loss) attributable to Western Refining, Inc.	$	275,994		$	—		$	275,994
Parent	$	(62,939	)	$	338,933		$	275,994
Guarantor subsidiaries	320,456			58,165			378,621
Non-guarantor subsidiaries	19,301			(47,118		)	(27,817		)
Eliminations	—			(349,980		)	(349,980		)
Comprehensive income attributable to Western Refining, Inc.	$	276,818		$	—		$	276,818

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS AND COMPREHENSIVE INCOME

For the Year Ended December 31, 2012

(In thousands)

	As Previously Reported			Adjustment			Revised and Restated
Parent	$	—		$	494,185		$	494,185
Guarantor subsidiaries	—			(46,756		)	(46,756		)
Non-guarantor subsidiaries	—			—			—
Eliminations	—			(447,429		)	(447,429		)
Equity in earnings (loss) of subsidiaries	$	—		$	—		$	—
Parent	(79,071		)	477,956			398,885
Guarantor subsidiaries	477,956			16,229			494,185
Non-guarantor subsidiaries	—			(46,756		)	(46,756		)
Eliminations	—			(447,429		)	(447,429		)
Net income (loss) attributable to Western Refining, Inc.	$	398,885		$	—		$	398,885
Parent	$	(79,071	)	$	477,956		$	398,885
Guarantor subsidiaries	478,594			16,229			494,823
Non-guarantor subsidiaries	—			(46,756		)	(46,756		)
Eliminations	—			(447,429		)	(447,429		)
Comprehensive income attributable to Western Refining, Inc.	$	399,523		$	—		$	399,523

121

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

For the Year Ended December 31, 2013

(In thousands)

	As Previously Reported			Adjustment			Revised and Restated
Parent	$	—		$	541,154		$	541,154
Guarantor subsidiaries	395,306			(547,838		)	(152,532		)
Non-guarantor subsidiaries	45,847			6,684			52,531
Eliminations	—			—			—
Net cash provided by (used in) operating activities	$	441,153		$	—		$	441,153
Parent	—			(775,000		)	(775,000		)
Guarantor subsidiaries	(902,179		)	644,429			(257,750		)
Non-guarantor subsidiaries	126,896			(129,825		)	(2,929		)
Eliminations	(120,602		)	260,396			139,794
Net cash provided by (used in) investing activities	$	(895,885	)	$	—		$	(895,885	)
Parent	$	—		$	233,846		$	233,846
Guarantor subsidiaries	351,162			(97,916		)	253,246
Non-guarantor subsidiaries	(2,929		)	124,466			121,537
Eliminations	120,602			(260,396		)	(139,794		)
Net cash provided by (used in) financing activities	$	468,835		$	—		$	468,835

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

For the Year Ended December 31, 2012

(In thousands)

	As Previously Reported			Adjustment			Revised and Restated
Parent	$	—		$	633,621		$	633,621
Guarantor subsidiaries	916,353			(573,761		)	342,592
Non-guarantor subsidiaries	—			(59,860		)	(59,860		)
Eliminations	—			—			—
Net cash provided by (used in) operating activities	$	916,353		$	—		$	916,353
Parent	—			—			—
Guarantor subsidiaries	18,506			(73,548		)	(55,042		)
Non-guarantor subsidiaries	—			(27,785		)	(27,785		)
Eliminations	—			101,333			101,333
Net cash provided by (used in) investing activities	$	18,506		$	—		$	18,506
Parent	$	—		$	(633,621	)	$	(633,621	)
Guarantor subsidiaries	(651,721		)	647,308			(4,413		)
Non-guarantor subsidiaries	—			87,646			87,646
Eliminations	—			(101,333		)	(101,333		)
Net cash provided by (used in) financing activities	$	(651,721	)	$	—		$	(651,721	)

122

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

28. Quarterly Financial Information (Unaudited)

Demand for gasoline is generally higher during the summer months than during the winter months. As a result, our operating results for the first and fourth calendar quarters are generally lower than those for the second and third calendar quarters of each year. During 2014, the volatility in crude oil prices and refining margins also contributed to the variability of our results of operations for the four calendar quarters.

The quarterly financial data for the years ended December 31, 2014, and 2013 is presented below.

	Year Ended December 31, 2014
	Quarter
	First			Second			Third			Fourth
	(Unaudited) (In thousands, except for per share data)
Net sales	$	3,725,143		$	4,351,290		$	4,052,324		$	3,024,816
Operating costs and expenses:
Cost of products sold (exclusive of depreciation and amortization)	3,160,737			3,731,169			3,379,555			2,448,502
Direct operating expenses (exclusive of depreciation and amortization)	198,349			203,463			218,183			230,639
Selling, general and administrative expenses	58,732			54,640			57,206			55,442
Affiliate severance costs	9,399			3,479			—			—
Loss (gain) and impairments on disposal of assets, net	886			119			(66		)	7,591
Maintenance turnaround expense	46,446			—			1,883			140
Depreciation and amortization	46,410			47,848			46,910			49,398
Total operating costs and expenses	3,520,959			4,040,718			3,703,671			2,791,712
Operating income	204,184			310,572			348,653			233,104
Other income (expense):
Interest income	195			221			483			289
Interest expense and other financing costs	(26,860		)	(25,722		)	(16,358		)	(20,336		)
Amortization of loan fees	(2,097		)	(2,079		)	(1,892		)	(1,718		)
Loss on extinguishment of debt	(8		)	(1		)	—			—
Other, net	1,482			983			(2,816		)	2,397
Income before income taxes	176,896			283,974			328,070			213,736
Provision for income taxes	(49,199		)	(93,407		)	(80,713		)	(69,285		)
Net income	127,697			190,567			247,357			144,451
Less net income attributed to non-controlling interest	42,151			33,871			60,608			13,516
Net income attributable to Western Refining, Inc.	$	85,546		$	156,696		$	186,749		$	130,935
Basic earnings per common share	$	1.07		$	1.88		$	1.85		$	1.34
Diluted earnings per common share	$	0.88		$	1.56		$	1.84		$	1.33

123

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

	Year Ended December 31, 2013
	Quarter
	First			Second			Third			Fourth
	(Unaudited) (In thousands, except for per share data)
Net sales	$	2,186,217		$	2,429,962		$	2,447,610		$	3,022,281
Operating costs and expenses:
Cost of products sold (exclusive of depreciation and amortization)	1,797,184			1,986,883			2,177,623			2,728,532
Direct operating expenses (exclusive of depreciation and amortization)	121,860			113,861			123,474			164,641
Selling, general and administrative expenses	26,552			29,450			28,777			52,252
Loss (gain) and impairments on disposal of assets, net	—			—			(7,024		)	2,035
Maintenance turnaround expense	43,168			35			2,895			4,151
Depreciation and amortization	24,332			27,143			27,735			38,638
Total operating costs and expenses	2,013,096			2,157,372			2,353,480			2,990,249
Operating income	173,121			272,590			94,130			32,032
Other income (expense):
Interest income	151			235			155			205
Interest expense and other financing costs	(17,988		)	(14,681		)	(13,432		)	(21,939		)
Amortization of loan fees	(1,604		)	(1,515		)	(1,523		)	(1,899		)
Loss on extinguishment of debt	(22,047		)	(24,719		)	(6		)	(1		)
Other, net	197			101			94			1,822
Income before income taxes	131,830			232,011			79,418			10,220
Provision for income taxes	(48,111		)	(82,752		)	(29,074		)	6,012
Net income	83,719			149,259			50,344			16,232
Less net income attributed to non-controlling interest	—			—			—			23,560
Net income (loss) attributable to Western Refining, Inc.	$	83,719		$	149,259		$	50,344		$	(7,328	)
Basic earnings (loss) per common share	$	0.96		$	1.81		$	0.63		$	(0.09	)
Diluted earnings (loss) per common share	$	0.81		$	1.46		$	0.53		$	(0.09	)

29. Western Refining Logistics, LP

WNRL is a publicly traded limited partnership that was formed to own, operate, develop and acquire logistics assets. Headquartered in El Paso, Texas, WNRL's assets consist of pipeline and gathering assets and terminalling, transportation and storage assets in the Southwestern portion of the U.S., including approximately 300 miles of pipelines and approximately 8.0 million barrels of active storage capacity, as well as other assets. The majority of WNRL's assets are integral to the operations of Western's refineries located in El Paso, Texas and near Gallup, New Mexico.

At December 31, 2014, we held a 66.2% limited partner interest in WNRL including a non-economic general partner interest. This interest included 8,158,592 common partnership units and 22,811,000 subordinated partnership units. All intercompany transactions with WNRL are eliminated upon consolidation.

WNRL generates revenue by charging fees for gathering, transporting and storing crude oil on their pipeline systems and for terminalling, transporting and storing crude oil and refined products at their terminals. We do not provide financial or equity support through any liquidity arrangements or financial guarantees to WNRL.

WNRL provides us with various pipeline transportation, terminal distribution and storage services under long-term, fee-based commercial agreements expiring in 2023. These agreements contain minimum volume commitments. Each agreement has fees that are indexed for inflation and provides us with options to renew for two additional five-year terms.

124

WESTERN REFINING, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

In addition to commercial agreements, we are also party to an omnibus agreement with WNRL that among other things provides for reimbursement to us for various general and administrative services provided to WNRL. We are also party to an operational services agreement with WNRL, under which we are reimbursed for personnel services provided by Western in support of WNRL's operations of its pipelines, terminals and storage facilities.

WNRL entered into a credit agreement that provides for a $300 million senior secured revolving credit facility, expiring October 16, 2018. The revolving credit facility is available to fund working capital, acquisitions, distributions, capital expenditures and for other general partnership purposes.

Initial Public Offering

On October 10, 2013, the common partnership units of WNRL began trading on the New York Stock Exchange under the symbol "WNRL." On October 16, 2013, WNRL completed its initial public offering of 15,812,500 common units representing limited partner interests at a price of $22.00 per unit.

On October 16, 2013, in exchange for assets contributed at historical cost, Western received:

• 6,998,500 common partnership units and 22,811,000 subordinated partnership units, representing an aggregate 65.3% limited partner interest;

• All WNRL's incentive distribution rights; and

• An aggregate cash distribution of $244.9 million to certain of Western's wholly-owned subsidiaries.

A summary of the proceeds received and the use of proceeds was as follows (in thousands):

Proceeds received from sale of common units	$	347,875
Use of proceeds:
Underwriting discounts and commissions	$	20,873
Structuring fees	1,739
Offering expenses	2,117
Retained for working capital	75,683
Distributed to Western Refining, Inc.	244,884
Revolving credit agreement closing costs	2,579
Total	$	347,875

Wholesale Acquisition

On October 15, 2014, pursuant to the terms of the Contribution Agreement, Western sold all of the outstanding limited liability company interests of WRW to WNRL, in exchange for consideration of $320 million in cash and 1,160,092 common units representing limited partner interests in WNRL.

As of the Closing Date, Western sold substantially all of its southwest wholesale assets including assets and related inventories of WRW's lubricant distribution, southwest bulk petroleum fuels distribution, and crude oil and products transportation businesses to WNRL.

The cash portion of the consideration consisted of $269.0 million in direct borrowings under the WNRL Revolving Credit Facility and $51.0 million from cash on-hand. We did not recognize a gain from the sale of WRW's assets to WNRL as the sale of assets was treated as a reorganization of entities under common control.

We entered into the following agreements with WNRL that each have initial ten year terms in connection with the Contribution Agreement:

• Product Supply Agreement – Western will supply and WNRL will purchase approximately 79,000 barrels per day of refined products for sale to WNRL’s wholesale customers. The agreement includes product pricing based upon OPIS or Platts indices on the day of delivery.

• Fuel Distribution and Supply Agreement – Western will purchase a minimum of 645,000 barrels per month of branded and unbranded motor fuels for our retail and cardlock sites at a price equal to WNRL’s product cost at each terminal, plus actual transportation costs, plus a margin of $0.03 per gallon.

125

WESTERN REFINING, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

• Crude Oil Trucking Transportation Services Agreement – Western will utilize WNRL’s crude oil trucks to haul a minimum of 1.525 million barrels of crude oil each month. Western will pay a flat rate per barrel based on the distance between the applicable pick-up and delivery points plus monthly fuel adjustments and customary applicable surcharges.

Distributions

On January 31, 2014, the board of directors of WNRL's general partner declared a quarterly cash distribution of $0.2407 per unit for the prorated period of October 16, 2013, through December 31, 2013, and corresponds to the prorated minimum quarterly distribution of $0.2875 per unit. WNRL paid the distribution on February 24, 2014, to all unitholders of record on February 14, 2014. WNRL paid no distributions prior to this date.

The table below summarizes WNRL's 2014 quarterly distribution declarations, payments and scheduled payments through February 27, 2015:

	2014
	Declaration Date	Record Date	Payment Date	Distribution per Common and Subordinated Unit
First quarter	May 2	May 16	May 26	$	0.2975
Second quarter	August 1	August 15	August 25	0.3075
Third quarter	October 31	November 14	November 24	0.3175
Fourth quarter	January 30	February 13	February 23	0.3325
Total				$	1.2550

30. Acquisitions

On November 12, 2013, Western purchased all of NTH’s interests in NT InterHoldCo LLC, a wholly-owned subsidiary of NTH that holds all of the membership interests in NTI and 35,622,500 common units representing a 38.7% limited partner interest in NTI for a purchase price of $775 million. The purchase price, including transaction expenses, was funded by a $550 million term loan and $242 million in cash.

NTI's assets are located in the Upper Great Plains region and include a refinery in St. Paul Park, Minnesota that has a 97,800 barrel per day refining capacity. Refining operations include crude fractionation, catalytic cracking, hydrotreating, reforming, alkylation, sulfur recovery and a hydrogen plant. The refinery processes predominately North Dakota and Canadian crude oils into products such as gasoline, diesel, jet fuel, kerosene, asphalt, propane, propylene and sulfur. The refined products are sold to markets primarily located in the Upper Great Plains of the United States. NTI also operates convenience stores under the SuperAmerica brand that are primarily located in Minnesota and Wisconsin and sells gasoline, merchandise and in some locations, diesel fuel.

The allocation of the purchase price of NTI at December 31, 2014 was revised from amounts previously reported in that intangible assets was increased by $7.6 million and goodwill was decreased by $7.6 million for revisions in our purchase price valuation. The allocation of the purchase price of NTI as of December 31, 2014, is summarized as follows (in thousands):

Net working capital	$	95,937
Property, plant and equipment	916,705
Intangible assets	45,800
Other assets	114,000
Long-term debt	(278,438		)
Other liabilities	(50,743		)
Non-controlling interest	(1,357,704		)
Fair value of net assets acquired	(514,443		)
Goodwill	1,289,443
Purchase price	$	775,000

126

WESTERN REFINING, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

The consolidated statements of operations include the results of NTI’s operations beginning on November 12, 2013. The following unaudited pro forma information assumes that (i) the acquisition of NTI occurred on January 1, 2012; (ii) $550.0 million was borrowed to fund the NTI acquisition on January 1, 2012, resulting in increased financing costs of $23.9 million and $24.0 million for the years ended December 31, 2013 and 2012, respectively; (iii) $36.7 million increased depreciation and amortization expense in both years for the increased estimated fair values of assets acquired beginning January 1, 2012; and (iv) income tax expense increased as a result of the increased operating income offset by increased depreciation, amortization and interest expense of $22.1 million and $12.9 million, for the years ended December 31, 2013 and 2012, respectively.

	Unaudited Pro Forma for the Years Ended December 31,
	2013		2012
	(In thousands, except per share data)
Net sales	$	14,044,131	$	13,856,934
Operating income	746,699		966,765
Net income	413,375		522,879
Basic earnings per share	$	3.56	$	4.79
Diluted earnings per share	2.96		3.79

The table below summarizes NTI's 2014 quarterly distribution declarations, payments and scheduled payments through December 31, 2014:

	2014
	Declaration Date	Record Date	Payment Date	Distribution per Unit
First quarter	February 7	February 21	February 28	$	0.41
Second quarter	May 6	May 19	May 30	0.77
Third quarter	August 5	August 18	August 29	0.53
Fourth quarter	November 4	November 14	November 25	1.00
Total				$	2.71

On February 6, 2015, NTI declared a quarterly distribution of $0.49 per unit to common unitholders of record on February 17, 2015, payable on February 27, 2015.

127

Item 9. Changes In and Disagreements With Accountants on Accounting and Financial Disclosure

None.

Item 9A. Controls and Procedures

Evaluation of disclosure controls and procedures. Our chief executive officer and chief financial officer, after evaluating the effectiveness of our “disclosure controls and procedures” (as defined in the Securities Exchange Act of 1934 Rules 13a-15(e) and 15d-15(e)) as of December 31, 2014 (the “Evaluation Date”), concluded that as of the Evaluation Date, our disclosure controls and procedures were effective.

Management’s Report on Internal Control Over Financial Reporting. Included herein under the caption "Management’s Report on Internal Control Over Financial Reporting" on page 59 of this report.

Attestation Report of the Registered Public Accounting Firm. Included herein under the caption "Report of Independent Registered Public Accounting Firm" on page 60 of this report.

Changes in internal control over financial reporting. There were no changes in our internal control over financial reporting that occurred during the quarter ended December 31, 2014, that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Item 9B. Other Information

None.

PART III

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

Item 10. Directors, Executive Officers and Corporate Governance

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

Item 11. Executive Compensation

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

128

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

Security Ownership of Certain Beneficial Owners and Management

The information required by this item is incorporated by reference to the information contained in Western Refining, Inc.’s Definitive Proxy Statement under the heading “Security Ownership of Certain Beneficial Owners and Management.”

Securities Authorized for Issuance Under Equity Compensation Plans

Plan Category	(a) Number of securities to be issued upon exercise of outstanding options, warrants and rights (1)	(b) Weighted average exercise price of outstanding options, warrants and rights (2)	(c) Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))
Equity compensation plans approved by security holders	380,695	—	2,894,264
Equity compensation plans not approved by security holders	—	—	—
Total	380,695	—	2,894,264

(1) Represents 380,695 shares underlying restricted share unit awards.

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

Item 13. Certain Relationships and Related Transactions and Director Independence

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

Item 14. Principal Accountant Fees and Services

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

129

PART IV

Item 15. Exhibits and Financial Statement Schedules

(a) Financial Statements:

See Index to Financial Statements included in Item 8.

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

Exhibit Index***

Number	Exhibit Title
2.1	Agreement and Plan of Merger, dated August 26, 2006, by and among Western Refining, Inc., New Acquisition Corporation and Giant Industries, Inc. (incorporated by reference to Exhibit 2.1 to the Company's Current Report on Form 8-K, filed with the SEC on August 28, 2006).
2.2	Amendment No. 1 to the Agreement and Plan of Merger, dated November 12, 2006, by and among Western Refining, Inc., New Acquisition Corporation and Giant Industries, Inc. (incorporated by reference to Exhibit 2.1 to the Company's Current Report on Form 8-K, filed with the SEC on November 13, 2006).
2.3	Contribution, Conveyance and Assumption Agreement by and among Western Refining Logistics, LP, Western Refining GP, LLC, Western Refining Southwest, Inc., San Juan Refining Company, LLC, Western Refining Pipeline, LLC, Western Refining Terminals, LLC, Western Refining Company, L.P. and the Company (incorporated by reference to Exhibit 10.2 to the Company's Current Report on Form 8-K, filed with the SEC on October 22, 2013).
2.4	Contribution, Conveyance and Assumption Agreement, dated as of September 25, 2014, by and among Western Refining, Inc., Western Refining Southwest, Inc., Western Refining Logistics GP, LLC and Western Refining Logistics, LP (incorporated by reference to Exhibit 2.1 to the Company's Current Report on Form 8-K, filed with the SEC on October 1, 2014).
2.5	Amendment No. 1 to the Contribution, Conveyance and Assumption Agreement, dated as of October 15, 2014, by and among Western Refining, Inc., Western Refining Southwest, Inc., Western Refining Logistics GP, LLC and Western Refining Logistics, LP (incorporated by reference to Exhibit 2.2 to the Company's Quarterly Report on Form 10-Q, filed with the SEC on November 6, 2014).
3.1	Certificate of Incorporation, as amended, of the Company as currently in effect (incorporated by reference to Exhibit 3.1 to the Company's Quarterly Report on Form 10-Q, filed with the SEC on August 7, 2014).
3.2	Bylaws, as amended, of the Company as currently in effect (incorporated by reference to Exhibit 3.2 to the Company's Quarterly Report on Form 10-Q, filed with the SEC on August 7, 2014).
4.1	Specimen of Company Common Stock Certificate (incorporated by reference to Exhibit 4.1 to the Company's Registration Statement on Form S-1/A (File No. 333-128629), filed with the SEC on December 5, 2005).
4.2	Registration Rights Agreement, dated January 24, 2006, by and between the Company and each of the stockholders listed on the signature pages thereto (incorporated by reference to Exhibit 4.1 to the Company's Current Report on Form 8-K, filed with the SEC on January 25, 2006).
4.3	Indenture dated June 10, 2009 between Western Refining, Inc. and The Bank of New York Mellon Trust Company, N.A., as trustee (incorporated by reference to Exhibit 4.1 to the Company's Quarterly Report on Form 10-Q, filed with the SEC on August 7, 2009).
4.4	Supplemental Indenture dated June 10, 2009 between Western Refining, Inc. and The Bank of New York Mellon Trust Company, N.A., as trustee (incorporated by reference to Exhibit 4.1 to the Company's Current Report on Form 8-K filed on June 10, 2009).
4.5	Form of Convertible Senior Note (included in Exhibit 4.4).
4.6	Indenture dated March 25, 2013 among Western Refining, Inc., the Guarantors named therein and U.S. Bank National Association, as trustee, paying agent, registrar and transfer agent (incorporated by reference to Exhibit 4.1 to the Company's Current Report on Form 8-K, filed with the SEC on March 25, 2013).
4.7	Form of 6.25% Senior Note (included in Exhibit 4.6).
4.8	Registration Rights Agreement dated March 25, 2013 among Western Refining, Inc. and Deutsche Bank Securities Inc., Merrill Lynch, Pierce, Fenner & Smith Incorporated, Credit Suisse Securities (USA) LLC, Goldman, Sachs & Co., RBS Securities Inc., Barclays Capital Inc., Credit Agricole Securities (USA) Inc., PNC Capital Markets, RB International Markets (USA) LLC, Regions Securities LLC, SunTrust Robinson Humphrey, Inc. and U.S. Bancorp Investments, Inc. as the Initial Purchasers (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, filed with the SEC on March 25, 2013).

130

Number	Exhibit Title
4.9	Indenture, dated as of November 8, 2012, by and among Northern Tier Energy LLC, Northern Tier Finance Corporation, Northern Tier Energy LP, the subsidiary guarantors party thereto and Deutsche Bank Trust Company Americas (incorporated by reference to Exhibit 4.1 of Northern Tier Energy LP's Current Report on Form 8-K (File No. 001-35612), filed with the SEC on November 13, 2012).
4.10	Form of 7.125% Senior Secured Note (included in Exhibit 4.9).
4.11	Supplemental Indenture, dated September 29, 2014, by and among Northern Tier Energy LLC, Northern Tier Finance Corporation, Northern Tier Energy LP, the subsidiary guarantors party thereto and Deutsche Bank Trust Company Americas (incorporated by reference to Exhibit 4.1 of Northern Tier Energy LP's Current Report on Form 8-K (File No. 001-35612), filed with the SEC on October 3, 2014).
4.12	Indenture dated February 11, 2015, among Western Refining Logistics, LP, WNRL Finance Corp., the Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 of Western Refining Logistics, LP's Current Report on Form 8-K (File No. 001-36114), filed with the SEC on February 11, 2015).
4.13	Form of 7.50% Senior Note (included in Exhibit 4.12).
10.1	Second Amended and Restated Revolving Credit Agreement dated as of April 11, 2013 by and among Western Refining, Inc., the several lenders from time to time party thereto and Bank of America, N.A., as Administrative Agent, Swing Line Lender and L/C Issuer (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, filed with the SEC on April 15, 2013).
10.2	Third Amended and Restated Revolving Credit Agreement dated October 2, 2014 by and among Western Refining, Inc., the several lenders from time to time party thereto and Bank of America, N.A., as Administrative Agent, Swing Line Lender and L/C Issuer (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, filed with the SEC on October 6, 2014).
10.3	Term Loan Credit Agreement dated as of November 12, 2013, by and among Western Refining, Inc., Bank of America, N.A., as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.2 to the Company's Current Report on Form 8-K, filed with the SEC on November 14, 2013).
10.4	First Amendment to the Credit Agreement, dated as of July 17, 2012, by and among the financial institutions party thereto, as the lenders, J.P. Morgan Chase Bank, N.A., as administrative agent and collateral agent, Bank of America, N.A., as syndication agent, and Macquarie Capital (USA) Inc. and SunTrust Bank, as co-documentation agents, and Northern Tier Energy LLC and certain subsidiaries of Northern Tier Energy LLC party thereto (incorporated by reference to Exhibit 10.13 to Amendment No. 6 to Northern Tier Energy LP’s Registration Statement on Form S-1 (File No. 333-178457), filed with the SEC on July 18, 2012).
10.5	Credit Agreement, dated September 29, 2014, among Northern Tier Energy LLC, each subsidiary of Northern Tier Energy LLC party thereto, the several lenders and issuing banks party thereto and J.P. Morgan Chase Bank, N.A. as Administrative Agent and Collateral Agent (incorporated by reference to Exhibit 10.1 to Northern Tier Energy LP's Current Report on Form 8-K (File No. 001-35612), filed with the SEC on October 3, 2014).
10.6	Credit Agreement, dated as of October 16, 2013, by and among Western Refining Logistics, LP, the lenders from time to time party thereto and Well Fargo Bank, National Association, as Administrative Agent, Swingline Lender and L/C Issuer (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K (File No. 001-36114), filed with the SEC on October 22, 2013).
10.7	Purchase Agreement, dated as of November 12, 2013, by and between Northern Tier Investors LLC and Western Refining, Inc. (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, filed with the SEC on November 14, 2013).
10.8	Operating Agreement, dated May 6, 1993, by and between Western Refining LP and Chevron U.S.A. Inc. (incorporated by reference to Exhibit 10.10 to the Company's Registration Statement on Form S-1/A, filed with the SEC on November 3, 2005).
10.9	Purchase and Sale Agreement, dated May 29, 2003, by and among Chevron U.S.A. Inc., Chevron Pipe Line Company, Western Refining LP and Kaston Pipeline Company, L.P. (incorporated by reference to Exhibit 10.11 to the Company's Registration Statement on Form S-1/A (File No. 333-128629), filed with the SEC on November 3, 2005).
10.10	Asset Purchase Agreement, dated November 30, 2011, by and among Western Refining Yorktown, Inc., and Western Refining Yorktown Holding Company as Seller and Plains Marketing, L.P., as Buyer (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, filed with the SEC on December 2, 2011).
10.11	Asset Purchase Agreement, dated November 30, 2011, by and among Western Refining Pipeline Company as Seller and Plains Pipeline, L.P., as Buyer (incorporated by reference to Exhibit 10.2 to the Company's Current Report on Form 8-K, filed with the SEC on December 2, 2011).

131

Number	Exhibit Title
10.12	Omnibus Agreement, dated October 16, 2013, by and among Western Refining Logistics, LP, Western Refining Logistics GP LLC, the Company, Western Refining Southwest, Inc., Western Refining Company, L.P. and Western Refining Wholesale, Inc. (incorporated by reference to Exhibit 10.3 to the Company's Current Report on Form 8-K, filed with the SEC on October 22, 2013).
10.13	Operational Services Agreement, dated October 16, 2013, by and among Western Refining Logistics, LP, Western Refining Company, L.P. and Western Refining Southwest, Inc. (incorporated by reference to Exhibit 10.4 to the Company's Current Report on Form 8-K, filed with the SEC on October 22, 2013).
10.14††	Pipeline and Gathering Services Agreement, dated October 16, 2013, by and among Western Refining Company, L.P., Western Refining Southwest, Inc. and Western Refining Pipeline, LLC (incorporated by reference to Exhibit 10.5 to the Company's Current Report on Form 8-K, filed with the SEC on October 22, 2013).
10.15††	Terminalling, Transportation and Storage Services Agreement, dated October 16, 2013, by and among Western Refining Company, L.P., Western Refining Southwest, Inc. and Western Refining Terminals, LLC (incorporated by reference to Exhibit 10.6 to the Company's Current Report on Form 8-K, filed with the SEC on October 22, 2013).
10.16††	Product Supply Agreement, dated October 15, 2014, by and among Western Refining Southwest, Inc., Western Refining Company, L.P. and Western Refining Wholesale, LLC (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, filed with the SEC on October 16, 2014).
10.17††	Fuel Distribution and Supply Agreement, dated October 15, 2014, by and between Western Refining Wholesale, LLC and Western Refining Southwest, Inc. (incorporated by reference to Exhibit 10.2 to the Company's Current Report on Form 8-K, filed with the SEC on October 16, 2014).
10.18††	Crude Oil Trucking Transportation Services Agreement, dated October 15, 2014, by and among Western Refining Wholesale, LLC, Western Refining Company, L.P. and Western Refining Southwest, Inc. (incorporated by reference to Exhibit 10.3 to the Company's Current Report on Form 8-K, filed with the SEC on October 16, 2014).
10.19†	Employment Agreement, dated January 24, 2006, by and between Western Refining GP, LLC and Paul L. Foster (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, filed with the SEC on January 25, 2006).
10.19.1†	First Amendment to the Employment Agreement referred to in Exhibit 10.19, dated December 28, 2006 (incorporated by reference to Exhibit 10.1.1 to the Company's Annual Report on Form 10-K, filed with the SEC on March 8, 2007).
10.19.2†	Second Amendment to the Employment Agreement referred to in Exhibit 10.19, dated December 31, 2008 (incorporated by reference to Exhibit 10.1.2 to the Company's Annual Report on Form 10-K, filed with the SEC on March 13, 2009).
10.19.3*†	Termination of Employment Agreement referred to in Exhibit 10.19, dated February 27, 2015, by and between Western Refining GP, LLC and Paul L. Foster.
10.20†	Employment Agreement, dated January 24, 2006, by and between Western Refining GP, LLC and Jeff A. Stevens (incorporated by reference to Exhibit 10.2 to the Company's Current Report on Form 8-K, filed with the SEC on January 25, 2006).
10.20.1†	First Amendment to the Employment Agreement referred to in Exhibit 10.20, dated December 28, 2006 (incorporated by reference to Exhibit 10.2.1 to the Company's Annual Report on Form 10-K, filed with the SEC on March 8, 2007).
10.20.2†	Second Amendment to the Employment Agreement referred to in Exhibit 10.20, dated December 31, 2008 (incorporated by reference to Exhibit 10.2.2 to the Company's Annual Report on Form 10-K, filed with the SEC on March 13, 2009).
10.21†	Employment Agreement, dated January 24, 2006, by and between Western Refining GP, LLC and Gary R. Dalke (incorporated by reference to Exhibit 10.5 to the Company's Current Report on Form 8-K, filed with the SEC on January 25, 2006).
10.21.1†	First Amendment to the Employment Agreement referred to in Exhibit 10.21, dated December 31, 2008 (incorporated by reference to Exhibit 10.4.1 to the Company's Annual Report on Form 10-K, filed with the SEC on March 13, 2009).
10.22†	Employment Agreement, dated January 24, 2006, by and between Western Refining GP, LLC and Lowry Barfield (incorporated by reference to Exhibit 10.6 to the Company's Current Report on Form 8-K, filed with the SEC on January 25, 2006).
10.22.1†	First Amendment to the Employment Agreement referred to in Exhibit 10.22, dated December 31, 2008 (incorporated by reference to Exhibit 10.5.1 to the Company's Annual Report on Form 10-K, filed with the SEC on March 13, 2009).
10.23†	Employment agreement, effective August 28, 2006, made by and between Western Refining GP, LLC and Mark J. Smith (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, filed with the SEC on August 16, 2006).

132

Number	Exhibit Title
10.23.1†	First Amendment to the Employment Agreement referred to in Exhibit 10.23, dated December 31, 2008 (incorporated by reference to Exhibit 10.27.1 to the Company's Annual Report on Form 10-K, filed with the SEC on March 13, 2009).
10.24†	Employment agreement, dated November 4, 2008, made by and between Western Refining GP, LLC and William R. Jewell (incorporated by reference to Exhibit 10.2 to the Company's Quarterly Report on Form 10-Q, filed with the SEC on November 7, 2008).
10.25†	Employment agreement, dated March 9, 2010, made by and between Western Refining GP, LLC and Jeffrey S. Beyersdorfer (incorporated by reference to Exhibit 10.31 to the Company's Annual Report on Form 10-K, filed with the SEC on March 12, 2010).
10.26†	Form of Indemnification Agreement, by and between the Company and each director and officer of the Company party thereto (incorporated by reference to Exhibit 10.7 to the Company's Current Report on Form 8-K, filed with the SEC on January 25, 2006).
10.27†	Western Refining Long-Term Incentive Plan (incorporated by reference to Exhibit 10.17 to the Company's Annual Report on Form 10-K, filed with the SEC on March 24, 2006).
10.27.1†	First Amendment to the Western Refining Long-Term Incentive Plan referred to in Exhibit 10.27, dated December 4, 2007 (incorporated by reference to Exhibit 10.19.1 to the Company's Annual Report on Form 10-K, filed with the SEC on March 13, 2009).
10.27.2†	Second Amendment to the Western Refining Long-Term Incentive Plan referred to in Exhibit 10.27, dated November 20, 2008 (incorporated by reference to Exhibit 10.19.2 to the Company's Annual Report on Form 10-K, filed with the SEC on March 13, 2009).
10.28†	Form of Restricted Stock Grant Agreement under the Western Refining Long-Term Incentive Plan (incorporated by reference to Exhibit 10.20 to the Company's Registration Statement on Form S-1/A (File No.333-128629), filed with the SEC on December 5, 2005).
10.29†	Form of Nonqualified Stock Option Agreement under the Western Refining Long-Term Incentive Plan (incorporated by reference to Exhibit 10.21 to the Company's Registration Statement on Form S-1/A (File No.333-128629), filed with the SEC on December 5, 2005).
10.30†	2010 Incentive Plan of Western Refining, Inc. (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, filed with the SEC on May 27, 2010).
10.31†	Form of Performance Unit Award Agreement between the Company and Participant under the 2010 Incentive Plan of Western Refining, Inc. (incorporated by reference to Exhibit 10.32 to the Company's Annual Report on Form 10-K, filed with the SEC on March 8, 2011).
10.32†	Form of Western Refining, Inc. Restricted Share Unit Award Agreement between the Company and Participant under the 2010 Incentive Plan of Western Refining, Inc. (incorporated by reference to Exhibit 10.33 to the Company's Annual Report on Form 10-K, filed with the SEC on March 8, 2011).
10.33†	Form of Western Refining, Inc. Restricted Share Unit Award Agreement between the Company and Non-Employee Director under the 2010 Incentive Plan of Western Refining, Inc. (incorporated by reference to Exhibit 10.3 to the Company's Quarterly Report on Form 10-Q, filed with the SEC on May 6, 2013).
10.34†	Form No. 2 of Western Refining, Inc. Restricted Share Unit Award Agreement between the Company and Participant under the 2010 Incentive Plan of Western Refining, Inc. (incorporated by reference to Exhibit 10.4 to the Company's Quarterly Report on Form 10-Q, filed with the SEC on May 6, 2013).
10.35†	Form of Western Refining, Inc. Restricted Share Unit Award Agreement (DE) between the Company and Non-Employee Director under the 2010 Incentive Plan of Western Refining, Inc. (incorporated by reference to Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q, filed with the SEC on November 4, 2013).
10.36†	Western Refining, Inc. Non-Employee Director Deferred Compensation Plan (incorporated by reference to Exhibit 10.25 to the Company's Annual Report on Form 10-K, filed with the SEC on March 1, 2013).
10.36.1†	Western Refining, Inc. Non-Employee Director Deferred Compensation Plan Adoption Agreement, dated as of January 1, 2009 (incorporated by reference to Exhibit 10.26 to the Company's Annual Report on Form 10-K, filed with the SEC on March 1, 2013).
10.37†	Northern Tier Energy LP 2012 Long Term Incentive Plan (incorporated by reference to Exhibit 10.2 to Northern Tier Energy LP’s Current Report on Form 8-K (File No. 001-35612), filed on July 30, 2012).
10.38†	Form of Northern Tier Energy LP 2012 Long Term Incentive Plan Restricted Unit Agreement (incorporated by reference to Exhibit 10.1 to Northern Tier Energy LP’s Current Report on Form 8-K (File No. 001-35612), filed on December 17, 2012).
10.39†	Form of Phantom Unit Award Agreement (time-based vesting) (incorporated by reference to Exhibit 10.1 to Northern Tier Energy LP’s Current Report on Form 8-K (File No. 001-35612), filed wih the SEC on May 2, 2014).

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Number	Exhibit Title
10.40†	Form of Phantom Unit Agreement (performance-based vesting) (incorporated by reference to Exhibit 10.2 to Northern Tier Energy LP’s Current Report on Form 8-K (File No. 001-35612), filed wih the SEC on December 8, 2014).
10.41†	Western Refining Logistics, LP 2013 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.7 to the Company's Current Report on Form 8-K (File No. 001-36114), filed with the SEC on October 22, 2013).
10.42†	Form of Phantom Unit Award Agreement (time-based vesting) (incorporated by reference to Exhibit 10.8 to Western Refining Logistics, LP’s Form S-1 Registration Statement (File No. 333-190135), filed with the SEC on September 27, 2013).
10.43†	Form of Phantom Unit Award Agreement (performance-based vesting) (incorporated by reference to Exhibit 10.9 to Western Refining Logistics, LP’s Form S-1 Registration Statement (File No. 333-190135), filed with the SEC on September 27, 2013).
10.44†	Form of Phantom Unit Award Agreement (time-based vesting) (incorporated by reference to Exhibit 10.1 to Western Refining Logistics, LP’s Quarterly Report on Form 10-Q (File No. 001-36114), filed with the SEC on May 12, 2014).
12.1*	Statements of Computation of Ratio of Earnings to Fixed Charges.
21.1*	List of Subsidiaries of the Company.
23.1*	Consent of Deloitte & Touche LLP, dated March 2, 2015.
31.1*	Certification Statement of Chief Executive Officer of the Company pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*	Certification Statement of Chief Financial Officer of the Company pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1**	Certification Statement of Chief Executive Officer of the Company pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2**	Certification Statement of Chief Financial Officer of the Company pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101*	Interactive Data Files.

_______________________________________

*	Filed herewith.
**	Furnished herewith.
***	Reports filed by the Company under the Securities Exchange Act of 1934, as amended (including Form 10-K, Form 10-Q and Form 8-K), are filed under File No. 001-32721.
†	Management contract or compensatory plan or arrangement.
††	The SEC has granted confidential treatment for certain portions of this Exhibit pursuant to a confidential treatment order. Such portions have been omitted and filed separately with the SEC.

(c) All financial statement schedules are omitted because the required information is not present or is not present in amounts sufficient to require submission of the schedule, or because the information required is included in the consolidated financial statements or notes thereto.

Our 2014 Annual Report is available upon request. Stockholders may obtain a copy of any exhibits to this Form 10-K at a charge of $0.10 per page. Requests should be made to: Investor Relations, Western Refining, Inc., 123 W. Mills Ave., Suite 200, El Paso, Texas 79901.

134

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

WESTERN REFINING, INC.

Signature	Title	Date
/s/ Jeff A. Stevens	Chief Executive Officer and	March 2, 2015
Jeff A. Stevens	President

________________________________________________________________________________________________________________________

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature	Title	Date
/s/ Jeff A. Stevens	Chief Executive Officer, President and Director	March 2, 2015
Jeff A. Stevens	(Principal Executive Officer)
/s/ Gary R. Dalke	Chief Financial Officer	March 2, 2015
Gary R. Dalke	(Principal Financial Officer)
/s/ Paul L. Foster	Executive Chairman and Director	March 2, 2015
Paul L. Foster
/s/ Scott D. Weaver	Vice President and Director	March 2, 2015
Scott D. Weaver
/s/ William R. Jewell	Chief Accounting Officer	March 2, 2015
William R. Jewell	(Principal Accounting Officer)
/s/ Carin M. Barth	Director	March 2, 2015
Carin M. Barth
/s/ Sigmund L. Cornelius	Director	March 2, 2015
Sigmund L. Cornelius
/s/ L. Frederick Francis	Director	March 2, 2015
L. Frederick Francis
/s/ Brian J. Hogan	Director	March 2, 2015
Brian J. Hogan
/s/ William D. Sanders	Director	March 2, 2015
William D. Sanders
/s/ Robert J. Hassler	Director	March 2, 2015
Robert J. Hassler

135