Document

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT

Pursuant to Section 13 or 15(d) of the

Securities Exchange Act of 1934

Date of Report (Date of earliest event reported): December 8, 2016

WESTERN REFINING, INC.

(Exact name of Registrant as specified in its charter)




Delaware	001-32721	20-3472415
(State or other jurisdiction of incorporation)	(Commission File Number)	(IRS Employer Identification Number)

123 West Mills Ave., Suite 200

El Paso, Texas 79901

(Address of principal executive offices)

(915) 534-1400

(Registrant’s telephone number, including area code)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:



þ	Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)



¨	Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)



¨	Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))



¨	Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Item 8.01. Other Events

As disclosed in our Quarterly Report on Form 10-Q for the period ended September 30, 2016, effective July 1, 2016, Western Refining, Inc. (“Western”, "we,", "us," "our" or the “Company”) changed our reportable segments due to changes in our organization. Prior to the acquisition of all of the outstanding common units not already held by us of Northern Tier Energy LP ("NTI") on June 23, 2016 ("the Merger"), we reported NTI as a separate reportable segment. Following the completion of the Merger, NTI became a wholly-owned subsidiary of Western and, as a result, we moved its assets and operations into our other reportable segments. Beginning on July 1, 2016, our management team began managing our businesses and allocating resources based on three reportable segments.

We have organized our operations into three segments: refining, WNRL and retail based on manufacturing and marketing processes, the nature of our products and services and each segment's respective customer base. The St. Paul Park refinery and related operations are included in the refining segment and the SuperAmerica retail and bakery assets and operations are included in the retail segment.

The following items of our Annual Report on Form 10-K for the three years ended December 31, 2015, have been recast for the segment changes described above, to the extent applicable, and are filed as exhibits to this Current Report on Form 8-K and incorporated herein by reference:


•	Exhibit 99.1


◦	Item 1. Business


◦	Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations


◦	Item 7A. Quantitative and Qualitative Disclosures About Market Risk


◦	Item 8. Financial Statements and Supplementary Data


•	Exhibit 101 - XBRL Interactive Data Files

The recast items of the Form 10-K described above have been updated for the aforementioned segment changes and have no effect on our previously reported consolidated results of operations, financial condition or cash flows. We have not otherwise updated our Form 10-K for activities or events occurring after the date these items were originally presented. This Current Report should be read in conjunction with our Quarterly Report on Form 10-Q for the period ended September 30, 2016.


Item 9.01	Financial Statements and Exhibits


(d)	Exhibits



Exhibit No.		Description
23.1		Consent of Deloitte & Touche LLP.
99.1		Business, Management’s Discussion and Analysis of Financial Condition and Results of Operations, Quantitative and Qualitative Disclosures About Market Risk and Financial Statements and Supplementary Data (Part I, Item 1, Part II, Items 7, 7A and 8 of our Annual Report on Form 10-K for the year ended December 31, 2015).
101		XBRL Interactive Data Files.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, the Registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.




WESTERN REFINING, INC.

By:	/s/ Karen B. Davis
Name:	Karen B. Davis
Title:	Executive Vice President and Chief Financial Officer

Dated: December 8, 2016

EXHIBIT INDEX



Exhibit No.		Description
23.1		Consent of Deloitte & Touche LLP.
99.1		Business, Management’s Discussion and Analysis of Financial Condition and Results of Operations, Quantitative and Qualitative Disclosures About Market Risk and Financial Statements and Supplementary Data (Part I, Item 1, Part II, Items 7, 7A and 8 of our Annual Report on Form 10-K for the year ended December 31, 2015).
101		XBRL Interactive Data Files.

Exhibit

Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in Registration Statement Nos. 333-168018 and 333-132854 on Form S-8 of our report dated February 26, 2016 (December 8, 2016 as to the effects of the changes in reportable segments described in Note 1 and subsequent events information described in Note 31), relating to the consolidated financial statements of Western Refining, Inc. and subsidiaries appearing in this Current Report on Form 8-K of Western Refining, Inc. filed on December 8, 2016.

/s/ DELOITTE AND TOUCHE LLP

Phoenix, Arizona

December 8, 2016

Exhibit

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Exhibit 99.1

Explanatory Note

Effective July 1, 2016, we changed our reportable segments due to changes in our organization. Prior to the acquisition of all the outstanding common units not already held by us of Northern Tier Energy LP ("NTI") on June 23, 2016 ("the Merger"), we reported NTI as a separate reportable segment. Following the completion of the Merger, NTI became a wholly-owned subsidiary of Western and, as a result, we moved its assets and operations into our other reportable segments. Beginning on July 1, 2016, our management team began managing our businesses and allocating resources based on three reportable segments.

The items herein included in the Annual Report on Form 10-K for the three years ended December 31, 2015, have been recast for the segment changes described above.

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 NTI and the controlling general partner interest, incentive distribution rights and a 66.4% 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 our refineries in El Paso, Texas (131,000 barrels per day, or bpd), near Gallup, New Mexico (25,000 bpd) and in St. Paul Park, Minnesota (98,000 bpd). We sell refined products primarily in Arizona, Colorado, Minnesota, New Mexico, Wisconsin, West Texas, the Mid-Atlantic region and Mexico through bulk distribution terminals and wholesale marketing networks. We also sell refined products through two retail networks with a total of 535 company-operated and franchised retail sites in the U.S.

We have included NTI and WNRL in our results of operations since the fourth quarter of 2013. We have 100% ownership of the general partners of both NTI and WNRL, giving us effective control of both entities. 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 wholesale petroleum products primarily in Arizona, California, Colorado, Nevada, New Mexico and Texas.

We entered into an Agreement and Plan of Merger dated as of December 21, 2015 (the “Merger Agreement”) with Western Acquisition Co, LLC, a wholly-owned subsidiary of Western (“MergerCo”), NTI and Northern Tier Energy GP LLC to acquire all of NTI’s outstanding common units not already held by us. Each of the outstanding NTI common units held by unitholders other than us (the “NTI Public Unitholders”) will be converted into the right to receive, subject to election by the NTI Public Unitholders and proration, (i) $15.00 in cash without interest and 0.2986 of a share of our common stock (ii) $26.06 in cash without interest or (iii) 0.7036 of a share of our common stock. Upon the terms and subject to the conditions set forth in the Merger Agreement, MergerCo will merge with and into NTI and the separate limited liability company existence of MergerCo will cease and NTI will continue to exist, as a limited partnership under Delaware law and as our indirect wholly-owned subsidiary, as the surviving entity in the merger (the “Merger”). The Merger is expected to close in the first half of 2016, pending the satisfaction of certain customary conditions and the approval of the Merger at a special meeting of NTI unitholders by the affirmative vote of holders of a majority of the outstanding NTI common units (including the NTI common units held by us). The transaction is expected to result in approximately 17.1 million additional shares of WNR common stock outstanding. Upon completion of the transaction, NTI will continue to exist as a limited partnership and will become a wholly-owned limited partnership subsidiary of WNR. See Note 30, NTI, in the Notes to Consolidated Financial Statements included in this annual report for additional information on this transaction.

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The following simplified diagram depicts the three publicly traded reporting entities in our organizational structure as of December 31, 2015:

Our operations are organized into three reportable segments based on manufacturing and marketing criteria and the nature of our products and services, our production processes and our types of customers. The three business segments are: refining, WNRL and retail.


•	Refining. Our refining segment owns and operates three refineries 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.


•	WNRL. WNRL owns and operates terminal, storage, transportation and wholesale assets consisting of a fleet of crude oil and refined product truck transports and wholesale petroleum product operations in the Southwest region. WNRL's primary customer are our refineries in the Southwest. WNRL purchases its wholesale 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 and Upper Great Plains region. 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 reportable segments, consolidated net sales to Kroger Company accounted for 11.4% 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, 2015 and 2014.

Refining Segment

Our refining group operates a refinery in El Paso, Texas (the "El Paso refinery"), a refinery near Gallup, New Mexico (the "Gallup refinery") and a refinery in St. Paul Park, Minnesota (the "St. Paul Park 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. We supply refined products to the St. Paul Park area through a pipeline and terminal system owned by Magellan Midstream Partners, LP ("Magellan") that has facilities throughout the Upper Great Plains region.

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Our refining group also includes our refined products marketing and distribution operations in the Mid-Atlantic region. Prior to our sale of the TexNew Mex Pipeline System (the "TexNew Mex Pipeline Transaction"), our refining segment included the operations of the TexNew Mex Pipeline System, and we have recast historical financial and operational data of the refining segment, for all periods presented, to reflect the sale of the TexNew Mex Pipeline System to WNRL.

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 may acquire refined products through exchange agreements and from various third-party suppliers. We sell these products to WNRL, to our retail segment, to other independent wholesalers and retailers, commercial accounts and sales and exchanges with major oil companies. We also sell crude oil directly or through 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 and crude oil for the years indicated:



	Year Ended December 31,
	2015		2014		2013
Gasoline	45.4	%	41.6	%	42.3	%
Diesel fuel	25.7		29.9		35.0
Jet fuel	5.4		5.4		13.7
Asphalt	5.2		3.6		3.2
Crude oil and other (1)	18.3		19.5		5.8
Total sales percentage by type	100.0	%	100.0	%	100.0	%


(1)	Crude oil sales for the years ended December 31, 2015, 2014 and 2013 were $1,078.2 million, $2,684.3 million and $118.5 million, respectively.

Customers. We sell a variety of refined products to our diverse customer base and through WNRL's 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, 2015, 2014 and 2013.

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 6.3%, 5.5% and 8.5% of our consolidated net sales during the years ended December 31, 2015, 2014 and 2013, 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 6.5%, 7.3% and 12.0% of our total sales volumes during the years ended December 31, 2015, 2014 and 2013, respectively. The decrease when comparing 2015 purchases to 2014 and 2013 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 in the U.S. Southwest region including Arizona, Colorado, New Mexico, Utah and West Texas and the Upper Great Plains region including Minnesota and Wisconsin. These regions are 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. Our 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, that access the region by pipeline, and, to a lesser extent, other U.S. and foreign refiners. 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.

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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.

El Paso Refinery

Our El Paso refinery has a crude oil throughput capacity of 131,000 bpd with access to WNRL logistics assets including approximately 5.1 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 The Chemours Company FC, LLC ("Chemours"), Chemours constructed and operates two sulfuric acid regeneration units on property we lease to Chemours 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. WNRL's crude oil pipeline system also includes the TexNew Mex Pipeline System that facilitates delivery of crude oil to El Paso.

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)	2015	2014	2013	2015
Crude Oil:
Sweet crude oil	105,064	96,384	93,654	77.8	%
Sour crude oil	22,949	25,113	25,195	17.0	%
Total Crude Oil	128,013	121,497	118,849	94.8	%
Other Feedstocks and Blendstocks:
Intermediates and other	4,534	3,735	4,130	3.3	%
Blendstocks	2,530	2,004	2,358	1.9	%
Total Other Feedstocks and Blendstocks	7,064	5,739	6,488	5.2	%
Total Crude Oil and Other Feedstocks and Blendstocks	135,077	127,236	125,337	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.

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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.

Gallup Refinery

Our Gallup refinery, located near Gallup, New Mexico, has a crude oil throughput capacity of 25,000 bpd and access to WNRL logistics assets including approximately 910,500 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, 2015.

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 WNRL's system.

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)	2015	2014	2013	2015
Crude Oil:
Sweet crude oil	24,071	25,130	23,635	90.1	%
Total Crude Oil	24,071	25,130	23,635	90.1	%
Other Feedstocks and Blendstocks:
Intermediates and other	934	867	—	3.4	%
Blendstocks	1,725	1,786	1,457	6.5	%
Total Other Feedstocks and Blendstocks	2,659	2,653	1,457	9.9	%
Total Crude Oil and Other Feedstocks and Blendstocks	26,730	27,783	25,092	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.

St. Paul Park Refinery

Our St. Paul Park refinery located in Southeast St. Paul Park, Minnesota, has a crude oil throughput capacity of 98,000 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.

The St. Paul Park refinery is an integrated refining operation that includes storage and transportation assets. Our transportation assets include a 17% interest in the Minnesota Pipe Line Company, LLC ("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

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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, 2015, our storage assets had an operating capacity of approximately 3.7 million barrels; comprised of 0.8 million barrels of crude oil storage and 2.9 million barrels of feedstock and product storage.

Process Summary. The St. Paul Park refinery is a cracking facility that 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. We purchase 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)	2015	2014	2013	2015
Crude Oil Feedstocks:
Canadian	38,417	34,184	37,045	41.0	%
Domestic	55,284	57,656	37,192	59.0	%
Total Crude Oil	93,701	91,840	74,237	100.00	%
Crude Oil Feedstocks by Type:
Light and intermediate	68,739	73,999	56,310	73.4	%
Heavy	24,962	17,841	17,927	26.6	%
Total Crude Oil	93,701	91,840	74,237	100.0	%
Other Feedstocks and Blendstocks (1):
Natural gasoline	—	38	—	—	%
Butanes	2,152	798	597	76.5	%
Gasoil	—	351	114	—	%
Other	662	498	516	23.5	%
Total Other Feedstocks and Blendstocks	2,814	1,685	1,227	100.0	%
Total Crude Oil and Other Feedstocks and Blendstocks	96,515	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 we purchase 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, 2015, approximately 41% 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. 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 465,000 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. We also

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purchase 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. We own 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 is through our light products terminal. Approximately 64% of the gasoline and diesel volumes for the year ended December 31, 2015, were sold via our light products terminal to company-operated and franchised SuperAmerica branded convenience stores, Marathon Petroleum Company LP ("Marathon") branded convenience stores and other resellers. We have 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 we supply. We also have 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 our seven-bay heavy products terminal and via rail and barge through our rail facilities and Mississippi River barge dock and are sold to a broad customer base.

The location of the St. Paul Park refinery allows us 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 II region. We sold the majority of the St. Paul Park refinery's 2015 gasoline and diesel sales volumes in Minnesota and Wisconsin with the remainder sold primarily in Iowa, Nebraska, Oklahoma and South and North Dakota. The St. Paul Park refinery supplied a majority of the gasoline and diesel sold in the company-operated or franchised convenience stores for the year ended December 31, 2015, as well as supplied the independently owned and operated Marathon branded stores in its marketing area.

We own 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 our crude oil input.

WNRL

WNRL owns and operates terminal, storage, transportation and wholesale assets. WNRL's primary customers are our refineries in the Southwest. WNRL is a primarily 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, 2015, Western's ownership of WNRL consisted of a 100% interest in WNRL's general partner and a 66.4% interest in a limited partnership that Western controls through the general partner.

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 Western Refining Wholesale, LLC ("WRW") to WNRL, in exchange for $320 million and 1,160,092 WNRL common partnership units. WNRL entered into commercial and service agreements with Western under which it operates the WRW assets acquired for the purpose of transporting and reselling refined products purchased from Western and transporting crude oil for Western.

On October 30, 2015, Western sold the TexNew Mex Pipeline System to WNRL. In connection with the closing, Western also entered into an amendment to our Pipeline and Gathering Services Agreement with WNRL (the "Amendment to the Pipeline Agreement"). The Amendment to the Pipeline Agreement amends the scope of the existing agreement to include the provision of storage services and a minimum volume commitment of 80,000 barrels of storage at the Star Lake storage tank. In this Amendment to the Pipeline Agreement, we have agreed to provide a minimum volume commitment of 13,000 bpd of crude oil for shipment on the TexNew Mex Pipeline System for 10 years from the date of the Amendment to the Pipeline Agreement. We are entitled to 80% of the distributable cash flows, as defined, resulting from crude oil throughput on the TexNew Mex Pipeline System above our 13,000 bpd minimum volume commitment.

Pipeline and Gathering Assets. WNRL's pipeline and gathering assets consist of approximately 685 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 828,000 barrels of active crude oil storage located primarily in the Delaware Basin and in the Four Corners area.

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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 675,900 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 185,700 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 where, between both locations, our combined active shell storage capacity is approximately 6.1 million barrels. 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 approximately 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, 25.7% and 25.1%, were to our retail segment and to Kroger Company, respectively, for the year ended December 31, 2015. 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

Southwest Retail

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 December 31, 2015, our retail group operated 258 retail stores located in Arizona, Colorado, New Mexico and Texas and 52 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 third-party 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 that are potentially better able to withstand volatile conditions in the fuel market and lower profitability in merchandise sales due to their size.

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 December 31, 2015:



Retail Store locations	Owned	Leased	Total
Arizona	26	75	101
Colorado	10	2	12
New Mexico	74	43	117
Texas	—	28	28
	110	148	258

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The following table summarizes the ownership and location of Western's cardlocks as of December 31, 2015:



Cardlock locations	Owned	Leased	Private Sites (1)	Total
Arizona	14	7	13	34
California	1	—	—	1
Colorado	2	—	—	2
New Mexico	3	1	1	5
Texas	—	10	—	10
	20	18	14	52


(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.

SuperAmerica Retail

We have a retail-marketing network of 277 convenience stores, as of December 31, 2015, located throughout Minnesota, Wisconsin and South Dakota. We operate 168 stores and support 109 franchised stores. We brand all of our company-operated and franchised convenience stores as SuperAmerica. We also own and operate SuperMom’s Bakery that prepares and distributes baked goods and other prepared items for sale in our retail outlets and for other third parties. Substantially all of the fuel gallons sold at our company-operated convenience stores for the period ended December 31, 2015, was supplied by our St. Paul Park refinery.

The main competitive factors affecting our SuperAmerica retail operations are the location of the stores, brand identification and product price and quality. Our SuperAmerica retail stores compete with Holiday, Kwik Trip, Marathon and Freedom Valu Centers. Large chains of retailers like BP, Costco Wholesale Corp., Wal-Mart Stores, Inc., Kroger Company and other large grocery retailers compete in the motor fuel retail business. Our SuperAmerica retail operations are substantially smaller than many of these competitors that are potentially better able to withstand volatile conditions in the fuel market and lower profitability in merchandise sales due to their size.

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, 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 with an effective date of 2017 for our El Paso and St. Paul Park refineries 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. The EPA established its final 2014 and 2015 blending volume requirements in November 2015, after the statutory deadlines. The EPA is required to establish the volume of renewable fuels that refineries must blend into their refined petroleum

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fuels annually. Obligated refineries, including each of our three refineries, demonstrate compliance with the RFS through the accumulation of RINs, which are unique serial numbers acquired through blending renewable fuels or 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. Blending renewable fuels into the finished petroleum fuels to comply with federal and state requirements could displace an increasing volume of a refinery’s product pool.

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. Industry organizations representing Minnesota truckers and auto dealers, U.S. auto manufacturers and U.S. fuels manufacturers have filed suit to challenge Minnesota's biodiesel mandate claiming it is in conflict with the RFS standards and the final outcome is yet to be determined.

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, 2015, our companies employed 7,347 people including 2,961 NTI employees and 562 WNRL employees in its wholesale segment. The collective bargaining agreements covering the El Paso and Gallup refinery employees expire in April 2021 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 218 full-time 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.

On July 2, 2015, 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.

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PART II


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.

Explanatory Note

The items herein included in the Annual Report on Form 10-K for the three years ended December 31, 2015, have been recast for the segment changes described above.

Company Overview

Through various transactions from 2013 through 2015, WNRL has purchased certain operating assets and businesses from Western. In consideration for these assets and businesses, WNRL paid a combination of WNRL partnership units and cash. These purchases began in October 2013 with the sale of pipeline and gathering assets and terminalling, transportation and storage assets. In October 2014, WNRL purchased substantially all of Western's Southwest-based wholesale and crude gathering business. In October 2015, WNRL purchased a 375-mile segment of the TexNew Mex Pipeline that extends from the crude oil station in Star Lake, New Mexico, in the Four Corners region to the T station in Eddy County, New Mexico (the "TexNew Mex Pipeline System") and other related assets. We transferred the businesses and all related net assets to WNRL at Western’s historical cost as these transactions were between entities under common control.

The financial position, results of operations and operating statistics of WNRL’s accounting predecessor for the contributed logistics assets prior to October 16, 2013 are contained herein as part of our historical information. In addition to the logistics assets contributed in conjunction with WNRL’s initial public offering in 2013 (the “Offering”), its accounting predecessor prior to the Offering contains the financial position and results of operations of other logistics assets that were contributed subsequent to the Offering. These assets relate to the historical financial results of the TexNew Mex Pipeline System. We refer to the financial position, results of operations and operating statistics of contributed and non-contributed assets, prior to October 16, 2013 as the WNRL Predecessor.

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 2015 Developments


•	We averaged total throughput of 135,077 bpd at the El Paso refinery for the year ended December 31, 2015, a 6.2% increase from 2014.


•	We averaged total throughput of 26,730 bpd at the Gallup refinery for the year ended December 31, 2015, a 3.8% decrease from 2014.


•	We averaged total throughput of 96,515 bpd at the St. Paul Park refinery for the year ended December 31, 2015, a 3.2% increase from 2014.

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•

We sold the TexNew Mex Pipeline System and other related assets to WNRL on October 30, 2015, in exchange for consideration of $170 million in cash, the issuance of approximately 0.4 million WNRL common units and 80,000 TexNew Mex Units. WNRL partially funded the purchase of the TexNew Mex Pipeline System and other related assets using $145.0 million borrowed under the WNRL Revolving Credit Facility.


•	We purchased 2,647,740 shares under our share repurchase programs at an average price of $39.64 per share.


•	We added 31 company-operated retail locations in southern Arizona and 3 company-operated retail locations and 20 franchise locations in the Midwest.


•	WNRL issued $300.0 million in aggregate principal amount of 7.5% Senior Notes due 2023.


•	Dividends and distributions declared and paid:


◦	$1.36 per Western common share;


◦	$1.4275 per WNRL common unit; and


◦	$3.80 per NTI common unit.

2015 Operating and Financial Highlights

Net income attributable to Western was $406.8 million, or $4.28 per diluted share for the year ended December 31, 2015, compared to $559.9 million, or $5.61 per diluted share for the year ended December 31, 2014. Our operating income decreased $166.4 million from December 31, 2014, to December 31, 2015, as shown by segment in the following table:



	Year Ended December 31,
	2015			2014			Change
	(In thousands)
Refining	$	900,513		$	1,107,103		$	(206,590	)
WNRL	86,713			70,295			16,418
Retail	41,279			42,087			(808		)
Other	(98,380		)	(122,972		)	24,592
Total operating income	$	930,125		$	1,096,513		$	(166,388	)

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;


•	product yield volumes that 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;


•	the impact of our economic hedging activity;


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

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. We record the results of our hedging activity within cost of products sold which directly impacts our results of operations.

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Excise and other taxes collected from customers and remitted to governmental authorities are not included in revenues or cost of products sold. 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 the related costs within cost of products sold. Cost of products sold for the year ended December 31, 2015 includes $43.5 million of realized and unrealized net gains from our economic hedging activities. The non-cash unrealized net losses were $50.2 million for the year ended December 31, 2015.

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 and 2015, the volatility in crude oil prices and refining margins contributed to the variability of our results of operations.

Safety, reliability and the environmental performance of our refineries’ operations are critical components of our financial performance. Unplanned downtime of our refineries generally results in lost refinery gross margin, increased maintenance costs and a temporary increase in our working capital investment. We attempt to mitigate the financial impact of planned downtime, such as a turnaround or a major maintenance project, through our 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 may lead to losses that qualify for reimbursement under our business interruption insurance and we record such reimbursements as revenues when received. 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.

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.

WNRL. WNRL's terminal throughput volumes depend upon 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 and 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 primarily driven by lower volumes of fuel being sold. 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 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

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TexNew Mex Pipeline System 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.

On October 30, 2015, we sold the TexNew Mex Pipeline System and other related assets to WNRL. WNRL acquired these assets from us in exchange for $170 million in cash, issuance of 421,031 common units that increased our limited partner interests in WNRL and 80,000 TexNew Mex Units.

WNRL provides a portion of our terminalling and storage services 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.

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

2013 NTI Acquisition

On November 12, 2013 Western purchased all of the 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, NTI, 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, 2015, 2014 and 2013:

2015


•	On February 11, 2015, WNRL entered into an indenture for the issuance of $300.0 million in aggregate principal amount of 7.5% Senior Notes due 2023 and used a portion of the proceeds from issuance of these notes to repay its outstanding direct borrowings under the WNRL 2018 Revolving Credit Facility.


•	WNRL borrowed $145.0 million under the WNRL 2018 Revolving Credit Facility on October 30, 2015, to partially fund the purchase of Western's TexNew Mex Pipeline System.

2014


•	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 increased the principal amount of the 2020 Secured Notes in September 2014 through issuance of an additional $75.0 million in principal amount.


•	WNRL borrowed $269.0 million under the WNRL 2018 Revolving Credit Facility on October 15, 2014, to partially fund the purchase of substantially all of Western's wholesale business.

2013


•	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.


•	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 $550.0 million term loan credit agreement on November 12, 2013, that matures on November 12, 2020.

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 for the year ended December 31, 2013. These losses are included in Loss on extinguishment of debt in the Consolidated Statements of Operations.

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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, 2015 included realized and unrealized net gains from our commodity hedging activities of $43.5 million, realized and unrealized net gains of $289.8 million for the year ended December 31, 2014 and realized and unrealized net losses of $1.0 million for the year ended December 31, 2013. 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.

We reduced the carrying value of our inventory by $175.1 million and $78.6 million in order to state the value at market prices which were lower than our cost at December 31, 2015 and 2014, respectively. Refined products inventory includes a lower of cost or market non-cash adjustment of $72.3 million and $41.7 million and crude oil and other raw materials inventory includes a lower of cost or market non-cash adjustment of $102.8 million and $36.9 million at December 31, 2015 and 2014, respectively. Global and domestic crude oil prices are expected to remain volatile during 2016, and we cannot estimate any future adjustments to our inventory carrying values.

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, 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. There was no change to our valuation allowance during the year ended December 31, 2015.

Planned Maintenance Turnaround

During the years ended December 31, 2015, 2014 and 2013, we incurred costs of $2.0 million, $48.5 million and $50.2 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. We currently plan for a major maintenance turnaround on several units of the St. Paul Park refinery in the fall of 2016 at an aggregate budgeted expense of approximately $40.0 million to $45.0 million.

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.

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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 both December 31, 2015 and 2014, we had goodwill of $1,289.4 million relating to the 2013 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.

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, 2015, 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

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of some of these costs from other parties are not recognized in the financial statements until they become probable. Legal costs associated with environmental remediation are included as part of the estimated liability.

Financial Instruments and Fair Value. We are exposed to various market risks, including changes in commodity prices. We use commodity future contracts, price swaps and options to reduce price volatility, to fix margins for refined products and to protect against price declines associated with our crude oil and blendstock inventories. We recognize all commodity hedge transactions that we enter as either assets or liabilities in the Consolidated Balance Sheets and those instruments are measured at fair value. For instruments used to mitigate the change in value of volumes subject to market prices, we elected not to pursue hedge accounting treatment for financial accounting purposes, generally because of the difficulty of establishing and maintaining the required documentation that would allow for hedge accounting. 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 reportable segment financial data and key operating statistics for the three years ended December 31, 2015, is presented below:

Consolidated



	Year Ended December 31,
	2015			2014			2013 (2)
	(In thousands, except per share data)
Statement of Operations Data:
Net sales (1)	$	9,787,036		$	15,153,573		$	10,086,070
Operating costs and expenses:
Cost of products sold (exclusive of depreciation and amortization) (1)	7,521,375			12,719,963			8,690,222
Direct operating expenses (exclusive of depreciation and amortization) (1)	902,925			850,634			523,836
Selling, general and administrative expenses	225,245			226,020			137,031
Affiliate severance costs	—			12,878			—
Loss (gain) and impairments on disposal of assets, net	51			8,530			(4,989		)
Maintenance turnaround expense	2,024			48,469			50,249
Depreciation and amortization	205,291			190,566			117,848
Total operating costs and expenses	8,856,911			14,057,060			9,514,197
Operating income	930,125			1,096,513			571,873
Other income (expense):
Interest income	703			1,188			746
Interest expense and other financing costs	(105,603		)	(97,062		)	(74,581		)
Loss on extinguishment of debt	—			(9		)	(46,773		)
Other, net	13,161			2,046			2,214
Income before income taxes	838,386			1,002,676			453,479
Provision for income taxes	(223,955		)	(292,604		)	(153,925		)
Net income	614,431			710,072			299,554
Less net income attributed to non-controlling interests (3)	207,675			150,146			23,560
Net income attributable to Western Refining, Inc.	$	406,756		$	559,926		$	275,994

Basic earnings per share	$	4.28		$	6.17		$	3.35
Diluted earnings per share	4.28			5.61			2.79
Dividends declared per common share	$	1.36		$	3.08		$	0.64
Weighted average basic shares outstanding	94,899			90,708			82,248
Weighted average dilutive shares outstanding	94,999			101,190			104,904

(1)

The information presented excludes $3,869.8 million, $5,322.8 million and $4,409.9 million of intercompany sales and $3,869.8 million, $5,306.2 million and $4,397.1 million of intercompany cost of products sold for the years ended December 31, 2015, 2014 and 2013, respectively, and $16.6 million and $12.8 million of intercompany direct operating expenses for the years ended December 31, 2014 and 2013, respectively, with no comparable activity for the year ended December 31, 2015.


(2)	The information presented includes the results of operations of NTI beginning November 12, 2013, the consummation date of the purchase transaction.


(3)	Net income attributable to non-controlling interests for the years ended December 31, 2015, 2014 and 2013, consisted of net income from NTI of $186.5 million, $131.9 million and $20.6 million, respectively, and net income from WNRL of $21.2 million, $18.2 million and $3.0 million, respectively.

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Gross Margin

Gross margin is a function of net sales less cost of products sold (exclusive of depreciation and amortization). Our consolidated margins decreased from 2014 through 2015 by 6.9%. This decrease was primarily due to refining margins and economic hedging activities. We discuss refining margins and economic hedging activities under our refining segment.

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 and the acquisition of NTI and regional margin environments in the locale of our non-refining operations.

Direct Operating Expenses

The increase in direct operating expenses was primarily due to increases of $28.5 million, $14.8 million and $10.6 million in our retail, refining and WNRL segments, respectively.

The increase from 2013 to 2014 in direct operating expenses was primarily due to increases of $206.8 million, $111.1 million and $8.0 million in our refining, retail and WNRL segments, respectively.

Selling, General and Administrative Expenses

The decrease in selling, general and administrative expenses from 2014 to 2015 resulted from a decrease of $11.0 million in our other category, partially offset by an increase of $5.5 million, $3.3 million and $1.5 million in our refining, retail and WNRL segments, respectively. The decrease in the other category was due to lower insurance and legal costs, partially offset by higher employee expenses based primarily on higher incentive compensation expenses in the current period.

The increase from 2013 to 2014 in selling, general and administrative expenses was primarily due to increases of $32.0 million, $26.4 million, $25.6 million and $5.0 million in our refining segment, retail segment, other category and WNRL segment, respectively. The increase in the other category was primarily due to corporate expenses associated with the NTI assets acquired during November 2013.

Affiliate Severance Costs

The severance costs incurred during the year ended December 31, 2014 reflect severance payments related to Western's acquisition of NTI's general partner.

Maintenance Turnaround Expenses

We reported minimal turnaround expenses during the year ended December 31, 2015. 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.

Depreciation and Amortization

The increase in depreciation and amortization from 2014 to 2015 resulted from an increase of $6.7 million, $4.1 million and $3.3 million in our WNRL, refining and retail segments, respectively.

The increase in depreciation and amortization from 2013 to 2014 resulted from an increase of $62.3 million, $6.6 million and $3.7 million in our refining, retail and WNRL segments, respectively.

Other Income (Expense)

The increase in interest expense from prior periods was attributable to interest incurred through WNRL's issuance of $300.0 million in aggregate principal amount of the WNRL 2023 Senior Notes and borrowings under WNRL's revolving credit facility of $145.0 million. This increase was partially offset during the current year by the retirement of our 5.75% Convertible Senior Unsecured Notes during the second quarter of 2014.

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.

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Segment Results

The following tables set forth our consolidating historical financial data for the periods presented below. Our operations are organized into three reportable 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, WNRL and retail. See Note 3, Segment Information, in the Notes to Consolidated Financial Statements included in this annual report for more detailed information.



	Year Ended December 31,
	2015			2014		2013
	(In thousands)
Consolidated Gross Margin by Segment
Refining	$	1,600,490		$	1,836,778	$	1,098,161
WNRL	291,730			256,969		127,411
Retail	373,689			339,440		169,729
Other	(248		)	423		547
Consolidated gross margin	$	2,265,661		$	2,433,610	$	1,395,848
Consolidated Direct Operating Expenses by Segment
Refining	$	481,496		$	466,656	$	259,822
WNRL	154,267			143,702		135,684
Retail	267,079			238,595		127,520
Other	83			1,681		810
Consolidated direct operating expenses	$	902,925		$	850,634	$	523,836
Consolidated Depreciation and Amortization by Segment
Refining	$	150,580		$	146,462	$	84,131
WNRL	26,912			20,187		16,515
Retail	23,197			19,869		13,245
Other	4,602			4,048		3,957
Consolidated depreciation and amortization	$	205,291		$	190,566	$	117,848

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

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Refining Segment

The selected historical financial data for the 2013 period presented below includes the financial results of the St. Paul Park refinery from the period beginning November 12, 2013, through the period ended December 31, 2013.



	Year Ended
	December 31,
	2015		2014		2013
	(In thousands, except per barrel data)
Statement of Operations Data:
Net sales (including intersegment sales) (1)	$	8,777,196	$	14,196,564	$	9,499,363
Operating costs and expenses:
Cost of products sold (exclusive of depreciation and amortization) (2)	7,176,706		12,343,186		8,388,391
Direct operating expenses (exclusive of depreciation and amortization)	481,496		483,256		272,633
Selling, general and administrative expenses	65,468		59,999		27,982
Loss (gain) and impairments on disposal of assets, net	409		8,089		(4,992		)
Maintenance turnaround expense	2,024		48,469		50,249
Depreciation and amortization	150,580		146,462		84,131
Total operating costs and expenses	7,876,683		13,089,461		8,818,394
Operating income	$	900,513	$	1,107,103	$	680,969
Key Operating Statistics:
Total sales volume (bpd) (1) (3)	338,403		315,656		260,681
Total refinery production (bpd)	256,197		246,780		230,551
Total refinery throughput (bpd) (4)	258,322		248,544		232,690
Per barrel of throughput:
Refinery gross margin (2) (5) (6)	$	16.93	$	20.40	$	18.72
Direct operating expenses (7)	5.10		5.33		4.61
Mid-Atlantic sales volume (bbls)	8,356		8,588		9,734
Mid-Atlantic margin per barrel	$	0.46	$	0.32	$	0.47

El Paso Refinery



	Year Ended
	December 31,
	2015		2014		2013
Key Operating Statistics
Refinery product yields (bpd):
Gasoline	70,200		62,252		61,893
Diesel and jet fuel	54,082		54,501		52,600
Residuum	4,174		5,121		5,445
Other	4,872		3,740		3,442
Total refinery production (bpd)	133,328		125,614		123,380
Refinery throughput (bpd):
Sweet crude oil	105,064		96,384		93,654
Sour crude oil	22,949		25,113		25,195
Other feedstocks and blendstocks	7,064		5,739		6,488
Total refinery throughput (bpd) (4)	135,077		127,236		125,337
Total sales volume (bpd) (3)	148,897		139,216		141,894
Per barrel of throughput:
Refinery gross margin (2) (5)	$	16.48	$	18.34	$	18.74
Direct operating expenses (7)	4.02		4.37		4.30

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Gallup Refinery



	Year Ended
	December 31,
	2015		2014		2013
Key Operating Statistics
Refinery product yields (bpd):
Gasoline	17,066		17,027		16,675
Diesel and jet fuel	7,994		8,858		6,980
Other	1,303		1,443		758
Total refinery production (bpd)	26,363		27,328		24,413
Refinery throughput (bpd):
Sweet crude oil	24,071		25,130		23,635
Other feedstocks and blendstocks	2,659		2,653		1,457
Total refinery throughput (bpd) (4)	26,730		27,783		25,092
Total sales volume (bpd) (3)	33,005		34,300		34,759
Per barrel of throughput:
Refinery gross margin (2) (5)	$	18.34	$	16.55	$	18.94
Direct operating expenses (7)	8.38		8.40		10.13

St. Paul Park Refinery



	Year Ended
	December 31,
	2015		2014		2013
Key Operating Statistics
Refinery product yields (bpd):
Gasoline	46,453		45,674		37,364
Diesel and jet fuel	33,356		33,910		28,444
Residuum	10,933		7,567		9,018
Other	5,764		6,687		7,932
Total refinery production (bpd)	96,506		93,838		82,758
Refinery throughput (bpd):
Light crude oil	55,612		59,386		42,163
Synthetic crude oil	13,127		14,613		18,956
Heavy crude oil	24,962		17,841		20,695
Other feedstocks and blendstocks	2,814		1,685		447
Total refinery throughput (bpd) (4)	96,515		93,525		82,261
Total sales volume (bpd) (3)	101,349		98,016		84,028
Per barrel of throughput:
Refinery gross margin (2) (5)	$	18.88	$	17.74	$	17.96
Direct operating expenses (7)	4.94		5.21		4.51

(1)

Refining net sales for the years ended December 31, 2015 and 2014, include $1,078.2 million, $2,684.3 million and $118.5 million representing a period average of 61,516 bpd, 72,402 bpd and 32,425 bpd in crude oil sales to third parties, respectively. 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, Gallup and St. Paul Park 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,
	2015			2014		2013
	(In thousands)
Realized hedging gain, net	$	93,699		$	95,331	$	15,868
Unrealized hedging gain (loss), net	(50,233		)	194,423		(16,898		)
Total hedging gain (loss), net	$	43,466		$	289,754	$	(1,030	)

(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 6.5%, 7.3% and 12.0% of our total consolidated sales volumes for the years ended December 31, 2015, 2014 and 2013, 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.

Our calculation of refinery gross margin excludes the sales and costs related to our Mid-Atlantic business that we report within the refining segment. The following table reconciles the sales and cost of sales used to calculate refinery gross margin with the total sales and cost of sales reported in the refining statement of operations data above:



	Year Ended
	December 31,
	2015		2014		2013
	(In thousands)
Refinery net sales (including intersegment sales)	$	8,177,250	$	13,207,406	$	8,322,841
Mid-Atlantic sales	599,946		989,158		1,176,522
Net sales (including intersegment sales)	$	8,777,196	$	14,196,564	$	9,499,363

Refinery cost of products sold (exclusive of depreciation and amortization)	$	6,580,591	$	11,356,782	$	7,216,474
Mid-Atlantic cost of products sold	596,115		986,404		1,171,917
Cost of products sold (exclusive of depreciation and amortization)	$	7,176,706	$	12,343,186	$	8,388,391

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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,
	2015		2014		2013
	(in thousands, except per barrel data)
Net sales (including intersegment sales)	$	8,177,250	$	13,207,406	$	8,322,841
Cost of products sold (exclusive of depreciation and amortization)	6,580,591		11,356,782		7,216,474
Depreciation and amortization	150,580		146,462		84,131
Gross profit	1,446,079		1,704,162		1,022,236
Plus depreciation and amortization	150,580		146,462		84,131
Refinery gross margin	$	1,596,659	$	1,850,624	$	1,106,367
Refinery gross margin per refinery throughput barrel	$	16.93	$	20.40	$	18.72
Gross profit per refinery throughput barrel	$	15.34	$	18.79	$	17.30

(6)

Cost of products sold for the combined refining segment includes changes in the lower of cost or market inventory reserve shown in the table below. The reserve changes are also included in the combined refinery gross margin but are not included in those measures for the individual refineries. The following table calculates the refinery gross margin per refinery throughput barrel excluding changes in the lower of cost or market inventory reserve:



	Year Ended
	December 31,
	2015		2014		2013
	(in thousands, except per barrel data)
Refinery gross margin	$	1,596,659	$	1,850,624	$	1,106,367
Net change in lower of cost or market inventory reserve	95,835		77,118		—
Refinery gross margin, excluding LCM adjustment	$	1,692,494	$	1,927,742	$	1,106,367
Refinery gross margin, excluding LCM adjustment, per refinery throughput barrel	$	17.95	$	21.25	$	18.72


(7)	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 decreased from 2014 to 2015 due primarily to a lower net gain on hedging activities, discussed in detail below. Excluding the impact of our hedging activities, refining margin per throughput barrel declined slightly from 2014 to 2015, reflective of the negative margin impact from our non-cash lower of cost or market inventory adjustment of $95.8 million, or $1.02 per throughput barrel, in 2015 compared to $77.1 million, or $0.85 per throughput barrel, in 2014. Refining cost of products sold also includes the net effect of inventory reductions that resulted in the liquidation of LIFO inventory levels. These LIFO liquidations resulted in a negative impact to refining gross margin of $16.1 million in 2015 compared to a positive impact of $1.1 million in 2014. These negative impacts to our refining margins were somewhat offset by higher benchmark refining margins. The decrease in sales and cost of sales was primarily due to lower selling prices of refined products and lower crude costs, respectively, in the year ended December 31, 2015.

The Gulf Coast benchmark 3:2:1 crack spread increased from $15.81 in 2014 to $18.24 in 2015. While lower crude oil costs throughout the industry produced a widening effect on the Gulf Coast crack spread, there was also a negative offset produced by the lower year over year discount of WTI crude oil to Brent crude oil, which declined from $5.66 per barrel in 2014 to $3.68 in 2015, reflective of the decline in global and domestic crude oil prices. The Group 3 6:3:2:1 crack spread increased from $11.08 in 2014 to $12.93 in 2015.

Compared to 2014, our El Paso refinery margins were negatively impacted by the pricing differential between WTI Midland crude oil and WTI Cushing crude oil (the "WTI Midland/Cushing differential"). The WTI Midland/Cushing differential averaged a discount of $0.37 per barrel for 2015 compared to $6.92 in 2014. This discount has been volatile and

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fluctuates based on local crude oil production, expanded crude oil takeaway capacity in the Permian Basin, crude oil outflow at Cushing and regional refining throughput volumes.

Refinery gross margin increased from 2013 to 2014 primarily due to gross margin associated with the NTI refining assets acquired during November 2013 ($469.5 million) and 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 oil to Brent crude oil, which declined from $10.67 per barrel in 2013 to $5.66 in 2014, reflective of the initial decline of global and domestic crude oil prices that began 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 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. The Group 3 6:3:2:1 crack spread decreased from $13.50 in 2013 to $11.08 in 2014.

During 2015, we recognized a net realized and unrealized gain from economic hedging activities of $43.5 million compared to a gain of $289.8 million in 2014 and a loss of $1.0 million in 2013. 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 greater net cost of purchased RINs. RIN costs were $35.5 million, $28.2 million and $30.5 million for the years ended December 31, 2015, 2014 and 2013, respectively. The increase in 2015 is primarily due to revised Renewable Fuel Standard blending requirements increased by the EPA in the fourth quarter of 2015 for the 2014 and 2015 calendar years.

Total refinery throughput increased from 2013 to 2014, and from 2014 to 2015 primarily due to El Paso refinery operational efficiencies gained from the turnarounds in 2013 and 2014. Also, our refined product sales volume was 123.5 million, 115.2 million and 68.7 million barrels in December 31, 2015, 2014 and 2013, respectively.

Direct Operating Expenses

The decrease in direct operating expenses from 2014 to 2015 is primarily due to decreases in energy expense of $12.0 million due to decreased natural gas prices and a decrease in St. Paul Park refinery maintenance expenses of $4.4 million. A partial offset to these decreases were increases in employee expenses of $6.0 million primarily generated by increased headcount, railcar lease expense of $3.6 million due to new short term leases in 2015, property tax expense of $1.7 million, outside support services expense of $1.5 million and maintenance expense of $1.3 million due to maintenance projects at the El Paso refinery.

The increase in direct operating expenses from 2013 through 2014 was primarily due to expenses associated with the St. Paul Park refinery assets acquired during November 2013 ($159.1 million). The increase was also due to greater 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).

Selling, General and Administrative Expenses

Selling, general and administrative expense increased from 2014 to 2015 primarily due to increased employee expenses ($4.2 million) due to greater incentive compensation and equity based compensation expenses, professional and legal costs ($0.7 million) and information technology expenses ($0.6 million).

Selling, general and administrative expense increased from 2013 to 2014 primarily due to expenses associated with the St. Paul Park refinery assets acquired during November 2013 ($30.0 million) and increased information technology expenses ($1.5 million).

Maintenance Turnaround Expenses

We reported minimal turnaround expenses during the year ended December 31, 2015. 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.

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Depreciation and Amortization

Depreciation and amortization increased from 2014 to 2015 due to additional depreciation at our El Paso refinery primarily resulting from assets capitalized during the first quarter of 2014 and additional depreciation associated with recently capitalized assets including the St. Paul Park refinery wastewater treatment plant in mid-2014.

Depreciation and amortization increased from 2013 to 2014 was primarily due to depreciation associated with the St. Paul Park refinery assets acquired during November 2013 and additional depreciation at our El Paso refinery primarily resulting from assets capitalized during the first quarter of 2013 and 2014 in El Paso.

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WNRL

The WNRL financial and operational data presented includes the historical results of all assets acquired from Western in the Wholesale Acquisition and the TexNew Mex Pipeline Transaction. These acquisitions from Western were transfers of assets between entities under common control. Accordingly, the financial 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. The financial information includes the historical results of the WNRL Predecessor, retrospectively adjusted due to the Wholesale Acquisition, for periods prior to October 16, 2013, and the results of WNRL, retrospectively adjusted for the Wholesale Acquisition and the TexNew Mex Pipeline Acquisition beginning October 16, 2013, the date WNRL commenced operations.



	Year Ended
	December 31,
	2015			2014		2013
	(In thousands)
Statement of Operations Data:
Net sales, net of excise taxes	$	2,599,867		$	3,501,888	$	3,407,128
Operating costs and expenses:
Cost of products sold, net of excise taxes	2,308,137			3,244,919		3,279,717
Direct operating expenses	154,267			143,702		135,684
Selling, general and administrative expenses	24,116			22,628		17,672
Loss (gain) and impairments on disposal of assets, net	(278		)	157		—
Depreciation and amortization	26,912			20,187		16,515
Total operating costs and expenses	2,513,154			3,431,593		3,449,588
Operating income (loss)	$	86,713		$	70,295	$	(42,460	)



	Year Ended
	December 31,
	2015		2014		2013
	(In thousands, except per gallon/barrel data)
Key Operating Statistics:
Pipeline and gathering (bpd) (1):
Mainline movements:
Permian/Delaware Basin system	47,368		24,644		3,258
TexNew Mex system	12,302		—		—
Four Corners system	56,079		45,232		38,091
Gathering (truck offloading) (bpd):
Permian/Delaware Basin system	23,617		24,166		10,169
Four Corners system	13,438		11,550		8,814
Terminalling, transportation and storage (bpd):
Shipments into and out of storage (includes asphalt)	391,842		381,371		367,208
Wholesale:
Fuel gallons sold	1,237,994		1,147,860		1,073,538
Fuel gallons sold to retail (included in fuel gallons sold, above)	314,604		268,148		254,907
Fuel margin per gallon (2)	$	0.030	$	0.022	$	0.026
Lubricant gallons sold	11,697		12,082		11,793
Lubricant margin per gallon (3)	$	0.73	$	0.86	$	0.89
Crude oil trucking volume (bpd)	45,337		36,314		12,603
Average crude oil trucking revenue per barrel	$	2.53	$	2.90	$	2.24

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(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. During the second quarter, we began shipping crude oil from the Four Corners system, through the TexNew Mex Pipeline System, to the Permian/Delaware system. Additional activity resulting from the opening of the TexNew Mex Pipeline System caused us to re-evaluate our method for measuring average Four Corners mainline movements. As such, we have adjusted our 2014 average daily activity on the Four Corners system for consistency with our 2015 method.


(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 Profit

Net sales are comprised of fee based revenues and product sale revenues. WNRL gross profit is a function of total revenues, net of excise taxes, less cost of products sold, net of excise taxes. WNRL gross profit increased by $34.8 million from 2014 to 2015. This increase was primarily due to increased fee based revenue of $23.6 million resulting from increasing certain pipeline, terminal and other service fee rates over 2014 rates. Also contributing to the increase were greater wholesale fuel margins of $9.9 million and greater truck freight revenue from crude oil gathering activity in the Permian Basin area of $3.5 million. Wholesale sales based revenues decreased due to a lower average price per gallon sold in 2015 of $1.80 compared to $2.83 in 2014.

WNRL gross profit increased by $129.6 million from 2013 to 2014 primarily because of only a partial year of comparative 2013 activity since WNRL commenced operations in October of that year. 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. Also contributing to this increase were WNRL's wholesale increased revenue of $28.1 million due to truck freight revenue from crude oil gathering activity in the Permian Basin.

Direct Operating Expenses

WNRL's direct operating expenses increased from 2014 through 2015 primarily due to higher employee expenses ($7.7 million) resulting from an increase in the number of drivers in our truck fleet, outside support services ($2.3 million) due to in-line inspections for pipeline segments and various tank repairs, maintenance expenses ($1.6 million) and increased energy expense ($0.8 million) specifically due to chemical additives used in the pipeline transportation process, partially offset by lower fuel expense for our transportation department ($3.6 million).

Direct operating expenses expenses increased from 2013 through 2014 primarily due to increased employee expense ($11.5 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).

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 higher 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.

Selling, General and Administrative Expenses

Selling, general and administrative expenses increased from 2014 to 2015 primarily due to increased corporate overhead related to the TexNew Mex Pipeline Acquisition ($1.6 million).

The increase in selling, general and administrative expenses from 2013 to 2014 primarily due to increased corporate overhead related to the Wholesale Acquisition ($5.8 million).

Depreciation and Amortization

The increase in depreciation and amortization from 2014 through 2015 was primarily due to TexNew Mex Pipeline depreciation and the ongoing expansion of WNRL's Delaware Basin logistics system.

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The increase in depreciation and amortization from 2013 through 2014 was primarily due to TexNew Mex Pipeline depreciation, 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.

Retail

The selected historical financial data for the 2013 period presented below represents the financial results of NTI retail from the period beginning November 12, 2013, through the period ended December 31, 2013.



	Year Ended
	December 31,
	2015			2014			2013
	(In thousands, except per gallon data)
Statement of Operations Data:
Net sales (including intersegment sales)	$	2,279,737		$	2,776,782		$	1,588,314
Operating costs and expenses:
Cost of products sold (exclusive of depreciation and amortization)	1,906,048			2,437,342			1,418,585
Direct operating expenses (exclusive of depreciation and amortization)	267,079			238,595			127,520
Selling, general and administrative expenses	42,312			39,017			12,629
Loss (gain) and impairments on disposal of assets, net	(178		)	(128		)	3
Depreciation and amortization	23,197			19,869			13,245
Total operating costs and expenses	2,238,458			2,734,695			1,571,982
Operating income	$	41,279		$	42,087		$	16,332
Key Operating Statistics:
Southwest Retail:
Retail fuel gallons sold	357,835			309,884			302,759
Average retail fuel sales price per gallon, net of excise taxes	$	2.02		$	3.31		$	3.41
Average retail fuel cost per gallon, net of excise taxes	1.82			3.11			3.23
Retail fuel margin per gallon (1)	0.20			0.20			0.18
Merchandise sales	$	311,654		$	266,677		$	253,096
Merchandise margin (2)	29.4		%	28.8		%	28.8		%
Operating retail outlets at period end	258			230			228
Cardlock gallons sold	65,508			67,420			67,803
Cardlock margin per gallon	$	0.163		$	0.178		$	0.153
Operating cardlocks at period end	52			50			53
SuperAmerica:
Retail fuel gallons sold	304,484			306,777			40,031
Retail fuel margin per gallon (1)	$	0.23		$	0.22		$	0.17
Merchandise sales	366,401			349,145			27,958
Merchandise margin (2)	25.6		%	25.9		%	25.0		%
Company-operated retail outlets at period end	168			165			164
Franchised retail outlets at period end	109			89			75

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	Year Ended
	December 31,
	2015			2014		2013
	(In thousands, except per gallon data)
Net Sales
Retail fuel sales, net of excise taxes	$	1,442,147		$	1,906,425	$	1,051,217
Merchandise sales	678,055			615,822		281,054
Cardlock sales	127,413			214,714		225,466
Other sales	32,122			39,821		30,577
Net sales	$	2,279,737		$	2,776,782	$	1,588,314
Cost of Products Sold
Retail fuel cost of products sold, net of excise taxes	$	1,298,456		$	1,776,825	$	987,510
Merchandise cost of products sold	492,578			448,674		201,258
Cardlock cost of products sold	116,506			202,489		215,082
Other cost of products sold	(1,492		)	9,354		14,735
Cost of products sold	$	1,906,048		$	2,437,342	$	1,418,585
Retail fuel margin per gallon (1)	$	0.22		$	0.21	$	0.19


(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.


(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 gross margin was primarily due to the Southwest retail outlets added from 2014 to 2015. 32 new Southwest retail outlets were added during the first half of 2015. The effect of the new retail outlets was an increase in retail gross margin from 2014 to 2015 of $19.5 million including an increase in merchandise margin ($10.0 million) and retail fuel margin ($8.0 million). The increase in gross margin was also the result of higher same store Southwest fuel sales volumes and increased same store Southwest merchandise gross margin ($5.0 million). The increase was also due to higher average SuperAmerica fuel margin per gallon, partially offset by lower SuperAmerica fuel sales volumes resulting in an overall $4.8 million increase in gross margin. SuperAmerica merchandise margin increased $3.4 million due primarily to sales growth in certain product segments, partially offset by the effect of certain promotional programs.

The increase in retail gross margin from 2013 to 2014 was primarily due to gross margin associated with the NTI retail assets acquired during November 2013 ($155.8 million). The increase was also due to the result of a 2.4% increase in Southwest fuel volumes from 2013 to 2014 and an increase of 5.4% in Southwest merchandise gross margin from 2013 to 2014. Contributing to the increase in gross margin was the Southwest retail outlets added from 2013 to 2014. The number of Southwest stores increased from 228 in 2013 to 230 in 2014.

Direct Operating Expenses

The increase in direct operating expenses from 2014 to 2015 was primarily due to the addition of the new Southwest retail outlets during 2015 which generated an additional $16.2 million in current year expenses. The addition of the new Southwest outlets resulted in increased employee expense ($7.0 million), lease expense ($3.0 million), credit card processing fees resulting from an increase in credit sales ($1.8 million), maintenance expense ($1.1 million) and utilities expense ($1.1 million). The increase was also due to higher employee expenses at SuperAmerica retail stores as a result of early adoption of a mandated minimum wage increase.

The increase in direct operating expenses from 2013 to 2014 was primarily due to expenses associated with the SuperAmerica retail assets acquired during November 2013 ($103.9 million) and expenses generated by Southwest 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.

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Selling, General and Administrative Expenses

The increase in selling, general and administrative expenses from 2014 to 2015 in selling, general and administrative expenses was primarily due to increased cardlock employee expenses ($1.8 million) due to increased administrative headcount and greater incentive compensation and higher SuperAmerica retail employee expenses.

Selling, general and administrative expense increased from 2013 to 2014 primarily due to expenses associated with the NTI retail assets acquired during November 2013 ($24.7 million) and increased outside support services resulting from outsourcing store audit services starting in May 2014.

Depreciation and Amortization

The increase in depreciation and amortization expense was primarily due to the addition of the new Southwest retail outlets that resulted in an additional $1.8 million in depreciation expense. This increase was also due to additional depreciation incurred from major remodels at three Southwest retail locations and the capitalization of a new retail point of sale system, accelerated depreciation of Southwest retail's existing point of sale system and accelerated depreciation for four closed Southwest outlets.

Depreciation and amortization increased from 2013 to 2014 primarily due to depreciation associated with the NTI retail assets acquired during November 2013 ($7.3 million). The majority of the Southwest retail outlets added from 2013 to 2014 were through operating leases and were therefore not depreciated.

Outlook

Our refining margins, excluding hedging activities, were stronger in 2015 compared to 2014. The Gulf Coast benchmark 3:2:1 crack spread increased from an average of $15.81 in 2014 to an average of $18.24 in 2015. Both Western and NTI base our crude oil purchases on pricing tied to WTI. In recent years, the discount relationship between WTI crude oil compared to Brent crude oil (the "WTI/Brent discount") has had a positive impact on refining margins at both Western and NTI. During 2015 the WTI/Brent discount declined to an average of $3.68 for the year ended December 31, 2015, compared to $5.66 in 2014, reflective of the ongoing volatility in domestic and international crude oil pricing. Additionally, the 2015 average WTI Midland/Cushing discount of $0.37 per barrel was a benefit to our El Paso refining margins, although not to the level realized in 2014, when this discount averaged $6.92 per barrel.

Thus far in 2016, the Gulf Coast benchmark 3:2:1 crack spread has averaged $10.11, year-to-date, and the WTI/Brent discount has averaged $0.35, year to date, through February 19, respectively. The Midland/Cushing premium has averaged $0.15 through February 19, 2016. The prices of crude oil and refined products have continued to decline thus far in the first quarter of 2016. A continued decline in these prices may negatively impact the carrying value of our inventories and result in additional lower of cost or market inventory adjustments.

The growth of gathering activity on our Delaware Basin Logistics System continues to positively impact our refining margins through increased deliveries of advantaged crude oil to our El Paso refinery. Also, NTI’s location allows for direct pipeline access to 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 continuing decline in Brent and WTI crude oil prices.

The Merger with NTI is expected to close in the first half of 2016, pending the satisfaction of certain conditions, including the approval of the Merger at a special meeting of NTI unitholders. Upon completion of the transaction, NTI will continue to exist as a limited partnership under Delaware law and as an indirect wholly-owned subsidiary of WNR.

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, 2015, we had cash and cash equivalents of $772.5 million, including NTI cash of $70.9 million and WNRL cash of $44.6 million, restricted cash of $69.1 million and no direct borrowings under the Western and NTI revolving credit facilities. Western had $973.6 million in total liquidity as of December 31, 2015, defined as Western’s cash and cash equivalents plus net availability under the Western Revolving Credit Facility. Western, NTI and WNRL had net availability under their revolving credit facilities of $247.5 million, $152.7 million and $154.3 million, respectively.

WNRL borrowed $145.0 million under the WNRL 2018 Revolving Credit Facility on October 30, 2015, to partially fund the purchase of Western's TexNew Mex Pipeline System. See Note 15, Long-Term Debt in the Notes to Consolidated Financial Statements included in this annual report for detailed information regarding our financing.

On December 21, 2015, we entered into the Merger Agreement to acquire all of NTI's remaining outstanding publicly held common units. At the effective time of the Merger, each of the outstanding NTI common units held by the NTI Public

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Unitholders will be converted into the right to receive, subject to election by the NTI Public Unitholders and proration, (i) $15.00 in cash without interest and 0.2986 of a share of WNR’s common stock, (ii) $26.06 in cash without interest or (iii) 0.7036 of a share of WNR common stock. We expect to fund the cash portion of the Merger consideration, approximately $858.2 million, with a combination of cash on hand, bank debt or capital markets debt, including a portion of which that we expect to finance through the incurrence of new indebtedness. In 2016, debt financing for the energy industry has become increasingly difficult and more expensive. In light of this, the cost we may incur to finance a portion of the cash consideration in the Merger, as well as any increases to the cost of our existing indebtedness in connection with the Merger, could have a material adverse effect our financial position, results of operations and cash flows. See Note 30, NTI, in the Notes to Consolidated Financial Statements for additional information on this transaction.

Cash Flows

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



	Year Ended December 31,
	2015			2014			2013
	(In thousands)
Cash flows provided by operating activities	$	843,083		$	737,633		$	441,153
Cash flows used in investing activities	(191,846		)	(380,864		)	(895,885		)
Cash flows provided by (used in) financing activities	(309,894		)	(393,680		)	468,835
Net increase (decrease) in cash and cash equivalents	$	341,343		$	(36,911	)	$	14,103

The increase in net cash from operating activities from 2014 to 2015 was primarily the result 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, 2015 and 2014. Working capital increased by $301.7 million primarily due to decreases in accounts payable and accrued liabilities resulting from the timing of crude oil payments and the price of crude oil.

Cash flows provided by operating activities for the year ended December 31, 2015, combined with $300.0 million and $145.0 million from the issuance of long-term debt and borrowings under WNRL's revolving credit facility, respectively, and an increase in restricted cash of $170.0 million were primarily used for the following investing and financing activities:

•Fund capital expenditures ($290.9 million) including the use of $267.9 million of restricted cash;

•Repayment of WNRL's revolving credit facility debt ($269.0 million);

•Payment of distributions to NTI and WNRL non-controlling interest holders ($238.4 million);

•Payment of cash dividends ($129.2 million);

•Purchases of common stock for treasury ($105.0 million);

•Payments on long-term debt and capital lease obligations ($7.4 million); and

•Payment of deferred financing costs ($6.8 million).

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);

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•Purchases of common stock for treasury ($259.2 million);

•Fund capital expenditures ($223.3 million); and

•Repayment of debt ($6.1 million).

Working Capital

Total working capital at December 31, 2015 was $1,114.4 million, consisting of $1,922.2 million in current assets and $807.9 million in current liabilities. Working capital at December 31, 2014 was $812.7 million, consisting of $1,768.5 million in current assets and $955.8 million in current liabilities. Our working capital at December 31, 2015 and 2014 was as follows:



	December 31,
	2015		2014
	(In thousands)
Western	$	1,077,697	$	769,812
WNRL	36,669		42,899
Total	$	1,114,366	$	812,711

Indebtedness

Our capital structure at December 31, 2015 and 2014 was as follows:



	December 31,
	2015			2014
	(In thousands)
Debt, including current maturities:
Western obligations:
Revolving Credit Facility due 2019	$	—		$	—
Term Loan Credit Facility due 2020, net of unamortized financing costs of $9,442 and $11,382, respectively	529,558			533,118
6.25% Senior Unsecured Notes due 2021, net of unamortized financing costs of $4,938 and $5,877, respectively	345,062			344,123
Total Western obligations	874,620			877,241
NTI obligations:
Revolving Credit Facility due 2019	—			—
7.125% Senior Secured Notes, due November 2020, net of unamortized financing costs of $2,032 and $2,345 and unamortized premium of $5,925 and $7,037, respectively	353,893			354,692
Total NTI obligations	353,893			354,692
WNRL obligations:
Revolving Credit Facility due 2018	145,000			269,000
7.5% Senior Notes due 2023, net of unamortized financing costs of $6,072 for 2015	293,928			—
Total WNRL obligations	438,928			269,000
Unamortized financing costs, revolving credit facilities	(17,047		)	(20,768		)
Long-term debt	1,650,394			1,480,165
Equity	2,945,906			2,787,644
Total capitalization	$	4,596,300		$	4,267,809

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 $290.9 million for the year ended December 31, 2015 and included improvement and regulatory projects for our refining group, WNRL projects and several smaller projects for our retail and corporate groups. Capital expenditures included $1.8 million of capitalized interest for 2015.

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The following table summarizes our budgeted capital expenditures for 2016:



	Western		WNRL		Totals
	(In thousands)
Sustaining	$	90,992	$	12,919	$	103,911
Discretionary	165,293		41,580		206,873
Regulatory	40,527		2,833		43,360
Total	$	296,812	$	57,332	$	354,144

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 60 mile crude oil pipeline project connecting Wink, Texas to Crane, Texas in the Permian Basin. 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. EPA regulation allows the one-time use of credits to extend the June 2012 deadline by up to 24 months. The EPA finalized Tier III regulations for gasoline sulfur content in 2014. The regulations have lowered gasoline sulfur content to 10 parts per million with an effective date of 2017 for our El Paso and St. Paul Park refineries and 2020 for our Gallup refinery. Meeting these regulations will require capital spending and adjustments to the operations of our refineries. 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 2013 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:



	2015		2014		2013
	(In millions)
EPA Initiative projects	$	—	$	—	$	3.8
Low benzene gasoline	—		—		0.1
Wastewater Treatment Plant	—		—		0.7
DHT expansion in El Paso	—		0.5		2.6
Flare Ja upgrades - El Paso and Gallup	7.9		1.3		—
Tier III low sulfur gasoline - El Paso	0.6		—		—
Total	$	8.5	$	1.8	$	7.2

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:



	2016		2017		2018
	(In millions)
Control room upgrades - El Paso and Gallup	$	16.4	$	—	$	—
Flare systems upgrades - Gallup	0.2		7.0		7.0
Tier III Low sulfur gasoline - Gallup	1.5		10.0		10.0
Fire suppression - Gallup	8.2		8.0		4.0
Various other projects	6.8		5.8		5.8
Total	$	33.1	$	30.8	$	26.8

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Contractual Obligations and Commercial Commitments

Information regarding our contractual obligations of the types described below as of December 31, 2015, is set forth in the following table:



	Payments Due by Period
	Totals		2016		2017 and 2018		2019 and 2020		2021 and Beyond
	(In thousands)
Long-term debt obligations (1)	$	2,206,289	$	101,275	$	346,041	$	1,047,254	$	711,719
Capital lease obligations	96,144		5,256		10,084		10,515		70,289
Operating lease obligations	585,879		58,885		102,323		84,625		340,046
Purchase obligations (2)	1,869,120		539,164		915,086		414,870		—
Environmental reserves (3)	18,294		10,099		6,306		444		1,445
Uncertain tax positions (4)	42,049		42,049		—		—		—
Other obligations (5)(6)	205,306		16,797		32,932		147,610		7,967
Total obligations (7)	$	5,023,081	$	773,525	$	1,412,772	$	1,705,318	$	1,131,466


(1)	Includes minimum principal payments and interest calculated using interest rates at December 31, 2015.


(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, 2015 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 are subject to change based upon future events. 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 $809.5 million related to NTI including long-term debt, capital leases, 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 20, Equity, in the Notes to Consolidated Financial Statements included in this annual report for detailed information regarding our dividends and 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 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.

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

At December 31, 2015, we held approximately 10.0 million barrels of crude oil, refined product and other inventories valued under the LIFO valuation method with an average cost of $64.93 per barrel. At December 31, 2015, the excess of the current cost of our crude oil, refined product and other feedstock and blendstock inventories over aggregated LIFO costs was $198.4 million.

At December 31, 2014, we 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.

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. 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, 2015, and open commodity hedging positions as of December 31, 2015, and December 31, 2014:



	Year Ended December 31,
	2015			2014		2013
	(In thousands)
Economic hedging activities recognized within cost of products sold
Realized hedging gain, net	$	93,699		$	95,331	$	15,868
Unrealized hedging gain (loss), net	(50,233		)	194,423		(16,898		)
Total hedging gain (loss), net	$	43,466		$	289,754	$	(1,030	)



	December 31, 2015			December 31, 2014
	(In thousands)
Open commodity hedging instruments (bbls)
Crude futures	4,593			(864		)
Refined product price and crack spread swaps	(5,645		)	(8,781		)
Total open commodity hedging instruments	(1,052		)	(9,645		)

Fair value of outstanding contracts, net
Other current assets	$	78,125		$	79,722
Other assets	11,881			56,533
Accrued liabilities	(10,273		)	(4,889		)
Other long-term liabilities	—			(1,400		)
Fair value of outstanding contracts - unrealized gain, net	$	79,733		$	129,966

During the three years ended December 31, 2015, 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

INDEX TO FINANCIAL STATEMENTS



	Page
Report of Independent Registered Public Accounting Firm	38
Consolidated Balance Sheets as of December 31, 2015 and 2014	39
Consolidated Statements of Operations for the Three Years ended December 31, 2015	40
Consolidated Statements of Comprehensive Income for the Three Years ended December 31, 2015	41
Consolidated Statements of Changes in Equity for the Three Years ended December 31, 2015	42
Consolidated Statements of Cash Flows for the Three Years ended December 31, 2015	43
Notes to Consolidated Financial Statements	44

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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, 2015 and 2014, 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, 2015. 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, 2015 and 2014, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2015, 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, 2015, 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 February 26, 2016 expressed an unqualified opinion on the Company’s internal control over financial reporting (not presented herein).

/s/ DELOITTE & TOUCHE LLP

Phoenix, Arizona

February 26, 2016 (December 8, 2016 as to the effects of the changes in reportable segments described in Note 1 and subsequent events information described in Note 31)

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WESTERN REFINING, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In thousands, except share data)



	As of December 31,
	2015			2014
ASSETS
Current assets:
Cash and cash equivalents	$	772,502		$	431,159
Accounts receivable, trade, net of a reserve for doubtful accounts of $169 and $484, respectively	359,237			467,527
Inventories	547,538			629,237
Prepaid expenses	73,213			88,415
Other current assets	169,728			152,125
Total current assets	1,922,218			1,768,463
Restricted cash	69,106			167,009
Equity method investment	97,513			96,080
Property, plant and equipment, net	2,305,171			2,153,189
Goodwill	1,289,443			1,289,443
Intangible assets, net	84,945			85,952
Other assets, net	64,997			82,050
Total assets	$	5,833,393		$	5,642,186
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	553,957		$	681,803
Accrued liabilities	248,395			268,449
Current portion of long-term debt	5,500			5,500
Total current liabilities	807,852			955,752
Long-term liabilities:
Long-term debt, less current portion	1,644,894			1,474,665
Lease financing obligation	53,232			27,489
Deferred income tax liability, net	312,914			354,809
Other liabilities	68,595			41,827
Total long-term liabilities	2,079,635			1,898,790
Commitments and contingencies
Equity:
Western shareholders' equity:
Common stock, par value $0.01, 240,000,000 shares authorized; 102,773,705 and 102,642,540 shares issued, respectively	1,028			1,026
Preferred stock, par value $0.01, 10,000,000 shares authorized; no shares issued and outstanding	—			—
Additional paid-in capital	492,848			487,748
Retained earnings	1,167,938			890,393
Accumulated other comprehensive income (loss), net of tax	651			(1,291		)
Treasury stock, 9,089,623 and 6,441,883 shares, respectively at cost	(363,168		)	(258,168		)
Total Western shareholders' equity	1,299,297			1,119,708
Non-controlling interest	1,646,609			1,667,936
Total equity	2,945,906			2,787,644
Total liabilities and equity	$	5,833,393		$	5,642,186

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,
	2015			2014			2013
Net sales	$	9,787,036		$	15,153,573		$	10,086,070
Operating costs and expenses:
Cost of products sold (exclusive of depreciation and amortization)	7,521,375			12,719,963			8,690,222
Direct operating expenses (exclusive of depreciation and amortization)	902,925			850,634			523,836
Selling, general and administrative expenses	225,245			226,020			137,031
Affiliate severance costs	—			12,878			—
Loss (gain) and impairments on disposal of assets, net	51			8,530			(4,989		)
Maintenance turnaround expense	2,024			48,469			50,249
Depreciation and amortization	205,291			190,566			117,848
Total operating costs and expenses	8,856,911			14,057,060			9,514,197
Operating income	930,125			1,096,513			571,873
Other income (expense):
Interest income	703			1,188			746
Interest expense and other financing costs	(105,603		)	(97,062		)	(74,581		)
Loss on extinguishment of debt	—			(9		)	(46,773		)
Other, net	13,161			2,046			2,214
Income before income taxes	838,386			1,002,676			453,479
Provision for income taxes	(223,955		)	(292,604		)	(153,925		)
Net income	614,431			710,072			299,554
Less net income attributed to non-controlling interests	207,675			150,146			23,560
Net income attributable to Western Refining, Inc.	$	406,756		$	559,926		$	275,994

Net earnings per share:
Basic	$	4.28		$	6.17		$	3.35
Diluted	$	4.28		$	5.61		$	2.79
Weighted average common shares outstanding:
Basic	94,899			90,708			82,248
Diluted	94,999			101,190			104,904

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,
	2015			2014			2013
Net income	$	614,431		$	710,072		$	299,554
Other comprehensive income items:
Benefit plans:
Amortization of net prior service cost	215			161			—
Reclassification of loss to income	50			21			47
Pension plan termination adjustment	—			—			217
Actuarial gain (loss)	1,683			(2,157		)	1,195
Net prior service credit	2,463			—			—
Other comprehensive income before tax	4,411			(1,975		)	1,459
Income tax	(403		)	295			(418		)
Other comprehensive income, net of tax	4,008			(1,680		)	1,041
Comprehensive income	618,439			708,392			300,595
Less comprehensive income attributed to non-controlling interests	209,741			149,407			23,777
Comprehensive income attributable to Western Refining, Inc.	$	408,698		$	558,985		$	276,818

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, 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 benefit 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 loss, 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
Stock-based compensation	—	—		4,231			—			—			—		—			11,729			15,960
Restricted share unit vesting	131,165	2		(2		)	—			—			—		—			—			—
Excess tax benefit from stock-based compensation	—	—		871			—			—			—		—			—			871
Cash dividends declared of $1.36 per share	—	—		—			(129,211		)	—			—		—			—			(129,211		)
Net income	—	—		—			406,756			—			—		—			207,675			614,431
Other comprehensive income, net of tax of $403	—	—		—			—			1,942			—		—			2,066			4,008
Distribution to non-controlling interest holders	—	—		—			—			—			—		—			(242,576		)	(242,576		)
Treasury stock, at cost	—	—		—			—			—			(2,647,740	)	(105,000		)	—			(105,000		)
Other	—	—		—			—			—			—		—			(221		)	(221		)
Balance at December 31, 2015	102,773,705	$	1,028	$	492,848		$	1,167,938		$	651		(9,089,623	)	$	(363,168	)	$	1,646,609		$	2,945,906

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,
	2015			2014			2013
Cash flows from operating activities:
Net income	$	614,431		$	710,072		$	299,554
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	205,291			190,566			117,848
Changes in fair value - commodity hedging instruments	50,233			(194,423		)	16,899
Reserve for doubtful accounts	(315		)	296			1,015
Amortization of loan fees and original issue discount	6,450			14,496			21,975
Loss on extinguishment of debt	—			9			46,773
Stock-based compensation expense	16,505			19,903			5,973
Deferred income taxes	(41,895		)	71,827			(64,347		)
Excess tax benefit from stock-based compensation	(871		)	(1,144		)	(8,362		)
Income from equity method investment, net of dividends	(1,672		)	(2,238		)	—
Loss (gain) and impairment on disposal of assets, net	51			8,530			(4,989		)
Changes in operating assets and liabilities:
Accounts receivable	108,604			132,107			(129,531		)
Inventories	81,699			(71,849		)	37,803
Prepaid expenses	15,202			23,722			(23,342		)
Other assets	(41,187		)	22,312			(4,020		)
Accounts payable and accrued liabilities	(198,707		)	(190,209		)	126,120
Other long-term liabilities	29,264			3,656			1,784
Net cash provided by operating activities	843,083			737,633			441,153
Cash flows from investing activities:
Capital expenditures	(290,863		)	(223,271		)	(205,677		)
Proceeds from the sale of assets	1,114			1,936			7,475
Return of capital on equity method investment	—			7,480			1,140
Northern Tier Energy acquisition, net of cash acquired	—			—			(698,823		)
Increase in restricted cash	(170,000		)	(320,000		)	—
Use of restricted cash	267,903			152,991			—
Net cash used in investing activities	(191,846		)	(380,864		)	(895,885		)
Cash flows from financing activities:
Additions to long-term debt	300,000			79,311			900,000
Payments on long-term debt and capital lease obligations	(7,368		)	(6,072		)	(325,369		)
Borrowings on revolving credit facility	145,000			269,000			—
Repayments of revolving credit facility	(269,000		)	—			(50,000		)
Distribution to non-controlling interest holders	(238,366		)	(173,637		)	(28,575		)
Debt retirement fees	—			—			(24,396		)
Deferred financing costs	(6,820		)	(9,649		)	(28,646		)
Purchases of common stock for treasury	(105,000		)	(259,222		)	(252,841		)
Dividends paid	(129,211		)	(293,746		)	(52,489		)
Convertible debt redemption	—			(809		)	(357		)
Net proceeds from issuance of WNRL common units	—			—			323,146
Excess tax benefit from stock-based compensation	871			1,144			8,362
Net cash provided by (used in) financing activities	(309,894		)	(393,680		)	468,835
Net increase (decrease) in cash and cash equivalents	341,343			(36,911		)	14,103
Cash and cash equivalents at beginning of year	431,159			468,070			453,967
Cash and cash equivalents at end of year	$	772,502		$	431,159		$	468,070

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, one near Gallup, New Mexico and one in St. Paul Park, Minnesota. We sell refined products in Arizona, Colorado, Minnesota, New Mexico, Wisconsin, West Texas, the Mid-Atlantic region and Mexico. Our product sales occur through bulk distribution terminals, wholesale marketing networks and two retail networks with a total of 535 company-owned and franchised retail sites in the U.S.

At December 31, 2015, we owned a 38.4% limited partner interest in Northern Tier Energy LP ("NTI") and the public held a 61.6% limited partner interest. We control NTI through our 100% ownership of its general partner. NTI owns and operates a refinery in St. Paul Park, Minnesota and has a retail-marketing network of 277 convenience stores; 109 of which operate through franchise agreements. NTI's primary areas of operation include Minnesota and Wisconsin.

We entered into an Agreement and Plan of Merger dated as of December 21, 2015 (the “Merger Agreement”) with Western Acquisition Co, LLC, NTI and Northern Tier Energy GP LLC, a wholly-owned subsidiary of Western (“MergerCo”), to acquire all of NTI’s outstanding common units not already held by us (the “Merger”). Each of the outstanding NTI common units held by unitholders other than us (the “NTI Public Unitholders”) will be converted into the right to receive, subject to election by the NTI Public Unitholders and proration, (i) $15.00 in cash without interest and 0.2986 of a share of our common stock, (ii) $26.06 in cash without interest or (iii) 0.7036 of a share of our common stock. Upon the terms and subject to the conditions set forth in the Merger Agreement, MergerCo will merge with and into NTI and the separate limited liability company existence of MergerCo will cease and NTI will continue to exist, as a limited partnership under Delaware law and as our indirect wholly-owned subsidiary, as the surviving entity in the Merger. The Merger is expected to close in the first half of 2016, pending the satisfaction of certain customary conditions and the approval of the Merger at a special meeting of NTI unitholders by the affirmative vote of holders of a majority of the outstanding NTI common units (including the NTI common units held by us). The transaction is expected to result in approximately 17.1 million additional shares of WNR common stock outstanding. Upon completion of the transaction, NTI will continue to exist as a limited partnership and will become a wholly-owned limited partnership subsidiary of WNR. See Note 30, NTI, and Note 31, Subsequent Events, for additional information.

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, 2015, we owned a 66.4% limited partner interest in Western Refining Logistics, LP ("WNRL") and the public held a 33.6% limited partner interest. We control WNRL through our 100% ownership of its general partner and we own the majority of WNRL's limited partnership interests. WNRL owns and operates logistics assets consisting of pipeline and gathering, terminalling, storage and transportation assets as well as a wholesale business that operates primarily in the Southwest. WNRL operates its logistics assets primarily for the benefit of the Company.

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. See Note 29, Western Refining Logistics, LP, for additional information on this transaction.

On October 30, 2015, we sold to WNRL a 375 mile segment of the TexNew Mex Pipeline system that extends from WNRL's crude oil station in Star Lake, New Mexico, in the Four Corners region to its T station in Eddy County, New Mexico (the "TexNew Mex Pipeline System"). We also sold an 80,000 barrel crude oil storage tank located at WNRL's crude oil pumping station in Star Lake, New Mexico and certain other related assets. WNRL acquired these assets from us in exchange for $170 million in cash, 421,031 common units representing limited partner interests in WNRL and 80,000 units of a newly created class of limited partner interests in WNRL, referred to as the "TexNew Mex Units". We refer to this transaction as the "TexNew Mex Pipeline Transaction".

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Effective July 1, 2016, we changed our reportable segments due to changes in our organization. Prior to the Merger, we reported NTI as a separate reportable segment. Following the completion of the Merger, NTI became a wholly-owned subsidiary of Western and, as a result, we moved its assets and operations into our other reportable segments. Beginning on July 1, 2016, our management team began managing our businesses and allocating resources based on three reportable segments.

The consolidated financial statements and accompanying notes included in the Annual Report on Form 10-K for the three years ended December 31, 2015, have been recast for the segment changes described above. 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 2015, 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 465,000 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.

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 beneficiary for accounting purposes.

We have non-controlling interests for NTI and WNRL of $1,646.6 million and $1,667.9 million in our Consolidated Balance Sheets as of December 31, 2015 and 2014, respectively.

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, 2015 relates to net proceeds from the sale of Western's TexNew Mex Pipeline System to WNRL. This cash is restricted through October 30, 2016 and must be used to reinvest in assets used in our business or as an offer of prepayment to lenders under the Western 2020 Term Loan Credit Facility.

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 was used to invest in capital assets.

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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 $0.2 million, $0.5 million and $0.9 million for the years ended December 31, 2015, 2014 and 2013, respectively. Additions, deductions and balances for the reserve for doubtful accounts for the three years ended December 31, 2015, are presented below:



	Year Ended December 31,
	2015			2014			2013
	(In thousands)
Balance at January 1	$	484		$	906		$	1,166
Additions (1)	367			3,095			1,015
Reductions	(682		)	(3,517		)	(1,275		)
Balance at December 31	$	169		$	484		$	906

(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

Our 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.

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. Our 17% interest in MPLI provides us 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 as of December 31, 2015 and 2014, respectively, and is included in other non-current assets in our Consolidated Balance Sheets.

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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.

See Note 10, Goodwill, for further disclosures.

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.

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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

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.

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.

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

We recognize compensation expense for equity-based awards issued under the NTI 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

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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.

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.

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Income Taxes

Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized to reflect temporary differences between the basis of assets and liabilities for financial reporting purposes and income tax purposes. Generally, deferred tax assets represent future income tax reductions while deferred tax liabilities represent income taxes that we expect to pay in the future. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The ultimate realization of our deferred tax assets depends upon generating sufficient future taxable income during the periods 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 November 12, 2013, initial acquisition of NTI (the "2013 NTI Acquisition"), 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.

We performed our purchase price allocation for the 2013 NTI Acquisition 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, NTI, for a summary of the purchase price allocation.

Reclassifications

We have reclassified certain balances from the prior year financial information in order to conform to our current presentation. We report these reclassified prior year balances in Note 3, Segment Information, Note 12, Other Assets, Net, Note 15, Long-Term Debt, Note 16, Income Taxes and Note 27, Condensed Consolidating Financial Information.

Recent Accounting Pronouncements

Effective January 1, 2015, we adopted the accounting and reporting requirements included in the Accounting Standards Codification ("ASC") for disposals when such disposal represents a strategic shift that will have a significant impact on the entity’s operations and financial results. These requirements have been applied prospectively. Our adoption of these changes, effective January 1, 2015, had no impact on our financial position, results of operations or cash flows.

Effective December 31, 2015, we adopted the accounting and reporting requirements included in the ASC for balance sheet classification of deferred taxes requiring deferred tax assets and liabilities to be classified as noncurrent. We have applied these requirements retrospectively. Accordingly, the reclassified presentation of our December 31, 2014 Consolidated Balance Sheet includes $57.9 million, previously reported as current deferred income tax liabilities, within the balance of $354.8 million in noncurrent deferred income tax liabilities as of December 31, 2014. The adoption of these accounting and reporting requirements had no impact on our results of operations or cash flows.

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Effective December 31, 2015, we adopted the accounting and reporting requirements included in the ASC for balance sheet classification of debt issuance costs requiring debt issuance costs to be presented as an offset to the related debt. We have applied these requirements retrospectively. Accordingly, the reclassified presentation of our December 31, 2014 Consolidated Balance Sheet includes $40.4 million, previously reported as debt issuance costs included in other assets, as an offset to the long-term debt, less current portion, balance of $1,474.7 million as of December 31, 2014. The adoption of these accounting and reporting requirements had no impact on our results of operations or cash flows.

For interim and annual periods beginning after December 15, 2015, the requirements related to the evaluation of limited partnerships or similar entities as variable interest entities ("VIE") were modified. The revised requirements may affect the method of consolidation for reporting entities involved with such entities. Application of the revised standards may follow the retrospective approach or a modified retrospective approach. The updated guidance is effective as of January 1, 2016. The adoption of these revised standards will not result in any change to our consolidation conclusions or impact our financial position, results of operations or cash flows. Additional disclosure is required for entities not previously included in the reporting entity as a VIE.

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 are currently evaluating the effect that certain of these new accounting requirements may have on our accounting and related reporting and disclosures in our consolidated financial statements.

Recognition and reporting of revenues - the requirements 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, 2018, and are to be applied retrospectively, with early adoption permitted for periods beginning after December 15, 2016, and interim periods thereafter.

Lease accounting - the requirements were amended to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and requiring disclosure of key leasing arrangement information. The main difference of the revised guidance to existing guidance is the recognition of lease assets and liabilities for leases currently classified as operating leases. These provisions are effective for fiscal years beginning after December 15, 2018, and may be applied either retrospectively or under a modified retrospective approach. The modified retrospective approach includes a number of practical expedients related to the identification and classification of leases entered into before the effective date of the revised guidance. Early adoption is permitted.

3. Segment Information

Our operations are organized into three reportable 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, WNRL and retail. See Note 24, Concentration of Risk, for a discussion on significant customers.

We treated the TexNew Mex Pipeline System assets we sold to WNRL in the TexNew Mex Pipeline Transaction as a transfer of assets between entities under common control. Accordingly, we have retrospectively adjusted the financial information for the affected reporting segments to include or exclude the historical results of the transferred assets for periods prior to the effective date of the transaction. The TexNew Mex Pipeline System was moved from the refining segment to the WNRL segment.

A description of each segment and the principal products follows:

Refining. We report the operations of three refineries in our refining segment: one in El Paso, Texas (the "El Paso refinery") with a 131,000 barrel per day ("bpd") capacity, one near Gallup, New Mexico (the "Gallup refinery") with a 25,000 bpd capacity and one in St. Paul Park, Minnesota (the "St. Paul Park refinery") with a 98,000 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 to WNRL, to our retail segment, to other independent wholesalers and retailers, commercial accounts and sales and exchanges with major oil companies. 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 our El Paso refinery.

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We have an exclusive supply and marketing agreement with a third party covering activities related to our refined product supply, sales and hedging in the Mid-Atlantic region. We recorded $1.8 million and $0.1 million in assets at December 31, 2015, and 2014, respectively, related to this supply agreement in our Consolidated Balance Sheets. The revenues and costs recorded under the supply agreement included $48.7 million and $34.6 million in net hedging gains for the year ended December 31, 2015, and 2014, respectively and $3.9 million in net hedging losses for the year ended December 31, 2013.

WNRL. WNRL owns and operates certain logistics assets that consist of pipeline and gathering, terminalling, storage and transportation assets, providing related services to our refining segment in the Southwest, including approximately 685 miles of pipelines and approximately 8.2 million barrels of active storage capacity. The majority of WNRL's logistics assets are integral to the operations of the El Paso and Gallup refineries.

WNRL also owns a wholesale business that operates primarily in the Southwest. WNRL's wholesale business includes the operations of several lubricant and bulk petroleum distribution plants and a fleet of crude oil, 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.

Retail. We operate retail networks located in the Southwest region ("Southwest Retail") and the Upper Great Plains region of the U.S. ("SuperAmerica"). Each of our retail networks sell various grades of gasoline, diesel fuel, convenience store merchandise and beverage and food products to the general public through retail convenience stores.

Southwest Retail obtains the majority of its gasoline and diesel fuel supply from WNRL and purchases general merchandise and beverage and food products from various third-party suppliers. At December 31, 2015, Southwest Retail operated 258 service stations and convenience stores or kiosks located in Arizona, Colorado, New Mexico and Texas compared to 230 and 228 service stations and convenience stores or kiosks at December 31, 2014 and 2013, respectively. The additional stores were added primarily under various operating and capital leases. At December 31, 2015, Southwest Retail operated 52 cardlocks located in Arizona, California and New Mexico compared to 50 and 53 cardlocks at December 31, 2014 and 2013, respectively.

As of December 31, 2015, SuperAmerica included the operations of 168 retail convenience stores and supported 109 franchised retail convenience stores. Our St. Paul Park refinery supplies the majority of the gasoline and diesel sold through these convenience stores.

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 and depreciation and amortization. The refining segment also includes costs related to periodic maintenance turnaround activities. Cost of products sold includes net realized and unrealized gains and losses related to our commodity hedging activities and reflects current costs adjusted, where appropriate, for LIFO and LCM inventory adjustments. Intersegment revenues are reported at prices that approximate market.

Activities of our business that are not included in the three segments mentioned above are included in the "Other" category. These activities consist primarily of corporate staff operations and other items that are not specific to the normal business of any one of our three reportable segments. We do not allocate certain items of other income and expense, including income taxes, to the individual segments. WNRL is primarily a pass-through entity 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 property, plant and equipment and other long-term assets.

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Disclosures regarding our reportable segments with reconciliations to consolidated totals for the three years ended December 31, 2015, are presented below:



	Year Ended
	December 31, 2015			December 31, 2014			December 31, 2013
	(In thousands)
Operating Results:
Refining (2) (3)
Net sales	$	8,777,196		$	14,196,564		$	9,499,363
Intersegment eliminations	3,072,806			4,291,617			3,506,335
Net refining sales to external customers	5,704,390			9,904,947			5,993,028
WNRL (2)
Net sales	2,599,867			3,501,888			3,407,128
Intersegment eliminations	786,324			1,011,575			882,533
Net WNRL sales to external customers	1,813,543			2,490,313			2,524,595
Retail (3)
Net sales	2,279,737			2,776,782			1,588,314
Intersegment eliminations	10,634			19,575			21,069
Net retail sales to external customers	2,269,103			2,757,207			1,567,245
Other (3)
Other revenue, net	—			1,106			1,202
Intersegment eliminations	—			—			—
Net other sales to external customers	—			1,106			1,202

Consolidated net sales to external customers	$	9,787,036		$	15,153,573		$	10,086,070

Operating income (loss)
Refining (1) (2) (3)	$	900,513		$	1,107,103		$	680,969
WNRL (2)	86,713			70,295			(42,460		)
Retail (3)	41,279			42,087			16,332
Other (3)	(98,380		)	(122,972		)	(82,968		)
Operating income	930,125			1,096,513			571,873
Other income (expense), net	(91,739		)	(93,837		)	(118,394		)
Consolidated income before income taxes	$	838,386		$	1,002,676		$	453,479

Depreciation and amortization
Refining (2) (3)	$	150,580		$	146,462		$	84,131
WNRL (2)	26,912			20,187			16,515
Retail (3)	23,197			19,869			13,245
Other (3)	4,602			4,048			3,957
Consolidated depreciation and amortization	$	205,291		$	190,566		$	117,848

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	Year Ended
	December 31, 2015		December 31, 2014		December 31, 2013
	(In thousands)
Capital expenditures
Refining (2) (3)	$	205,879	$	119,582	$	105,882
WNRL (2)	61,005		79,172		84,825
Retail (3)	20,895		22,056		9,771
Other (3)	3,084		2,461		5,199
Consolidated capital expenditures	$	290,863	$	223,271	$	205,677

Total assets
Refining (2) (3) (including $1,267,455 of goodwill)	$	4,133,402	$	4,238,787	$	4,242,082
WNRL (2)	456,938		439,471		434,761
Retail (3) (including $21,988, $21,988 and $29,588 of goodwill, respectively)	444,382		417,269		391,146
Other (3)	798,671		546,659		407,110
Consolidated total assets	$	5,833,393	$	5,642,186	$	5,475,099

(1)

The effect of our economic hedging activity is included within operating income of our refining segment as a component of cost of products sold. The cost of products sold within our refining segment included $43.5 million and $289.8 million in net realized and unrealized economic hedging gains for the years ended December 31, 2015 and 2014, respectively, and $1.0 million in net realized and unrealized economic hedging losses for the year ended December 31, 2013.

(2)

WNRL's financial data includes its historical financial results and an allocated portion of corporate general and administrative expenses, previously reported as Other, for the three years ended December 31, 2015. WNRL operating results include activity of the TexNew Mex Pipeline System that was previously recorded within our refining segment. The WNRL Predecessor includes the historical financial results of the TexNew Mex Pipeline System. The information contained herein for WNRL has been retrospectively adjusted, to include the historical results of the TexNew Mex Pipeline System, for periods between the Offering and the effective date of the transaction.


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

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, which we consider Level 1 assets and liabilities, approximated their fair values at December 31, 2015, and December 31, 2014, 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 $70.1 million and $70.0 million consisting of short-term money market deposits and commercial paper were included in the Consolidated Balance Sheets as of December 31, 2015 and 2014, respectively.

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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.

The following tables represent our assets and liabilities for our commodity hedging contracts measured at fair value on a recurring basis as of December 31, 2015 and 2014, and the basis for that measurement:



	Carrying Value at December 31, 2015			Fair Value Measurement at December 31, 2015 Using								Netting Adjustments			Recorded Value at December 31, 2015
	Carrying Value at December 31, 2015			Level 1		Level 2			Level 3			Netting Adjustments			Recorded Value at December 31, 2015
	(In thousands)
Gross financial assets:
Other current assets	$	95,062		$	—	$	95,062		$	—		$	(16,937	)	$	78,125
Other assets	11,881			—		11,881			—			—			11,881
Gross financial liabilities:
Accrued liabilities	(21,454		)	—		(15,698		)	(5,756		)	11,181			(10,273		)
Other long-term liabilities	(5,756		)	—		(5,756		)	—			5,756			—
	$	79,733		$	—	$	85,489		$	(5,756	)	$	—		$	79,733



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

Commodity hedging contracts designated as Level 3 financial assets consisted of 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 them 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. Fair value adjustments referred to as credit valuation adjustments ("CVA") are included in the carrying amounts of commodity hedging contracts. 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, 2015 and 2014.



	December 31,
	2015			2014
	(In thousands)
Asset (liability) balance at beginning of period	$	330		$	(1,935	)
Change in fair value of Level 3 trades open at the beginning of the period	—			3,240
Fair value of trades entered into during the period	(5,756		)	(1,437		)
Fair value reclassification from Level 3 to Level 2	(330		)	462
Asset (liability) balance at end of period	$	(5,756	)	$	330

A hypothetical change of 10% to the estimated future cash flows attributable to our Level 3 commodity price swaps would result in a $0.6 million change in the estimated fair value.

As of December 31, 2015 and 2014, the carrying amount and estimated fair value of our debt was as follows:



	December 31,
	2015		2014
	(In thousands)
Western obligations:
Carrying amount	$	874,620	$	877,241
Fair value	867,178		878,360
NTI obligations:
Carrying amount	$	353,893	$	354,692
Fair value	360,500		351,313
WNRL obligations:
Carrying amount	$	438,928	$	269,000
Fair value	439,000		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,
	2015		2014
	(In thousands)
Refined products (1)	$	201,928	$	257,476
Crude oil and other raw materials	288,403		318,565
Lubricants	14,996		14,265
Retail store merchandise	42,211		38,931
Inventories	$	547,538	$	629,237


(1)	Includes $14.5 million and $18.2 million of inventory valued using the FIFO valuation method at December 31, 2015 and 2014, respectively.

As of December 31, 2015 and 2014, refined products valued under the LIFO method and crude oil and other raw materials totaled 10.0 million barrels and 9.3 million barrels, respectively. At December 31, 2015 and 2014, the excess of the

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

current cost of our crude oil, refined product and other feedstock and blendstock inventories over LIFO cost was $198.4 million and $28.4 million, respectively. The non-cash impact of changes in our LIFO reserves decreased our cost of products sold for the years ended December 31, 2015 and 2014, by $170.0 million and $222.0 million, respectively, and increased our cost of products sold for the year ended December 31, 2013, by $65.4 million.

In order to state our inventories at market values that were lower than our LIFO costs, we reduced the carrying values of our inventory through non-cash LCM inventory adjustments of $175.1 million and $78.6 million at December 31, 2015 and 2014, respectively.

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



	Year Ended December 31,
	2015			2014		2013
	(In thousands, except per share amount)
Increase (decrease) in operating income	$	(16,111	)	$	1,097	$	3,207
Increase (decrease) in net income	(11,808		)	777		2,119
Increase (decrease) in earnings per diluted share	$	(0.12	)	$	0.01	$	0.02

Average LIFO cost per barrel of our refined products and crude oil and other raw materials inventories as of December 31, 2015 and 2014, was as follows:



	December 31,
	2015					2014
	Barrels	LIFO Cost		Average LIFO Cost Per Barrel		Barrels	LIFO Cost		Average LIFO Cost Per Barrel
	(In thousands, except cost per barrel)
Refined products	3,536	$	259,722	$	73.45	3,707	$	283,333	$	76.43
Crude oil and other	6,490	391,237		60.28		5,577	355,470		63.74
	10,026	$	650,959	64.93		9,284	$	638,803	68.81

6. Prepaid Expenses

Prepaid expenses were as follows:



	December 31,
	2015		2014
	(In thousands)
Prepaid crude oil and other raw materials inventories	$	23,793	$	55,223
Prepaid insurance and other	49,420		33,192
Prepaid expenses	$	73,213	$	88,415

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7. Other Current Assets

Other current assets were as follows:



	December 31,
	2015		2014
	(In thousands)
Unrealized hedging gains	$	78,125	$	79,722
Material and chemical inventories	54,053		49,433
Excise and other taxes receivable	21,801		17,461
Exchange and other receivables	15,749		5,509
Other current assets	$	169,728	$	152,125

8. Equity Method Investment

We own a 17% common equity interest in MPL. The carrying value of this equity method investment was $97.5 million and $96.1 million at December 31, 2015 and 2014, respectively.

Summarized financial information for MPL for the years ended December 31, 2015, 2014 and 2013 and as of December 31, 2015 and 2014, was as follows:



	Year Ended December 31,
	2015		2014		2013
	(In thousands)
Revenues	$	206,195	$	184,712	$	24,082
Operating costs and expenses	88,909		141,250		12,524
Income from operations	117,286		43,462		11,558
Net income	96,485		22,821		9,524
Net income attributable to MPL unitholders	86,832		13,168		8,174



	December 31, 2015		December 31, 2014
	(In thousands)
Current assets	$	24,020	$	9,578
Noncurrent assets	441,825		450,662
Total assets	$	465,845	$	460,240

Current liabilities	$	17,658	$	21,887
Noncurrent liabilities	—		—
Total liabilities	$	17,658	$	21,887

Equity	$	448,187	$	438,353

As of December 31, 2015 and 2014, respectively, the carrying amount of the equity method investment was $21.3 million and $21.6 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 $13.1 million, $7.5 million and $2.6 million, respectively, for the years ended December 31, 2015, 2014 and 2013. Equity income from MPL was $14.8 million, $2.2 million and $1.4 million, respectively, for the years ended December 31, 2015, 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,
	2015			2014
	(In thousands)
Refinery facilities and related equipment	$	2,348,663		$	2,217,013
Pipelines, terminals and transportation equipment	533,040			369,080
Retail facilities and related equipment	328,419			288,338
Wholesale facilities and related equipment	61,133			57,158
Corporate	50,812			48,871
	3,322,067			2,980,460
Accumulated depreciation	(1,016,896		)	(827,271		)
Property, plant and equipment, net	$	2,305,171		$	2,153,189

Depreciation expense was $201.2 million, $187.1 million and $114.7 million for the years ended December 31, 2015, 2014 and 2013, respectively. Depreciation expense for the years ended December 31, 2015, 2014 and 2013, included $78.7 million, $76.5 million and $10.7 million, respectively, of depreciation related to NTI.

10. Goodwill

At December 31, 2015 and 2014, we had goodwill of $1,289.4 million, respectively, relating to the 2013 NTI Acquisition. Declines in NTI's market capitalization could be an 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, 2015							December 31, 2014							Weighted Average Amortization Period (Years)
	Gross Carrying Value		Accumulated Amortization			Net Carrying Value		Gross Carrying Value		Accumulated Amortization			Net Carrying Value		Weighted Average Amortization Period (Years)
	(In thousands)
Amortizable assets:
Licenses and permits	$	20,427	$	(13,729	)	$	6,698	$	20,427	$	(12,148	)	$	8,279	4.3
Customer relationships	7,551		(3,921		)	3,630		7,551		(3,366		)	4,185		6.5
Rights-of-way and other	6,839		(1,797		)	5,042		7,878		(3,613		)	4,265		7.8
	34,817		(19,447		)	15,370		35,856		(19,127		)	16,729
Unamortizable assets:
Franchise rights and trademarks	50,500		—			50,500		50,500		—			50,500
Liquor licenses	19,075		—			19,075		18,723		—			18,723
Intangible assets, net	$	104,392	$	(19,447	)	$	84,945	$	105,079	$	(19,127	)	$	85,952

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Intangible asset amortization expense was $2.9 million, $2.8 million and $2.8 million for the years ended December 31, 2015, 2014 and 2013, respectively, based upon estimates of useful lives ranging from 1 to 35 years. Estimated amortization expense for the next five fiscal years is as follows (in thousands):



2016	$	2,739
2017	2,798
2018	2,798
2019	2,130
2020	1,186

12. Other Assets, Net

Other assets, net of amortization, were as follows:



	December 31,
	2015		2014
	(In thousands)
Purchase agreement	$	16,067	$	—
Unrealized hedging gains	11,881		56,533
Cost method investment	7,872		7,884
Other	29,177		17,633
Other assets, net of amortization	$	64,997	$	82,050

13. Accrued and Other Long-Term Liabilities

Accrued liabilities were as follows:



	December 31,
	2015		2014
	(In thousands)
Payroll and related costs	$	77,482	$	70,949
Excise and other taxes	67,932		58,556
Professional and other	28,093		32,237
Property taxes	20,175		17,567
Interest	17,093		9,251
Margin and other customer deposits	17,059		17,142
Fair value of open commodity hedging positions, net	10,273		4,889
Environmental reserves	10,099		8,377
Banking fees and other financing	189		1,311
Income taxes	—		48,170
Accrued liabilities	$	248,395	$	268,449

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Other long-term liabilities were as follows:



	December 31,
	2015		2014
	(In thousands)
Unrecognized tax benefits	$	42,049	$	12,000
Retiree plan obligations and other	10,529		10,802
Environmental reserves	8,195		10,086
Asset retirement obligations	7,822		7,539
Fair value of open commodity hedging positions, net	—		1,400
Other long-term liabilities	$	68,595	$	41,827

The table below summarizes changes in our environmental liability accruals:



	December 31, 2014		Increase (Decrease)		Payments			December 31, 2015
	(In thousands)
Discounted liabilities	$	2,902	$	1,697	$	(966	)	$	3,633
Undiscounted liabilities	15,561		303		(1,203		)	14,661
Total environmental liabilities	$	18,463	$	2,000	$	(2,169	)	$	18,294

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.

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The following table reconciles the beginning and ending aggregate carrying amount of our AROs for the three years ended December 31, 2015:



	December 31,
	2015			2014			2013
	(In thousands)
Liability, beginning of period	$	7,539		$	7,327		$	5,088
Liabilities incurred	58			17			11
Liabilities acquired	—			—			1,786
Liabilities settled	(187		)	(313		)	(145		)
Accretion expense	412			508			587
Liability, end of period	$	7,822		$	7,539		$	7,327

Our ARO liability excludes $0.2 million and $0.1 million of ARO classified as other accrued liabilities as of December 31, 2015 and 2014, respectively.

15. Long-Term Debt

Long-term debt was as follows:



	December 31,
	2015			2014
	(In thousands)
Western obligations:
Revolving Credit Facility due 2019	$	—		$	—
Term Loan Credit Facility due 2020, net of unamortized financing costs of $9,442 and $11,382, respectively	529,558			533,118
6.25% Senior Unsecured Notes due 2021, net of unamortized financing costs of $4,938 and $5,877, respectively	345,062			344,123
Total Western obligations	874,620			877,241
NTI obligations:
Revolving Credit Facility due 2018	—			—
7.125% Senior Secured Notes, due November 2020, net of unamortized financing costs of $2,032 and $2,345 and unamortized premium of $5,925 and $7,037, respectively	353,893			354,692
Total NTI obligations	353,893			354,692
WNRL obligations:
Revolving Credit Facility due 2018	145,000			269,000
7.5% Senior Notes due 2023, net of unamortized financing costs of $6,072 for 2015	293,928			—
Total WNRL obligations	438,928			269,000
Unamortized financing costs, revolving credit facilities	(17,047		)	(20,768		)
Long-term debt	1,650,394			1,480,165
Current portion of long-term debt	(5,500		)	(5,500		)
Long-term debt, net of current portion	$	1,644,894		$	1,474,665

As of December 31, 2015, annual long-term debt maturities through 2017 are $5.5 million. In 2018, 2019 and 2020, long-term debt maturities are $150.5 million, $5.5 million and $867.0 million, respectively. Thereafter, total long-term debt maturities are $650.0 million.

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Interest expense and other financing costs were as follows:



	Year Ended December 31,
	2015			2014			2013
	(In thousands)
Contractual interest:
Western obligations	$	45,248		$	51,114		$	42,768
NTI obligations	24,474			20,342			4,883
WNRL obligations	21,079			1,096			—
	90,801			72,552			47,651
Amortization of loan fees	7,561			7,786			6,541
Amortization of original issuance discount	—			7,352			15,502
Other interest expense	9,059			11,717			6,835
Capitalized interest	(1,818		)	(2,345		)	(1,948		)
Interest expense and other financing costs	$	105,603		$	97,062		$	74,581

We amortize original issue discounts and financing fees using the effective interest method over the respective term of the debt. Our creditors have no recourse to the assets owned by either of NTI or WNRL, and the creditors of NTI and WNRL have no recourse to our assets or those of our other subsidiaries.

Western Obligations

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, 2015, we had no direct borrowings under the Revolving Credit Agreement, and we had net availability under the Western 2019 Revolving Credit Facility of $247.5 million. This availability is net of $64.4 million in outstanding letters of credit.

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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 of $1.4 million until September 30, 2020, 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.

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 occur 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.

Our payment of dividends is limited under the terms of the Western 2019 Revolving Credit Facility, the Western 2021 Indenture and the Western 2020 Term Loan Credit Facility, and in part, depends on our ability to satisfy certain financial

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covenants. Note guarantors will be released if they cease to be a Restricted Subsidiary as the result of a transaction permitted under the terms of the indenture, including through the disposition of capital stock of the guarantor.

NTI Obligations

Revolving Credit Facility

On September 29, 2014, certain subsidiaries of 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 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 LLC ("NTI LLC") and certain of its subsidiaries that are borrowers thereunder, 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% 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, 2015, the availability under the NTI Revolving Credit Facility was $152.7 million. This availability is net of $46.3 million in outstanding letters of credit. There were no borrowings under the NTI Revolving Credit Facility at December 31, 2015.

7.125% Secured Notes

On November 8, 2012, 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 by an additional $75.0 million in principal value at a premium of $4.2 million. This additional 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.

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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. On February 11, 2015, WNRL repaid its outstanding direct borrowings under the WNRL Revolving Credit Facility with a portion of the proceeds from the issuance of its 7.5% Senior Notes, discussed below. On October 30, 2015, WNRL borrowed $145.0 million under the WNRL Revolving Credit Facility to partially fund the purchase of the TexNew Mex Pipeline System from Western.

The WNRL Revolving 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. As of December 31, 2015, the availability under the WNRL Revolving Credit Facility was $154.3 million, net of $145.0 million direct borrowings and $0.7 million in outstanding letters of credit.

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 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 7.5% Senior 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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

16. Income Taxes

The following is an analysis of our consolidated income tax expense for the three years ended December 31, 2015:



	Year Ended December 31,
	2015			2014		2013
	(In thousands)
Current:
Federal	$	228,457		$	187,320	$	193,719
State	30,222			32,581		25,578
Total current	258,679			219,901		219,297
Deferred:
Federal	(27,876		)	63,182		(62,954		)
State	(6,848		)	9,521		(2,418		)
Total deferred	(34,724		)	72,703		(65,372		)
Provision for income taxes	$	223,955		$	292,604	$	153,925

We paid income tax, net of refunds, of $283.3 million, $228.0 million and $223.6 million for the years ended December 31, 2015, 2014 and 2013, 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, 2015:



	Year Ended December 31,
	2015			2014			2013
	(In thousands)
Taxes at the federal statutory rate	$	293,435		$	350,937		$	158,718
State income taxes, net of federal tax benefit (2)	13,637			31,477			17,666
Valuation allowance for state net operating losses	—			(2,887		)	(2,776		)
Domestic Activity Production deduction	(14,000		)	(11,900		)	(12,763		)
Non-controlling interests	(70,214		)	(50,044		)	(8,383		)
Federal tax credit for production of ultra low sulfur diesel	—			(15,486		)	—
Federal tax credit for increasing research activities (1)	38			(4,522		)	(999		)
Other, net	1,059			(4,971		)	2,462
Total income tax expense	$	223,955		$	292,604		$	153,925


(1)	The federal tax credit for increasing research activities includes $0.04 million, $4.5 million and $1.0 million in unrecognized tax benefits for the years ended December 31, 2015, 2014 and 2013, respectively.


(2)	State income taxes, net of federal tax benefit, include $5.0 million and $0.8 million in unrecognized tax benefits for the years ended December 31, 2015 and 2014, respectively.

The effective tax rates for 2015, 2014 and 2013 were 26.7%, 29.2% and 33.9%, respectively, as compared to the federal statutory rate of 35% in all years.

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The following is a reconciliation of unrecognized tax benefits for the three years ended December 31, 2015:



	December 31,
	2015			2014			2013
	(In thousands)
Unrecognized tax benefits at beginning of year	$	13,762		$	10,571		$	9,572
Increases related to current year tax positions	1,100			1,500			999
Increases related to prior year tax positions	26,329			3,845			—
Decreases related to prior year tax positions	(1,017		)	(2,154		)	—
Decreases resulting from the expiration of the statute of limitations	—			—			—
Unrecognized tax benefits at end of year	$	40,174		$	13,762		$	10,571

We recorded unrecognized tax benefits as of December 31, 2015 of $40.2 million, of which $26.4 million would affect our effective tax rate if recognized. We believe that it is reasonably possible that a decrease of up to $16.9 million in unrecognized tax benefits related to federal exposures may be necessary within the coming year. We had accrued interest or penalties of $1.7 million with respect to the unrecognized tax benefit.

The Internal Revenue Service (the "IRS") has finalized examinations of our tax years ending December 31, 2007, 2008, 2009, 2010 and 2011. We are subject to examination by the IRS for tax years ending December 31, 2012, or after, and by the major state tax jurisdictions (Arizona, California, Maryland, Minnesota, New Mexico, Texas and Virginia) for tax years ending December 31, 2011, or after.

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



	December 31,
	2015									2014
	Assets			Liabilities			Net			Assets			Liabilities			Net
	(In thousands)
Inventories	$	—		$	(28,411	)	$	(28,411	)	$	—		$	(41,713	)	$	(41,713	)
Stock-based compensation	1,614			—			1,614			1,468			—			1,468
Property, plant and equipment	—			(261,476		)	(261,476		)	—			(298,100		)	(298,100		)
Investment in WNRL	77,824			—			77,824			81,453			—			81,453
Investment in NTI				(81,789		)	(81,789		)	—			(64,013		)	(64,013		)
Postretirement obligations	2,595			—			2,595			3,175			—			3,175
Commodity hedging activities	—			(33,260		)	(33,260		)	—			(50,850		)	(50,850		)
Environmental and retirement obligations	3,742			—			3,742			3,489			—			3,489
Other, net	6,247			—			6,247			10,282			—			10,282
Net operating loss and tax credit carryforwards	20,828			—			20,828			20,828			—			20,828
Valuation allowance	(20,828		)	—			(20,828		)	(20,828		)	—			(20,828		)
Net deferred taxes	$	92,022		$	(404,936	)	$	(312,914	)	$	99,867		$	(454,676	)	$	(354,809	)

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

At December 31, 2015, 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	$	(6,108	)	$	(260	)	2023
Virginia and Maryland	(17,860		)	(760		)	2024
Virginia and Maryland	(522		)	(22		)	2026
Virginia and Maryland	(32,417		)	(1,380		)	2027
Virginia and Maryland	(59,019		)	(2,512		)	2028
Virginia and Maryland	(102,088		)	(4,345		)	2029
Virginia and Maryland	(137,669		)	(5,860		)	2030
Virginia and Maryland	(134,468		)	(5,689		)	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, 2015. There was no change to our valuation allowance during the year ended December 31, 2015.

17. Retirement Plans

We fully recognize the obligations associated with our retiree healthcare and other postretirement plans and NTI's single-employer defined benefit cash balance plan 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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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

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:



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



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

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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, 2015:



	Cash Balance Plan						Retiree Medical Plan
	As of December 31,
	2015			2014			2015			2014
	(In thousands)
Benefit obligation at beginning of period	$	6,965		$	4,560		$	3,098		$	2,113
Service cost	2,326			2,054			315			231
Interest cost	366			327			135			116
Actuarial (gain) loss	(151		)	612			(697		)	675
Plan amendments	—			—			(2,463		)	—
Plan participants' contributions	—			—			26			18
Benefits paid	(579		)	(588		)	(69		)	(55		)
Benefit obligation at end of period	$	8,927		$	6,965		$	345		$	3,098
Fair value of plan assets at beginning of period	$	4,319		$	4,566		$	—		$	—
Employer contribution	2,200			200			43			37
Actual return on plan assets	(8		)	141			—			—
Benefits paid	(579		)	(588		)	(69		)	(55		)
Plan participants' contributions	—			—			26			18
Fair value of plan assets at end of period	$	5,932		$	4,319		$	—		$	—
Current liabilities	—			—			61			69
Non-current liabilities	2,995			2,646			284			3,029
Unfunded status recognized in the consolidated balance sheets	$	2,995		$	2,646		$	345		$	3,098
Accumulated benefit obligation	$	8,927		$	6,965		$	345		$	3,098



	Cash Balance Plan									Retiree Medical Plan
	As of December 31,
	2015			2014			2013			2015			2014			2013
	(In thousands)
Net periodic benefit cost includes:
Service cost	$	2,326		$	2,054		$	1,914		$	315		$	231		$	288
Interest cost	366			327			169			135			116			106
Expected return on assets	(165		)	(218		)	(115		)	—			—			—
Recognized net actuarial loss	22			—			40			32			—			—
Amortization of prior service cost	24			25			—			137			137			161
Net periodic benefit cost	$	2,573		$	2,188		$	2,008		$	619		$	484		$	555
Changes recognized in other comprehensive income:
Prior service cost amortization	$	(24	)	$	(24	)	$	—		$	(137	)	$	(137	)	$	—
Recognized net actuarial loss	—			—			—			(32		)	—			—
Net prior service credit	—			—			—			(2,463		)	—			—
Net actuarial loss (gain)	22			687			(354		)	(697		)	675			—
Pre-tax unrecognized net loss included in accumulated other comprehensive income at end of period	$	(2	)	$	663		$	(354	)	$	(3,329	)	$	538		$	—

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	Cash Balance Plan						Retiree Medical Plan
	As of December 31,
	2015		2014		2013		2015		2014		2013
Weighted average assumptions used to determine benefit obligations at December 31:
Discount rate	4.50	%	4.00	%	5.00	%	2.50	%	4.00	%	5.00	%
Rate of compensation increase	3.00		3.00		4.00		N/A		N/A		N/A
Weighted average assumptions used to determine net periodic benefit cost:
Discount rate	4.00		5.00		4.00		4.00		5.00		4.00
Expected long-term return on assets	3.75		4.75		4.25		N/A		N/A		N/A
Rate of compensation increase	3.00		4.00		4.00		N/A		N/A		N/A

The health care cost trend rate for the Retiree Medical Plan for 2015 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 $2.2 million, $0.2 million and $2.5 million were made during the period ended December 31, 2015, 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 $2.5 million during the year ended December 31, 2016.

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



	Cash Balance Plan		Retiree Medical Plan
2016	$	343	$	61
2017	391		65
2018	531		46
2019	695		49
2020	859		31
2021 - 2025	6,495		126

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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 4.43% and 4.09% at December 31, 2015 and 2014, respectively, to determine the benefit obligation, the components of the postretirement obligation were:



	As of December 31,
	2015			2014
	(In thousands)
Benefit obligation at beginning of year	$	6,735		$	5,793
Service cost	124			92
Interest cost	251			264
Benefits paid	(182		)	(206		)
Actuarial (gain) loss	(1,035		)	792
Benefit obligation at end of year	$	5,893		$	6,735
Unfunded status	$	(5,893	)	$	(6,735	)
Current liabilities	$	(202	)	$	(300	)
Non-current liabilities	(5,691		)	(6,435		)
Unfunded status recognized in the consolidated balance sheets	$	(5,893	)	$	(6,735	)



	Year Ended December 31,
	2015			2014		2013
	(In thousands)
Net periodic benefit cost includes:
Service cost	$	124		$	92	$	115
Interest cost	251			264		254
Amortization of net actuarial loss	23			20		34
Net periodic benefit cost	$	398		$	376	$	403
Pre-tax unrecognized net loss included in accumulated other comprehensive gain at beginning of year	$	1,596		$	784	$	1,670
Net actuarial (gain) loss	(1,035		)	792		(852		)
Amortization of net actuarial loss	(23		)	20		(34		)
Pre-tax unrecognized net loss included in accumulated other comprehensive gain at end of year	$	538		$	1,596	$	784

The weighted average discount rates used to determine net periodic benefit costs were 4.09%, 4.88% and 4.14% for 2015, 2014 and 2013, respectively. The following benefit payments (in thousands) are expected to be paid in the year indicated:



2016	$	206
2017	211
2018	218
2019	226
2020	238
2021 - 2025	1,346

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The health care cost trend rate for the plan covering El Paso employees for 2015 and future years is capped at 4.00%. The health care cost trend rate for the plan covering Yorktown employees for 2015 is 4.50% trending to 4.50% in 2016. 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	$	(53	)
Effect on accumulated benefit obligation	19		(604		)


(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,
	2015			2014			2013
	(In thousands)
Beginning of period balance	$	(1,291	)	$	(350	)	$	(1,174	)
Amortization of net prior service cost	83			63			—
Net prior service credit	945			—			—
Reclassification of loss to income	50			21			47
Pension plan termination adjustment	—			—			217
Actuarial gain (loss)	1,267			(1,320		)	978
Income tax	(403		)	295			(418		)
End of period balance	$	651		$	(1,291	)	$	(350	)

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. 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 $10.0 million, $9.1 million and $8.5 million in connection with this plan for the years ended December 31, 2015, 2014 and 2013, 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-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 $7.4 million, $7.1 million and $6.1 million for the year ended December 31, 2015, 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 2015, 2014 and 2013, 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

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gasoline and distillate production. The physical volumes are not exchanged; these contracts are net settled with cash. These hedging activities 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.



	Year Ended December 31,
	2015			2014		2013
	(In thousands)
Economic hedging activities recognized within cost of products sold:
Realized hedging gain, net	$	93,699		$	95,331	$	15,868
Unrealized hedging gain (loss), net	(50,233		)	194,423		(16,898		)
Total hedging gain (loss), net	$	43,466		$	289,754	$	(1,030	)



	December 31, 2015			December 31, 2014
	(In thousands)
Open commodity hedging instruments (bbls):
Crude futures	4,593			(864		)
Refined product price and crack spread swaps	(5,645		)	(8,781		)
Total open commodity hedging instruments	(1,052		)	(9,645		)

Fair value of outstanding contracts, net:
Other current assets	$	78,125		$	79,722
Other assets	11,881			56,533
Accrued liabilities	(10,273		)	(4,889		)
Other long-term liabilities	—			(1,400		)
Fair value of outstanding contracts - unrealized gain, net	$	79,733		$	129,966

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

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The following table presents offsetting information regarding Western's commodity hedging contracts as of December 31, 2015 and 2014:



	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, 2015	Gross Amounts of Recognized Assets (Liabilities)			Gross Amounts Offset in the Consolidated Balance Sheet
	(In thousands)
Gross financial assets:
Other current assets	$	95,062		$	(16,937	)	$	78,125
Other assets	11,881			—			11,881
Gross financial liabilities:
Accrued liabilities	(21,454		)	11,181			(10,273		)
Other long-term liabilities	(5,756		)	5,756			—
	$	79,733		$	—		$	79,733



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

Our commodity hedging activities are initiated within guidelines established by management and approved by our board of directors. 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, 2015, 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 $14.61 to $17.13 per contract. Settlement prices for our distillate crack spread swaps range from $7.08 to $12.19 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
	2016		2017		2018
Inventory positions (futures and swaps):
Crude oil and refined products - net long positions	3,982		—		—
Natural gas - net long positions	793		—		—
Refined product positions (crack spread swaps):
Distillate - net short positions	(2,247	)	(1,305	)	—
Unleaded gasoline - net short positions	(2,275	)	—		—

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19. Stock-Based Compensation

The Western Refining 2006 Long-Term Incentive Plan (the “2006 LTIP”) and the Amended and Restated 2010 Incentive Plan of Western Refining, Inc. (the “2010 Incentive Plan”) allow for restricted share unit awards ("RSU") among other forms of awards. As of December 31, 2015, there were 19,856 and 2,730,269 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 vesting period on a straight-line basis. Effective March 25, 2015, our board of directors approved administrative amendments to the 2010 Incentive Plan.

As of December 31, 2015, there were 399,214 unvested RSUs 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,
	2015		2014		2013
	(In thousands)
Direct operating expenses	$	—	$	—	$	61
Selling, general and administrative expenses	4,231		4,338		5,428
Total stock compensation expense	$	4,231	$	4,338	$	5,489

As of December 31, 2015, the aggregate fair value at grant date of outstanding RSUs was $14.9 million. The aggregate intrinsic value of RSUs was $14.2 million. The unrecognized compensation cost of outstanding RSUs was $10.7 million. Unrecognized compensation cost for RSUs will be recognized over a weighted average period of approximately 3.43 years.

The excess tax benefit related to the RSUs that vested during the year ended December 31, 2015 was $0.9 million using a statutory blended rate of 38.1%. The aggregate fair value at the grant date of the RSUs that vested during the year ended December 31, 2015 was $3.8 million. The related aggregate intrinsic value of these RSUs was $6.1 million at the vesting date.

The excess tax benefit related to the RSUs 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 RSUs 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 RSUs and restricted shares was $7.1 million and $0.1 million, respectively, at the vesting date.

The excess tax benefit related to the RSUs 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 RSUs and restricted shares that vested during the year ended December 31, 2013 was $3.2 million and $4.1 million, respectively. The related aggregate intrinsic value of these RSUs and restricted shares was $5.6 million and $23.8 million, respectively, at the vesting date.

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The following table summarizes our RSU and restricted share activity for the three years ended December 31, 2015:



	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, 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		—		—
Awards granted	155,828		48.26		—		—
Awards vested	(131,165	)	29.19		—		—
Awards forfeited	(6,144	)	36.76		—		—
Not vested at December 31, 2015	399,214		37.43		—		—

NTI 2012 Long-Term Incentive Plan

Approximately 7.4 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. The NTI LTIP permits the award of unit options, restricted units, phantom units, distribution equivalent rights, unit appreciation rights and other awards that derive their value from the market price of NTI's common units. As of December 31, 2015, approximately 1.0 million units were outstanding under the NTI LTIP. NTI recognizes the expense on all NTI LTIP awards ratably from the grant date until all units become unrestricted or vest. Awards generally vest ratably over a three-year period beginning on the award's first anniversary date. Compensation expense related to these restricted units is based on the grant date fair value as determined by the closing market price on the grant date, reduced by the fair value of estimated forfeitures. For awards to employees, NTI estimates a forfeiture rate that is subject to revision depending on the actual forfeiture experience.

NTI incurred $10.3 million, $14.0 million and $0.4 million of unit-based compensation expense for the years ended December 31, 2015, 2014 and 2013, respectively.

Restricted Common Units

As of December 31, 2015, NTI had 0.2 million restricted common units outstanding. Upon vesting, these common units will no longer be restricted. All restricted common units participate in distributions on an equal basis with NTI common units and must be paid no later than 30 days after the distribution date to common unitholders. For restricted common unit awards outstanding at December 31, 2015, 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. NTI has one restricted common unit award with a clause stating distributions are to be accrued until the underlying units vest, at which time the accrued distributions applicable to those units will be paid to the award holder. The accrued distributions on that award at December 31, 2015 and 2014, were $0.7 million and $0.4 million, respectively.

Phantom Common Units

Service-based Awards

During 2014, NTI began awarding service-based phantom common units to key employees. As of December 31, 2015, NTI had 0.6 million service-based phantom common units outstanding. Upon vesting, NTI may settle these units in NTI common units or cash at the discretion of NTI's board of directors or its Compensation Committee. Like the restricted common units, the phantom common units participate in distributions on an equal basis with common units. However, distributions on phantom common units are accrued until the underlying units vest at which time the distributions are paid in cash. In the event that unvested phantom common units are forfeited or canceled, any accrued distributions on the underlying units are forfeited by the grantee. As of December 31, 2015 and 2014, NTI had $2.5 million and $0.8 million, respectively, in accrued service-

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based phantom common unit distributions included in accrued liabilities and other liabilities in the Consolidated Balance Sheets. For phantom common unit awards outstanding at December 31, 2015, the forfeiture rates on NTI LTIP awards ranged from zero to 20%, depending on the employee classification.

Performance-based Phantom Units

In January 2015, NTI granted 0.3 million Performance-based Phantom Units ("NTI Performance LTIPs"), under the NTI LTIP. Assuming a threshold EBITDA is achieved, participants are entitled to an award under the NTI Performance LTIPs based on NTI’s achievement of two criteria compared to the performance peer group over the performance period: (a) return on capital employed, referred to as a performance condition and (b) total unitholder return, referred to as a market condition. NTI accounts for the performance conditions and market conditions in each NTI Performance LTIPs as separate awards. Each of the performance condition awards and market condition awards represent the right to receive NTI common units or cash, or a combination of both, at the discretion of NTI's board of directors or its Compensation Committee, at the end of a three-year performance period, in an amount ranging from 0% to 200% of the original number of units granted depending on NTI’s achievement of the performance conditions and market conditions, respectively.

Performance Condition Awards. The 0.3 million NTI Performance LTIPs include 0.2 million performance condition awards. The fair value of performance condition awards is estimated using the market price of NTI's common units on the grant date and NTI management's assessment of the probability of the number of performance condition awards that will ultimately be awarded. The estimated fair value of these performance condition awards is amortized over a three-year vesting period using the straight-line method. On a quarterly basis, NTI estimates the ultimate payout percentage, relative to target, and adjusts compensation expense accordingly. At December 31, 2015, NTI estimates that 200% of the target unit count will be achieved at the end of the vesting term.

Market Condition Awards. The 0.3 million NTI Performance LTIPs include 0.1 million market condition awards. The estimated fair value for market condition awards is estimated using a Monte Carlo simulation model as of the grant date and the related expense is amortized over a three-year vesting period using the straight-line method. The compensation expense relating to the market condition awards is determined at the award's date and expensed ratably at a fixed rate over the vesting term. However, for purposes of the phantom common unit activity table below, NTI estimates at December 31, 2015, that 88.2% of the target unit count will be achieved at the end of the vesting term.

Expected volatilities are based on the historical volatility over the most recent three-year period. The risk-free rate is based on the U.S. Treasury yield curve in effect at the date of valuation. The assumptions used in the Monte Carlo simulation used to value NTI's market condition awards as of December 31, 2015, are presented below:



Expected volatility	34.10	%
Risk-free interest rate	0.84	%

As of December 31, 2015, NTI had $1.0 million in accrued performance-based phantom common unit distributions included in accrued liabilities in the Consolidated Balance Sheet.

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



	Restricted Units				Phantom Units
	Restricted Units				Service-Based Units		Performance-Based Units		Total		Weighted Average Grant Date Fair Value
	Number of Units		Weighted Average Grant Date Fair Value		Number of Units		Number of Units		Total		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		—		351,470		26.99
Awards vested	(390,109	)	25.99		(923	)	—		(923	)	27.01
Awards forfeited	(7,194	)	25.21		(12,854	)	—		(12,854	)	27.01
Not vested at December 31, 2014	396,109		24.73		337,693		—		337,693		26.99
Awards granted	1,026		24.90		447,880		182,354		630,234		23.37
Incremental performance units	—		—		—		80,418		80,418		23.06
Awards vested	(205,711	)	24.71		(112,446	)	—		(112,446	)	27.02
Awards forfeited	—		—		(91,245	)	(2,082	)	(93,327	)	26.22
Not vested at December 31, 2015	191,424		24.75		581,882		260,690		842,572		24.00

As of December 31, 2015 and 2014, the total unrecognized compensation cost for NTI LTIP units was $16.1 million and $12.1 million, respectively.

Western Refining Logistics, LP 2013 Long-Term Incentive Plan

The Western Refining Logistics, LP 2013 Long-Term Incentive Plan (the "WNRL LTIP") provides, among other awards, for grants of phantom units and distribution equivalent rights ("DERs"). As of December 31, 2015, 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 $2.0 million and $1.6 million for the years ended December 31, 2015 and 2014, respectively, 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, 2015, was $7.9 million. The aggregate intrinsic value of phantom units was $6.9 million. Total unrecognized compensation cost related to our non-vested phantom units totaled $6.2 million as of December 31, 2015, that is expected to be recognized over a weighted-average period of approximately 3.37 years.

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A summary of WNRL's unit award activity for the three years ended December 31, 2015, 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
Awards granted	72,005		28.33
Awards vested	(60,556	)	28.95
Awards forfeited	(11,913	)	30.78
Not vested at December 31, 2015	279,787		28.06

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.

On various dates between March 26, 2014, and June 16, 2014, we delivered an aggregate of 22,759,243 shares of common stock to Noteholders to satisfy the conversion of the aggregate principal amount of Western Convertible Notes. See Note 15, Long-Term Debt, for additional information.

Between July 18, 2012 and December 31, 2015, our board of directors has approved five 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 September of 2015 (the "September 2015 Program"). The November 2014 share repurchase program expired on November 3, 2015. The September 2015 program is scheduled to expire on December 31, 2016. Our common stock repurchase programs are subject to discontinuance by our board of directors at any time. As of December 31, 2015, we had not repurchased any shares of our common stock under the September 2015 Program.

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The following table summarizes our share repurchase activity for our 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, 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
Shares purchased during 2015	—	—		—	—		—	—		2,647,740	105,000
Shares purchased at December 31, 2015	6,786,365	$	200,000	4,617,798	$	135,111	4,976,039	$	200,000	4,140,614	$	164,222


(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, 2015, we had $200.0 million remaining in authorized expenditures under the September 2015 Program. Through December 31, 2015, we have purchased 20.5 million shares of our common stock under our share repurchase programs. As of February 19, 2016, we had $125.0 million remaining in authorized expenditures under the September 2015 Program.

Dividends

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.

The table below summarizes our 2015 cash dividend declarations, payments and scheduled payments through December 31, 2015:

Declaration Date

Record Date

Payment Date

Dividend per common share

Total Payment (in thousands)

First quarter

February 6

February 20

March 6

0.30

28,638

Second quarter

April 21

May 5

May 20

0.34

32,476

Third quarter

July 17

July 27

August 12

0.34

32,498

Fourth quarter

October 16

October 27

November 12

0.38

35,599

Total

129,211

On January 6, 2016, our board of directors approved a cash dividend for the first quarter of 2016 of $0.38 per share of common stock in an aggregate payment of $35.6 million that was paid on February 4, 2016 to holders of record on January 20, 2016.

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NTI Distributions

The table below summarizes NTI's 2015 quarterly distribution declarations, payments and scheduled payments through December 31, 2015:



Declaration Date	Record Date	Payment Date	Distribution per Unit
February 5	February 21	February 27	$	0.49
May 5	May 18	May 29	1.08
August 4	August 17	August 28	1.19
November 3	November 16	November 25	1.04
Total			$	3.80

On February 3, 2016, NTI declared a quarterly distribution of $0.38 per unit to common unitholders of record on February 12, 2016, payable on February 19, 2016.

WNRL Distributions

The table below summarizes WNRL's 2015 quarterly distribution declarations, payments and scheduled payments through December 31, 2015:



Declaration Date	Record Date	Payment Date	Distribution per Common and Subordinated Unit
January 30	February 13	February 23	$	0.3325
May 1	May 15	May 26	0.3475
July 31	August 14	August 24	0.3650
October 30	November 13	November 23	0.3825
			$	1.4275

In addition to its quarterly distributions, WNRL paid incentive distributions of $1.1 million for the year ended December 31, 2015 to Western as its General Partner and holder of its incentive distribution rights.

On February 1, 2016, WNRL declared a quarterly distribution of $0.3925 per unit to common unitholders of record on February 11, 2016, payable on February 26, 2016.

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 RSUs. 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 RSUs in the two-class method when calculating earnings per share.

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



	Year Ended December 31,
	2015			2014			2013
	(In thousands, except per share data)
Basic earnings per common share:
Allocation of earnings:
Net income attributable to Western Refining, Inc.	$	406,756		$	559,926		$	275,994
Distributed earnings	(129,211		)	(293,746		)	(52,489		)
Income allocated to participating securities	—			(3		)	(814		)
Distributed earnings allocated to participating securities	—			3			191
Undistributed income available to Western Refining, Inc.	$	277,545		$	266,180		$	222,882
Weighted average number of common shares outstanding (1)	94,899			90,708			82,248
Basic earnings per common share:
Distributed earnings per share	$	1.36		$	3.24		$	0.64
Undistributed earnings per share	2.92			2.93			2.71
Basic earnings per common share	$	4.28		$	6.17		$	3.35


(1)	Excludes the weighted average number of common shares outstanding associated with participating securities of 884 shares and 300,490 shares for the years ended December 31, 2014 and 2013, respectively.



	Year Ended December 31,
	2015		2014		2013
	(In thousands, except per share data)
Diluted earnings per common share:
Net income attributable to Western Refining, Inc.	$	406,756	$	559,926	$	275,994
Tax effected interest related to convertible debt	—		8,010		16,864
Net income available to Western Refining, Inc., assuming dilution	$	406,756	$	567,936	$	292,858
Weighted average number of diluted shares outstanding	94,999		101,190		104,904
Diluted earnings per common share	$	4.28	$	5.61	$	2.79

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



	Year Ended December 31,
	2015	2014	2013
	(In thousands)
Weighted average number of common shares outstanding	94,899	90,708	82,248
Common equivalent shares from Convertible Senior Notes	—	10,349	22,500
Restricted shares and share units	100	133	156
Weighted average number of diluted shares outstanding	94,999	101,190	104,904

A shareholder's interest in our common stock could become diluted as a result of vestings of RSUs 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 RSUs that have not vested and common equivalent shares related to the Western Convertible Notes. We include unvested RSUs 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.

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22. Cash Flows

Supplemental disclosures of cash flow information were as follows:



	Year Ended December 31,
	2015		2014		2013
	(In thousands)
Income taxes paid	$	283,330	$	227,953	$	223,594
Interest paid, excluding amounts capitalized	95,012		83,943		48,751

Non-cash investing and financing activities were as follows:
Issuance of common shares for redemption of Western Convertible Notes	—		357,608		—
Accrued capital expenditures	53,361		9,189		—
Assets acquired through capital lease obligations	29,082		—		—
PP&E derecognized from sale leaseback continuing involvement release	1,773		—		—
Transfer of capital spares from fixed asset to inventory	1,490		—		—
Distributions accrued on unvested NTI equity awards	4,210		—		—

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, 2015, and 2014, we had consolidated environmental accruals of $18.3 million and $18.5 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 our El Paso refinery. We are currently remediating, in conjunction with Chevron U.S.A., Inc. ("Chevron"), these areas 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 our 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 $6.6 million remained as of December 31, 2015. 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.

In September 2011, we and the U.S. Environmental Protection Agency (the “EPA”) entered into a Consent Decree under the Petroleum Refinery Enforcement Initiative (“EPA Initiative”). Under the EPA Initiative, the EPA is investigating industry-

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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.

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 Fluid Catalytic Cracking Unit ("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 emission offset projects to be completed by the end of 2017. We incurred $0.1 million and $1.9 million for the years ended December 31, 2015 and 2014, respectively, to implement an FCC emission offset project. We paid penalties between 2009 and 2012 totaling $2.7 million.

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, 2015, we have expended $4.5 million and have accrued the remaining estimated costs of $3.5 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. 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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St. Paul Park Refinery

At December 31, 2015, and 2014, liabilities for remediation and closure obligations totaled $8.6 million and $8.7 million, respectively, of which $2.6 million and $2.9 million, respectively, are recorded on a discounted basis. These discounted liabilities are expected to be settled over at least the next 22 years. At December 31, 2015, the estimated future cash flows to settle these discounted liabilities totaled $3.2 million and are discounted at a rate of 2.74%. 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 $0.1 million and $0.2 million at December 31, 2015, and 2014, respectively.

On June 3, 2014, the St. Paul Park refinery 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 our review of the test results and additional discussions with MPCA, we now regard the likelihood of future remediation and closure costs related to the lagoon as probable. At December 31, 2015 and 2014, we estimated the remediation and closure costs to be approximately $6.0 million and $5.8 million, respectively, subject to further engineering and methodology studies. In connection with NTI's December 2010 acquisition of the St. Paul Park refinery, among other assets, from the Marathon Petroleum Company LP ("Marathon"), we entered into an agreement with Marathon that required Marathon to share in the future remediation costs of this lagoon, should they be required. During the third quarter of 2015, we entered into a settlement and release agreement with Marathon and received $3.5 million pursuant to this settlement that we recorded as a reduction of direct operating expenses.

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. During 2015, We successfully negotiated a new collective bargaining agreement covering employees at the El Paso refinery that is scheduled to expire in April of 2021. 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.

The St. Paul Park refinery has 185 employees associated with its operations that are covered by a collective bargaining agreement that expires in December 2016. SuperAmerica has 25 employees associated with its operations that are covered by a collective bargaining agreement that expires in August 2017.

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 that 2014 and 2015 will be consistent with this history. The net cost of meeting our estimated renewable volume obligations, including sales and purchases of RINs, was $35.5 million, $28.2 million and $30.5 million for the year ended December 31, 2015, 2014 and 2013, respectively.

In addition, the EPA has investigated and brought enforcement actions against companies it believes produced invalid RINs. We may have purchased RINs that the EPA will determine are invalid. Previously, we have entered into settlements and entered into another settlement in May 2015, with the EPA regarding RINs we purchased that the EPA ultimately determined were invalid. 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.

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.

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24. Concentration of Risk

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, 2015 and 2014.

All sales were domestic sales in the United States, except for sales of gasoline and diesel fuel for export into Mexico. The sales for export were to PMI Trading Limited, an affiliate of Petroleos Mexicanos, the Mexican state-owned oil company, and accounted for approximately 6.3%, 5.5% and 8.5% of consolidated sales during the years ended December 31, 2015, 2014 and 2013, 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, cardlocks, 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 products and services, such as natural gas, electricity, water and transportation services for use by our refineries and logistics assets 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 The Chemours Company FC, LLC ("Chemours"), Chemours constructed and operates two sulfuric acid regeneration units on property we leased to Chemours 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.

In November 2007, we entered into a ten-year lease agreement for office space in downtown El Paso, Texas. The building serves as our headquarters. In December 2007, we 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 37 capital leases, with initial terms of 20 years, expiring in 2017 through 2035. The current portion of our capital lease obligation of $1.0 million and $0.6 million is included in accrued liabilities and the non-current portion of $53.2 million and $27.5 million is included in lease financing obligations in the accompanying Consolidated Balance Sheets as of December 31, 2015 and 2014, respectively. The capital lease obligations include a deferred gain of $2.3 million. These capital leases were discounted using annual rates of 3.24% to 10.51%. Total remaining interest related to these leases was $44.1 million and $21.6 million at December 31, 2015, and 2014, respectively. Annual payments, including interest, for the next five years are approximately $5.2 million annually with the remaining $70.3 million due through 2035.

The following table presents our future minimum lease commitments under capital leases and non-cancelable operating leases that have lease terms of one year or more (in thousands) as of December 31, 2015:



	Operating		Capital
2016	$	58,885	$	5,256
2017	52,828		5,030
2018	49,495		5,054
2019	44,407		5,164
2020	40,218		5,351
2021 and thereafter	340,046		70,289
Total minimum lease payments	$	585,879	96,144
Less amount that represents interest			44,134
Present value of net minimum capital lease payments			$	52,010

Total rental expense was $64.7 million, $53.7 million and $23.6 million for the years ended December 31, 2015, 2014 and 2013, respectively. Contingent rentals and subleases were not significant in any year.

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26. Related Party Transactions

We lease office space in a building located in El Paso, Texas that is owned by an entity controlled by one of our officers. 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, 2015, 2014 and 2013, we made rental payments under this lease to the related party of $0.2 million. We have no amounts due as of December 31, 2015, 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, 2015, NTI incurred $55.4 million and $12.6 million in crude transportation costs with MPL for the years ended December 31, 2015 and 2014, respectively. 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. NTI's Chief Executive Officer is a member of MPL's board of managers.

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, 2015, the Parent and certain subsidiary guarantors have fully and unconditionally guaranteed our Western 2021 Senior Unsecured Notes on a joint and several basis. NTI and WNRL are subsidiaries that have not guaranteed the Western 2021 Senior Unsecured Notes. As a result of the Parent and certain subsidiaries' 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.

Due to the retrospective adjustments of financial position, results of operations and cash flows from the guarantor to the non-guarantor entities resulting from the TexNew Mex Pipeline Transaction, we have revised the condensed consolidating financial information for all periods presented. See Note 1, Organization and Basis of Presentation, and Note 29, Western Refining Logistics, LP, for additional information on this transaction. Additionally, the condensed consolidating financial information has been revised for the retrospective adoption of accounting standards. See Note 2, Summary of Accounting Policies, for additional information on these recent accounting pronouncements.

NTI and WNRL are publicly held master limited partnerships. As of December 31, 2015, we owned a 38.4% limited partnership interest in NTI and a 66.4% limited partnership interest in WNRL, 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.

Our transactions with WNRL, including fees paid under our pipeline, terminalling and services agreements, are eliminated and have no impact on our condensed consolidated financial statements. All intercompany accounts and transactions with NTI and WNRL are eliminated in our condensed consolidated financial statements.

NTI's long-term debt is comprised of its NTI 2020 Secured Notes and the NTI Revolving Credit Facility. NTI creditors under the NTI 2020 Secured Notes and the NTI Revolving Credit Facility have no recourse to the Parent's assets except to the extent of the assets of Northern Tier Energy GP LLC, the general partner of NTI that we wholly own. Any recourse to NTI’s general partner would be limited to the extent of the general partner’s assets that other than its investment in NTI are not significant. Furthermore, the Parent's creditors have no recourse to the assets of NTI's general partner, NTI and its consolidated subsidiaries. See Note 15, Long-Term Debt, for a description of NTI’s debt obligations.

WNRL generates revenues by charging fees and tariffs for transporting crude oil through its pipelines and truck fleet, for transporting refined and other products through its terminals and pipelines, for providing storage in its storage tanks and at its terminals and selling refined products through its wholesale distribution network. We do not provide financial or equity support through any liquidity arrangements and/or debt guarantees to WNRL.

WNRL's long-term debt is comprised of the WNRL 2023 Senior Notes and the WNRL Revolving Credit Facility. With the exception of the assets of Western Refining Logistic GP, LLC, the general partner of WNRL, 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 which, other than its investment and incentive distribution rights 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

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WESTERN REFINING, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

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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WESTERN REFINING, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

CONDENSED CONSOLIDATING BALANCE SHEETS

As of December 31, 2015

(In thousands)



	Parent		Guarantor Subsidiaries		Non-Guarantors		Eliminations			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	21	$	656,966	$	115,515	$	—		$	772,502
Accounts receivable, trade, net of a reserve for doubtful accounts	—		122,593		236,644		—			359,237
Accounts receivable, affiliate	—		55,550		3,505		(59,055		)	—
Inventories	—		311,589		235,949		—			547,538
Prepaid expenses	—		55,699		17,514		—			73,213
Other current assets	—		135,139		34,589		—			169,728
Total current assets	21		1,337,536		643,716		(59,055		)	1,922,218
Restricted cash	—		69,106		—		—			69,106
Equity method investment	—		—		97,513		—			97,513
Property, plant and equipment, net	—		1,099,787		1,205,384		—			2,305,171
Goodwill	—		—		1,289,443		—			1,289,443
Intangible assets, net	—		31,401		53,544		—			84,945
Investment in subsidiaries	3,964,578		—		—		(3,964,578		)	—
Due from affiliate	—		1,797,047		—		(1,797,047		)	—
Other assets, net	—		42,166		22,831		—			64,997
Total assets	$	3,964,599	$	4,377,043	$	3,312,431	$	(5,820,680	)	$	5,833,393
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable, trade	$	—	$	262,550	$	291,407	$	—		$	553,957
Accounts payable, affiliate	920		—		58,135		(59,055		)	—
Accrued liabilities	5,508		142,257		100,630		—			248,395
Current portion of long-term debt	5,500		—		—		—			5,500
Total current liabilities	11,928		404,807		450,172		(59,055		)	807,852
Long-term liabilities:
Long-term debt, less current portion	856,327		—		788,567		—			1,644,894
Due to affiliate	1,797,047		—		—		(1,797,047		)	—
Lease financing obligation	—		42,168		11,064		—			53,232
Deferred income tax liability, net	—		275,634		37,280		—			312,914
Deficit in subsidiaries	—		395,774		—		(395,774		)	—
Other liabilities	—		63,674		4,921		—			68,595
Total long-term liabilities	2,653,374		777,250		841,832		(2,192,821		)	2,079,635
Equity:
Equity - Western	1,299,297		3,194,986		373,818		(3,568,804		)	1,299,297
Equity - Non-controlling interest	—		—		1,646,609		—			1,646,609
Total equity	1,299,297		3,194,986		2,020,427		(3,568,804		)	2,945,906
Total liabilities and equity	$	3,964,599	$	4,377,043	$	3,312,431	$	(5,820,680	)	$	5,833,393

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WESTERN REFINING, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

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		1,710,103		2,045		(1,717,183		)	—
Inventories	—		379,563		249,674		—			629,237
Prepaid expenses	—		69,580		18,835		—			88,415
Other current assets	—		128,564		23,561		—			152,125
Total current assets	5,056		2,755,582		725,008		(1,717,183		)	1,768,463
Restricted cash	—		167,009		—		—			167,009
Equity method investment	—		—		96,080		—			96,080
Property, plant and equipment, net	—		983,562		1,169,627		—			2,153,189
Goodwill	—		—		1,289,443		—			1,289,443
Intangible assets, net	—		31,586		54,366		—			85,952
Investment in subsidiaries	3,637,607		—		—		(3,637,607		)	—
Other assets, net	—		67,652		14,398		—			82,050
Total assets	$	3,642,663	$	4,005,391	$	3,348,922	$	(5,354,790	)	$	5,642,186
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable, trade	$	—	$	347,133	$	334,670	$	—		$	681,803
Accounts payable, affiliate	1,656,412		—		60,771		(1,717,183		)	—
Accrued liabilities	5,506		179,922		83,021		—			268,449
Current portion of long-term debt	5,500		—		—		—			5,500
Total current liabilities	1,667,418		527,055		478,462		(1,717,183		)	955,752
Long-term liabilities:
Long-term debt, less current portion	855,537		—		619,128		—			1,474,665
Lease financing obligation	—		18,860		8,629		—			27,489
Deferred income tax liability, net	—		317,530		37,279		—			354,809
Deficit in subsidiaries	—		248,375		—		(248,375		)	—
Other liabilities	—		36,530		5,297		—			41,827
Total long-term liabilities	855,537		621,295		670,333		(248,375		)	1,898,790
Equity:
Equity - Western	1,119,708		2,857,041		532,191		(3,389,232		)	1,119,708
Equity - Non-controlling interest	—		—		1,667,936		—			1,667,936
Total equity	1,119,708		2,857,041		2,200,127		(3,389,232		)	2,787,644
Total liabilities and equity	$	3,642,663	$	4,005,391	$	3,348,922	$	(5,354,790	)	$	5,642,186

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS AND COMPREHENSIVE INCOME

For the Year Ended December 31, 2015

(In thousands)



	Parent			Guarantor Subsidiaries			Non-Guarantors			Eliminations			Consolidated
Net sales	$	—		$	7,543,712		$	5,602,023		$	(3,358,699	)	$	9,787,036
Operating costs and expenses:
Cost of products sold (exclusive of depreciation and amortization)	—			6,358,612			4,521,462			(3,358,699		)	7,521,375
Direct operating expenses (exclusive of depreciation and amortization)	—			443,010			459,915			—			902,925
Selling, general and administrative expenses	189			118,585			106,471			—			225,245
Loss (gain) and impairments on disposal of assets, net	—			620			(569		)	—			51
Maintenance turnaround expense	—			2,024			—			—			2,024
Depreciation and amortization	—			99,642			105,649			—			205,291
Total operating costs and expenses	189			7,022,493			5,192,928			(3,358,699		)	8,856,911
Operating income (loss)	(189		)	521,219			409,095			—			930,125
Other income (expense):
Equity in earnings (loss) of subsidiaries	461,049			42,470			—			(503,519		)	—
Interest income	—			389			314			—			703
Interest expense and other financing costs	(54,104		)	(2,717		)	(48,782		)	—			(105,603		)
Other, net	—			492			12,669			—			13,161
Income (loss) before income taxes	406,756			561,853			373,296			(503,519		)	838,386
Provision for income taxes	—			(223,908		)	(47		)	—			(223,955		)
Net income (loss)	406,756			337,945			373,249			(503,519		)	614,431
Less net income attributed to non-controlling interests	—			—			207,675			—			207,675
Net income (loss) attributable to Western Refining, Inc.	$	406,756		$	337,945		$	165,574		$	(503,519	)	$	406,756
Comprehensive income attributable to Western Refining, Inc.	$	406,756		$	338,600		$	166,861		$	(503,519	)	$	408,698

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WESTERN REFINING, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

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)	—			425,428			441,806			(16,600		)	850,634
Selling, general and administrative expenses	186			114,080			111,754			—			226,020
Affiliate severance costs	—			—			12,878			—			12,878
Loss (gain) and impairments on disposal of assets, net	—			8,465			65			—			8,530
Maintenance turnaround expense	—			48,469			—			—			48,469
Depreciation and amortization	—			93,835			96,731			—			190,566
Total operating costs and expenses	186			10,221,423			8,435,423			(4,599,972		)	14,057,060
Operating income (loss)	(186		)	782,819			313,880			—			1,096,513
Other income (expense):
Equity in earnings (loss) of subsidiaries	630,407			51,747			—			(682,154		)	—
Interest income	—			795			393			—			1,188
Interest expense and other financing costs	(70,286		)	(1,044		)	(25,732		)	—			(97,062		)
Loss on extinguishment of debt	(9		)	—			—			—			(9		)
Other, net	—			(604		)	2,650			—			2,046
Income (loss) before income taxes	559,926			833,713			291,191			(682,154		)	1,002,676
Provision for income taxes	—			(292,145		)	(459		)	—			(292,604		)
Net income (loss)	559,926			541,568			290,732			(682,154		)	710,072
Less net income attributed to non-controlling interests	—			—			150,146			—			150,146
Net income (loss) attributable to Western Refining, Inc.	$	559,926		$	541,568		$	140,586		$	(682,154	)	$	559,926
Comprehensive income attributable to Western Refining, Inc.	$	559,926		$	541,091		$	140,122		$	(682,154	)	$	558,985

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WESTERN REFINING, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

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)	—			365,840			170,807			(12,811		)	523,836
Selling, general and administrative expenses	185			110,727			26,119			—			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	—			90,593			27,255			—			117,848
Total operating costs and expenses	185			9,813,987			4,353,115			(4,653,090		)	9,514,197
Operating income (loss)	(185		)	573,956			(1,898		)	—			571,873
Other income (expense):
Equity in earnings (loss) of subsidiaries	391,526			(42,479		)	—			(349,047		)	—
Interest income	—			697			49			—			746
Interest expense and other financing costs	(68,574		)	(802		)	(5,205		)	—			(74,581		)
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			(5,232		)	(349,047		)	453,479
Provision for income taxes	—			(153,830		)	(95		)	—			(153,925		)
Net income (loss)	275,994			377,934			(5,327		)	(349,047		)	299,554
Less net income attributed to non-controlling interests	—			—			23,560			—			23,560
Net income (loss) attributable to Western Refining, Inc.	$	275,994		$	377,934		$	(28,887	)	$	(349,047	)	$	275,994
Comprehensive income (loss) attributable to Western Refining, Inc.	$	275,994		$	378,621		$	(28,750	)	$	(349,047	)	$	276,818

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WESTERN REFINING, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

For the Year Ended December 31, 2015

(In thousands)



	Parent			Guarantor Subsidiaries			Non-Guarantors			Eliminations			Consolidated
Cash flows from operating activities:
Net cash provided by (used in) operating activities	$	87,364		$	433,863		$	502,676		$	(180,820	)	$	843,083
Cash flows from investing activities:
Capital expenditures	—			(157,600		)	(134,820		)	1,557			(290,863		)
Contributions to affiliate	—			(178,243		)	—			178,243			—
Proceeds from the sale of assets	—			2,028			643			(1,557		)	1,114
Increase in restricted cash	—			(170,000		)	—			—			(170,000		)
Use of restricted cash	—			267,903			—			—			267,903
Net cash provided by (used in) investing activities	—			(235,912		)	(134,177		)	178,243			(191,846		)
Cash flows from financing activities:
Additions to long-term debt	—			—			300,000			—			300,000
Payments on long-term debt and capital lease obligations	(5,500		)	(842		)	(1,026		)	—			(7,368		)
Borrowings on revolving credit facility	—			—			145,000			—			145,000
Repayments of revolving credit facility	—			—			(269,000		)	—			(269,000		)
Contributions from affiliate	152,347			—			25,896			(178,243		)	—
Distribution to non-controlling interest holders	—			—			(238,366		)	—			(238,366		)
Deferred financing costs	—			—			(6,820		)	—			(6,820		)
Distribution to affiliate	—			—			(180,820		)	180,820			—
Purchases of common stock for treasury	(105,000		)	—			—			—			(105,000		)
Dividends paid	(129,211		)	—			—			—			(129,211		)
Convertible debt redemption	—			—			—			—			—
Distribution to Western Refining, Inc.	—			170,000			(170,000		)	—			—
Excess tax benefit from stock-based compensation	—			871			—			—			871
Net cash provided by (used in) financing activities	(87,364		)	170,029			(395,136		)	2,577			(309,894		)
Net increase (decrease) in cash and cash equivalents	—			367,980			(26,637		)	—			341,343
Cash and cash equivalents at beginning of year	21			288,986			142,152			—			431,159
Cash and cash equivalents at end of year	$	21		$	656,966		$	115,515		$	—		$	772,502

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WESTERN REFINING, INC. AND SUBSIDIARIES

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	)	$	520,972		$	403,087		$	(131,580	)	$	737,633
Cash flows from investing activities:
Capital expenditures	—			(99,204		)	(124,067		)	—			(223,271		)
Proceeds from the sale of assets	—			1,260			676			—			1,936
Return of capital from equity method investment	—			—			7,480			—			7,480
Contributions to affiliate	—			(678,628		)	(93,546		)	772,174			—
Increase in restricted cash	—			(320,000		)	—			—			(320,000		)
Use of restricted cash	—			152,991			—			—			152,991
Net cash provided by (used in) investing activities	—			(943,581		)	(209,457		)	772,174			(380,864		)
Cash flows from financing activities:
Additions to long-term debt	—			—			79,311			—			79,311
Payments on long-term debt and capital lease obligations	(5,759		)	—			(313		)	—			(6,072		)
Borrowings on revolving credit facility	—			—			269,000			—			269,000
Contributions from affiliate	618,564			93,546			60,064			(772,174		)	—
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 common stock for treasury	(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			(222,622		)	(640,594		)	(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

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WESTERN REFINING, INC. AND SUBSIDIARIES

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	$	541,738		$	(149,406	)	$	48,821		$	—		$	441,153
Cash flows from investing activities:
Capital expenditures	—			(112,968		)	(92,709		)	—			(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	—			(155,347		)	—			155,347			—
Net cash provided by (used in) investing activities	(775,000		)	(260,876		)	(15,356		)	155,347			(895,885		)
Cash flows from financing activities:
Additions to long-term debt	900,000			—			—			—			900,000
Payments on long-term debt and capital lease obligations	(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	14,538			—			140,809			(155,347		)	—
Purchases of common stock for treasury	(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	233,262			253,246			137,674			(155,347		)	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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Due to the change in the guarantor structure resulting from the TexNew Mex Pipeline Transaction, 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 this adjustment to the prior year condensed consolidating financial information is summarized as follows:

CONDENSED CONSOLIDATING BALANCE SHEETS

As of December 31, 2014

(In thousands)



	As Previously Reported			Adjustment			Revised
Parent	$	3,637,607		$	—		$	3,637,607
Guarantor subsidiaries	(354,686		)	106,311			(248,375		)
Non-guarantor subsidiaries	—			—			—
Eliminations	(3,282,921		)	(106,311		)	(3,389,232		)
Investment (deficit) in subsidiaries	$	—		$	—		$	—

Parent	$	3,676,126		$	(33,463	)	$	3,642,663
Guarantor subsidiaries	4,118,796			(113,405		)	4,005,391
Non-guarantor subsidiaries	3,242,338			106,584			3,348,922
Eliminations	(5,354,702		)	(88		)	(5,354,790		)
Total assets	$	5,682,558		$	(40,372	)	$	5,642,186

Parent	$	2,556,418		$	(33,463	)	$	2,522,955
Guarantor subsidiaries	1,261,755			(113,405		)	1,148,350
Non-guarantor subsidiaries	1,148,522			273			1,148,795
Eliminations	(2,071,781		)	106,223			(1,965,558		)
Total liabilities	$	2,894,914		$	(40,372	)	$	2,854,542

Parent	$	1,119,708		$	—		$	1,119,708
Guarantor subsidiaries	2,857,041			—			2,857,041
Non-guarantor subsidiaries	2,093,816			106,311			2,200,127
Eliminations	(3,282,921		)	(106,311		)	(3,389,232		)
Total equity	$	2,787,644		$	—		$	2,787,644

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CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS AND COMPREHENSIVE INCOME

For the Year Ended December 31, 2014

(In thousands)



	As Previously Reported			Adjustment			Revised
Parent	$	630,407		$	—		$	630,407
Guarantor subsidiaries	55,944			(4,197		)	51,747
Non-guarantor subsidiaries	—			—			—
Eliminations	(686,351		)	4,197			(682,154		)
Equity in earnings (loss) of subsidiaries	$	—		$	—		$	—

Parent	559,926			—			559,926
Guarantor subsidiaries	541,568			—			541,568
Non-guarantor subsidiaries	144,783			(4,197		)	140,586
Eliminations	(686,351		)	4,197			(682,154		)
Net income (loss) attributable to Western Refining, Inc.	$	559,926		$	—		$	559,926

Parent	$	559,926		$	—		$	559,926
Guarantor subsidiaries	541,091			—			541,091
Non-guarantor subsidiaries	144,319			(4,197		)	140,122
Eliminations	(686,351		)	4,197			(682,154		)
Comprehensive income attributable to Western Refining, Inc.	$	558,985		$	—		$	558,985

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS AND COMPREHENSIVE INCOME

For the Year Ended December 31, 2013

(In thousands)



	As Previously Reported			Adjustment			Revised
Parent	$	391,526		$	—		$	391,526
Guarantor subsidiaries	(41,546		)	(933		)	(42,479		)
Non-guarantor subsidiaries	—			—			—
Eliminations	(349,980		)	933			(349,047		)
Equity in earnings (loss) of subsidiaries	$	—		$	—		$	—

Parent	275,994			—			275,994
Guarantor subsidiaries	377,934			—			377,934
Non-guarantor subsidiaries	(27,954		)	(933		)	(28,887		)
Eliminations	(349,980		)	933			(349,047		)
Net income (loss) attributable to Western Refining, Inc.	$	275,994		$	—		$	275,994

Parent	$	275,994		$	—		$	275,994
Guarantor subsidiaries	378,621			—			378,621
Non-guarantor subsidiaries	(27,817		)	(933		)	(28,750		)
Eliminations	(349,980		)	933			(349,047		)
Comprehensive income attributable to Western Refining, Inc.	$	276,818		$	—		$	276,818

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CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

For the Year Ended December 31, 2014

(In thousands)



	As Previously Reported			Adjustment			Revised
Parent	$	(54,846	)	$	—		$	(54,846	)
Guarantor subsidiaries	517,756			3,216			520,972
Non-guarantor subsidiaries	406,303			(3,216		)	403,087
Eliminations	(131,580		)	—			(131,580		)
Net cash provided by (used in) operating activities	$	737,633		$	—		$	737,633

Parent	—			—			—
Guarantor subsidiaries	(940,365		)	(3,216		)	(943,581		)
Non-guarantor subsidiaries	(152,609		)	(56,848		)	(209,457		)
Eliminations	712,110			60,064			772,174
Net cash provided by (used in) investing activities	$	(380,864	)	$	—		$	(380,864	)

Parent	$	54,846		$	—		$	54,846
Guarantor subsidiaries	414,690			—			414,690
Non-guarantor subsidiaries	(282,686		)	60,064			(222,622		)
Eliminations	(580,530		)	(60,064		)	(640,594		)
Net cash provided by (used in) financing activities	$	(393,680	)	$	—		$	(393,680	)

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

For the Year Ended December 31, 2013

(In thousands)



	As Previously Reported			Adjustment			Revised
Parent	$	541,154		$	584		$	541,738
Guarantor subsidiaries	(152,532		)	3,126			(149,406		)
Non-guarantor subsidiaries	52,531			(3,710		)	48,821
Eliminations	—			—			—
Net cash provided by (used in) operating activities	$	441,153		$	—		$	441,153

Parent	(775,000		)	—			(775,000		)
Guarantor subsidiaries	(257,750		)	(3,126		)	(260,876		)
Non-guarantor subsidiaries	(2,929		)	(12,427		)	(15,356		)
Eliminations	139,794			15,553			155,347
Net cash provided by (used in) investing activities	$	(895,885	)	$	—		$	(895,885	)

Parent	$	233,846		$	(584	)	$	233,262
Guarantor subsidiaries	253,246			—			253,246
Non-guarantor subsidiaries	121,537			16,137			137,674
Eliminations	(139,794		)	(15,553		)	(155,347		)
Net cash provided by (used in) financing activities	$	468,835		$	—		$	468,835

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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 2015 and 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, 2015, and 2014 is presented below.



	Year Ended December 31, 2015
	Quarter
	First			Second			Third			Fourth
	(Unaudited) (In thousands, except for per share data)
Net sales	$	2,318,730		$	2,828,892		$	2,569,090		$	2,070,324
Operating costs and expenses:
Cost of products sold (exclusive of depreciation and amortization)	1,741,310			2,177,887			1,895,772			1,706,406
Direct operating expenses (exclusive of depreciation and amortization)	215,311			224,723			234,440			228,451
Selling, general and administrative expenses	55,803			59,540			54,465			55,437
Loss (gain) and impairments on disposal of assets, net	282			(387		)	(52		)	208
Maintenance turnaround expense	105			593			490			836
Depreciation and amortization	49,926			51,143			51,377			52,845
Total operating costs and expenses	2,062,737			2,513,499			2,236,492			2,044,183
Operating income	255,993			315,393			332,598			26,141
Other income (expense):
Interest income	163			201			186			153
Interest expense and other financing costs	(24,957		)	(27,316		)	(26,896		)	(26,434		)
Other, net	3,206			4,024			4,327			1,604
Income before income taxes	234,405			292,302			310,215			1,464
Provision for income taxes	(59,437		)	(78,435		)	(92,117		)	6,034
Net income	174,968			213,867			218,098			7,498
Less net income (loss) attributed to non-controlling interests	68,979			79,948			64,795			(6,047		)
Net income attributable to Western Refining, Inc.	$	105,989		$	133,919		$	153,303		$	13,545
Basic earnings per common share	$	1.11		$	1.40		$	1.61		$	0.14
Diluted earnings per common share	$	1.11		$	1.40		$	1.61		$	0.14

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	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	(28,957		)	(27,801		)	(18,250		)	(22,054		)
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 interests	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

29. Western Refining Logistics, LP

WNRL is a publicly traded limited partnership that owns, operates, develops and acquires logistics assets and related businesses. WNRL's assets consist of pipeline and gathering assets and terminalling, transportation and storage assets, including approximately 685 miles of pipelines and approximately 8.2 million barrels of active storage capacity, as well as other assets in the Southwestern portion of the U.S. 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, 2015, we held a 66.4% limited partner interest in WNRL including a non-economic general partner interest. This interest included 8,579,623 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.

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

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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. 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.


•	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

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distance between the applicable pick-up and delivery points plus monthly fuel adjustments and customary applicable surcharges.

TexNew Mex Pipeline System Acquisition

On October 30, 2015, we sold to WNRL a 375 mile segment of the TexNew Mex Pipeline System that extends from WNRL's crude oil station in Star Lake, New Mexico, in the Four Corners region to its T station in Eddy County, New Mexico. We also sold an 80,000 barrel crude oil storage tank located at WNRL's crude oil pumping station in Star Lake, New Mexico and certain other related assets. WNRL acquired these assets from us in exchange for $170 million in cash and 421,031 common units representing limited partner interests in WNRL and 80,000 TexNew Mex Units.

In connection with the closing, we also entered into an amendment to our Pipeline and Gathering Services Agreement with WNRL (the "Amendment to the Pipeline Agreement"). The Amendment to the Pipeline Agreement amends the scope of the existing agreement to include the provision of storage services and a minimum volume commitment of 80,000 barrels of storage at the Star Lake storage tank. In this Amendment to the Pipeline Agreement, we have agreed to provide a minimum volume commitment of 13,000 bpd of crude oil for shipment on the Contributed TexNew Mex Pipeline for 10 years from the date of the Amendment to the Pipeline Agreement. We also amended our limited partnership agreement with WNRL whereby WNRL will issue us a new class of WNRL partnership interests, in connection with the acquisition, that entitle us to 80% of the economics resulting from crude oil throughput on the Contributed TexNew Mex Pipeline above 13,000 bpd. WNRL will be entitled to 20% of the economics resulting from crude oil throughput on the Contributed TexNew Mex Pipeline above our 13,000 bpd minimum volume commitment.

WNRL funded the cash consideration through $145.0 million in new borrowings under its Revolving Credit Facility and $25.0 million from cash on hand. As required for accounting purposes, WNRL recorded the acquired assets at the historical book value as the asset transaction was between entities under common control.

30. NTI

2013 NTI Acquisition

On November 12, 2013, Western purchased all of the interests in NT InterHoldCo LLC, a wholly-owned subsidiary of Northern Tier Holdings LLC, 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 98,000 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 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

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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, 2013; (ii) $550.0 million was borrowed to fund the 2013 NTI Acquisition on January 1, 2013, resulting in increased financing costs of $23.9 million for the year ended December 31, 2013; (iii) $36.7 million increased depreciation and amortization expense for the year ended December 31, 2013 for the increased estimated fair values of assets acquired beginning January 1, 2013; 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 for the year ended December 31, 2013.



	Unaudited Pro Forma for the Year Ended December 31, 2013
	(In thousands, except per share data)
Net sales	$	14,044,131
Operating income	746,699
Net income	413,375

Basic earnings per share	$	3.56
Diluted earnings per share	2.96

NTI Merger Agreement

On December 21, 2015, Western entered into the Merger Agreement, by and among Western, Western Acquisition Co, LLC, a Delaware limited liability company and wholly-owned subsidiary of Western (“MergerCo”), NTI and Northern Tier Energy GP LLC, the general partner of NTI and a wholly-owned subsidiary of Western (“NTI GP”). Upon the terms and subject to the conditions set forth in the Merger Agreement, MergerCo will merge with and into NTI, the separate limited liability company existence of MergerCo will cease and NTI will continue to exist, as a limited partnership under Delaware law and as an indirect wholly-owned subsidiary of Western, as the surviving entity in the Merger.

NT InterHoldCo LLC, a Delaware limited liability company and wholly-owned subsidiary of Western (“NT InterHoldCo”), owns 100% of the membership interests in NTI GP and approximately 38.4% of NTI’s outstanding common units representing limited partner interests in NTI (“NTI Common Units”). NT InterHoldCo also owns 100% of the membership interests in Western Acquisition Holdings, LLC, a Delaware limited liability company and holder of 100% of the membership interests in MergerCo (“MergerCo HoldCo”). Following the Merger, NTI GP will remain the sole general partner of NTI, the NTI Common Units held by Western and its subsidiaries will be unchanged and remain issued and outstanding, and, by virtue of the Merger, all of the membership interests in MergerCo will automatically be converted into the number of NTI Common Units (excluding any NTI Common Units owned by Western and its subsidiaries) issued and outstanding immediately prior to the effective time of the Merger (the “Effective Time”). Consequently, NT InterHoldCo and its wholly-owned subsidiary, MergerCo HoldCo, will become the sole limited partners of NTI. At the Effective Time, each of the outstanding NTI Common Units held by the NTI Public Unitholders will be converted into the right to receive, subject to election by the NTI Public Unitholders and proration, (i) $15.00 in cash without interest and 0.2986 of a share of Western’s common stock, par value $0.01 per share (“Western Common Stock”) (the “Standard Mix of Consideration”), (ii) $26.06 in cash without interest (the “Cash Election”), or (iii) 0.7036 of a share of Western Common Stock (the “Stock Election”). The Cash and Stock Elections will be subject to proration to ensure that the total amount of cash paid and the total number of shares of Western Common Stock issued and delivered (which may include shares of Western Common Stock held in treasury by Western and reissued) in the Merger to NTI Public Unitholders as a whole are equal to the total amount of cash and number of shares of Western Common Stock that would have been paid and issued if all NTI Public Unitholders received the Standard Mix of Consideration. The transaction is expected to result in the payment and delivery of approximately $858.2 million in cash and 17.1 million shares of Western Common Stock to the NTI Public Unitholders.

The parties anticipate that the Merger will close in the first half of 2016, pending the satisfaction of certain customary conditions thereto. Pursuant to the terms of the Merger Agreement, with respect to the quarter in which the closing date of the Merger (the "Closing Date") occurs, NTI will, to the extent it generates available cash in such quarter, make a prorated quarterly cash distribution to all NTI common unitholders, including NT InterHoldCo, for the portion of the quarter that NTI Public Unitholders own NTI Common Units prior to the Closing Date, in the event that NTI Public Unitholders who receive

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Western Common Stock in the Merger would not receive a dividend with respect to the Western Common Stock received in the Merger, due to the record date for such dividend occurring before the Closing Date.

The Merger Agreement contains customary representations, warranties, covenants and agreements by each of the parties. Completion of the Merger is conditioned upon, among other things: (1) approval of the Merger Agreement and the transactions contemplated by the Merger Agreement, including the Merger (the “Merger Transactions”), by the affirmative vote of NTI common unitholders, as of the record date for the NTI special meeting, holding a majority of the outstanding NTI Common Units; (2) any waiting period applicable to the Merger Transactions under the Hart-Scott-Rodino Antitrust Act of 1976, as amended (the “HSR Act”) having been terminated or expired; (3) all filings, consents, approvals, permits and authorizations required to be made or obtained prior to the Effective Time in connection with the Merger Transactions having been made or obtained; (4) the absence of legal injunctions or impediments prohibiting the Merger Transactions; (5) the effectiveness of a registration statement on Form S-4 (the “Registration Statement”) with respect to the issuance of new shares of Western Common Stock in the Merger; and (6) approval of the listing on the New York Stock Exchange, subject to official notice of issuance, of the new shares of Western Common Stock to be issued and delivered (or, to the extent held in treasury by Western, delivered but not issued) in the Merger. On January 29, 2016, the United States Federal Trade Commission granted early termination of the waiting periods applicable to the Merger Transactions under the HSR Act. Pursuant to the Merger Agreement, Western has agreed to vote the NTI common units owned beneficially or of record by it or any of its subsidiaries in favor of the adoption and approval of the Merger Agreement and the Merger Transactions.

The Board of Directors of Western has approved the Merger Agreement and the Merger Transactions. The NTI GP Conflicts Committee, acting for NTI GP in its capacity as the general partner of NTI, approved the Merger Agreement and the Merger Transactions, and determined that the Merger Agreement and the Merger Transactions are fair and reasonable to NTI and the holders of NTI Common Units other than NTI GP and its affiliates (the “NTI Unaffiliated Unitholders”) and are not adverse to the interests of NTI or the interests of the NTI Unaffiliated Unitholders.

On January 19, 2016, Western filed a preliminary registration statement on Form S-4 (the “Preliminary S-4”) to register the shares of Western Common Stock to be issued and delivered (or, to the extent held in treasury by Western, delivered but not issued) in the Merger. The Preliminary S-4 is subject to future amendments depending on review and comments by the Securities and Exchange Commission (the “SEC”). On that same date, the parties to the Merger Agreement jointly filed a transaction statement on Schedule 13E-3, which discloses the material terms of the Merger Transactions and is also subject to future amendments.

31. Subsequent Events

Tesoro Merger

On November 16, 2016, we entered into an Agreement and Plan of Merger (the “Tesoro Merger Agreement”) with Tesoro Corporation, a Delaware corporation (“Tesoro”), Tahoe Merger Sub 1, Inc., a Delaware corporation and wholly-owned subsidiary of the Company (“Merger Sub 1”), and Tahoe Merger Sub 2, LLC, a Delaware limited liability company and wholly owned subsidiary of Tesoro (“Merger Sub 2”), pursuant to which Merger Sub 1 will merge with and into the Company (the “First Merger,” and, if a second merger election as discussed below is not made, the “Tesoro Merger”), with the Company surviving the First Merger as a wholly owned subsidiary of Tesoro. Subject to the terms and conditions set forth in the Tesoro Merger Agreement, upon consummation of the First Merger, each share of our common stock, par value $0.01 per share (each, a “Company Share”) issued and outstanding immediately prior to the effective time of the First Merger (excluding Company Shares owned by the Company or Tesoro or any of their respective direct or indirect wholly-owned subsidiaries that are not held on behalf of third parties) will be converted into and become exchangeable for, at the election of the holder of such Company Share, either (a) $37.30 in cash or (b) 0.4350 shares of common stock, par value $0.16⅔ per share, of Tesoro, in each case without interest. The transaction is expected to close in the first half of 2017 and is subject to customary closing conditions, including approval by the shareholders of both companies and the receipt of regulatory approval.

NTI Merger

We entered into the Merger Agreement as of December 21, 2015 with MergerCo, NTI and Northern Tier Energy GP LLC, to acquire all of NTI’s outstanding common units not already held by us. On June 23, 2016, following the approval of the Merger Agreement by NTI common unitholders, all closing conditions to the Merger were satisfied, and the Merger was successfully completed. We incurred $500 million of additional secured indebtedness under our amended term loan credit agreement to partially fund the Merger consideration.

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WESTERN REFINING, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

St. Paul Park Logistics Transaction

On September 15, 2016, we sold certain assets consisting of terminals, transportation and storage assets and the related land located on site at our St. Paul Park refinery and Cottage Grove tank farm to WNRL. These assets primarily receive, store and distribute crude oil, feedstock and refined products associated with the St. Paul Park refinery. WNRL acquired these assets from us in exchange for $195.0 million in cash and 628,224 common units representing limited partner interests in WNRL.

WNRL Equity Issuances

On September 7, 2016, WNRL entered into an underwriting agreement relating to the issuance and sale of 7,500,000 of its common units representing limited partner interests in the Partnership. The closing of the offering occurred on September 13, 2016. WNRL also granted the underwriter an option to purchase additional common units on the same terms which was exercised in full and closed on September 30, 2016, for 1,125,000 additional common units.

On May 16, 2016, WNRL entered into an underwriting agreement relating to the issuance and sale by WNRL of 3,750,000 common units representing limited partner interests in WNRL. The closing of the offering occurred on May 20, 2016. WNRL also granted the underwriter an option to purchase up to 562,500 additional WNRL common units on the same terms. The underwriter fully exercised the option on June 1, 2016.

Dividends

During 2016, our board of directors approved cash dividends of $1.52 per share of common stock in an aggregate payment of $152.7 million.

Legal Matters

On August 24, 2016, an alleged NTI unitholder (“Plaintiff”) filed a purported class action lawsuit against Western, NTI, NTI GP, members of the NTI GP board of directors at the time of the Merger, Evercore Group, L.L.C. (“Evercore”), and MergerCo (collectively, “Defendants”) (the “Merger Litigation”). The Merger Litigation appears to challenge the adequacy of disclosures made in connection with the Merger. Plaintiff seeks monetary damages and attorneys’ fees. The Merger Litigation is in the earliest stages of litigation. Western believes the Merger Litigation is without merit and intends to vigorously defend against it.

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