10-K

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

þ	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the Fiscal Year Ended December 31, 2016
OR
¨	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the transition period from  to

Commission File Number	Registrant; State of Incorporation; Address and Telephone Number	I.R.S. Employer Identification No.
001-32721	WESTERN REFINING, INC.	20-3472415
	Delaware
	212 N. Clark Dr.
	El Paso, Texas 79905
	(915) 775-3300
001-35612	NORTHERN TIER ENERGY LP	80-0763623
	Delaware
	1250 W. Washington Street, Suite 300
	Tempe, Arizona 85281
	(602) 302-5450

Securities registered pursuant to Section 12(b) of the Act:

Title of Each Class	Name of Each Exchange on Which Registered
Western Refining, Inc. - Common Stock	New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. 

Western Refining, Inc.	Yes	þ	No	o
Northern Tier Energy LP	Yes	þ	No	o

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. 

Western Refining, Inc.	Yes	o	No	þ
Northern Tier Energy LP	Yes	o	No	þ

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. 

Western Refining, Inc.	Yes	þ	No	o
Northern Tier Energy LP	Yes	þ	No	o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). 

Western Refining, Inc.	Yes	þ	No	o
Northern Tier Energy LP	Yes	þ	No	o

Indicate by check mark if disclosure of delinquent filers pursuant to rule 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. 

Western Refining, Inc.	þ
Northern Tier Energy LP	þ

Indicate by check mark if the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Western Refining, Inc.	Large accelerated filer þ	Accelerated filer o	Non-accelerated filer o	Smaller reporting company o
Northern Tier Energy LP	Large accelerated filer o	Accelerated filer o	Non-accelerated filer þ	Smaller reporting company o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  

Western Refining, Inc.	Yes	o	No	þ
Northern Tier Energy LP	Yes	o	No	þ

The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant computed based on the New York Stock Exchange closing price on June 30, 2016 (the last business day of the registrant’s most recently completed second fiscal quarter) was $1,723,259,136.

As of February 24, 2017, there were 108,698,435 shares outstanding, par value $0.01, of the registrant’s common stock.

Northern Tier Energy LP meets the conditions set forth in General Instruction I(1)(a), (b) and (d) of Form 10-K and is therefore filing this form with the reduced disclosure format.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the definitive proxy statement relating to the registrant’s 2017 annual meeting of stockholders are incorporated by reference into Part III of this report or will be provided in an amendment filed on Form 10-K/A.

WESTERN REFINING, INC. AND SUBSIDIARIES

INDEX

PART I
Item 1.	Business	3
Item 1A.	Risk Factors	13
Item 1B.	Unresolved Staff Comments	29
Item 2.	Properties	29
Item 3.	Legal Proceedings	30
Item 4.	Mine Safety Disclosures	30
PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	31
Item 6.	Selected Financial Data	34
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	37
Item 7A.	Quantitative and Qualitative Disclosure About Market Risk	66
Item 8.	Financial Statements and Supplementary Data	68
Item 9.	Changes In and Disagreements With Accountants on Accounting and Financial Disclosure	139
Item 9A.	Controls and Procedures	139
Item 9B.	Other Information	139
PART III
Item 10.	Directors, Executive Officers and Corporate Governance	140
Item 11.	Executive Compensation	140
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	140
Item 13.	Certain Relationships and Related Transactions and Director Independence	141
Item 14.	Principal Accountant Fees and Services	141
PART IV
Item 15.	Exhibits and Financial Statement Schedules	142
Item 16.	Form 10-K Summary	149
Signatures		150
Northern Tier Energy LP Financial Statements		152
EX-12.1
EX-21.1
EX-23.1
EX-31.1
EX-31.2
EX-32.1
EX-32.2
EX-101

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Explanatory Note

This report on Form 10-K is a combined report being filed separately by Western Refining, Inc. (“Western”) and Northern Tier Energy LP (“NTI”). Western owns all of the common units of NTI and NTI meets the conditions set forth in General Instruction I(1)(a), (b) and (d) of Form 10-K and is therefore filing its information within this Form 10-K with the reduced disclosure format. NTI's debt is in the form of senior secured notes due in 2020 and the indenture governing NTI's senior secured notes requires that it publicly disclose its quarterly financial position, results of operations and cash flows through the maturity date or retirement of its senior secured notes. Western and NTI have elected to include NTI's statements of financial position, results of operations, statements of cash flows and corresponding notes to its consolidated financial statements for all periods required within a separate section of this Annual Report on Form 10-K. Each of Western and NTI is filing on its own behalf the information contained in this report that relates to itself, and neither entity makes any representation as to information relating to the other entity. Where information or an explanation is provided that is substantially the same for each entity, such information or explanation has been combined in this report. Where information or an explanation is not substantially the same for each entity, separate information and explanation has been provided.

Forward-Looking Statements

As provided by the safe harbor provisions of the Private Securities Litigation Reform Act of 1995, certain statements included throughout this Annual Report on Form 10-K and in particular under the sections entitled Item 1. Business, Item 3. Legal Proceedings and Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations relating to matters that are not historical fact are forward-looking statements that represent management’s beliefs and assumptions based on currently available information. These forward-looking statements relate to matters such as our industry, including the regulation of our industry, business strategy, our proposed merger with Tesoro Corporation (“Tesoro”), future operations, our expectations for margins and crack spreads, seasonality, the discount between West Texas Intermediate ("WTI") crude oil and Dated Brent crude oil as well as the discount between WTI Cushing and WTI Midland crude oils, volatility of crude oil prices, additions to pipeline capacity in the Permian Basin and at Cushing, Oklahoma, pipeline access to advantaged crude oil, expected share repurchases and dividends, volatility in pricing of Renewable Identification Numbers ("RIN"), taxes, capital expenditures, liquidity and capital resources and other financial and operating information. Forward-looking statements also include those regarding the timing of completion of certain operational and maintenance improvements we are making at our refineries, future operational and refinery efficiencies and cost savings, timing of future maintenance turnarounds, the amount or sufficiency of future cash flows and earnings growth, future expenditures, future contributions related to pension and postretirement obligations, our ability to manage our inventory price exposure through commodity hedging instruments, the impact upon our business of existing and future state and federal regulatory requirements, environmental loss contingency accruals, projected remediation costs or requirements and the expected outcomes of legal proceedings in which we are involved. We have used the words “anticipate,” “assume,” “believe,” “budget,” “continue,” “could,” “estimate,” “expect,” “forecast,” “intend,” “may,” “plan,” “position,” “potential,” “predict,” “project,” “strategy,” “will,” “future” and similar terms and phrases to identify forward-looking statements in this report.

Forward-looking statements reflect our current expectations regarding future events, results or outcomes. These expectations may or may not be realized. Some of these expectations may be based upon assumptions or judgments that prove to be incorrect or that are affected by unknown risks or uncertainties. Consequently, no forward-looking statements can be guaranteed. In addition, our business and operations involve numerous risks and uncertainties, many that are beyond our control, that could result in our expectations not being realized or otherwise materially affect our financial condition, results of operations and cash flows.

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

• the possibility that the proposed merger with Tesoro is not consummated in a timely manner or at all;

• the diversion of management in connection with the proposed merger with Tesoro;

• our ability to realize the anticipated benefits of the merger with NTI;

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

• the successful integration and future performance of acquired assets, businesses or third-party product supply, and the possibility that expected synergies may not be achieved;

• the impact on us of increased levels and cost of indebtedness used to fund our merger with NTI or the cash portion of the merger consideration and increased cost of existing indebtedness due to the actions taken to consummate the merger with NTI;

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• our ability to obtain debt or equity financing on satisfactory terms to fund additional acquisitions, expansion projects, working capital requirements and the repayment or refinancing of indebtedness;

• changes in crack spreads;

• changes in the spreads between WTI Cushing crude oil and other crude oil benchmarks such as West Texas Sour crude oil, WTI Midland crude oil, Bakken shale crude oil, Dated Brent crude oil and Western Canadian Select crude oil;

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

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

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

• changes in the underlying demand for our refined products;

• instability and volatility in the financial markets, including as a result of potential disruptions caused by economic uncertainties, commodity price fluctuations and expectations for changes in interest rates;

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

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

• changes in the availability and cost of capital;

• actions of customers and competitors;

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

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

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

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

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

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

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

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

• labor relations;

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

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

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

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

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PART I

In this Annual Report on Form 10-K, all references to “Western Refining,” “the Company,” “Western,” “we,” “us” and “our” refer to Western Refining, Inc. ("WNR") and its subsidiaries, unless the context otherwise requires or where otherwise indicated.

Item 1. Business

Western Refining, Inc.

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 and the controlling general partner interest, incentive distribution rights and a 52.6% limited partner interest in Western Refining Logistics, LP (“WNRL”). WNRL common partnership units trade on the NYSE under the symbol "WNRL."

We produce refined products at our refineries in El Paso, Texas (135,000 barrels per day, or bpd, crude oil throughput capacity), near Gallup, New Mexico (25,000 bpd capacity) and St. Paul Park, Minnesota (102,000 bpd capacity). 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 544 company-operated and franchised retail sites in the United States.

WNRL provides logistical services to our refineries in the Southwest and Upper Great Plains regions and operates several lubricant and bulk petroleum distribution plants and a fleet of crude oil, asphalt and refined product delivery trucks. WNRL distributes wholesale petroleum products primarily in Arizona, Colorado, Nevada, New Mexico and Texas.

On November 16, 2016, we entered into an Agreement and Plan of Merger (the “Tesoro Merger Agreement”) with Tesoro, Tahoe Merger Sub 1, Inc., a Delaware corporation and wholly-owned subsidiary of Tesoro (“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 (each, a “Western Share”) issued and outstanding immediately prior to the effective time of the First Merger (excluding Western 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 Western Share, either (a) $37.30 in cash or (b) 0.4350 shares of common stock in each case without interest. Western stockholders as of the close of business on February 10, 2017, the record date, have been invited to attend a special meeting of Western stockholders on March 24, 2017 at 10:00 am Mountain Standard Time, to consider and vote upon a proposal to adopt the Tesoro Merger Agreement and certain other matters related to the Tesoro Merger. On February 16, 2017, Tesoro filed with the SEC, and the SEC declared effective, a registration statement on Form S-4 (Reg. No. 333-215080), containing a joint proxy statement/prospectus of Tesoro and Western, which proxy statement/prospectus was first mailed to Tesoro and Western stockholders on February 17, 2017. See Note 31, Tesoro Merger, in the Notes to Consolidated Financial Statements included in this annual report for additional information on this transaction.

We own 100% of the limited partner interest in Northern Tier Energy LP ("NTI") and 100% of its general partner. We entered into an Agreement and Plan of Merger dated as of December 21, 2015 (the “NTI Merger Agreement”), with Western Acquisition Co, LLC, which is a wholly-owned subsidiary of Western, NTI and Northern Tier Energy GP LLC, to acquire all of NTI’s outstanding common units not already held by us (the “NTI Merger”). On June 23, 2016, following the approval of the NTI Merger Agreement by NTI common unitholders, all closing conditions to the NTI Merger were satisfied, and the NTI Merger was successfully completed. We incurred $500 million of additional secured indebtedness under our amended term loan credit agreement to partially fund the NTI Merger consideration. 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 reporting entities in our organizational structure as of December 31, 2016:

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 in the Southwest and terminal and storage assets in the Upper Great Plains region. WNRL's Southwest wholesale assets consist of a fleet of crude oil, asphalt and refined product truck transports and wholesale petroleum product operations. WNRL's primary customer is our refining segment. 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 ("cardlock") locations located in the Southwest ("Southwest Retail") and Upper Great Plains ("SuperAmerica") regions. 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. No single customer accounted for more than 10% of consolidated net sales for the years ended December 31, 2016, 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 via WNRL and through a third-party pipeline and terminal system that has facilities throughout the Upper Great Plains region.

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Our refining segment also includes our refined products marketing and distribution operations in the Mid-Atlantic region. On September 15, 2016, we sold certain assets consisting of terminals, transportation and storage assets and the related land located 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 (the "St. Paul Park Logistics Assets"). Prior to our sale of the St. Paul Park Logistics Assets (the "St. Paul Park Logistics Transaction"), our refining segment included the operations of the St. Paul Park Logistics Assets, and we have recast historical financial and operational data of the refining segment, for all periods presented, to reflect the sale of the St. Paul Park Logistics Assets 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 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 category for the years indicated:

	Year Ended December 31,
	2016		2015		2014
Gasoline	42.4	%	45.4	%	41.6	%
Diesel fuel	28.2		25.7		29.9
Jet fuel	7.4		5.4		5.4
Asphalt	5.5		5.2		3.6
Crude oil and other (1)	16.5		18.3		19.5
Total sales percentage by type	100.0	%	100.0	%	100.0	%

(1) Crude oil sales for the years ended December 31, 2016, 2015 and 2014 were $547.4 million, $1,078.2 million and $2,684.3 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 segment accounted for more than 10% of our consolidated net sales during the years ended December 31, 2016, 2015 and 2014.

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 6.0%, 6.3% and 5.5% of our consolidated net sales during the years ended December 31, 2016, 2015 and 2014, respectively.

We also purchase additional refined products from third parties to supplement supply to our customers primarily in the Mid-Atlantic region. These products are similar to the products that we currently manufacture and represented approximately 5.7%, 6.5% and 7.3% of our total sales volumes during the years ended December 31, 2016, 2015 and 2014, respectively. The decrease from 2014 to 2016 was primarily the result of lower refined product sales activities in the Mid-Atlantic region.

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 petroleum products distributors such as Shell Oil Company, BP Oil, CITGO Petroleum Corporation, Valero Energy Corporation and Exxon Mobil Corporation.

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

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

El Paso Refinery

Our El Paso refinery has a crude oil throughput capacity of 135,000 bpd with access to third-party pipeline systems and WNRL logistics assets including approximately 5.3 million barrels of storage capacity, a refined product terminal and an asphalt plant and terminal. The refinery is well situated to serve two separate geographic areas allowing a diversified market pricing exposure. Tucson and Phoenix typically reflect a West Coast market pricing structure while El Paso, Albuquerque and Juarez, Mexico typically reflect a Gulf Coast market pricing structure.

Process Summary. Our El Paso refinery is a cracking facility that has historically run a high percentage of WTI crude oil to optimize the yields of higher value refined products that currently account for over 90% of our production output. We have the flexibility to process up to 22% West Texas Sour ("WTS") crude oil. Under a sulfuric acid regeneration and sulfur gas processing agreement with Veolia North America, Inc. ("Veolia"), Veolia constructed and operates two sulfuric acid regeneration units on property we lease to Veolia 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)	2016	2015	2014	2016
Crude Oil:
Sweet crude oil	104,454	105,064	96,384	74.7	%
Sour crude oil	26,612	22,949	25,113	19.0	%
Total Crude Oil	131,066	128,013	121,497	93.7	%
Other Feedstocks and Blendstocks:
Intermediates and other	5,562	4,534	3,735	4.0	%
Blendstocks	3,243	2,530	2,004	2.3	%
Total Other Feedstocks and Blendstocks	8,805	7,064	5,739	6.3	%
Total Crude Oil and Other Feedstocks and Blendstocks	139,871	135,077	127,236	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

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refinery. We deliver gasoline and distillate products to Tucson and Phoenix through Kinder Morgan's East Line and to Albuquerque and Juarez, Mexico, through pipelines owned by Magellan Midstream Partners, LP ("Magellan").

Both Kinder Morgan’s East Line and Magellan's pipeline to Albuquerque are interstate pipelines regulated by the Federal Energy Regulatory Commission (the "FERC"). The tariff provisions for these pipelines include prorating policies that grant historical shippers line space that is consistent with their prior activities as well as a prorated portion of any expansions.

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, 2016.

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 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)	2016	2015	2014	2016
Crude Oil:
Sweet crude oil	22,964	24,071	25,130	89.2	%
Total Crude Oil	22,964	24,071	25,130	89.2	%
Other Feedstocks and Blendstocks:
Intermediates and other	1,230	934	867	4.8	%
Blendstocks	1,557	1,725	1,786	6.0	%
Total Other Feedstocks and Blendstocks	2,787	2,659	2,653	10.8	%
Total Crude Oil and Other Feedstocks and Blendstocks	25,751	26,730	27,783	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 St. Paul Park, Minnesota, has a crude oil throughput capacity of 102,000 bpd with access to third-party transportation systems and WNRL logistics assets including approximately 4.0 million barrels of storage capacity. It has the ability to process a variety of light, heavy, sweet and sour crudes into higher value refined products. 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 and, to a lesser extent, major U.S. and foreign refiners.

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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").

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 our 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 our St. Paul Park refinery.

	Period Ended December 31,			Percentage For Year Ended December 31,
Refinery Feedstocks (bpd)	2016	2015	2014	2016
Crude Oil Feedstocks:
Canadian	41,482	38,417	34,184	46.6	%
Domestic	47,469	55,284	57,656	53.4	%
Total Crude Oil	88,951	93,701	91,840	100.00	%
Crude Oil Feedstocks by Type:
Light and intermediate	67,310	68,739	73,999	75.7	%
Heavy	21,641	24,962	17,841	24.3	%
Total Crude Oil	88,951	93,701	91,840	100.0	%
Other Feedstocks and Blendstocks (1):
Natural gasoline	622	—	38	18.0	%
Butanes	2,722	2,152	798	78.9	%
Gasoil	—	—	351	—	%
Other	105	662	498	3.0	%
Total Other Feedstocks and Blendstocks	3,449	2,814	1,685	100.0	%
Total Crude Oil and Other Feedstocks and Blendstocks	92,400	96,515	93,525	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 our 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, 2016, approximately 47% 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. In response, NTI increased the principal amount of its 2020 Secured Notes in September 2014 by an additional $75.0 million in principal value and increased its revolving credit facility to $500.0 million, which it primarily uses for crude procurement.

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 purchase ethanol and biodiesel, as well as conventional petroleum based blendstocks, such as natural gasoline, to supplement the fuels produced at the refinery.

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Refined Products Transportation. We distribute all gasoline and diesel fuel produced at our St. Paul Park refinery through pipelines owned by Magellan and via WNRL logistics 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 WNRL's light products terminal. Approximately 60% of the gasoline and diesel volumes for the year ended December 31, 2016, were sold via the 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 that allows us 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 and WNRL's light products terminal. Asphalt and heavy fuel oil are transported from the refinery via truck from WNRL's seven-bay heavy products terminal and via rail and barge through WNRL's 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 our refinery's 2016 gasoline and diesel sales volumes in Minnesota and Wisconsin with the remainder sold primarily in Iowa, Nebraska, Oklahoma and South and North Dakota.

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 the St. Paul Park refinery crude oil input.

WNRL

WNRL owns and operates terminal, storage, transportation and wholesale assets. WNRL's primary customers are our refineries in the Southwest and Upper Great Plains region. 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, 2016, Western's ownership of WNRL consisted of a 100% interest in WNRL's general partner and a 52.6% interest in a limited partnership that Western controls through the general partner.

On September 15, 2016, WNRL purchased the St. Paul Park Logistics Assets. In connection with the St. Paul Park Logistics Transaction, we entered into a terminalling, transportation and storage services agreement with Western under which WNRL agreed to provide product storage services, product throughput services and product additive and blending services at the terminal facilities located at or near the St. Paul Park Refinery. 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. On October 15, 2014, Western sold all of the outstanding limited liability company interests of Western Refining Wholesale, LLC ("WRW") to WNRL. 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 for the purpose of generating fee-based revenues. See Note 29, Western Refining Logistics, LP, in the Notes to Consolidated Financial Statements included in this annual report for detailed information regarding these transactions.

Logistics - Pipeline and Gathering Assets. WNRL's pipeline and gathering assets consist of approximately 705 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. WNRL's pipeline and gathering assets also include two crude oil pipeline segments and one pipeline segment not currently in service, each of which is approximately 2.5 miles and extends from our St. Paul Park refinery in St. Paul Park, Minnesota to the St. Paul Park refinery's tank farm in Cottage Grove, Minnesota. These pipeline systems connect at various points to an aggregate of approximately 959,000 barrels of active crude oil storage located primarily in the Delaware Basin and in the Four Corners area.

Logistics - Terminalling, Transportation, Asphalt and Storage Assets. WNRL's terminalling, transportation and storage infrastructure consist of refined product distribution terminals at the El Paso, Gallup and St. Paul Park refineries and stand-alone refined products terminals located in Bloomfield and Albuquerque, New Mexico.

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The Bloomfield product distribution terminal is permitted to operate at 19,000 bpd with a total storage capacity of approximately 696,000 barrels and a truck loading rack with four loading bays. 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 bays. 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.

Our St. Paul Park Logistics Assets provides the St. Paul Park refinery with storage and transfer services required to support the refinery's operations. The tank farm consists of storage tanks with a combined shell storage capacity of approximately 4.0 million barrels. Our St. Paul Park terminal distributes refined products supplied by the St. Paul Park refinery from a light products rack, a heavy products loading rack, certain rail and barge facilities and certain other related logistics assets.

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

During the fourth quarter of 2016, WNRL completed an evaluation of its lubricant operations. After careful consideration, having concluded that lubricants are not strategic to its core operations, WNRL has taken steps to divest the remaining assets associated with this business. WNRL anticipates a completed sale within the first half of 2017. Assets related to our lubricant operations include $10.1 million in inventories and $7.3 million in property, plant and equipment in our Consolidated Balance Sheet at December 31, 2016. WNRL expects proceeds from this divestiture to result in a gain on disposal of assets; however, no amounts related to this anticipated transaction have been recorded in the Consolidated Statements of Operations for the year ended December 31, 2016.

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, 25.6% and 21.8%, were to our retail segment and to Kroger Company, respectively, for the year ended December 31, 2016. 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

Southwest Retail 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, 2016, Southwest Retail operated 259 retail stores located in Arizona, Colorado, New Mexico and Texas and 51 cardlocks located in Arizona, 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 Southwest Retail 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, Dollar General, Family Dollar and other large grocery retailers compete in the motor fuel retail business. Our Southwest 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 Southwest Retail stores operate under various brands, including Giant, Western, Western Express, Howdy's and Mustang. Gasoline brands sold through these stores include Western, Giant, Phillips 66 Company, Conoco, 76, Shell Oil Company, Chevron, Mobil and Texaco.

SuperAmerica Retail

We have a retail-marketing network of 285 convenience stores, as of December 31, 2016, located throughout Minnesota, Wisconsin and South Dakota. We brand all of our company-operated and franchised convenience stores as SuperAmerica. We

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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, 2016, 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.

The following table summarizes the ownership and location of our Southwest Retail and SuperAmerica Retail stores as of December 31, 2016:

	Owned	Leased	Franchised	Total
Southwest Retail:
Arizona	26	74	—	100
Colorado	10	2	—	12
New Mexico	74	43	—	117
Texas	—	30	—	30
	110	149	—	259
SuperAmerica Retail:
Minnesota	2	161	109	272
South Dakota	—	1	1	2
Wisconsin	—	6	5	11
	2	168	115	285

The following table summarizes the ownership and location of our cardlocks as of December 31, 2016:

	Owned	Leased	Private Sites (1)	Total
Arizona	14	7	13	34
Colorado	2	—	—	2
New Mexico	3	1	1	5
Texas	—	10	—	10
	19	18	14	51

(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.

Northern Tier Energy LP

NTI is a downstream energy limited partnership with refining, retail and logistics operations that serves the Upper Great Plains region of the United States. Western indirectly owns 100% of both Northern Tier Energy GP LLC and NTI. NTI operates the St. Paul Park Refinery and SuperAmerica retail business which are described above. For the year ended December 31, 2016, NTI had total revenues of $2,888.6 million, operating income of $105.6 million and net income of $76.5 million. For the year ended December 31, 2015, NTI had total revenues of $3,405.0 million, operating income of $368.1 million and net income of $331.0 million.

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

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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 significant 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 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, 2016, our companies employed 7,134 people including 559 WNRL employees in its wholesale segment. The collective bargaining agreements covering the El Paso, Gallup and St. Paul Park refinery employees expire in April2021, April2020 and December2020, 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 agreement covering the SuperMom's bakery operations expire in August 2017. Through our control of WNRL's general partner and its affiliate entities, we have seconded 295 full-time employees to WNRL as well as other employees who may provide services to WNRL from time to time.

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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, 2016, 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 32.1 to this Form 10-K are the certifications required by Sections 302 and 906 of the Sarbanes-Oxley Act of 2002.

Item 1A. Risk Factors

An investment in our common shares involves risk. In addition to the other information in this report and our other filings with the SEC, you should carefully consider the following risk factors in evaluating us and our business. The following risk factors relate to both Western and NTI.

Risks Related to Our Proposed Merger with Tesoro

Western stockholders will have a reduced ownership and voting interest in the combined company after the merger with Tesoro and will exercise less influence over management.

Currently, Western stockholders have the right to vote in the election of the Western board and the power to approve or reject any matters requiring stockholder approval under Delaware law and Western’s certificate of incorporation and bylaws. Upon completion of the Tesoro Merger, each Western stockholder who receives shares of Tesoro common stock in the Tesoro Merger will become a stockholder of Tesoro with a percentage ownership of Tesoro that is smaller than the Western stockholder’s current percentage ownership of Western. Based on the number of issued and outstanding shares of Tesoro common stock and shares of Western common stock as of February 8, 2017 and on the exchange ratio of 0.4350, after the merger Western stockholders are expected to become owners of between approximately 26.9% and approximately 29.0% of the outstanding shares of Tesoro common stock, depending on the number of Western stockholders that make a cash election, and without giving effect to any shares of Tesoro common stock held by Western stockholders prior to the completion of the Tesoro Merger. Even if all former Western stockholders voted together on all matters presented to Tesoro stockholders from time to time, the former Western stockholders would exercise significantly less influence over Tesoro after the completion of the merger relative to their influence over Western prior to the completion of the Tesoro Merger, and thus would have a less significant impact on the approval or rejection of future Tesoro proposals submitted to a stockholder vote.

The Tesoro Merger Agreement limits Western’s ability to pursue alternatives to the merger.

The Tesoro Merger Agreement contains provisions that may discourage a third party from submitting an acquisition proposal to Western that might result in greater value to Western’s stockholders than the Tesoro Merger, or may result in a potential competing acquirer of Western, proposing to pay a lower per share price to acquire Western, than it might otherwise have proposed to pay. These provisions include a general prohibition on Western from soliciting or, subject to certain exceptions relating to the exercise of fiduciary duties by the Western board, entering into discussions with any third party regarding any acquisition proposal or offer for a competing transaction. Western also has an unqualified obligation to submit the Western merger proposal to a vote by its stockholders, even if Western receives an alternative acquisition proposal that the Western board believes is superior to the Tesoro Merger, unless Western terminates the Tesoro Merger Agreement in accordance with its terms prior to such time.

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The Tesoro Merger Agreement may be terminated in accordance with its terms and the Tesoro Merger may not be completed.

The Tesoro Merger Agreement is subject to a number of conditions that must be fulfilled in order to complete the Tesoro Merger. Those conditions include, among others: the adoption of the Tesoro Merger Agreement by Western stockholders, the approval by Tesoro stockholders of the issuance of shares of Tesoro common stock in connection with the Tesoro Merger, the expiration or termination of the waiting period applicable to the Tesoro Merger under the HSR Act without the imposition of a burdensome condition, the accuracy of representations and warranties under the Tesoro Merger Agreement (subject to the materiality standards set forth in the Tesoro Merger Agreement), Tesoro’s and Western’s performance of their respective obligations under the Tesoro Merger Agreement in all material respects and Western’s receipt of a written opinion of Davis Polk & Wardwell LLP (or another nationally recognized law firm selected by Western) regarding certain U.S. federal income tax matters. These conditions to the closing of the Tesoro Merger may not be fulfilled in a timely manner or at all, and, accordingly, the Tesoro Merger may be delayed or may not be completed.

On December 8, 2016, notification and report forms under the HSR Act were filed with the FTC and the DOJ, which is referred to as the initial filing, with respect to the proposed merger. The waiting period with respect to the notification and report forms filed under the HSR Act was originally scheduled to expire at 11:59 p.m. Eastern Time on January 9, 2017. Effective January 9, 2017, as permitted by the Merger Agreement, Tesoro voluntarily withdrew its HSR Act notification to provide the FTC and the DOJ an extension beyond the initial 30-day HSR Act waiting period to conduct its review. On January 11, 2017, Tesoro re-filed its HSR Act notification with the FTC and DOJ. The new waiting period under the HSR Act was scheduled to expire at 11:59 p.m. on February 10, 2017. On February 10, 2017, Tesoro and Western received a second request from the FTC in connection with the FTC’s review of the transactions contemplated by the merger agreement. Issuance of the second request extends the waiting period under the HSR Act until 30 days after both Tesoro and Western have complied with the second request or such later time as Tesoro and Western may agree with the FTC, unless the waiting period is terminated earlier by the FTC.

Under the terms of the Tesoro Merger Agreement, Tesoro will not be required to defend litigation or any similar proceeding if the DOJ or the FTC authorizes its staff to seek a preliminary injunction or restraining order to enjoin the completion of the merger.

Although Tesoro and Western currently believe they should be able to obtain the expiration or termination of the waiting period applicable under the HSR Act in a timely manner, they cannot be certain when or if it will be obtained or, if obtained, whether such expiration or termination will require terms, conditions or restrictions not currently contemplated that will be detrimental to the surviving company after the completion of the merger. Tesoro and Western have agreed to take certain actions to obtain the expiration or termination of the waiting period applicable under the HSR Act, except that Tesoro and Western will not be required to take any action constituting a burdensome condition, as defined in the Tesoro Merger Agreement.

In addition, Western has received a letter, dated January 27, 2017, from the Office of the Minnesota AG stating that the Office of the Minnesota AG intends to review the merger under the antitrust laws and requesting that Western provide information regarding the potential competitive effects of the merger in Minnesota.  Western is in the process of responding to this letter.

In addition, if the Tesoro Merger is not completed by November 16, 2017, either Tesoro or Western Refining may choose not to proceed with the Tesoro Merger and the parties can mutually decide to terminate the Tesoro Merger Agreement at any time, before or after stockholder approval. In addition, Tesoro and Western Refining may elect to terminate the Tesoro Merger Agreement in certain other circumstances.

Failure to complete the Tesoro Merger could negatively impact the price of shares of Western common stock, as well as Western’s respective future businesses and financial results.

The Tesoro Merger Agreement contains a number of conditions that must be satisfied or waived prior to the completion of the Tesoro Merger. There can be no assurance that all of the conditions to the Tesoro Merger will be so satisfied or waived. If the conditions to the Tesoro Merger are not satisfied or waived, Tesoro and Western Refining will be unable to complete the Tesoro Merger.

If the Tesoro Merger is not completed for any reason, including the failure to receive the required approvals of Western’s stockholders, Western’s business and financial results may be adversely affected as follows:

• Western may experience negative reactions from the financial markets, including negative impacts on the market price of shares of Western common stock;

• the manner in which customers, vendors, business partners and other third parties perceive Western may be negatively impacted, which in turn could affect Western’s marketing operations or their ability to compete for new business or obtain renewals in the marketplace more broadly;

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• Western may experience negative reactions from employees; and

• Western will have expended time and resources that could otherwise have been spent on Western’s existing businesses and the pursuit of other opportunities that could have been beneficial to the company, and Western Refining’s ongoing business and financial results may be adversely affected.

In addition to the above risks, if the Tesoro Merger Agreement is terminated and either party’s board seeks an alternative transaction, such party’s stockholders cannot be certain that such party will be able to find a party willing to engage in a transaction on more attractive terms than the Tesoro Merger. If the Tesoro Merger Agreement is terminated under specified circumstances, either Tesoro or Western Refining may be required to pay the other party a termination fee, reverse termination fee or other termination-related payment.

Western will be subject to business uncertainties while the Tesoro Merger is pending, which could adversely affect their respective businesses.

Uncertainty about the effect of the Tesoro Merger on employees and customers may have an adverse effect on Western. These uncertainties may impair Western’s ability to attract, retain and motivate key personnel until the Tesoro Merger is completed and for a period of time thereafter, and could cause customers and others that deal with Western to seek to change their existing business relationships with Western. Employee retention at Western may be particularly challenging during the pendency of the Tesoro Merger, as employees may experience uncertainty about their roles with Tesoro following the Tesoro Merger. In addition, the Tesoro Merger Agreement restricts Western from entering into certain corporate transactions and taking other specified actions without the consent of the other party, and generally requires Western to continue its operations in the ordinary course, until completion of the Tesoro Merger. These restrictions may prevent Western from pursuing attractive business opportunities that may arise prior to the completion of the Tesoro Merger.

Western will incur significant transaction and merger-related costs in connection with the Tesoro Merger, which may be in excess of those anticipated by Western.

Western has incurred and will incur substantial expenses in connection with the negotiation and completion of the transactions contemplated by the Tesoro Merger Agreement, including the costs and expenses of filing, printing and mailing the joint proxy statement/prospectus and all filing and other fees paid to the SEC in connection with the Tesoro Merger.

Western expects to continue to incur a number of non-recurring costs associated with completing the Tesoro Merger, combining the operations of the two companies and achieving desired synergies. These fees and costs have been, and will continue to be, substantial. The substantial majority of non-recurring expenses will consist of transaction costs related to the Tesoro Merger and include, among others, employee retention costs, fees paid to financial, legal and accounting advisors, severance and benefit costs and filing fees.

Western will also incur transaction fees and costs related to formulating and implementing integration plans, including facilities and systems consolidation costs and employment-related costs. Western will continue to assess the magnitude of these costs, and additional unanticipated costs may be incurred in the Tesoro Merger and the integration of the two companies’ businesses. Although Western expects that the elimination of duplicative costs, as well as the realization of other efficiencies related to the integration of the businesses, should allow Western to offset integration-related costs over time, this net benefit may not be achieved in the near term, or at all.

The costs described above, as well as other unanticipated costs and expenses, could have a material adverse effect on the financial condition and operating results of Tesoro following the completion of the Tesoro Merger.

Many of these costs will be borne by Western even if the Tesoro Merger is not completed.

Lawsuits have been filed against Western and the members of its board of directors challenging the adequacy of the disclosures made in the initial version of the joint proxy statement/prospectus filed on December 14, 2016, and an adverse ruling in one or more of these lawsuits may prevent the Tesoro Merger from being completed.

As of February 8, 2017, Western and the members of its board of directors have been named as defendants in five purported stockholder class actions filed in the United States District Court for the Western District of Texas by Western Refining stockholders challenging the adequacy of the disclosures to Western stockholders made in the initial version of the joint proxy statement/prospectus filed on December 14, 2016 regarding the transaction. The actions have been consolidated and an interim lead plaintiff and lead counsel have been appointed. The parties have also agreed to select an operative complaint. Although Tesoro, Tahoe Merger Sub 1, Inc., and Tahoe Merger Sub 2, LLC are included as defendants in the caption of three of the five complaints (but not the operative complaint), the body of those complaints does not identify those entities as defendants, and the complaints do not appear to assert any claims against them. None of the parties named as defendants in the case captions have been served with the complaint in any of these actions as of the date of this filing. Among other remedies, the plaintiffs seek to enjoin the Tesoro Merger until additional information relating to the transaction is disclosed. The actions also seek to recover costs and disbursements from the defendants, including attorneys’ fees and experts’ fees. The lawsuits are

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in a preliminary stage. On February 23, 2017, Western and the members of its board of directors filed a motion to dismiss the operative complaint in the consolidated proceedings. Additional lawsuits may be filed against Western and/or its board of directors in connection with the Tesoro Merger.

One of the conditions to the closing of the Tesoro Merger is that there must not have been enacted, issued, promulgated, enforced or entered by a court or other governmental entity of competent jurisdiction any applicable law that is in effect and restrains, enjoins or otherwise prohibits completion of the Tesoro Merger or the other transactions contemplated by the Tesoro Merger Agreement. Therefore, if any of the plaintiffs in one or more of these actions or in any additional lawsuits that may be filed secures injunctive relief or other relief prohibiting, delaying or otherwise adversely affecting the defendants’ ability to complete the Tesoro Merger, then such injunctive or other relief may prevent the Tesoro Merger from becoming effective within the expected timeframe or at all.

Risks Related to Our Business and Industry

The price volatility of crude oil, other feedstocks, refined products and fuel and utility services has had and may continue to have a material adverse effect on our earnings and cash flows.

Our earnings and cash flows from operations depend on the margin above fixed and variable expenses (including the cost of refinery feedstocks such as crude oil) at which we are able to sell refined products. Refining margins historically have been volatile and are likely to continue to be volatile, as a result of a variety of factors, including fluctuations in the prices of crude oil, other feedstocks, refined products and fuel and utility services.

In recent years, the prices of crude oil, other feedstocks and refined products have fluctuated. The NYMEX WTI postings of crude oil for 2016 ranged from $29.64 per barrel in February 2016 to $52.17 per barrel in December 2016 to $52.94 as of February 24, 2017. In addition, the WTI/Brent discount has been volatile and we expect continued volatility in crude oil pricing and crack spreads. It is possible that this volatility in crude oil pricing and crack spreads may continue for prolonged periods of time due to numerous factors beyond our control. Prolonged periods of low crude oil prices could impact production growth of inland crude oil, which could reduce the amount of advantaged crude oil available and/or the discount of such crude oil and thereby impacting the profitability of our refineries. Prices of crude oil, other feedstocks and refined products depend on numerous factors beyond our control, including the supply of and demand for crude oil, other feedstocks, gasoline and other refined products. Such supply and demand are affected by, among other things:

• changes in global and local economic and political conditions;

• domestic and foreign demand for crude oil and refined products, especially in the U.S., China and India;

• worldwide political conditions, particularly in significant oil producing regions such as the Middle East, West Africa Russia and Latin America;

• political and geopolitical instability or armed conflict in oil producing regions;

• the level of foreign and domestic production of crude oil and refined products and the level of crude oil, feedstocks and refined products imported into the U.S. that can be impacted by accidents, interruptions in transportation, inclement weather or other events affecting producers and suppliers;

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

• utilization rates of U.S. refineries;

• changes in fuel specifications required by environmental and other laws;

• the ability of the members of the Organization of Petroleum Exporting Countries ("OPEC") to influence oil price and production controls;

• commodities speculation;

• development and marketing of alternative and competing fuels;

• pricing and other actions taken by competitors that impact the market;

• product pipeline capacity, including the Magellan Southwest System pipeline, Kinder Morgan’s East Line and the Magellan pipeline system, all of which could increase supply in certain of our service areas and therefore reduce our margins;

• accidents, interruptions in transportation, inclement weather or other events that can cause unscheduled shutdowns or otherwise adversely affect our plants, machinery or equipment or those of our suppliers or customers; 

• federal and state government regulations and taxes; and

• local factors, including market conditions, weather conditions and the level of operations of other refineries and pipelines in our service areas.

Volatility has had, and may continue to further have, a negative effect on our results of operations to the extent that the margin between refined product prices and feedstock prices narrows.

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

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“last-in, first-out” ("LIFO") inventory valuation methodology, if the market value of our inventory were to further decline to an amount less than our LIFO cost, we would record a write-down of inventory and a non-cash charge to cost of products sold, such as we recorded in the fourth quarter of 2015. Due to the volatility in the price of crude oil and other blendstocks, we experienced fluctuations in our LIFO reserves during the past three years. We also experienced LIFO liquidations based on decreased levels in our inventories. These LIFO liquidations resulted in an increase in cost of products sold of $2.9 million and $16.1 million for the years ended December 31, 2016 and 2015, respectively, and a decrease in cost of products sold of $1.1 million for the year ended December 31, 2014.

In addition, the volatility in costs of fuel, principally natural gas and other utility services, principally electricity, used by our refineries affects operating costs. Fuel and utility prices have been, and will continue to be, affected by factors outside our control, such as supply and demand for fuel and utility services in both local and regional markets. Natural gas prices have historically been volatile. Typically, electricity prices fluctuate with natural gas prices. Future increases in fuel and utility prices may have a material adverse effect on our business, financial condition, results of operations and cash flows.

If the price of crude oil increases significantly or our credit profile changes, or if we or our subsidiaries are unable to access our respective credit agreements for borrowings or for letters of credit, our liquidity and our ability to purchase enough crude oil to operate our refineries at full capacity could be materially and adversely affected.

We and certain of our subsidiaries rely on borrowings and letters of credit under each of our respective credit agreements to purchase crude oil for our refineries. Changes in our credit profile could affect the way crude oil suppliers view our ability to make payments and induce them to shorten the payment terms of their invoices with us or require additional support such as letters of credit. Due to the large dollar amounts and volume of our crude oil and other feedstock purchases, any imposition by our creditors of more burdensome payment terms on us, or our subsidiaries’ inability to access their credit agreements or other similar arrangements may have a material effect on our liquidity and our ability to make payments to our suppliers that could hinder our ability to purchase sufficient quantities of crude oil to operate our refineries at planned rates. In addition, if the price of crude oil increases significantly, we may not have sufficient capacity under the credit agreements or sufficient cash on hand, to purchase enough crude oil to operate our refineries at planned rates. A failure to operate our refineries at planned rates could have a material adverse effect on our business, financial condition, results of operations and cash flows.

Our hedging transactions may limit our gains and expose us to other risks.

We enter into hedging transactions from time to time to manage our exposure to commodity price risks or to fix sales margins on future gasoline and distillate production. These transactions limit our potential gains if commodity prices rise above the levels established by our hedging instruments. These transactions may also expose us to risks of financial losses, for example, if our production is less than we anticipated at the time we entered into a hedge agreement or if a counterparty to our hedge contracts fails to perform its obligations under the contracts. Some of our hedging agreements also require us to furnish cash collateral, letters of credit or other forms of performance assurance. Mark-to-market calculations that result in settlement obligations by us to the counterparties could impact our liquidity and capital resources.

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

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

Recent events have given rise to a heightened possibility of a substantial change to fiscal and tax policies, which may include comprehensive tax reform. We cannot predict the impact these changes will have on our business; however, it is possible that these changes could adversely affect our business, our cash flows, our profitability, and our ability to compete domestically and internationally. Until we know what changes are enacted, we will not know the type or extent of the effects on our business.

The present U.S. federal income tax treatment of publicly traded partnerships including WNRL may be modified by administrative, legislative or judicial changes or differing interpretations at any time. For example, a proposal in the Fiscal Year 2017 Budget had recommended that certain publicly traded partnerships earning income from activities related to fossil fuels be taxed as corporations beginning in 2021. From time to time, members of Congress propose and consider such substantive changes to the existing federal income tax laws that affect publicly traded partnerships. If successful, this could result in a material decrease in our income from our interests in those subsidiaries.

In addition, the IRS, on May 5, 2015, issued proposed regulations concerning which activities give rise to qualifying income within the meaning of Section 7704 of the Internal Revenue Code. We do not believe the proposed regulations affect our subsidiaries' ability to qualify as publicly traded partnerships. However, finalized regulations could modify the amount of gross income that they are able to treat as qualifying income for the purposes of the qualifying income requirement.

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Any modification to the U.S. federal income tax laws may be applied retroactively and could make it more difficult or impossible for our subsidiaries to meet the exception for certain publicly traded partnerships to be treated as partnerships for U.S. federal income tax purposes. We are unable to predict whether any of these changes or other proposals will ultimately be enacted. Any such changes could negatively impact the value of our investments in such publicly traded partnerships.

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

Our level of debt may have important consequences to you. Among other things, it may:

• limit our ability to use our cash flows, or obtain additional financing, for future working capital, capital expenditures, acquisitions or other general corporate purposes;

• restrict our ability to pay dividends;

• require a substantial portion of our cash flows from operations to make debt service payments;

• limit our flexibility to plan for, or react to, changes in our business and industry conditions;

• place us at a competitive disadvantage compared to our less leveraged competitors; and

• increase our vulnerability to the impact of adverse economic and industry conditions.

We cannot assure you that we will continue to generate sufficient cash flows or that we and our subsidiaries will be able to borrow funds under certain credit agreements in amounts sufficient to enable us and our subsidiaries to service our debt or meet our working capital and capital expenditure requirements. Our ability to generate sufficient cash flows from our operating activities will continue to be primarily dependent on producing or purchasing and selling sufficient quantities of refined products at margins sufficient to cover fixed and variable expenses. If our margins were to deteriorate significantly, or if our earnings and cash flows were to suffer for any other reason, we and our subsidiaries may be unable to comply with the financial covenants set forth in our and their respective credit facilities. If we or our subsidiaries fail to satisfy these covenants, we and our subsidiaries could be prohibited from borrowing for our working capital needs and issuing letters of credit that would hinder our ability to purchase sufficient quantities of crude oil to operate our refineries at planned rates. To the extent that we and our subsidiaries are unable to generate sufficient cash flows from operations, or if we and our subsidiaries are unable to borrow or issue letters of credit under certain credit agreements, we and our subsidiaries may be required to sell assets, reduce capital expenditures, refinance all or a portion of our existing debt, or obtain additional financing through equity or debt financings. If additional funds are obtained by issuing equity securities, our existing stockholders could be diluted. We cannot assure you that we would be able to refinance our debt, sell assets or obtain additional financing on terms acceptable to us, if at all. In addition, our ability to incur additional debt will be restricted under the covenants contained in credit agreements and our indentures. See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations; Liquidity and Capital Resources; Working Capital and Indebtedness.

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

Our and our subsidiaries’ credit agreements and indentures contain covenants and events of default that may limit our financial flexibility and ability to undertake certain types of transactions. For instance, we and our subsidiaries are subject to covenants that restrict our activities, including restrictions on:

• creating liens;

• engaging in mergers, consolidations and sales of assets;

• incurring additional indebtedness;

• providing guarantees;

• engaging in different businesses;

• making investments;

• making certain dividend, debt and other restricted payments;

• engaging in certain transactions with affiliates; and

• entering into certain contractual obligations.

Debt instruments of our and our subsidiaries are subject to financial covenants. Our ability and that of our subsidiaries to comply with these covenants will depend on factors outside our control, including refined product margins. We cannot assure you that we and our subsidiaries will satisfy these covenants. If we fail to satisfy the covenants set forth in these facilities or an event of default occurs under the applicable facility, the maturity of the debt instruments could be accelerated or we could be prohibited from borrowing for our working capital needs and issuing letters of credit. A similar result could occur if our subsidiaries fail to satisfy the covenants applicable to them in their respective debt instruments. If our and our subsidiaries' obligations under the debt instruments are accelerated and we do not have sufficient cash on hand to pay all amounts due, we could be required to sell assets, to refinance all or a portion of our indebtedness or to obtain additional financing through equity or debt financings. Refinancing may not be possible and additional financing may not be available on commercially acceptable

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terms, or at all. If we or our subsidiaries cannot borrow or issue letters of credit under our respective credit agreements, we would need to seek additional financing, if available, or curtail our operations.

We have capital needs for which our internally generated cash flows and other sources of liquidity may not be adequate.

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

Our refineries consist of many processing units, a number of which have been in operation for many years. Equipment, even if properly maintained, may require significant capital expenditures and expenses to keep it operating at optimum efficiency. One or more of the units may require unscheduled downtime for unanticipated maintenance or repairs that are more frequent than our scheduled turnaround for such units. Scheduled and unscheduled maintenance could reduce our revenues during the period of time that the units are not operating. We have taken significant measures to expand and upgrade units in our refineries by installing new equipment and redesigning older equipment to improve refinery capacity. The installation and redesign of key equipment at our refineries involves significant uncertainties, including the following: our upgraded equipment may not perform at expected throughput levels; the yield and product quality of new equipment may differ from design and/or specifications and redesign or modification of the equipment may be required to correct equipment that does not perform as expected that could require facility shutdowns until the equipment has been redesigned or modified. Any of these risks associated with new equipment, redesigned older equipment or repaired equipment could lead to lower revenues or higher costs or otherwise have a material adverse effect on our business, financial condition, results of operations and cash flows.

The dangers inherent in our operations and our reliance on logistics assets could cause disruptions and could expose us to potentially significant losses, costs or liabilities. Any significant interruptions in the operations of any of our refineries could materially and adversely affect our business, financial condition, results of operations and cash flows.

Our operations are subject to significant hazards and risks inherent in refining operations and in transporting and storing crude oil, intermediate products and refined products. Failure to identify and manage these risks could result in explosions, fires, refinery or pipeline releases of crude oil or refined products or other incidents resulting in personal injury, loss of life, environmental damage, property damage, legal liability, loss of revenue and substantial fines by government authorities. These hazards and risks include, but are not limited to, the following:

• natural disasters;

• weather-related disruptions;

• fires;

• explosions;

• pipeline ruptures and spills;

• third-party interference;

• disruption of natural gas deliveries;

• disruptions of electricity deliveries;

• disruption of sulfur gas processing by Veolia at our El Paso refinery; and

• mechanical failure of equipment at our refineries or third-party facilities.

Any of the foregoing could result in production and distribution difficulties and disruptions, environmental pollution, personal injury or wrongful death claims and other damage to our properties and the properties of others. There is also risk of mechanical failure and equipment shutdowns both in general and following unforeseen events. For example, we may experience unplanned downtime at our El Paso, Gallup or St. Paul Park refineries due to weather, interruptions to our electrical supply or other causes. In any of these situations, undamaged refinery processing units may be dependent on or interact with damaged process units and, accordingly, may also be subject to being shut down.

Our refineries consist of many processing units, several of which have been in operation for a long time. One or more of the units may require unscheduled downtime for unanticipated maintenance or repairs, or our planned turnarounds may last longer than anticipated. Scheduled and unscheduled maintenance could reduce our revenues and increase our costs during the period of time that our units are not operating.

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Our refining activities are conducted at our El Paso refinery in Texas, our Gallup refinery in New Mexico and our St. Paul Park refinery in Minnesota. The refineries constitute a significant portion of our operating assets, and our refineries supply a significant portion of our fuel to our wholesale and retail operations.

In addition, we rely on a variety of logistics assets including but not limited to: rail, pipelines, product terminals, storage tanks and trucks to facilitate the movement of crude oil, feedstocks and refined products within our business. Some of these assets are owned and or operated by WNRL or third-parties. We could experience an interruption of supply or an increased cost to deliver refined products to market if the ability to utilize these logistics assets is disrupted.

Because of the significance to us of our refining operations and the logistics assets they depend on, the occurrence of any of the events described above could significantly disrupt our production and distribution of refined products and any sustained disruption could have a material adverse effect on our business, financial condition, results of operations and cash flows.

Weather conditions and natural disasters could materially and adversely affect our business and operating results, including the supply of our feedstocks.

The effects of weather conditions and natural disasters can lead to volatility in the costs and availability of crude oil and other feedstocks and/or negatively impact our operations or those of our customers and suppliers, which could have a material adverse effect on our business, financial condition, results of operations and cash flows. Crude oil supplies for our El Paso and Gallup refineries primarily come from the Permian Basin in Texas and New Mexico, other basins in Northern New Mexico and basins in Utah. As a result, our El Paso and Gallup refineries may be disproportionately exposed to the impact of delays or interruptions of supply from these regions caused by natural disasters or adverse weather conditions. In addition, from time to time, we may obtain certain of our feedstocks for the El Paso and Gallup refineries and some refined products we purchase for resale by pipeline from Gulf Coast refineries that are subject to severe weather risks such as hurricanes and other severe events. Crude oil supplies for our St. Paul Park refinery are from the Bakken Shale of North Dakota and from Western Canada. As a result, our St. Paul Park refinery may be disproportionately exposed to the impact of delays or interruptions of supply from that region caused by natural disasters or adverse weather conditions. An interruption to our supply of feedstocks for the El Paso or the St. Paul Park refineries could have a material adverse effect on our business, financial condition, results of operations and cash flows.

Our operations involve environmental risks that could give rise to material liabilities.

Our operations, and those of prior owners or operators of our properties, have previously resulted in spills, discharges, or other releases of petroleum or hazardous substances into the environment, and such spills, discharges or releases could also happen in the future. Past or future spills related to any of our operations, including our refineries, product terminals, convenience stores or transportation of refined products or hazardous substances from those facilities, may give rise to liability (including strict liability, or liability without fault, and clean-up responsibility) to governmental entities or private parties under federal, state, or local environmental laws, as well as under common law. For example, we could be held strictly liable under the Comprehensive Environmental Responsibility, Compensation and Liability Act for contamination of properties that we currently own or operate and facilities to which we transported or arranged for the transportation of wastes or by-products for use, treatment, storage or disposal, without regard to fault or whether our actions were in compliance with law at the time. Our liability could also increase if other responsible parties, including prior owners or operators of our facilities, fail to complete their clean-up obligations. Based on current information, we do not believe these liabilities are likely to have a material adverse effect on our business, financial condition, results of operations or cash flows. In the event that new spills, discharges, or other releases of petroleum or hazardous substances occur or are discovered or there are other changes in facts or in the level of contributions being made by other responsible parties, there could be a material adverse effect on our business, financial condition, results of operations and cash flows.

In addition, we may face liability for alleged personal injury or property damage due to exposure to chemicals or other hazardous substances located at or released from our facilities or otherwise related to our current or former operations. We may also face liability for personal injury, property damage, natural resource damage, or for clean-up costs for the alleged migration of contamination or other hazardous substances from our facilities to adjacent and other nearby properties.

We may incur significant costs to comply with environmental, health and safety laws and regulations.

Our operations and properties are subject to extensive federal, state and local environmental, health and safety regulations governing, among other things, the generation, storage, handling, use and transportation of petroleum and hazardous substances, the emission and discharge of materials into the environment, waste management, characteristics and composition of gasoline, diesel and other fuels and the monitoring, reporting and control of greenhouse gas emissions. If we fail to comply with these regulations, we may be subject to administrative, civil and criminal proceedings by governmental authorities, as well as civil proceedings by environmental groups and other entities and individuals. A failure to comply, and any related proceedings, including lawsuits, could result in significant costs and liabilities, penalties, judgments against us or governmental or court orders that could alter, limit or stop our operations.

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In addition, new environmental laws and regulations, including new regulations relating to alternative energy sources and increased vehicle fuel economy, new state regulations relating to fuel quality, and the risk of global climate change regulation, as well as new interpretations of existing laws and regulations, increased governmental enforcement, or other developments could require us to make additional unforeseen expenditures. Many of these laws and regulations are becoming increasingly stringent, and the cost of compliance with these requirements can be expected to increase over time. We are not able to predict the impact of new or changed laws or regulations or changes in the ways that such laws or regulations are administered, interpreted, or enforced. The requirements to be met, as well as the technology and length of time available to meet those requirements, continue to develop and change. To the extent that the costs associated with meeting any or all of these requirements are substantial and not adequately provided for, there could be a material adverse effect on our business, financial condition, results of operations and cash flows.

The EPA has issued rules pursuant to the Clean Air Act that require refiners to reduce the sulfur content of gasoline and diesel fuel and reduce the benzene content of gasoline by various specified dates. We incurred, and may incur in the future, substantial costs to comply with the EPA’s low sulfur and low benzene rules. Our strategy for complying with low sulfur gasoline and low benzene gasoline regulations at our refineries relies partially on purchasing credits. If credits are not available or are too costly, we may not be able to meet the EPA’s deadlines using a credit strategy. Failure to meet the EPA’s clean fuels mandates could have a material adverse effect on our business, financial condition, results of operations and cash flows.

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

Renewable fuels mandates may reduce demand for the petroleum fuels we produce, which could have a material adverse effect on our business, financial condition, results of operations and cash flows.

Pursuant to the Energy Policy Act of 2005 and the Energy Independence and Security Act of 2007, the EPA has promulgated the RFS implementing mandates to blend renewable fuels into petroleum fuels produced and sold in the United States. We are subject to the RFS, which requires obligated parties to blend renewable fuels, such as ethanol, into petroleum fuels sold in the United States. A RIN is generated for each gallon of renewable fuel produced under the RFS. At the end of each year, obligated parties must surrender sufficient RINs to meet their renewable fuel obligations under the RFS. The obligated volume increases annually over time until 2022. The obligation for our refineries is met through a combination of blending renewable fuels and purchasing RINs from other parties. We must also purchase waiver credits for cellulosic biofuels from the EPA. Uncertainty surrounding RFS requirements in recent years has resulted in increased volatility in RIN prices. We cannot predict the future prices of RINs or waiver credits, but the costs to obtain the necessary number of RINs and waiver credits could be material.

In 2010 and 2011, the EPA issued partial waivers with conditions allowing a maximum of 15% ethanol to be used in certain vehicles. Future changes to existing laws and regulations could increase the minimum volumes of renewable fuels that must be blended with refined petroleum fuels. Because we do not produce renewable fuels, increasing the volume of renewable fuels that must be blended into our products could displace an increasing volume of our refineries’ product pool, potentially resulting in lower earnings and materially adversely affecting our business, financial condition and results of operations and cash flows.

Certain states, including Minnesota and New Mexico, have renewable fuel mandates that could further displace volume of a refinery's product pool. Minnesota law currently requires that all diesel sold in the state for use in internal combustion engines, with limited exceptions, must contain at least 10% biodiesel which may increase to 20% in 2018. Minnesota law also currently requires, with limited exceptions, that all gasoline sold or offered for sale in the state must contain the maximum amount of ethanol allowed under federal law for use in all gasoline powered motor vehicles. New Mexico law currently requires that all diesel sold in the state for use in internal combustion engines, with limited exceptions, must contain at least 5% biodiesel. Although the state has historically waived this mandate due to infrastructure limitations within the state, future waivers are not guaranteed.

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If sufficient RINs are unavailable for purchase or if we have to pay a significantly higher price for RINs, or if we are otherwise unable to meet the EPA's RFS mandates, our business, financial condition and results of operations could be materially adversely affected.

Under the RFS, the volume of renewable fuels refineries are obligated to blend into their finished petroleum products is adjusted annually. We currently blend renewable fuels and purchase RINs on the open market, as well as waiver credits for cellulosic biofuels from the EPA, in order to comply with the RFS. Existing laws or regulations could change, and the minimum volumes of renewable fuels that must be blended with refined petroleum products may increase. In the future, we may be required to purchase additional RINs on the open market and waiver credits from the EPA in order to comply with the RFS.

During 2013, the price of RINs was very volatile as the EPA’s proposed renewable fuel volume mandates approached the "blend wall." The blend wall refers to the point at which refiners are required to blend more ethanol into the transportation fuel supply than can be supported by the demand for E10 gasoline (gasoline containing 10 percent ethanol by volume). In November 2013, the EPA published the annual renewable fuel percentage standards for 2014, which acknowledged the blend wall and were generally lower than the volumes for 2013 and lower than statutory mandates. The price of RINs decreased significantly after the 2014 percentage standards were published; however, RIN prices remained volatile and increased subsequently in 2014. In November 2015, the EPA published final notice for RFS obligated volumes for 2014, 2015 and 2016 and Biomass-Based Diesel for 2017. The current standard may cause the blend wall to again become an issue affecting the overall supply of RINs.

We cannot predict the future prices of RINs or waiver credits. The cost of RINs is dependent upon a variety of factors, which include EPA regulations, the availability of RINs for purchase, the price at which RINs can be purchased, transportation fuel production levels, the mix of our petroleum products, as well as the fuel blending performed at our refineries, all of which can vary significantly from quarter to quarter. Additionally, because we do not produce renewable fuels, increasing the volume of renewable fuels that must be blended into our products could displace an increasing volume of our refineries' product pool, potentially resulting in lower earnings. If sufficient RINs are unavailable for purchase or if we have to pay a significantly higher price for RINs, or if we are otherwise unable to meet the EPA's RFS mandates, our business, financial condition, results of operations and cash flows could be materially adversely affected.

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

The EPA has adopted and implemented regulations to restrict emissions of greenhouse gases under certain provisions of the Clean Air Act. For example, the EPA requires, in certain circumstances, permitting of certain emissions of greenhouse gases from large stationary sources, such as refineries. The EPA has also adopted rules requiring refiners to report greenhouse gas emissions on an annual basis for emissions occurring after January 1, 2010. Further, the United States Congress has considered legislation related to the reduction of greenhouse gases through “cap and trade” programs. In addition, Minnesota is a participant in the Midwest Greenhouse Gas Reduction Accord, a non-binding resolution that could lead to the creation of a regional greenhouse gas cap-and-trade program if the Minnesota legislature and the legislatures of other participating states and province enact implementing legislation. Although the participating states and Canadian province are not currently pursuing this commitment, similar state or regional initiatives may be pursued in the future.

On the international level, on December 12, 2015, 195 nations, including the U.S., finalized the text of an international climate change accord in Paris, France (the “Paris Agreement”). The Paris Agreement calls for countries to set their own GHG emissions targets, make these emissions targets more stringent over time and be transparent about the GHG emissions reporting and the measures each country will use to achieve its GHG emissions targets. Additional U.S. GHG emissions reduction laws, regulations or other initiatives may be required in the future in connection with the Paris Agreement.

To the extent that future legislation, rules and regulations are enacted, our operating costs, including capital expenditures, may increase and additional operating restrictions could be imposed on our business, which could have a material adverse effect on our business, financial condition, results of operations and cash flows. Finally, some scientists have concluded that increasing concentrations of greenhouse gases in the earth’s atmosphere may produce climate changes that may have significant physical effects, such as increased frequency and severity of storms, droughts, floods and other climatic events, which if any such event were to occur, it may have a material adverse effect on our business, financial condition, results of operations and cash flows.

Increased regulation of hydraulic fracturing could result in reductions or delays in crude oil production in our existing areas of operation, which could impact our crude oil supply and adversely impact our business.

A significant percentage of the crude oil production in our existing areas of operation is being developed from unconventional sources, such as shale, using hydraulic fracturing. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into the formation to stimulate production. A number of federal agencies, including the EPA and the U.S. Department of Energy, are analyzing, or have been requested to review, a variety of environmental issues associated with

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shale development, including hydraulic fracturing. In addition, the EPA has asserted federal regulatory authority over hydraulic fracturing activities under the Safe Drinking Water Act’s Underground Injection Control Program and under the Toxic Substances Control Act of 1976 and in September 2015 issued proposed rules regulating methane emissions from oil and natural gas completion operations. The rules were finalized in June 2016 and became effective in August 2016. Further, some states and municipalities have adopted and other states and municipalities are considering adopting, regulations prohibiting hydraulic fracturing in certain areas or imposing more stringent disclosure. At the same time, certain environmental groups have suggested that additional laws may be needed to more closely and uniformly regulate the hydraulic fracturing process and legislation has been proposed by some members of Congress to provide for such regulation. We cannot predict whether any such legislation will ever be enacted and if so, what its provisions would be. If additional levels of regulation are imposed at the federal, state or local level, this could result in corresponding delays, increased operating costs and process prohibitions for crude oil producers and potentially negatively impact our crude oil supply, which could adversely affect our business, financial condition, results of operations and cash flows.

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

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

We could experience business interruptions caused by pipeline shutdown.

Our El Paso refinery is our largest refinery and is dependent on a pipeline owned by Kinder Morgan for the delivery of all of our crude oil. Because our crude oil refining capacity at the El Paso refinery is approaching the delivery capacity of the pipeline, our ability to offset lost production due to disruptions in supply with increased future production is limited due to this crude oil supply constraint. In addition, we will be unable to take advantage of further expansion of the El Paso refinery’s production without securing additional crude oil supplies or pipeline expansion. We also deliver a substantial percentage of the refined products produced at our El Paso refinery through three principal product pipelines.

We also have a pipeline system that delivers crude oil and natural gas liquids to our Gallup refinery. The Gallup refinery is dependent on the crude oil pipeline system for the delivery of the crude oil necessary to run the refinery. If the operation of the pipeline system is disrupted, we may not receive the crude oil necessary to run the refinery. Certain rights-of-way necessary for our crude oil pipeline system to deliver crude oil to our Gallup refinery must be renewed periodically.

Our St. Paul Park refinery receives all of its crude oil and delivers a portion of its refined products through pipelines. We distribute a portion of its transportation fuels through pipelines owned and operated by Magellan. In addition, we are dependent on the Minnesota Pipeline system that is the supply route for crude oil and transported all of the crude oil used at the refinery. Because we only have a minority equity interest in the pipeline, we do not have full control over the performance of the pipeline.

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

As a result, we could experience an interruption of supply or delivery, or an increased cost of receiving crude oil and delivering refined products to market, if the ability of these pipelines to transport crude oil, blended stocks or refined products is disrupted because of accidents, weather interruption, governmental regulation, terrorism, other third-party action, or any other events beyond our control. A prolonged inability to receive crude oil or transport refined products on pipelines that we currently utilize could have a material adverse effect on our business, financial condition, results of operations and cash flows.

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

We continually contract with third-party crude oil suppliers to maintain a sufficient supply of crude oil for production at our refineries. A material decrease in crude oil production from the fields, that supply our refineries as a result of economic, regulatory, or natural influences, availability of equipment, facilities, personnel or services, plant closures for scheduled maintenance, or transportation problems, or an increase in crude oil transport capacities out of the regions that supply our refineries, could result in a decline in the volume of crude oil available to our refineries. In addition, the future growth of our

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operations may depend in part on whether we can contract for additional supplies of crude oil at a greater rate than the rate of decline in our current supplies. If we are unable to secure sufficient crude oil supplies to our refineries, we may not be able to take full advantage of current and future expansion of our refineries' production capacities. A decline in available crude oil to our refineries or an inability to secure additional crude oil supplies to meet the needs of current or future refinery expansions could result in an overall decline in volumes of refined products produced by our refineries and could have a material adverse effect on our business, financial condition, results of operations and cash flows.

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

Our operations require numerous permits and authorizations under various laws and regulations, including environmental and health and safety laws. These authorizations and permits are subject to revocation, renewal or modification and can require operational changes that may involve significant costs, to limit impacts or potential impacts on the environment, health and safety and/or our and our subsidiaries’ permits and licenses relating to the sale of alcohol and tobacco products. A violation of these authorization or permit conditions or other legal or regulatory requirements could result in substantial fines, criminal sanctions, permit revocations, injunctions and/or refinery shutdowns. In addition, major modifications of our operations could require modifications to our existing permits or expensive upgrades to our existing pollution control equipment that could have a material adverse effect on our business, financial condition, results of operations and cash flows.

Competition in the refining, marketing and retail industries is intense and an increase in competition in the areas in which we sell our refined products could adversely affect our sales and profitability.

We compete with a broad range of refining and marketing companies, including certain multinational oil companies. Because of their geographic diversity, larger and more complex refineries, integrated operations and greater resources, some of our competitors may be better able to withstand volatile market conditions, to compete on the basis of price, to obtain crude oil in times of shortage and to bear the economic risks inherent in all phases of the refining industry.

We are not engaged in the petroleum exploration and production business and therefore do not produce any of our crude oil feedstocks. Certain of our competitors, however, obtain a portion of their feedstocks from their own production. Competitors that have their own production are at times able to offset losses from refining operations with profits from production, and may be better positioned to withstand periods of depressed refining margins or feedstock shortages. In addition, we compete with other industries that provide alternative means to satisfy the energy and fuel requirements of our industrial, commercial and individual consumers. If we are unable to compete effectively with these competitors, both within and outside of our industry, there could be a material adverse effect on our business, financial condition, results of operations and cash flows.

The areas where we sell refined products are also supplied by various refined product pipelines. Any expansions or additional product supplied by these third-party pipelines could put downward pressure on refined product prices in these areas.

Portions of our operations in the areas we operate may be impacted by competitors’ plans, as well as plans of our own, for expansion projects and refinery improvements that could increase the production of refined products. In addition, we anticipate that lower quality crude oils that are typically less expensive to acquire, can and will be processed by our competitors as a result of refinery improvements. These developments could result in increased competition in the areas in which we operate.

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

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

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

A portion of our strategy to grow our business is dependent on our ability to make selective acquisitions. We actively seek to acquire assets such as refineries, pipelines, terminals and retail fuel and convenience stores that complement our existing assets and/or broaden our geographic presence. For example, during 2013 we formed WNRL to develop and acquire terminals, storage tanks, pipelines and other logistics assets. WNRL’s acquisition strategy is based, in large part, on its expectation of ongoing divestitures of gathering, transportation and storage assets by industry participants, including Western. Additionally, the NTI Merger was successfully completed on June 23, 2016.

Any acquisition involves potential risks, including, among other things:

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

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

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

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

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

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

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

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

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

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

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

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

Our insurance policies do not cover all losses, costs or liabilities that we may experience.

Our insurance coverage does not cover all potential losses, costs or liabilities. We could suffer losses for uninsurable or uninsured risks or in amounts in excess of our existing insurance coverage. Our ability to obtain and maintain adequate insurance may be adversely affected by conditions in the insurance market over which we have no control. In addition, if we experience any more insurable events, our annual premiums could increase further or insurance may not be available at all. The occurrence of an event that is not fully covered by insurance or the loss of insurance coverage could have a material adverse effect on our business, financial condition, results of operations and cash flows.

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

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

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

As of December 31, 2016, we employed approximately 7,134 people, with collective bargaining agreements covering about 620 of those employees. WNRL employs approximately 559 employees in its wholesale segment. During 2014, we renegotiated a collective bargaining agreement covering employees at our Gallup refinery that expires in 2020. We also negotiated a new collective bargaining agreement covering employees at our El Paso refinery, renewing the collective bargaining agreement to expire in April of 2021. We also have collective bargaining agreement that expires in December2020 associated with the operations of the St. Paul Park refining operations and another collective bargaining agreement associated

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with SuperAmerica retail operations that expires in August 2017. While our El Paso, Gallup and St. Paul Park collective bargaining agreements contain “no strike” provisions, those provisions are not effective in the event that an agreement expires. Accordingly, we may not be able to prevent a strike or work stoppage in the future, and any such work stoppage could cause disruptions in our business and have a material adverse effect on our business, financial condition, results of operations and cash flows.

Long-lived and intangible assets comprise a significant portion of our total assets.

Long-lived assets and both amortizable intangible assets and intangible assets with indefinite lives must be tested for recoverability whenever events or changes in circumstances indicate that the carrying amount of those assets may not be recoverable. We evaluate the remaining useful lives of our intangible assets with indefinite lives at least annually. If events or circumstances no longer support an indefinite life, the intangible asset is tested for impairment and prospectively amortized over its estimated remaining useful life. Long-lived and amortizable intangible assets are not recoverable if their carrying amount exceeds the sum of the undiscounted cash flows expected to result from their use and eventual disposition. If a long-lived or amortizable intangible asset is not recoverable, an impairment loss is recognized in an amount by which its carrying amount exceeds its fair value, with fair value determined generally based on discounted estimated net cash flows.

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

Our operating results are seasonal and generally lower in the first and fourth quarters of the year.

Demand for gasoline is generally higher during the summer months than during the winter months. As a result, our operating results for the first and fourth calendar quarters are generally lower than those for the second and third calendar quarters of each year. In addition, unseasonably cool weather in summer months and/or unseasonably warm weather in winter months in the regions where we sell our refined products can impact the demand for gasoline and diesel.

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

Our ability to pay dividends in the future is limited by contractual restrictions and cash generated by operations.

We are a holding company and all of our operations are conducted through our subsidiaries. Consequently, we will rely on dividends or advances from our subsidiaries to fund any dividends. The ability of our operating subsidiaries to pay dividends and our ability to receive distributions from those entities are subject to applicable local law.

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

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

In addition, our ability to pay dividends to our stockholders is subject to certain restrictions in our debt instruments and such restrictions could restrict our ability to pay dividends in the future. In addition, our payment of dividends will depend upon our ability to generate sufficient cash flows. Our board of directors will review our dividend policy periodically in light of the factors referred to above, and we cannot assure you of the amount of dividends, if any, that may be paid in the future.

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Under the Tesoro Merger Agreement, we have agreed that, until the completion of the Tesoro Merger, we will not declare, set aside, make or pay any dividend or other distribution in respect of any of our capital stock, except for regular quarterly cash dividends to the holders of shares of our common stock in an amount not in excess of $0.38 per share.

Our controlling stockholders may have conflicts of interest with other stockholders in the future.

Mr. Paul Foster, our Executive Chairman, and Messrs. Jeff Stevens, our Chief Executive Officer and President and a current director, and Scott Weaver, a current director, own approximately 22.5% of our common stock as of February 24, 2017. As a result, Mr. Foster and the other members of this group may strongly influence or effectively control the election of our directors, our corporate and management policies, and determine, without the consent of our other stockholders, the outcome of any corporate transaction or other matter submitted to our stockholders for approval, including potential mergers or acquisitions, asset sales, and other significant corporate transactions. The interests of Mr. Foster and the other members of this group may not coincide with the interests of other holders of our common stock.

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

Our future performance depends to a significant degree upon the continued contributions of our senior management team, including our executive officers and key technical employees. We do not currently maintain key man life insurance with respect to any member of our senior management team. The loss or unavailability to us of any member of our senior management team or a key technical employee could significantly harm us. We face competition for these professionals from our competitors, our customers and other companies operating in our industry. To the extent that the services of members of our senior management team would be unavailable to us for any reason, we would be required to hire other personnel to manage and operate our companies. We may not be able to locate or employ such qualified personnel on acceptable terms, or at all.

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

Terrorist attacks in the U.S. as well as events occurring in response to or in connection with them, may adversely affect our operations, financial condition, results of operations, cash flows and prospects. Energy-related assets (that could include refineries and terminals such as ours or pipelines such as the ones on which we depend for our crude oil supply and refined product distribution) may be at greater risk of future terrorist attacks than other possible targets. A direct attack on our assets or assets used by us could have a material adverse effect on our operations, financial condition, results of operations, cash flows and prospects. In addition, any terrorist attack could have an adverse impact on energy prices, including prices for our crude oil and refined products and an adverse impact on the margins from our refining and marketing operations. In addition, disruption or significant increases in energy prices could result in government imposed price controls. While we currently maintain some insurance that provides coverage against terrorist attacks, such insurance has become increasingly expensive and difficult to obtain. As a result, insurance providers may not continue to offer this coverage to us on terms that we consider affordable, or at all.

We are dependent on technology infrastructure and maintain and rely upon certain critical information systems for the effective operation of our businesses. These information systems include data network and telecommunications, internet access and our websites and various computer hardware equipment and software applications. These information systems are subject to damage or interruption from a number of potential sources including natural disasters, software viruses or other malware, power failures, cyber-attacks and other events. To the extent that these information systems are under our control, we have implemented measures such as virus protection software and emergency recovery processes to address the outlined risks. However, security measures for information systems cannot be guaranteed. Breaches to our networks could lead to such information being accessed, publicly disclosed, lost or stolen, and could result in legal claims or proceedings, liability under laws that protect the privacy of customer information, disrupt the services we provide and damage our reputation, any of which could have a material adverse effect on our business, financial condition, results of operations and cash flows. Any compromise of our data security or our inability to use or access these information systems at critical points in time could unfavorably impact the timely and efficient operation of our business and subject us to additional costs and liabilities.

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

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

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each of these obligations that could consequently have a material adverse effect on our business, results of operations or liquidity.

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

Our business is highly dependent on financial, accounting and other data processing systems and other communications and information systems, including our enterprise resource planning tools and credit and debit card sales at our retail stores and within our wholesale business. We process a large number of transactions and transmit confidential credit and debit card information securely over public networks on a daily basis and rely upon the proper functioning of computer systems. If a key system was to fail or experience unscheduled downtime for any reason, even if only for a short period, our operations and financial results could be affected adversely. These information systems are subject to damage or interruption from a number of potential sources including natural disasters, software viruses or other malware, power failures, cyber-attacks and other events. To the extent that these information systems are under our control, we have implemented measures such as virus protection software, intrusion detection systems and emergency recovery processes to address the outlined risks. However, security measures for information systems cannot be guaranteed to be failsafe. Any security breach could expose us to risks of data loss, litigation and liability and could seriously disrupt our operations and any resulting negative publicity could significantly harm our reputation. Our formal disaster recovery plan may not prevent delays or other complications that could arise from an information systems failure. Further, our business interruption insurance may not compensate us adequately for losses that may occur.

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

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

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

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

One of our subsidiaries acts as the general partner of a master limited partnership that may involve a higher exposure to legal liability than our historic business operations.

Western Refining Logistics GP, LLC acts as the general partner of WNRL, a master limited partnership. Our control of the general partner of WNRL may increase the possibility of claims of breach of fiduciary duties, including claims of conflicts of interest related to WNRL. Any liability resulting from such claims could have a material adverse effect on our future business, financial condition, results of operations and cash flows.

Derivatives regulation in the United States could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price and other risks associated with our business.

We use derivative instruments to manage our commodity price risk. The Dodd-Frank Act was enacted in 2010. Many of the provisions of the Dodd-Frank Act require implementing regulations by agencies including the Commodity Futures Trading Commission (the “CFTC”) and the SEC. The CFTC has implemented the majority of its rules governing swaps, including many commodity swaps.

Of particular importance to us, the CFTC has the authority, under certain findings, to establish position limits for certain futures, options on futures and swap contracts. As of today, there are position limits governing the holding of futures positions in nine agricultural contracts. Certain bona fide hedging transactions or positions are exempt from these position limits. In 2011, the CFTC adopted position limit rules that expanded the types of contracts covered by the limits to include additional agricultural commodities, as well as certain metals and energy contracts, as well as to include swaps on those contracts. Those rules were subsequently vacated by the U.S. District Court for the District of Columbia. Starting in November 2013, the CFTC has, through a series of actions, re-proposed these swap and expanded position limits rules. Whether and when these proposed rules or other position limits rules will be adopted, and the applicability of any adopted rules to us and the impact on our ability to cost-effectively hedge our commodity risks, remain unclear.

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

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

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

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

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

Item 1B. Unresolved Staff Comments

None.

Item 2. Properties

Western Refining, Inc.

Our principal properties are described under Item 1. Business and the information is incorporated herein by reference. As of December 31, 2016, we were a party to a number of cancelable and non-cancelable leases for certain properties, including our corporate headquarters in El Paso and administrative offices in Tempe, Arizona. See Note 25, Leases and Other Commitments, in the Notes to Consolidated Financial Statements included elsewhere in this annual report.

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Northern Tier Energy LP

NTI's principal properties are described under Item 1. Business and the information is incorporated herein by reference. As of December 31, 2016, NTI was a party to a number of cancelable and non-cancelable leases for certain properties. See Note 17. Leasing Arrangements, in NTI's Notes to Consolidated Financial Statements included elsewhere in this annual report.

Item 3. Legal Proceedings

Western Refining, Inc.

In the ordinary conduct of our business, we are subject to periodic lawsuits, investigations and claims, including environmental claims and employee related matters. Although we cannot predict with certainty the ultimate resolution of lawsuits, investigations and claims asserted against us, we do not believe that any currently pending legal proceeding or proceedings to which we are a party will have a material adverse effect on our business, financial condition, results of operations or cash flows. See "Legal Matters" in Note 23, Contingencies, in the Notes to Consolidated Financial Statements included in this annual report for further discussion.

Northern Tier Energy LP

In the ordinary conduct of NTI's business, it is subject to periodic lawsuits, investigations and claims, including environmental claims and employee related matters. Although NTI cannot predict with certainty the ultimate resolution of lawsuits, investigations and claims asserted against it, NTI does not believe that any currently pending legal proceedings or proceedings to which it is a party will have a material adverse effect on its business, financial condition, results of operations or cash flows. See "Legal Matters" in Note 18, Commitments and Contingencies, in NTI's Notes to Consolidated Financial Statements included in this annual report for further discussion.

Item 4. Mine Safety Disclosures

Not Applicable.

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PART II

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

Market Information

Our common stock is listed on the NYSE under the symbol “WNR.” As of February 24, 2017, we had 55 holders of record of our common stock. The following table summarizes the high and low sales prices of our common stock as reported on the NYSE Composite Tape for the quarterly periods in the past two fiscal years and dividends declared on our common stock for the same periods:

	High		Low		Dividends per Common Share
2016:
First quarter	$	39.76	$	24.43	$	0.38
Second quarter	29.45		18.14		0.38
Third quarter	28.83		19.18		0.38
Fourth quarter	40.09		26.04		0.38
2015:
First quarter	$	51.31	$	31.83	$	0.30
Second quarter	50.48		41.65		0.34
Third quarter	50.71		38.02		0.34
Fourth quarter	47.55		34.58		0.38

Our payment of dividends is limited under the terms of our Western Revolving Credit Agreement, our Senior Unsecured Notes and our Term Loan Credit Agreement, and in part, depends on our ability to satisfy certain financial covenants. Also, as a holding company, we rely on dividends or advances from our subsidiaries to fund any dividends. The ability of WNRL to pay us dividends is restricted by covenants in its debt instruments and any future financing agreements. Throughout 2016, our board of directors approved and we declared quarterly cash dividends totaling $152.7 million paid on various dates throughout the year.

On January 4, 2017, our board of directors approved a cash dividend for the first quarter of 2017 of $0.38 per share of common stock in an aggregate payment of approximately $41.3 million that was paid on February 2, 2017 to holders of record on January 18, 2017.

Under the Tesoro Merger Agreement, we have agreed that, until the completion of the Tesoro Merger, we will not declare, set aside, make or pay any dividend or other distribution in respect of any of our capital stock, except for regular quarterly cash dividends to the holders of shares of our common stock in an amount not in excess of $0.38 per share.

Securities Authorized for Issuance Under Equity Compensation Plans

See Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.

Performance Graph

The following performance graph and related information shall not be deemed “soliciting material” or “filed” with the SEC, nor shall such information be incorporated by reference into any further filings under the Securities Act of 1933 or the Securities Exchange Act of 1934, each as amended, except to the extent we specifically incorporate it by reference into such filing.

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The following graph compares the cumulative 60-month total stockholder return on our common stock relative to the cumulative total stockholder returns of the Standard & Poor’s ("S&P, 500") index and a customized peer group of six companies that includes: Alon USA Energy, Inc., CVR Energy, Inc., Delek US Holdings Inc., HollyFrontier Corp., Tesoro Corp. and Valero Energy Corp. An investment of $100 (with reinvestment of all dividends) is assumed to have been made in our common stock and peer group on December 31, 2011. The index on December 31, 2016, and its relative performance are tracked through this date. The stock price performance included in this graph is not necessarily indicative of future stock price performance.

COMPARISON OF 5 YEAR CUMULATIVE TOTAL RETURN

(Tabular representation of data in graph above)

	Dec		Dec		Dec		Dec		Dec		Dec
	2011		2012		2013		2014		2015		2016
Western Refining, Inc.	$	100.00	$	234.96	$	360.76	$	346.01	$	336.49	$	378.47
S&P 500	100.00		116.00		153.57		174.60		177.01		198.18
Peer Group	100.00		189.75		265.54		264.69		358.70		335.83

Purchases of Equity Securities by the Issuer and Affiliated Purchasers

Between July 18, 2012 and December 31, 2016, our board of directors authorized five separate share repurchase programs of up to $200 million, per program, of our outstanding common stock. Our board of directors approved a share repurchase program in September of 2015 that expired on December 31, 2016. Through December 31, 2016, we have purchased 23.0 million shares of our common stock under the share repurchase programs. On December 31, 2016, we had no active share repurchase program. Under the Tesoro Merger Agreement, we have agreed that, until the completion of the Tesoro Merger, we will not purchase or otherwise acquire any of our common stock.

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The following table presents shares repurchased, by month, during 2016.

	Total number of shares purchased as part of publicly announced plans or programs (1)	Average price paid per share		Maximum dollar value of shares that may yet be purchased under the programs (In thousands) (2)
January 1 - January 31	786,138	$	31.80	$	175,000
February 1 - February 29	1,676,212	29.83		125,000
March 1 - March 31	—	—		125,000
April 1 - April 30	—	—		125,000
May 1 - May 31	—	—		125,000
June 1 - June 30	—	—		125,000
July 1 - July 31	—	—		125,000
August 1 - August 31	—	—		125,000
September 1 - September 30	—	—		125,000
October 1 - October 31	—	—		125,000
November 1 - November 30	—	—		125,000
December 1 - December 31	—	—		—
Total	2,462,350	$	30.46

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

(2) On September 21, 2015, our board of directors authorized a share repurchase program of up to $200 million, which expired on December 31, 2016 with $125.0 million in remaining funds authorized under the program.

Northern Tier Energy LP

NTI is a wholly-owned subsidiary of Western and there is no public market for its equity securities.

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Item 6. Selected Financial Data

The following tables set forth a summary of our historical financial and operating data for the periods indicated. The summary results of operations and financial position data as of and for the five years ended December 31, 2016, have been derived from the consolidated financial statements of Western Refining, Inc. and its subsidiaries.

The information presented includes the results of operations of NTI beginning November 12, 2013, the date of our initial acquisition of NTI (the "2013 NTI Acquisition"). The information presented also includes the financial results for WNRL from October 16, 2013 forward. In addition to the impact of the non-controlling interests in net income of NTI and WNRL, refinery margins have decreased due to additional fees paid by Western to WNRL for logistics services and refining direct operating expenses have decreased for the costs associated with WNRL that are no longer included in refining direct operating costs. Consequently, our results of operations for 2013 are not fully comparable with prior or future periods.

The information presented below should be read in conjunction with Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and the consolidated financial statements and the notes thereto included in Item 8. Financial Statements and Supplementary Data.

	Year Ended December 31,
	2016		2015		2014		2013		2012
	(In thousands, except per share data)
Statement of Operations Data
Net sales	$	7,743,213	$	9,787,036	$	15,153,573	$	10,086,070	$	9,503,134
Total operating costs and expenses (1)	7,399,788		8,856,911		14,057,060		9,514,197		8,791,239
Operating income	$	343,425	$	930,125	$	1,096,513	$	571,873	$	711,895
Net income	$	187,006	$	614,431	$	710,072	$	299,554	$	398,885
Less net income attributed to non-controlling interests (3)	62,067		207,675		150,146		23,560		—
Net income attributable to Western Refining, Inc.	$	124,939	$	406,756	$	559,926	$	275,994	$	398,885
Basic earnings per share	$	1.24	$	4.28	$	6.17	$	3.35	$	4.42
Diluted earnings per share	1.24		4.28		5.61		2.79		3.71
Dividends declared per common share	$	1.52	$	1.36	$	3.08	$	0.64	$	2.74
Weighted average basic shares outstanding	100,473		94,899		90,708		82,248		89,270
Weighted average dilutive shares outstanding	100,868		94,999		101,190		104,904		111,822

	Year Ended December 31,
	2016		2015		2014		2013		2012
	(In thousands)
Other Data
Adjusted EBITDA (2)	$	575,994	$	1,298,124	$	1,231,443	$	754,839	$	1,083,669
Balance Sheet Data (at end of period)
Cash and cash equivalents	$	268,581	$	772,502	$	431,159	$	468,070	$	453,967
Restricted cash	—		69,106		167,009		—		—
Working capital	688,477		1,114,366		812,711		479,160		586,923
Total assets	5,560,397		5,833,393		5,642,186		5,475,099		2,457,706
Total debt and lease financing obligations	1,936,468		1,703,626		1,507,654		1,373,651		487,320
Total equity	2,296,960		2,945,906		2,787,644		2,570,587		909,070

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

	Year Ended December 31,
	2016			2015			2014		2013			2012
	(In thousands)
Realized commodity hedging gain (loss), net	$	58,773		$	93,699		$	95,331	$	15,868		$	(144,448	)
Unrealized commodity hedging gain (loss), net	(77,674		)	(50,233		)	194,423		(16,898		)	(229,672		)
Total realized and unrealized commodity hedging gain (loss), net	$	(18,901	)	$	43,466		$	289,754	$	(1,030	)	$	(374,120	)

(2) Adjusted EBITDA represents earnings before interest and debt expense, provision for income taxes, depreciation, amortization, maintenance turnaround expense and certain other non-cash income and expense items. However, Adjusted EBITDA is not a recognized measurement under U.S. generally accepted accounting principles ("GAAP"). Our management believes that the presentation of Adjusted EBITDA is useful to investors because it is frequently used by securities analysts, investors and other interested parties in the evaluation of companies in our industry. In addition, our management believes that Adjusted EBITDA is useful in evaluating our operating performance compared to that of other companies in our industry because the calculation of Adjusted EBITDA generally eliminates the effects of financings, income taxes, the accounting effects of significant turnaround activities (that many of our competitors capitalize and thereby exclude from their measures of EBITDA) and certain non-cash charges that are items that may vary for different companies for reasons unrelated to overall operating performance.

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

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

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

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

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

Because of these limitations, Adjusted EBITDA should not be considered a measure of discretionary cash available to us to invest in the growth of our business. We compensate for these limitations by relying primarily on our GAAP results and using Adjusted EBITDA only supplementally.

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The following table reconciles net income attributable to Western Refining, Inc. to Adjusted EBITDA for the periods presented:

	Year Ended December 31,
	2016			2015		2014			2013			2012
	(In thousands)
Net income attributable to Western Refining, Inc.	$	124,939		$	406,756	$	559,926		$	275,994		$	398,885
Net income attributed to non-controlling interests	62,067			207,675		150,146			23,560			—
Interest and debt expense	123,291			105,603		97,062			74,581			88,209
Provision for income taxes	54,868			223,955		292,604			153,925			218,202
Depreciation and amortization	216,787			205,291		190,566			117,848			93,907
Maintenance turnaround expense	47,137			2,024		48,469			50,249			47,140
Loss (gain) and impairments on disposal of assets, net	(1,271		)	51		8,530			(4,989		)	—
Loss on extinguishment of debt	3,916			—		9			46,773			7,654
Net change in lower of cost or market inventory reserve	(133,414		)	96,536		78,554			—			—
Unrealized loss (gain) on commodity hedging transactions, net	77,674			50,233		(194,423		)	16,898			229,672
Adjusted EBITDA	$	575,994		$	1,298,124	$	1,231,443		$	754,839		$	1,083,669

(3) Net income attributed to non-controlling interests for the years ended December 31, 2016, 2015 and 2014, consisted of income from NTI of $35.3 million, $186.5 million and $131.9 million, respectively. Net income attributed to non-controlling interests for the years ended December 31, 2016, 2015 and 2014, consisted of income from WNRL of $26.7 million, $21.2 million and $18.2 million, respectively.

Northern Tier Energy LP

Omitted pursuant to General Instruction I(2)(a) to Form 10-K.

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

You should read the following discussion together with the financial statements and the notes thereto included elsewhere in this annual report. This discussion contains forward-looking statements that are based on management’s current expectations, estimates and projections about our business and operations. The cautionary statements made in this report should be read as applying to all related forward-looking statements wherever they appear in this report. Our actual results may differ materially from those currently anticipated and expressed in such forward-looking statements as a result of a number of factors, including those we discuss under Part I — Item 1A. Risk Factors and elsewhere in this report. You should read such Risk Factors and Forward-Looking Statements in this report. In this Item 7, all references to “Western Refining,” “the Company,” “Western,” “we,” “us” and “our” refer to Western Refining, Inc. and its subsidiaries, unless the context otherwise requires or where otherwise indicated.

Company Overview

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

Major Influences on Results of Operations

Summary of 2016 Events

• We averaged total throughput of 139,871 bpd at the El Paso refinery, a 3.5%increase from 2015.

• We averaged total throughput of 25,751 bpd at the Gallup refinery, a 3.7%decrease from 2015.

• We averaged total throughput of 92,400 bpd at the St. Paul Park refinery, a 4.3%decrease from 2015.

• We acquired the remaining publicly held units of NTI for $859.9 million in cash and 17.1 million shares of Western common stock.

• We incurred $500 million of additional secured indebtedness to partially fund the cash portion of the NTI Merger consideration.

• On September 15, 2016, we sold the St. Paul Park Logistics Assets to WNRL in exchange for $195 million in cash and 628,224 common units representing limited partner interests in WNRL.

• We successfully completed the turnaround of the No. 2 crude unit at our St. Paul Park refinery.

• We had net non-cash lower of cost or market ("LCM") recoveries related to our crude oil, finished product and retail LIFO inventory values of $133.4 million.

• We terminated our third-party supplier agreement related to our Mid-Atlantic operations and acquired $46.0 million in finished product inventories valued at market on December 31, 2016.

• We recognized $6.1 million of expense related to the Tesoro Merger, which included transaction and consulting costs.

• We purchased 2,462,350 shares under our share repurchase programs at an average price of $30.46 per share.

• WNRL issued 12,937,500 common units to the public in exchange for net proceeds of $277.8 million.

• Dividends and distributions declared and paid:

◦ $1.52 per Western common share;

◦ $1.63 per WNRL common unit; and

◦ $0.56 per NTI common unit.

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2016 Operating and Financial Highlights

We have organized our operations into threereportable 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. Prior to the NTI Merger on June 23, 2016, we also reported NTI as a separate reportable segment. Following the completion of the NTI Merger, NTI became a wholly-owned subsidiary of Western and, as a result, we have moved its net assets and operations into our refining segment, retail segment and other category. Beginning on July 1, 2016, our management team, led by our chief operating decision maker, began monitoring our business and allocating resources based on these three reportable segments. We have retrospectively adjusted the historical segment financial data for the periods presented to reflect our revised segment presentation.

Net income attributable to Western was $124.9 million, or $1.24 per diluted share for the year ended December 31, 2016, compared to $406.8 million, or $4.28 per diluted share for the year ended December 31, 2015. Our operating income decreased$586.7 million from December 31, 2015, to December 31, 2016, as shown by segment in the following table:

	Year Ended December 31,
	2016			2015			Change
	(In thousands)
Refining	$	357,610		$	930,531		$	(572,921	)
WNRL	70,095			55,794			14,301
Retail	25,146			41,279			(16,133		)
Other	(109,426		)	(97,479		)	(11,947		)
Total operating income	$	343,425		$	930,125		$	(586,700	)

Overview of Segments

Refining. The following items can 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 our 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.

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, 2016 includes $18.9 million of realized and unrealized net losses from our economic hedging activities. The non-cash unrealized net losses included in the consolidated total were $77.7 million for the year ended December 31, 2016.

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Demand for gasoline is generally higher during the summer months than during the winter months. As a result, our operating results for the first and fourth calendar quarters are generally lower than those for the second and third calendar quarters of each year. From 2014 to 2016, 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 year ended December 31, 2014 include $5.8 million in business interruption recoveries related to processing outages that occurred during the first and fourth quarters of 2011 at the El Paso refinery.

Pursuant to a supply agreement with a third party, we received monthly distribution amounts from the supplier equal to one-half of the amount by which our refined product sales in the Mid-Atlantic exceeded the supplier's costs of acquiring, transporting and hedging the refined product related to such sales. To the extent our refined product sales did not exceed the refined product costs during any month, we paid one-half of that amount to the supplier. Our payments to the supplier were limited to an aggregate annual amount of $2.0 million. This supply agreement expired on December 31, 2016. On that date, we acquired $46.0 million in finished product inventories valued at market related to our Mid-Atlantic operations and now realize 100% of the operating results, without limitations on operating losses.

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.

NTI Merger

We entered into an Agreement and Plan of Merger dated as of December 21, 2015 (the “NTI Merger Agreement”), with Western Acquisition Co, LLC, which is a wholly-owned subsidiary of Western, NTI and Northern Tier Energy GP LLC, to acquire all of NTI’s outstanding common units not already held by us (the “NTI Merger”). On June 23, 2016, following the approval of the NTI Merger Agreement by NTI common unitholders, all closing conditions to the NTI Merger were satisfied, and the NTI Merger was successfully completed. See Note 30, NTI, in the Notes to Consolidated Financial Statements included in this annual report for more detailed information.

WNRL

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. On September 15, 2016, we sold the St. Paul Park Logistics Assets to WNRL in exchange for $195 million in cash and 628,224 common units representing limited partner

39

interests in WNRL. On October 30, 2015, we sold the TexNew Mex Pipeline System and other related assets to WNRL. On October 15, 2014, we sold substantially all of our wholesale business to WNRL. 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. See Note 29, Western Refining Logistics, LP, 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, 2016, 2015 and 2014:

2016

• On June 23, 2016, as an incremental supplement to the Western 2020 Term Loan Credit Facility, we incurred $500.0 million in new term debt that matures on June 23, 2023.

• On December 29, 2016, we made a non-mandatory prepayment of $125.0 million under our Western 2023 Term Loan Credit Facility.

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.

As a result of the long-term debt redemptions described above, we recognized insignificant losses on extinguishment of debt for the years ended December 31, 2016 and 2014. These losses are included in Loss on extinguishment of debt in the Consolidated Statements of Operations.

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

Equity Transactions

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

Our operating results for the years ended December 31, 2016 included realized and unrealized net losses from our commodity hedging activities of $18.9 million, realized and unrealized net gains of $43.5 million for the year ended December 31, 2015 and realized and unrealized net gains of $289.8 million for the year ended December 31, 2014. 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 $41.7 million and $175.1 million in order to state the value at market prices which were lower than our cost at December 31, 2016 and 2015, respectively. Refined products inventory includes a lower of cost or market non-cash adjustment of $28.6 million and $72.3 million and crude oil and other raw materials inventory

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includes a lower of cost or market non-cash adjustment of $13.1 million and $102.8 million at December 31, 2016 and 2015, respectively. Global and domestic crude oil prices are expected to remain volatile during 2017, and we cannot estimate any future adjustments to our inventory carrying values.

We purchased $46.0 million in finished product inventories valued at market in late December 2016 in connection with the termination of a supply agreement with a third party for our Mid-Atlantic business.

Our income tax provisions include the effects of a decrease in our valuation allowance of $3.8 million and $2.9 million for the years ended December 31, 2016 and 2014, 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.

Maintenance Turnaround Expense

During the years ended December 31, 2016, 2015 and 2014, we incurred costs of $47.1 million, $2.0 million and $48.5 million, respectively, for maintenance turnarounds. During 2016, we completed the turnaround of the No. 2 crude unit at our St. Paul Park refinery. In the first quarter of 2014, we completed a scheduled maintenance turnaround for the south side units of the El Paso refinery. We currently plan for a major maintenance turnaround on the St. Paul Park refinery during the spring of 2017 and on the north side unit of the El Paso refinery in the fall of 2017 at an aggregate budgeted expense of approximately $42.4 million.

Critical Accounting Policies and Estimates

We prepare our financial statements in conformity with U.S. GAAP. Note 2, Summary of Accounting Policies, to our Consolidated Financial Statements contains a summary of our significant accounting policies. Certain amounts included in or affecting our consolidated financial statements and related disclosures must be estimated, requiring us to make certain assumptions with respect to values or conditions that cannot be known with certainty at the time our financial statements are prepared. These estimates and assumptions affect the amounts we report for our assets and liabilities, our revenues and expenses during the reporting period, and our disclosure of contingent assets and liabilities at the date of our financial statements. We routinely evaluate these estimates, utilizing historical experience, consultation with experts and other methods we consider reasonable in the particular circumstances. Actual results may differ significantly from our estimates, and any effects on our financial condition, results of operations or cash flows resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known.

We believe that of our significant accounting policies, the following are noteworthy because they are based on estimates and assumptions that require complex and/or subjective assumptions by management that can materially impact reported results.

Historically, the refining industry has experienced significant fluctuations in operating results over an extended business cycle including changes in crack spreads and refining margins, changes in operating costs including natural gas and electricity and higher costs of complying with government regulations. It is reasonably possible that at some future downturn in refining operations that the assumptions used in our forecasts and projections used to determine impairment of our goodwill, intangibles and long-live assets would significantly change, resulting in an impairment charge in the future. A prolonged, moderate decrease in our refining or operating margins could potentially result in impairment to our goodwill, intangibles and long-live assets. Such impairment charges could be material in the period taken.

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.

Refined products inventories held by our refineries and SuperAmerica retail are valued under the LIFO valuation method. Our refined product inventories for Southwest Retail, our Mid-Atlantic business and WNRL wholesale are valued using the first-in, first-out (“FIFO”) inventory valuation method. Retail merchandise inventory is valued using 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.

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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, 2016 and 2015, 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 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 significant 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 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.

Intangible Assets. We amortize intangible assets, such as rights-of-way, licenses and permits over their economic useful lives, unless the economic useful lives of the assets are indefinite. If an intangible asset’s economic useful life is determined to be indefinite, then that asset is not amortized. We consider factors such as the asset’s history, our plans for that asset and the market for products associated with the asset when the intangible asset is acquired. We consider these same factors when reviewing the economic useful lives of our existing intangible assets as well. We review the economic useful lives of our intangible assets at least annually.

Environmental and Other Loss Contingencies. We record liabilities for loss contingencies, including environmental remediation costs, when such losses are probable and can be reasonably estimated. Environmental costs are expensed if they relate to an existing condition caused by past operations with no future economic benefit. Estimates of projected environmental costs are made based upon internal and third-party assessments of contamination, available remediation technology and environmental regulations. Loss contingency accruals, including those for environmental remediation, are subject to revision as further information develops or circumstances change and such accruals can take into account the legal liability of other parties.

Certain of our environmental obligations are recorded on a discounted basis. Where the available information is sufficient to estimate the amount of liability, that estimate is used. Where the information is only sufficient to establish a range of probable liability and no point within the range is more likely than other, the lower end of the range is used. Possible recoveries of some of these costs from other parties are not recognized in the financial statements until they become probable. Legal costs associated with environmental remediation are included as part of the estimated liability.

Financial Instruments and Fair Value. We are exposed to various market risks, including changes in commodity prices. We use commodity future contracts, price swaps and options to reduce price volatility, to fix margins for refined products and to protect against price declines associated with our crude oil and blendstock inventories. We recognize all commodity hedge transactions that we enter as either assets or liabilities in the Consolidated Balance Sheets and those instruments are measured at fair value. For instruments used to mitigate the change in value of volumes subject to market prices, we elected not to pursue hedge accounting treatment for financial accounting purposes, generally because of the difficulty of establishing and maintaining the required documentation that would allow for hedge accounting. Moreover, the swap contracts used to fix the margin on a portion of our future gasoline and distillate production do not qualify for hedge accounting treatment. Therefore,

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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 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. 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, 2016, is presented below:

Consolidated

	Year Ended December 31,
	2016			2015			2014
	(In thousands, except per share data)
Statement of Operations Data:
Net sales (1)	$	7,743,213		$	9,787,036		$	15,153,573
Operating costs and expenses:
Cost of products sold (exclusive of depreciation and amortization) (1)	5,978,811			7,521,375			12,719,963
Direct operating expenses (exclusive of depreciation and amortization) (1)	928,023			902,925			850,634
Selling, general and administrative expenses	217,861			225,245			226,020
Merger and reorganization costs	12,440			—			12,878
Loss (gain) and impairments on disposal of assets, net	(1,271		)	51			8,530
Maintenance turnaround expense	47,137			2,024			48,469
Depreciation and amortization	216,787			205,291			190,566
Total operating costs and expenses	7,399,788			8,856,911			14,057,060
Operating income	343,425			930,125			1,096,513
Other income (expense):
Interest income	692			703			1,188
Interest and debt expense	(123,291		)	(105,603		)	(97,062		)
Loss on extinguishment of debt	(3,916		)	—			(9		)
Other, net	24,964			13,161			2,046
Net income before income taxes	241,874			838,386			1,002,676
Provision for income taxes	(54,868		)	(223,955		)	(292,604		)
Net income	187,006			614,431			710,072
Less net income attributed to non-controlling interests (2)	62,067			207,675			150,146
Net income attributable to Western Refining, Inc.	$	124,939		$	406,756		$	559,926
Basic earnings per share	$	1.24		$	4.28		$	6.17
Diluted earnings per share	1.24			4.28			5.61
Dividends declared per common share	$	1.52		$	1.36		$	3.08
Weighted average basic shares outstanding	100,473			94,899			90,708
Weighted average dilutive shares outstanding	100,868			94,999			101,190

(1) The information presented excludes $3,558.4 million, $3,869.8 million and $5,322.8 million of intercompany sales and $3,558.4 million, $3,869.8 million and $5,306.2 million of intercompany cost of products sold for the years ended December 31, 2016, 2015 and 2014, respectively, and $16.6 million of intercompany direct operating expenses for the year ended December 31, 2014 with no comparable activity for the years ended December 31, 2016 and 2015.

(2) Net income attributable to non-controlling interests for the years ended December 31, 2016, 2015 and 2014, consisted of net income from NTI of $35.3 million, $186.5 million and $131.9 million, respectively, and net income from WNRL of $26.7 million, $21.2 million and $18.2 million, respectively.

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Gross Margin

Gross margin is a non-GAAP performance measure that we calculate as net sales less cost of products sold (exclusive of depreciation and amortization). Gross margin is a non-GAAP performance measure that we believe is important to investors in evaluating our performance as a general indication of the amount above costs of products that we are able to sell our products.

	Year Ended December 31,
	2016		2015		2014
	(In thousands)
Net sales	$	7,743,213	$	9,787,036	$	15,153,573
Cost of products sold (exclusive of depreciation and amortization)	5,978,811		7,521,375		12,719,963
Gross margin	$	1,764,402	$	2,265,661	$	2,433,610

Our consolidated gross margins decreased from 2015 to 2016 by 22.1%. This decrease was primarily due to the impact of refining margins and economic hedging activities. We discuss refining margins and economic hedging activities under our refining segment.

Our consolidated gross margins decreased from 2014 to 2015 by 6.9%. This decrease was primarily due to the impact of refining margins and economic hedging activities. We discuss refining margins and economic hedging activities under our refining segment.

Direct Operating Expenses

The increase in direct operating expenses from 2015 to 2016 was primarily due to increases of $14.0 million and $12.1 million in our retail and refining segments, respectively, partially offset by a decrease of $0.8 million in our WNRL segment.

The increase in direct operating expenses from 2014 to 2015 was primarily due to increases of $28.5 million, $18.1 million and $7.3 million in our retail, refining and WNRL segments, respectively.

Selling, General and Administrative Expenses

The decrease in selling, general and administrative expenses from 2015 to 2016 resulted from a decrease of $6.2 million, $1.7 million and $0.8 million in our refining, WNRL and retail segments, respectively, partially offset by an increase of $1.3 million in our other category. The increase in the other category was due to higher legal and insurance expenses in the current period.

The decrease in selling, general and administrative expenses from 2014 to 2015 resulted from a decrease of $10.7 million in our other category, partially offset by an increase of $5.4 million, $3.3 million and $1.2 million in our refining, retail and WNRL segments, respectively. The decrease in our 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.

Merger and Reorganization Costs

The costs incurred during the year ended December 31, 2016 consist of severance payments and reorganization costs for the NTI Merger and transaction and consulting costs related to the Tesoro Merger. The 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

During the year ended December 31, 2016, we incurred turnaround expenses associated with the 2016 turnaround of the No. 2 crude unit at our St. Paul Park refinery. In the first quarter of 2014, we completed a scheduled maintenance turnaround for the south side units of the El Paso refinery.

Depreciation and Amortization

The increase in depreciation and amortization from 2015 to 2016 resulted from an increase of $8.9 million and $3.9 million in our refining and WNRL segments, respectively, partially offset by a decrease of $1.2 million in our other category.

The increase in depreciation and amortization from 2014 to 2015 resulted from an increase of $6.5 million, $4.4 million and $3.3 million in our WNRL, refining and retail segments, respectively.

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Other Income (Expense)

The increase in interest expense from 2015 to 2016 was attributable to interest incurred in 2016 on borrowings under the Western 2023 Term Loan Credit Facility that we issued during the second quarter of 2016 and greater borrowings under the NTI and WNRL revolving credit facilities during 2016.

The loss on extinguishment of debt recorded for the year ended December 31, 2016, was attributable to a non-mandatory prepayment of $125.0 million under our Western 2023 Term Loan Credit Facility on December 29, 2016.

The increase in interest expense from 2014 to 2015 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 by the retirement of our 5.75% Convertible Senior Unsecured Notes during the second quarter of 2014.

Segment Results

We have organized our operations into threereportable 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. Prior to the NTI Merger on June 23, 2016, we also reported NTI as a separate reportable segment. Following the completion of the NTI Merger, NTI became a wholly-owned subsidiary of Western and, as a result, we have moved its net assets and operations into our refining segment, retail segment and other category. Beginning on July 1, 2016, our management team, led by our chief operating decision maker, began monitoring our business and allocating resources based on these three reportable segments. We have retrospectively adjusted the historical segment financial data for the periods presented to reflect our revised segment presentation.

We treated the St. Paul Park Logistics Assets we sold to WNRL 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. We moved the St. Paul Park Logistics Assets from the refining segment to the WNRL segment.

We present below the performance measure of gross margin for each of our reportable segments. Gross margin is a non-GAAP performance measure that we believe is important to investors in evaluating our segments' performance as a general indication of the amount above segment costs of products that each reportable segment is able to sell its products.

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The following tables set forth our historical financial data by segment for the periods presented. 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,
	2016			2015			2014
	(In thousands)
Consolidated Gross Margin by Segment
Refining	$	1,087,120		$	1,600,490		$	1,836,778
WNRL	306,605			291,730			256,969
Retail	370,677			373,689			339,440
Other	—			(248		)	423
Consolidated gross margin	$	1,764,402		$	2,265,661		$	2,433,610
Consolidated Direct Operating Expenses by Segment
Refining	$	472,128		$	459,996		$	441,926
WNRL	174,936			175,767			168,432
Retail	281,039			267,079			238,595
Other	(80		)	83			1,681
Consolidated direct operating expenses	$	928,023		$	902,925		$	850,634
Consolidated Depreciation and Amortization by Segment
Refining	$	150,989		$	142,108		$	137,715
WNRL	39,242			35,384			28,934
Retail	23,193			23,197			19,869
Other	3,363			4,602			4,048
Consolidated depreciation and amortization	$	216,787		$	205,291		$	190,566

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

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Refining Segment

	Year Ended
	December 31,
	2016		2015		2014
	(In thousands, except bpd and per barrel data)
Statement of Operations Data:
Net sales (including intersegment sales) (1)	$	6,918,931	$	8,777,196	$	14,196,564
Operating costs and expenses:
Cost of products sold (exclusive of depreciation and amortization) (2)	5,831,811		7,176,706		12,343,186
Direct operating expenses (exclusive of depreciation and amortization)	472,128		459,996		458,526
Selling, general and administrative expenses	59,239		65,422		59,999
Loss and impairments on disposal of assets, net	17		409		8,089
Maintenance turnaround expense	47,137		2,024		48,469
Depreciation and amortization	150,989		142,108		137,715
Total operating costs and expenses	6,561,321		7,846,665		13,055,984
Operating income	$	357,610	$	930,531	$	1,140,580
Key Operating Statistics:
Total sales volume (bpd) (1) (3)	312,699		338,403		315,656
Total refinery production (bpd)	256,177		256,197		246,780
Total refinery throughput (bpd) (4)	258,023		258,322		248,544
Per barrel of throughput:
Refinery gross margin (2) (5) (6)	$	11.45	$	16.93	$	20.40
Refinery gross margin, excluding LCM adjustment (2) (5) (6)	10.05		17.95		21.25
Direct operating expenses (7)	5.00		4.87		5.05
Mid-Atlantic sales volume (bbls)	7,239		8,356		8,588
Mid-Atlantic margin per barrel	$	0.82	$	0.46	$	0.32

El Paso Refinery

	Year Ended
	December 31,
	2016		2015		2014
Key Operating Statistics
Refinery product yields (bpd):
Gasoline	74,916		70,200		62,252
Diesel and jet fuel	55,793		54,082		54,501
Residuum	2,929		4,174		5,121
Other	4,747		4,872		3,740
Total refinery production (bpd)	138,385		133,328		125,614
Refinery throughput (bpd):
Sweet crude oil	104,454		105,064		96,384
Sour crude oil	26,612		22,949		25,113
Other feedstocks and blendstocks	8,805		7,064		5,739
Total refinery throughput (bpd) (4)	139,871		135,077		127,236
Total sales volume (bpd) (3)	148,808		148,897		139,216
Per barrel of throughput:
Refinery gross margin (2) (5) (6)	$	10.93	$	16.48	$	18.34
Direct operating expenses (7)	3.82		4.02		4.37

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Gallup Refinery

	Year Ended
	December 31,
	2016		2015		2014
Key Operating Statistics
Refinery product yields (bpd):
Gasoline	16,315		17,066		17,027
Diesel and jet fuel	7,574		7,994		8,858
Other	1,355		1,303		1,443
Total refinery production (bpd)	25,244		26,363		27,328
Refinery throughput (bpd):
Sweet crude oil	22,964		24,071		25,130
Other feedstocks and blendstocks	2,787		2,659		2,653
Total refinery throughput (bpd) (4)	25,751		26,730		27,783
Total sales volume (bpd) (3)	34,427		33,005		34,300
Per barrel of throughput:
Refinery gross margin (2) (5) (6)	$	12.23	$	18.34	$	16.55
Direct operating expenses (7)	9.51		8.38		8.40

St. Paul Park Refinery

	Year Ended
	December 31,
	2016		2015		2014
Key Operating Statistics
Refinery product yields (bpd):
Gasoline	46,287		46,453		45,674
Diesel and jet fuel	30,767		33,356		33,910
Residuum	9,661		10,933		7,567
Other	5,833		5,764		6,687
Total refinery production (bpd)	92,548		96,506		93,838
Refinery throughput (bpd):
Light crude oil	49,794		55,612		59,386
Synthetic crude oil	17,516		13,127		14,613
Heavy crude oil	21,641		24,962		17,841
Other feedstocks and blendstocks	3,449		2,814		1,685
Total refinery throughput (bpd) (4)	92,400		96,515		93,525
Total sales volume (bpd) (3)	98,965		101,349		98,016
Per barrel of throughput:
Refinery gross margin (2) (5) (6)	$	9.17	$	18.88	$	17.74
Direct operating expenses (7)	4.66		4.33		4.49

(1) Refining net sales for the years ended December 31, 2016, 2015 and 2014, include $547.4 million, $1,078.2 million and $2,684.3 million representing a period average of 34,177 bpd, 61,516 bpd and 72,402 bpd in crude oil sales to third parties, respectively.

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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,
	2016			2015			2014
	(In thousands)
Realized hedging gain, net	$	58,773		$	93,699		$	95,331
Unrealized hedging gain (loss), net	(77,674		)	(50,233		)	194,423
Total hedging gain (loss), net	$	(18,901	)	$	43,466		$	289,754

(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 5.7%, 6.5% and 7.3% of our total consolidated sales volumes for the years ended December 31, 2016, 2015 and 2014, respectively. The majority of the purchased refined products are distributed through our refined product sales activities in the Mid-Atlantic region where we satisfied our refined product customer sales requirements via a third-party supply agreement through December 31, 2016.

(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.

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,
	2016		2015		2014
	(In thousands)
Refinery net sales (including intersegment sales)	$	6,485,540	$	8,177,250	$	13,207,406
Mid-Atlantic sales	433,391		599,946		989,158
Net sales (including intersegment sales)	$	6,918,931	$	8,777,196	$	14,196,564
Refinery cost of products sold (exclusive of depreciation and amortization)	$	5,404,339	$	6,580,591	$	11,356,782
Mid-Atlantic cost of products sold	427,472		596,115		986,404
Cost of products sold (exclusive of depreciation and amortization)	$	5,831,811	$	7,176,706	$	12,343,186

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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,
	2016		2015		2014
	(in thousands, except per barrel data)
Net sales (including intersegment sales)	$	6,485,540	$	8,177,250	$	13,207,406
Cost of products sold (exclusive of depreciation and amortization)	5,404,339		6,580,591		11,356,782
Depreciation and amortization	150,989		142,108		137,715
Gross profit	930,212		1,454,551		1,712,909
Plus depreciation and amortization	150,989		142,108		137,715
Refinery gross margin	$	1,081,201	$	1,596,659	$	1,850,624
Refinery gross margin per refinery throughput barrel	$	11.45	$	16.93	$	20.40
Gross profit per refinery throughput barrel	$	9.85	$	15.43	$	18.88

(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 that we believe is useful in evaluating our refinery performance exclusive of the impact of fluctuations in inventory values:

	Year Ended
	December 31,
	2016			2015		2014
	(in thousands, except per barrel data)
Refinery gross margin	$	1,081,201		$	1,596,659	$	1,850,624
Net change in lower of cost or market inventory reserve	(131,954		)	95,835		77,118
Refinery gross margin, excluding LCM adjustment	$	949,247		$	1,692,494	$	1,927,742
Refinery gross margin, excluding LCM adjustment, per refinery throughput barrel	$	10.05		$	17.95	$	21.25

(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 non-GAAP performance measure that we calculate as net sales (including intersegment sales) less cost of products sold (exclusive of depreciation and amortization):

	Year Ended
	December 31,
	2016		2015		2014
	(In thousands)
Net sales	$	6,918,931	$	8,777,196	$	14,196,564
Cost of products sold (exclusive of depreciation and amortization)	5,831,811		7,176,706		12,343,186
Refinery gross margin	$	1,087,120	$	1,600,490	$	1,853,378

Refinery gross margins depend on both the price of crude oil or other feedstock and the price of refined products. Factors affecting the prices of petroleum based commodities include supply and demand in crude oil, gasoline and other refined products. Supply and demand for these products depend on changes in domestic and foreign economies, weather conditions, domestic and foreign political affairs, production levels, logistics constraints, availability of imports, marketing of competitive fuels, crude oil price differentials and government regulation.

Excluding the impact of our hedging activities, refining margin per throughput barrel declined from 2015 to 2016 in a manner generally consistent with the decrease in industry benchmarks. The positive margin impact from our non-cash lower of cost or market inventory adjustment was$132.0 million, or$1.40 per throughput barrel, in 2016 compared to a negative margin

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impact of $95.8 million, or $1.02 per throughput barrel, in 2015. 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 $2.9 million in 2016 compared to $16.1 million in 2015.

The Gulf Coast benchmark 3:2:1 crack spread decreased from $18.24 in 2015 to $12.55 in 2016. Our crude oil purchases are based on pricing tied to WTI that, in recent quarters, has experienced price volatility relative to Brent crude oil reflective of the decline in global and domestic crude oil prices. During 2016, this differential decreased to an average of $0.38 per barrel from an average of $3.68 per barrel for 2015. Our El Paso refinery margins have historically benefited from the WTI Midland/Cushing crude oil differential. However, this differential has been volatile, has narrowed over the past year, and at times has shifted to a premium rather than a discount. For 2016, the WTI Midland/Cushing differential averaged a discount of $0.15 per barrel, compared to an average discount of $0.37 for 2015. This differential continues to be volatile and fluctuates based on local crude oil production, crude oil outflows at Midland and Cushing and regional refining throughput volumes. The Group 3 6:3:2:1 crack spread decreased from $12.93 in 2015 to $7.84 in 2016.

Refinery gross margin decreased from 2014 to 2015 due primarily to a lower net gain on hedging activities. 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 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.

During 2016, we recognized a net realized and unrealized loss from economic hedging activities of $18.9 million compared to a gain of $43.5 million in 2015 and a gain of $289.8 million in 2014. 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 $65.4 million, $35.5 million and $28.2 million for the years ended December 31, 2016, 2015 and 2014, respectively. The increase in 2016 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 2014 to 2016 primarily due to El Paso refinery operational efficiencies gained from the turnarounds in 2014 and 2015. Also, our refined product sales volume was 114.4 million, 123.5 million and 115.2 million barrels in December 31, 2016, 2015 and 2014, respectively.

Direct Operating Expenses

The increase in direct operating expenses from 2015 to 2016 is primarily a result of increases in transportation expenses at our St. Paul Park refinery ($13.3 million), environmental expenses ($4.6 million), property taxes ($3.2 million) and railcar lease expense ($2.5 million) due to new short-term leases in 2016. Offsetting these increases were decreases in energy, chemical and catalyst expense ($6.1 million) partially due to lower natural gas prices, outside support services ($4.7 million) and employee expense ($3.2 million).

The increase in direct operating expenses from 2014 through 2015 was primarily due to higher employee expenses ($14.8 million) primarily generated by increased headcount, outside support services expense ($6.1 million), railcar lease expense ($3.7 million) due to new short term leases in 2015, transportation expenses at our St. Paul Park refinery ($2.7 million) and property tax expense ($1.7 million). Partially offsetting these increases were decreases in environmental expenses primarily incurred at our St. Paul Park refinery ($11.1 million), energy expense ($8.9 million) due to decreased natural gas prices, operating materials and supplies ($6.1 million) and insurance expense ($0.8 million).

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Selling, General and Administrative Expenses

Selling, general and administrative expense decreased from 2015 to 2016 primarily due to $1.8 million paid in 2015 to terminate a supply agreement without corresponding current period activity, decreased professional and legal fees ($2.1 million), lower insurance expense ($1.8 million) and lower information technology expenses ($1.7 million). Offsetting these decreases were increased employee expenses ($1.4 million).

Selling, general and administrative expense increased from 2014 to 2015 primarily due to increased employee expenses ($8.8 million) due to greater incentive compensation and equity based compensation expenses, insurance expense ($1.9 million) and $1.8 million paid in 2015 to terminate a supply agreement. Offsetting these decreases were decreased professional and legal costs ($7.0 million).

Maintenance Turnaround Expenses

We incurred turnaround expenses associated with the turnaround of the No. 2 crude unit at our St. Paul Park refinery during 2016. 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.

Depreciation and Amortization

Depreciation and amortization increased from 2015 to 2016 due to additional depreciation associated with recently capitalized logistics assets.

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.

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WNRL

The WNRL financial and operational data presented includes the historical results of all assets acquired from Western in the St. Paul Park Logistics Transaction, the TexNew Mex Pipeline Transaction and the Wholesale Acquisition (as defined in Note 1, Organization and Basis of Presentation, in the Notes to Consolidated Financial Statements included in this annual report). These acquisitions from Western were transfers of assets between entities under common control. We have retrospectively adjusted historical financial and operational data of WNRL, for all periods presented, to reflect the purchase and consolidation of the purchased assets into WNRL.

	Year Ended
	December 31,
	2016			2015			2014
	(In thousands)
Statement of Operations Data:
Net sales	$	2,222,718		$	2,599,867		$	3,501,888
Operating costs and expenses:
Cost of products sold	1,916,113			2,308,137			3,244,919
Direct operating expenses	174,936			175,767			168,432
Selling, general and administrative expenses	23,386			25,063			23,839
Loss (gain) and impairments on disposal of assets, net	(1,054		)	(278		)	157
Depreciation and amortization	39,242			35,384			28,934
Total operating costs and expenses	2,152,623			2,544,073			3,466,281
Operating income	$	70,095		$	55,794		$	35,607

	Year Ended
	December 31,
	2016		2015		2014
	(In thousands, except per gallon/barrel data)
Key Operating Statistics:
Pipeline and gathering (bpd):
Mainline movements:
Permian/Delaware Basin system	51,805		47,368		24,644
TexNew Mex system	9,543		12,302		—
Four Corners system (1)	53,204		56,079		45,232
Gathering (truck offloading) (bpd):
Permian/Delaware Basin system	17,662		23,617		24,166
Four Corners system	10,464		13,438		11,550
Terminalling, transportation and storage (bpd):
Shipments into and out of storage (includes asphalt)	441,865		391,842		381,371
Wholesale:
Fuel gallons sold	1,258,027		1,237,994		1,147,860
Fuel gallons sold to retail (included in fuel gallons sold, above)	332,214		314,604		268,148
Fuel margin per gallon (2)	$	0.028	$	0.030	$	0.022
Lubricant gallons sold	6,787		11,697		12,082
Lubricant margin per gallon (3)	$	0.85	$	0.73	$	0.86
Asphalt trucking volume (bpd)	4,727		—		—
Crude oil trucking volume (bpd)	38,582		45,337		36,314
Average crude oil trucking revenue per barrel	$	2.16	$	2.53	$	2.90

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(1) Some barrels of crude oil in route to Western's Gallup refinery and Permian/Delaware Basin are transported on more than one mainline. Mainline movements for the Four Corners and Delaware Basin systems include each barrel transported on each mainline.

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

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

Gross Margin

Gross Margin. Gross margin is a non-GAAP performance measure that we calculate as net sales (including intersegment sales) less cost of products sold (exclusive of depreciation and amortization):

	Year Ended
	December 31,
	2016		2015		2014
	(In thousands)
Net sales	$	2,222,718	$	2,599,867	$	3,589,646
Cost of products sold (exclusive of depreciation and amortization)	1,916,113		2,308,137		3,332,677
Gross margin	$	306,605	$	291,730	$	256,969

WNRL gross margin increased$14.9 million from 2015 to 2016. This increase was primarily due to increased fee based revenue of $17.2 million in logistics operations primarily resulting from the St. Paul Park logistics acquisition in the current year. Also contributing to the increase were higher margin of $4.7 million period over period from new asphalt hauling activity by truck. Partially offsetting the margin increase were decreased wholesale fuel margins of $1.2 million, reduced crude oil trucking margin of $1.6 million and a $4.5 milliondecrease in margin from lubricant sales. Wholesale fuel sales revenue decreased due to overall pricing declines. The average price per gallon in 2016 was $1.51 compared to $1.80 for 2015.

WNRL gross margin increased by $34.8 million from 2014 to 2015. This increase was primarily due to increased fee based revenue in our logistics segment of $23.6 million resulting from increased pipeline utilization and increases to certain pipeline, terminal and other service fee rates over 2014 rates. Also contributing to the increase were higher wholesale fuel margins of $9.9 million and higher truck freight revenue from crude oil gathering activity in the Permian Basin area of $3.5 million. Sales based revenues decreased due to a lower average price per gallon sold by our wholesale segment in 2015 of $1.80 compared to $2.83 for 2014.

Direct Operating Expenses

WNRL's direct operating expenses were relatively flat, but included decreases due to lower maintenance expenses ($5.0 million), chemical additives used in the pipeline transportation process ($1.3 million) and lower fuel expense for WNRL's transportation department ($1.0 million), partially offset by higher outside support services ($2.9 million) due to in-line inspections for pipeline segments and various tank repairs and higher employee expenses ($2.5 million).

Direct operating expenses increased from 2014 through 2015 primarily due to increased employee expense ($7.8 million), higher maintenance expense ($2.3 million), partially offset by lower materials and supplies from WNRL logistics ($3.6 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 decreased from 2015 to 2016 primarily due to decreased professional and legal services ($1.2 million) related to acquisitions, employee expenses ($0.4 million) due to the sale of assets related to our lubricant sales activities in California and other permits and taxes ($0.3 million), partially offset by increased allocated expenses ($0.6 million).

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The increase in selling, general and administrative expenses from 2014 to 2015 primarily due to increased corporate overhead related to the St. Paul Park Logistics Transaction and the TexNew Mex Pipeline Acquisition of $1.3 million.

Loss (Gain) and Impairments on Disposal of Assets, Net

The increase in loss (gain) on disposal of assets, net was primarily due to the sale of assets related to WNRL's lubricant sales activities in California during the current period.

Depreciation and Amortization

The increase in depreciation and amortization from 2015 to 2016 was primarily due to the ongoing expansion of WNRL's Delaware Basin and Four Corners logistics systems.

The increase in depreciation and amortization from 2014 to 2015 was primarily due to TexNew Mex Pipeline depreciation, the ongoing expansion of WNRL's Delaware Basin and Four Corners logistics systems and the expansion of WNRL's truck fleet.

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Retail

	Year Ended
	December 31,
	2016			2015			2014
	(In thousands, except per gallon data)
Statement of Operations Data:
Net sales (including intersegment sales)	$	2,159,946		$	2,279,737		$	2,776,782
Operating costs and expenses:
Cost of products sold (exclusive of depreciation and amortization)	1,789,269			1,906,048			2,437,342
Direct operating expenses (exclusive of depreciation and amortization)	281,039			267,079			238,595
Selling, general and administrative expenses	41,533			42,312			39,017
Gain and impairments on disposal of assets, net	(234		)	(178		)	(128		)
Depreciation and amortization	23,193			23,197			19,869
Total operating costs and expenses	2,134,800			2,238,458			2,734,695
Operating income	$	25,146		$	41,279		$	42,087
Key Operating Statistics:
Southwest Retail:
Retail fuel gallons sold	394,925			357,835			309,884
Average retail fuel sales price per gallon, net of excise taxes	$	1.70		$	2.02		$	3.31
Average retail fuel cost per gallon, net of excise taxes	1.54			1.82			3.11
Retail fuel margin per gallon (1)	0.16			0.20			0.20
Merchandise sales	$	330,244		$	311,654		$	266,677
Merchandise margin (2)	29.4		%	29.4		%	28.8		%
Operating retail outlets at period end	259			258			230
Cardlock gallons sold	64,067			65,508			67,420
Cardlock margin per gallon	$	0.122		$	0.163		$	0.178
Operating cardlocks at period end	51			52			50
SuperAmerica:
Retail fuel gallons sold	306,825			304,484			306,777
Retail fuel margin per gallon (1)	$	0.22		$	0.23		$	0.22
Merchandise sales	367,737			366,401			349,145
Merchandise margin (2)	25.9		%	25.6		%	25.9		%
Company-operated retail outlets at period end	170			168			165
Franchised retail outlets at period end	115			109			89

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	Year Ended
	December 31,
	2016		2015			2014
	(In thousands, except per gallon data)
Net Sales
Retail fuel sales, net of excise taxes	$	1,301,580	$	1,442,147		$	1,906,425
Merchandise sales	697,981		678,055			615,822
Cardlock sales	104,079		127,413			214,714
Other sales	56,306		32,122			39,821
Net sales	$	2,159,946	$	2,279,737		$	2,776,782
Cost of Products Sold
Retail fuel cost of products sold, net of excise taxes	$	1,170,348	$	1,298,456		$	1,776,825
Merchandise cost of products sold	505,638		492,578			448,674
Cardlock cost of products sold	95,928		116,506			202,489
Other cost of products sold	17,355		(1,492		)	9,354
Cost of products sold	$	1,789,269	$	1,906,048		$	2,437,342
Gross margin	$	370,677	$	373,689		$	339,440
Retail fuel margin per gallon (1)	$	0.19	$	0.22		$	0.21

(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 non-GAAP performance measure that we calculate as net sales (including intersegment sales) less cost of products sold (exclusive of depreciation and amortization). The decrease in gross margin was primarily due to lower same store Southwest Retail fuel gross margin of $8.6 million and a decrease in cardlock gross margin of $2.8 million due to lower sales volumes. The net effect in Southwest Retail of 31 new retail outlets added during January of 2015, one retail outlet added in the second quarter of 2015, four retail outlets closed in the third and fourth quarters of 2015 and one retail outlet added in the second and third quarters of 2016 was an increase in gross margin of $2.9 million from 2015 to 2016 including an increase in merchandise margin ($2.2 million) and retail fuel margin ($0.4 million). The decrease in gross margin was partially offset by increased same store Southwest Retail merchandise gross margin ($3.2 million). SuperAmerica gross margin increased by $2.1 million due to higher fuel and merchandise margins resulting from the expansion of the company-owned locations by 2 stores and franchised locations by 6 stores. SuperAmerica cost of products sold included net non-cash LCM recoveries of $1.4 million for the year ended December 31, 2016 and charges of $0.7 million for the year ended December 31, 2015.

The increase in retail gross margin from 2014 to 2015 was primarily due to the Southwest retail outlets added during 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.

Direct Operating Expenses

The increase in direct operating expenses from 2015 to 2016 was primarily due to higher SuperAmerica employee expense of $2.5 million due to a Minnesota state mandated increase in the minimum wage in mid-2015. Additionally, SuperAmerica incurred higher store lease expense, maintenance expense and miscellaneous expenses including advertising and utilities expense of $3.3 million, $1.5 million and $1.8 million, respectively, during 2016, due to both additional company-operated stores and lease renewals at higher monthly rates. The net effect of 31 Southwest Retail outlets added during January

58

of 2015, one added in the second quarter of 2015, four retail outlets closed in the third and fourth quarters of 2015 and one retail outlet added in the second and third quarters of 2016 was an additional $1.8 million in expenses. Additionally, there was an increase in same store Southwest Retail employee expenses of $3.0 million, partially offset by a decrease in same store Southwest Retail insurance expense of $0.6 million.

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 adopting early a mandated minimum wage increase.

Selling, General and Administrative Expenses

The decrease in selling, general and administrative expenses from 2015 to 2016 was primarily due to decreased cardlock employee expenses of $1.0 million.

The increase in selling, general and administrative expenses from 2014 to 2015 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.

Depreciation and Amortization

Depreciation and amortization expense remained relatively consistent from 2015 to 2016.

The increase in depreciation and amortization expense from 2014 to 2015 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.

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NTI

General Instruction I(2)(a) of Form 10-K allows for the omission of Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations from the presentation of NTI's financial position and operating results, provided that NTI includes within this Form 10-K its management's narrative analysis of the results of operations explaining the reasons for material changes in revenue and expenses for the periods presented. Set forth below are the operating results of NTI, as presented in NTI's standalone financial statements in its Consolidated Statements of Operations for the years ended December 31, 2016, 2015 and 2014. These operating results do not reflect Western's accounting adjustments to consolidate NTI into Western's operating segments. The following results are intended to be considered separately from Western's consolidated segment presentation, which incorporates NTI's operations, as adjusted in consolidation, into Western's reportable segments.

	Year Ended
	December 31,
	2016			2015
	(In millions)
Revenue	$	2,888.6		$	3,405.0
Costs, expenses and other:
Cost of sales	2,311.6			2,613.5
Direct operating expenses	314.3			297.8
Turnaround and related expenses	45.8			10.6
Depreciation and amortization	46.5			44.0
Selling, general and administrative expenses	82.5			82.9
Merger-related expenses	4.7			2.5
Income from equity method investments	(21.9		)	(14.8		)
Other (income) loss, net	(0.5		)	0.4
Operating income	105.6			368.1
Interest expense, net	(24.8		)	(28.7		)
Income before income taxes	80.8			339.4
Income tax provision	(4.3		)	(8.4		)
Net income	$	76.5		$	331.0

Year Ended December 31, 2016 Compared to the Year Ended December 31, 2015

Revenue. Revenue for the year ended December 31, 2016 was $2,888.6 million compared to $3,405.0 million for the year ended December 31, 2015, a decrease of 15.2%. Refining revenue decreased 17.5% and retail revenue decreased 7.6% compared to the year ended December 31, 2015. This decrease was primarily driven by a decrease in refining revenue, primarily due to lower selling prices of refined products. Also contributing to the decrease was a 0.8%increase in refining sales volumes of refined products versus the year ended December 31, 2015. The lower refined product volumes are primarily attributable to planned turnaround activities at our St. Paul Park refinery during the year ended December 31, 2016. Retail revenue decreased primarily due to lower market prices per gallon for fuel sales during the year ended December 31, 2016. Excise taxes included in revenue totaled $432.2 million and $402.9 million for the years ended December 31, 2016 and 2015, respectively.

Cost of sales. Cost of sales totaled $2,311.6 million for the year ended December 31, 2016 compared to $2,613.5 million for the year ended December 31, 2015, a decrease of 11.6%, primarily due to lower refining crude costs, a 0.8%increase in sales volumes of refined products during the year ended December 31, 2016 and a non-cash lower of cost or market inventory reserve adjustment of $92.7 million as a result of rising feedstocks and finished product prices. An increase in losses from realized and unrealized hedging activities also contributed to cost of sales in the 2016 period by $12.8 million. Excise taxes included in cost of sales were $432.2 million and $402.9 million for the years ended December 31, 2016 and 2015, respectively.

Direct operating expenses. Direct operating expenses totaled $314.3 million for the year ended December 31, 2016 compared to $297.8 million for the year ended December 31, 2015, an increase of 5.5%, due primarily to the impact of higher fleet hauling expenses of $9.0 million, rental expenses and environmental costs in 2016. These increases were partially offset by lower natural gas costs, net of related hedging, of $8.4 million.

Turnaround and related expenses. Turnaround and related expenses totaled $45.8 million for the year ended December 31, 2016 compared to $10.6 million for the year ended December 31, 2015, an increase of 332.1%. The turnaround

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costs in the years ended December 31, 2016 and 2015 related primarily to the turnaround of the No. 2 sulfur recovery unit, distillate hydrotreater and No. 2 SCOT unit.

Depreciation and amortization. Depreciation and amortization was $46.5 million for the year ended December 31, 2016 compared to $44.0 million for the year ended December 31, 2015, an increase of 5.7%. This increase was due to increased assets placed in service and other assets throughout 2016.

Selling, general and administrative expenses. Selling, general and administrative expenses were $82.5 million for the year ended December 31, 2016 compared to $82.9 million for the year ended December 31, 2015. This decrease of 0.5% from the prior-year period relates primarily to lower insurance and legal costs, partially offset by higher equity-based compensation expense.

Merger-related expenses. Legal and advisory costs of $4.7 million and $2.5 million were incurred during the year ended December 31, 2016 and 2015, respectively, as a result of the NTI Merger Agreement with Western. The increase was due to severance and retention costs incurred in 2016.

Income from equity method investment. Income from equity method investment was $21.9 million for the year ended December 31, 2016 compared to $14.8 million of income for the year ended December 31, 2015. This increase was driven primarily by higher equity income due to lower MPL operating costs.

Other (income) loss, net. Other (income) loss, net was $0.5 million of income for the year ended December 31, 2016 compared to a $0.4 million loss for the year ended December 31, 2015. This increase is driven primarily by a gain from the derecognition of a capital lease liability due to the release from an environmental matter at a retail store in 2016.

Interest expense, net. Interest expense, net was $24.8 million for the year ended December 31, 2016 and $28.7 million for the year ended December 31, 2015. This decrease is due to capitalization of interest for refining capital projects during 2016.

Income tax provision. The income tax provision for the year ended December 31, 2016 was $4.3 million compared to $8.4 million for the year ended December 31, 2015. The decrease was due to lower retail pre-tax income.

Net income. Our net income was $76.5 million for the year ended December 31, 2016 compared to $331.0 million for the year ended December 31, 2015. This decrease in net income is primarily attributable to a decrease in gross margin of $214.5 million. Net income was further weakened by an increase of $35.2 million in turnaround and related expenses, an increase of $16.5 million in direct operating expenses, $2.2 million in higher merger related costs and $2.5 million in higher depreciation and amortization costs. Partially offsetting these unfavorable changes, was a $92.7 million favorable lower of cost or market inventory adjustment, $7.1 million in higher income from our equity method investment in MPL, a decrease of $0.4 million in selling, general and administrative expenses and a decrease of $3.9 million in interest expense, net.

Outlook

Our refining margins, excluding hedging activities, were weaker for the El Paso, Gallup and St. Paul Park refineries in 2016 compared to 2015. The Gulf Coast benchmark ("GC") 3:2:1 crack spread refers to the approximate refining margin resulting from processing three barrels of crude oil to produce two barrels of gasoline and one barrel of diesel fuel. The GC 3:2:1 decreased from an average of $18.24 in 2015 to an average of $12.55 in 2016. The GC 3:2:1 through February 24, 2017 averaged $13.41 per barrel.

The St. Paul Park refinery benchmarks its refining margin against the Group 3 6:3:2:1 benchmark crack spread. The Group 3 6:3:2:1 refers to the approximate refining margin resulting from processing six barrels of WTI crude oil to produce three barrels of gasoline, two barrels of diesel fuel and one barrel of residual fuel. Prices are derived from PADD II Group 3 conventional gas and ultra-low diesel fuel prices and the price of Western Canadian Select (“WCS”) crude oil for residual fuel. This benchmark decreased from an average of $12.93 per barrel for 2015, to an average of $7.84 per barrel for 2016. The Group 3 6:3:2:1 averaged $8.17 per barrel through February 24, 2017.

Both Western and NTI record crude oil purchases on pricing tied to WTI. The WTI Midland/Cushing differential can have a significant impact on refining margins at El Paso. The WTI Midland/Cushing differential averaged a discount of $0.15 per barrel for 2016, which, compared to a discount of $0.37 per barrel that we realized in El Paso during 2015, negatively impacted our El Paso refining margins in the current year. The WTI Midland/Cushing differential has averaged a premium of $0.79 per barrel through February 24, 2017.

The discounts to WTI for Bakken Shale crude oil and WCS crude oil can have a significant impact on refining margins at St. Paul Park. The Bakken/WTI discount averaged $1.24 per barrel for 2016 compared to $1.55 per barrel for 2015. The Bakken/WTI discount averaged $0.30 per barrel through February 24, 2017. The WCS/WTI discount averaged $13.69 per barrel for 2016 versus $11.99 per barrel for 2015. The WCS/WTI discount averaged $13.10 per barrel through February 24, 2017.

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The prices of crude oil and refined products have been volatile thus far in 2017. Continued volatility in these prices may impact the carrying value of our inventories and result in additional lower of cost or market inventory adjustments. An increase in prices, such as we experienced in 2016, may positively impact the carrying value of our inventories, while a decrease in these prices could negatively impact our inventory carrying values. Also, during 2016, we experienced volatility in the pricing of RINs. We expect continued volatility as the industry strives to meet RFS obligations.

Liquidity and Capital Resources

Our primary sources of liquidity are from cash from operations, cash on hand and availability under our revolving credit facilities. To a lesser extent, we also generate liquidity from the issuance of securities.

As of December 31, 2016, we had cash and cash equivalents of $268.6 million, including NTI cash of $29.5 million and WNRL cash of $14.7 million. There were no direct borrowings under the Western and NTI revolving credit facilities as of December 31, 2016. Western had $735.4 million in total liquidity as of December 31, 2016, defined as Western’s cash and cash equivalents plus net availability under the Western and NTI Revolving Credit Facilities. Western, NTI and WNRL had net availability under their revolving credit facilities of $266.6 million, $214.9 million and $479.0 million, respectively.

WNRL purchased the St. Paul Park Logistics Assets for $195.0 million and 628,224 common units on September 15, 2016. WNRL funded the cash portion of the consideration through a combination of $20.3 million in direct borrowings under the WNRL Revolving Credit Facility and $174.7 million of cash on hand primarily generated from WNRL's equity offering of 8,625,000 common units during the third quarter of 2016.

Pursuant to the NTI Merger Agreement, we paid $859.9 million in cash and issued 17.1 million shares of Western common stock adjusted slightly for cash paid in lieu of fractional shares. We incurred $500 million of additional secured indebtedness under the amended term loan credit agreement to partially fund the NTI Merger consideration. On December 29, 2016, we made a non-mandatory prepayment of $125.0 million under the amended term loan credit agreement from cash on hand. See Note 15, Long-Term Debt, and Note 30, NTI, in the Notes to Consolidated Financial Statements included in this annual report for further discussion.

WNRL borrowed $145.0 million under the WNRL Revolving Credit Facility on October 30, 2015, to partially fund the purchase of Western's TexNew Mex Pipeline System. During 2016, WNRL repaid $179.1 million of its outstanding direct borrowings under the WNRL Revolving Credit Facility using the proceeds generated through our equity issuances during the period. We had direct borrowings of $20.3 million under the WNRL revolving credit facility as of December 31, 2016. See Note 15, Long-Term Debt, in the Notes to Consolidated Financial Statements included in this annual report for further discussion.

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. This option 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.

Our board of directors has periodically approved various share repurchase programs authorizing us to repurchase up to $200 million of our outstanding common stock, per program. On September 21, 2015, our board of directors authorized a share repurchase program of up to $200 million, which expired on December 31, 2016 with $125.0 million in remaining funds authorized under the program.

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Cash Flows

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

	Year Ended December 31,
	2016			2015			2014
	(In thousands)
Net cash provided by operating activities	$	383,747		$	843,083		$	737,633
Net cash used in investing activities	(226,342		)	(191,846		)	(380,864		)
Net cash used in financing activities	(661,326		)	(309,894		)	(393,680		)
Net increase (decrease) in cash and cash equivalents	$	(503,921	)	$	341,343		$	(36,911	)

The decrease in net cash from operating activities from 2015 to 2016 was primarily the result of a decrease in net income, a change in the lower of cost or market reserve adjustment and changes in our working capital, offset by our commodity hedging activity as disclosed in our Consolidated Statements of Cash Flows for the years ended December 31, 2016 and 2015. Working capital decreased by $425.9 million primarily due to increases 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, 2016, combined with a $500.0 million addition to Western's long-term debt, $466.9 million of borrowings on the NTI and WNRL revolving credit facilities and $277.8 million from the issuance of WNRL common units, were primarily used for the following investing and financing activities:

Investing Activities:

•Fund capital expenditures ($301.0 million)

•Use of $264.1 million of restricted cash; and

•Increase in the amount of restricted cash ($195.0 million).

Financing Activities:

• Payment of consideration to NTI public unitholders ($859.9 million), sourced from cash on hand and from the proceeds of additions to Western's long-term debt;

•Repayment of NTI's revolving credit facility debt ($412.5 million);

•Repayment of WNRL's revolving credit facility debt ($179.1 million);

•Payment of cash dividends ($153.7 million);

•Payment of long-term debt and capital lease obligations ($135.4 million);

•Purchase of common stock for treasury ($75.0 million);

•Payment of distributions to non-controlling interest holders ($66.3 million);

•Payment of deferred financing costs ($12.7 million); and

•Payment of transaction costs associated with the NTI Merger ($11.7 million).

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, were primarily used for the following investing and financing activities:

Investing Activities:

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

•Increase in the amount of restricted cash ($170.0 million).

Financing Activities:

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

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

•Payment of cash dividends ($129.2 million);

•Purchase 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).

Working Capital

Total working capital at December 31, 2016 was $688.5 million, consisting of $1,672.5 million in current assets and $984.0 million in current liabilities. 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. Our working capital at December 31, 2016 and 2015 was as follows:

	December 31,
	2016			2015
	(In thousands)
Western	$	705,667		$	1,078,574
WNRL	(17,190		)	35,792
Total	$	688,477		$	1,114,366

Indebtedness

Our capital structure at December 31, 2016 and 2015 was as follows:

	December 31,
	2016		2015
	(In thousands)
Debt, including current maturities:
Western obligations:
Revolving Credit Facility due 2019	$	—	$	—
Term Loan - 5.25% Credit Facility due 2020	533,500		539,000
6.25% Senior Unsecured Notes due 2021	350,000		350,000
Term Loan - 5.50% Credit Facility due 2023	372,500		—
Total Western obligations	1,256,000		889,000
NTI obligations:
Revolving Credit Facility due 2019	—		—
7.125% Senior Secured Notes, due November 2020	349,980		350,000
Total NTI obligations	349,980		350,000
WNRL obligations:
Revolving Credit Facility due 2018	20,300		145,000
7.5% Senior Notes due 2023	300,000		300,000
Total WNRL obligations	320,300		445,000
Less unamortized discount, premium and debt issuance costs	43,975		33,606
Long-term debt	1,882,305		1,650,394
Equity	2,296,960		2,945,906
Total capitalization	$	4,179,265	$	4,596,300

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 $301.0 million for the year ended December 31, 2016 and included improvement and regulatory projects for our refining segment, WNRL projects and several smaller projects for our retail and corporate groups. Capital expenditures included $10.7 million of capitalized interest for 2016.

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The following table summarizes our budgeted capital expenditures for 2017:

	Western (1)		WNRL		Totals
	(In thousands)
Sustaining	$	89,200	$	11,500	$	100,700
Discretionary	145,800		27,000		172,800
Regulatory	31,100		4,100		35,200
Total	$	266,100	$	42,600	$	308,700

(1) Western's capital expenditure budget for 2017 is $266.1 million, of which $230.7 million is for our refining segment, $29.5 million for our retail segment and $5.9 million for other general projects.

Sustaining Projects. Sustaining maintenance capital expenditures are those related to refinery turnarounds, 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 and new cardlocks.

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.

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:

	2017		2018		2019
	(In millions)
Tier III Low sulfur gasoline - Gallup	$	3.0	$	10.0	$	12.5
Fire suppression - Gallup	8.9		—		—
Flare systems upgrades - Gallup	0.5		—		—
Total	$	12.4	$	10.0	$	12.5

Contractual Obligations and Commercial Commitments

Information regarding our contractual obligations of the types described below as of December 31, 2016, is set forth in the following table:

	Payments Due by Period
	Totals		2017		2018 and 2019		2020 and 2021		2022 and Beyond
	(In thousands)
Long-term debt obligations (1)	$	2,507,080	$	135,583	$	281,448	$	1,380,540	$	709,509
Capital lease obligations	95,190		5,419		10,997		11,635		67,139
Operating lease obligations	546,803		55,675		99,778		85,704		305,646
Purchase obligations (2)	1,945,787		783,704		1,087,601		74,482		—
Environmental reserves (3)	13,784		6,946		2,295		2,192		2,351
Uncertain tax positions (4)	58,317		58,317		—		—		—
Other obligations (5) (6)	194,607		17,620		33,855		139,145		3,987
Total obligations	$	5,361,568	$	1,063,264	$	1,515,974	$	1,693,698	$	1,088,632

(1) Includes minimum principal payments and interest calculated using interest rates at December 31, 2016.

(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, 2016 multiplied by the contract volumes.

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(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.

Dividends and Distributions

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.

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, 2016, we held approximately 10.9 million barrels of crude oil, refined product and other inventories valued under the LIFO valuation method with an average cost of $64.11 per barrel. At December 31, 2016, the excess of the current cost of our crude oil, refined product and other feedstock and blendstock inventories over aggregated LIFO costs was $140.1 million.

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.

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.

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The following tables summarize our economic hedging activity recognized within cost of products sold for the three years ended December 31, 2016, and open commodity hedging positions as of December 31, 2016, and December 31, 2015:

	Year Ended December 31,
	2016			2015			2014
	(In thousands)
Economic hedging activities recognized within cost of products sold
Realized hedging gain, net	$	58,773		$	93,699		$	95,331
Unrealized hedging gain (loss), net	(77,674		)	(50,233		)	194,423
Total hedging gain (loss), net	$	(18,901	)	$	43,466		$	289,754

	December 31, 2016			December 31, 2015
	(In thousands)
Open commodity hedging instruments (bbls)
Crude oil differential swaps, net long positions	2,124			5,155
Crude futures	(1,703		)	(562		)
Refined product price and crack spread swaps	(6,632		)	(5,645		)
Total open commodity hedging instruments	(6,211		)	(1,052		)
Fair value of outstanding contracts, net
Other current assets	$	13,649		$	78,125
Other assets	8			11,881
Accrued liabilities	(10,827		)	(10,273		)
Other long-term liabilities	(771		)	—
Fair value of outstanding contracts - unrealized gain, net	$	2,059		$	79,733

During the three years ended December 31, 2016, we did not have any commodity derivative instruments that were designated or accounted for as hedges.

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Item 8. Financial Statements and Supplementary Data

Management’s Report on Internal Control Over Financial Reporting

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

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

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

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

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

Our management assessed the effectiveness of our internal control over financial reporting as of December 31, 2016, for Western Refining, Inc. and its subsidiaries. In making this assessment, our management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) in the 2013 Internal Control-Integrated Framework. Based on its assessment, our management believes that, as of December 31, 2016, our internal control over financial reporting is effective based on those criteria.

Our independent registered public accounting firm, Deloitte & Touche LLP, has issued an audit report on our internal control over financial reporting. This report appears on page 69 of this annual report.

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Report of Independent Registered Public Accounting Firm

The Board of Directors and Shareholders of

Western Refining, Inc.

El Paso, Texas

We have audited the internal control over financial reporting of Western Refining, Inc. and subsidiaries (the "Company") as of December 31, 2016, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying “Management's Report on Internal Control Over Financial Reporting”. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit.

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

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

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

In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2016, based on the criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended December 31, 2016 of the Company and our report dated March 1, 2017 expressed an unqualified opinion on those financial statements.

/s/ DELOITTE & TOUCHE LLP

Phoenix, Arizona

March 1, 2017

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INDEX TO FINANCIAL STATEMENTS

	Page
Report of Independent Registered Public Accounting Firm	71
Consolidated Balance Sheets as of December 31, 2016 and 2015	72
Consolidated Statements of Operations for the Three Years ended December 31, 2016	73
Consolidated Statements of Comprehensive Income for the Three Years ended December 31, 2016	74
Consolidated Statements of Changes in Equity for the Three Years ended December 31, 2016	75
Consolidated Statements of Cash Flows for the Three Years ended December 31, 2016	76
Notes to Consolidated Financial Statements	77

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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, 2016 and 2015, 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, 2016. 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, 2016 and 2015, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2016, 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, 2016, based on the criteria established in Internal Control-Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 1, 2017 expressed an unqualified opinion on the Company’s internal control over financial reporting.

/s/ DELOITTE & TOUCHE LLP

Phoenix, Arizona

March 1, 2017

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WESTERN REFINING, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In thousands, except share data)

	As of December 31,
	2016		2015
ASSETS
Current assets:
Cash and cash equivalents (WNRL: $14,652 and $44,605, respectively)	$	268,581	$	772,502
Accounts receivable, trade, net of a reserve for doubtful accounts of $235 and $169, respectively (WNRL: $65,240 and $55,053, respectively)	423,171		359,237
Inventories (WNRL: $10,144 and $15,200, respectively)	771,989		547,538
Prepaid expenses (WNRL: $6,421 and $4,133, respectively)	95,355		73,213
Other current assets (WNRL: $6,403 and $5,943, respectively)	113,421		169,728
Total current assets	1,672,517		1,922,218
Restricted cash	—		69,106
Equity method investment	102,685		97,513
Property, plant and equipment, net (WNRL: $419,448 and $430,141, respectively)	2,364,482		2,305,171
Goodwill	1,289,443		1,289,443
Intangible assets, net (WNRL: $6,515 and $7,757, respectively)	83,812		84,945
Other assets (WNRL: $3,233 and $3,376, respectively)	47,458		64,997
Total assets	$	5,560,397	$	5,833,393
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable (WNRL: $9,186 and $10,501, respectively)	$	753,933	$	553,957
Accrued liabilities (WNRL: $39,599 and $30,624, respectively)	219,607		248,395
Current portion of long-term debt	10,500		5,500
Total current liabilities	984,040		807,852
Long-term liabilities:
Long-term debt, less current portion (WNRL: $313,032 and $437,467, respectively)	1,871,805		1,644,894
Lease financing obligation	54,163		53,232
Deferred income tax liability, net (WNRL: $641 and $0, respectively)	260,293		312,914
Other liabilities (WNRL: $9 in both periods)	93,136		68,595
Total long-term liabilities	2,279,397		2,079,635
Commitments and contingencies
Equity:
Western shareholders' equity:
Common stock, par value $0.01, 240,000,000 shares authorized; 108,512,228 and 102,773,705 shares issued, respectively	1,085		1,028
Preferred stock, par value $0.01, 10,000,000 shares authorized; no shares issued and outstanding	—		—
Additional paid-in capital	633,381		492,848
Retained earnings	1,061,168		1,167,938
Accumulated other comprehensive income, net of tax	1,226		651
Treasury stock, 9,089,623 shares at cost	—		(363,168		)
Total Western shareholders' equity	1,696,860		1,299,297
Non-controlling interest	600,100		1,646,609
Total equity	2,296,960		2,945,906
Total liabilities and equity	$	5,560,397	$	5,833,393

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,
	2016			2015			2014
Net sales	$	7,743,213		$	9,787,036		$	15,153,573
Operating costs and expenses:
Cost of products sold (exclusive of depreciation and amortization)	5,978,811			7,521,375			12,719,963
Direct operating expenses (exclusive of depreciation and amortization)	928,023			902,925			850,634
Selling, general and administrative expenses	217,861			225,245			226,020
Merger and reorganization costs	12,440			—			12,878
Loss (gain) and impairments on disposal of assets, net	(1,271		)	51			8,530
Maintenance turnaround expense	47,137			2,024			48,469
Depreciation and amortization	216,787			205,291			190,566
Total operating costs and expenses	7,399,788			8,856,911			14,057,060
Operating income	343,425			930,125			1,096,513
Other income (expense):
Interest income	692			703			1,188
Interest and debt expense	(123,291		)	(105,603		)	(97,062		)
Loss on extinguishment of debt	(3,916		)	—			(9		)
Other, net	24,964			13,161			2,046
Income before income taxes	241,874			838,386			1,002,676
Provision for income taxes	(54,868		)	(223,955		)	(292,604		)
Net income	187,006			614,431			710,072
Less net income attributed to non-controlling interests	62,067			207,675			150,146
Net income attributable to Western Refining, Inc.	$	124,939		$	406,756		$	559,926
Net earnings per share:
Basic	$	1.24		$	4.28		$	6.17
Diluted	$	1.24		$	4.28		$	5.61
Weighted average common shares outstanding:
Basic	100,473			94,899			90,708
Diluted	100,868			94,999			101,190

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,
	2016			2015			2014
Net income	$	187,006		$	614,431		$	710,072
Other comprehensive income items:
Benefit plans:
Amortization of net prior service cost	(253		)	215			161
Reclassification of loss to income	—			50			21
Pension plan termination adjustment	420			—			—
Actuarial gain (loss)	724			1,683			(2,157		)
Net prior service credit	—			2,463			—
Other comprehensive income (loss) before tax	891			4,411			(1,975		)
Income tax	(386		)	(403		)	295
Other comprehensive income (loss), net of tax	505			4,008			(1,680		)
Comprehensive income	187,511			618,439			708,392
Less comprehensive income attributed to non-controlling interests	61,997			209,741			149,407
Comprehensive income attributable to Western Refining, Inc.	$	125,514		$	408,698		$	558,985

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)

										Accum.
	Common Stock									Other
				Additional						Compr.								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, 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 benefit 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 and 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
Stock-based compensation	—	—		7,513			—			—			—		—			5,848			13,361
Restricted share unit and phantom stock vesting	174,102	1		(1		)	—			—			—		—			—			—
Excess tax benefit from stock-based compensation	—	—		573			—			—			—		—			—			573
Cash dividends declared of $1.52 per share	—	—		—			(153,691		)	—			—		—			—			(153,691		)
NTI merger	5,564,421	56		144,189			(78,018		)	—			11,551,973		438,168			(1,329,348		)	(824,953		)
Transaction costs for NTI merger	—	—		(11,741		)	—			—			—		—			—			(11,741		)
Net income	—	—		—			124,939			—			—		—			62,067			187,006
Other comprehensive income, net of tax of $386	—	—		—			—			575			—		—			(70		)	505
Issuance of WNRL common units	—	—		—			—			—			—		—			277,751			277,751
Offering costs for issuance of WNRL common units	—	—		—			—			—			—		—			(655		)	(655		)
Distribution to non-controlling interest holders	—	—		—			—			—			—		—			(62,102		)	(62,102		)
Treasury stock, at cost	—	—		—			—			—			(2,462,350	)	(75,000		)	—			(75,000		)
Balance at December 31, 2016	108,512,228	$	1,085	$	633,381		$	1,061,168		$	1,226		—		$	—		$	600,100		$	2,296,960

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,
	2016			2015			2014
Cash flows from operating activities:
Net income	$	187,006		$	614,431		$	710,072
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	216,787			205,291			190,566
Changes in fair value of commodity hedging instruments	77,674			50,233			(194,423		)
Reserve for doubtful accounts	66			(315		)	296
Amortization of loan fees and original issue discount	8,766			6,450			14,496
Loss on extinguishment of debt	3,916			—			9
Stock-based compensation expense	22,523			16,505			19,903
Deferred income taxes	(17,679		)	(41,895		)	71,827
Change in lower of cost or market reserve	(133,414		)	96,536			78,554
Excess tax benefit from stock-based compensation	(1,033		)	(871		)	(1,144		)
Income from equity method investment, net of dividends	(5,410		)	(1,672		)	(2,238		)
Loss (gain) and impairments on disposal of assets, net	(1,271		)	51			8,530
Changes in operating assets and liabilities:
Accounts receivable	(64,810		)	108,604			132,107
Inventories	(91,037		)	(14,837		)	(150,403		)
Prepaid expenses	(22,142		)	15,202			23,722
Other assets	(4,372		)	(41,187		)	22,312
Accounts payable and accrued liabilities	193,389			(198,707		)	(190,209		)
Other long-term liabilities	14,788			29,264			3,656
Net cash provided by operating activities	383,747			843,083			737,633
Cash flows from investing activities:
Capital expenditures	(300,969		)	(290,863		)	(223,271		)
Proceeds from the sale of assets	5,521			1,114			1,936
Return of capital on equity method investment	—			—			7,480
Increase in restricted cash	(195,000		)	(170,000		)	(320,000		)
Use of restricted cash	264,106			267,903			152,991
Net cash used in investing activities	(226,342		)	(191,846		)	(380,864		)
Cash flows from financing activities:
Additions to long-term debt	500,000			300,000			79,311
Payments on long-term debt and capital lease obligations	(135,392		)	(7,368		)	(6,072		)
Borrowings on revolving credit facility	466,900			145,000			269,000
Repayments of revolving credit facility	(591,600		)	(269,000		)	—
Payments for NTI units related to merger	(859,893		)	—			—
Transaction costs for NTI merger	(11,741		)	—			—
Distribution to non-controlling interest holders	(66,311		)	(238,366		)	(173,637		)
Deferred financing costs	(12,727		)	(6,820		)	(9,649		)
Purchases of common stock for treasury	(75,000		)	(105,000		)	(259,222		)
Dividends paid	(153,691		)	(129,211		)	(293,746		)
Convertible debt redemption	—			—			(809		)
Proceeds from issuance of WNRL common units	277,751			—			—
Offering costs for issuance of WNRL common units	(655		)	—			—
Excess tax benefit from stock-based compensation	1,033			871			1,144
Net cash used in financing activities	(661,326		)	(309,894		)	(393,680		)
Net increase (decrease) in cash and cash equivalents	(503,921		)	341,343			(36,911		)
Cash and cash equivalents at beginning of year	772,502			431,159			468,070
Cash and cash equivalents at end of year	$	268,581		$	772,502		$	431,159

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 our refineries in El Paso, Texas; near Gallup, New Mexico and 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 544 company-owned and franchised retail sites in the United States.

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 Tesoro (“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 Tesoro Merger,” and, if a second merger election as discussed below is not made, the “Tesoro Merger”), with the Company surviving the First Tesoro 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 Tesoro Merger, each share of our common stock, par value $0.01 per share issued and outstanding immediately prior to the effective time of the First Tesoro Merger (excluding our common stock 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 each share of our common stock, either (a) $37.30 in cash or (b) 0.4350 shares of Tesoro common stock, par value $0.16⅔ per share, in each case without interest. See Note 31, Tesoro Merger, for additional information.

At December 31, 2016, we own 100% of the limited partner interest in Northern Tier Energy LP ("NTI") and 100% of its general partner. We entered into an Agreement and Plan of Merger dated as of December 21, 2015 (the “NTI Merger Agreement”), with Western Acquisition Co, LLC (“MergerCo”) which is a wholly-owned subsidiary of Western, NTI and Northern Tier Energy GP LLC, to acquire all of NTI’s outstanding common units not already held by us (the “NTI Merger”). On June 23, 2016, following the approval of the NTI Merger Agreement by NTI common unitholders, all closing conditions to the NTI Merger were satisfied, and the NTI Merger was successfully completed. We incurred $500 million of additional secured indebtedness under our amended term loan credit agreement to partially fund the NTI Merger consideration. See Note 30, NTI, for additional information.

We formed Western Refining Logistics, LP ("WNRL") as a Delaware master limited partnership to own, operate, develop and acquire terminals, storage tanks, pipelines and other logistics assets and related businesses. At December 31, 2016, we owned a 52.6% limited partner interest in WNRL and the public held a 47.4% 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 September 15, 2016, we sold certain assets consisting of terminals, transportation and storage assets and the related land located 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 (the "St. Paul Park Logistics Assets"). 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. We refer to this transaction as the "St. Paul Park Logistics Transaction." The St. Paul Park Logistics Transaction was a reorganization of entities under common control. See Note 29, Western Refining Logistics, LP, for additional information on this transaction.

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. The option 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.

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WESTERN REFINING, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

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." The TexNew Mex Pipeline Transaction was a reorganization of entities under common control. See Note 29, Western Refining Logistics, LP, for additional information on this transaction.

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 "Wholesale Acquisition"). 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.

The WNRL financial and operational data presented includes the historical results of all assets acquired from Western in the St. Paul Park Logistics Transaction, the TexNew Mex Pipeline Transaction and the Wholesale Acquisition. These acquisitions from Western were transfers of assets between entities under common control. We have retrospectively adjusted historical financial and operational data of WNRL, for all periods presented, to reflect the purchase and consolidation of the purchased assets into WNRL.

During the third quarter of 2016, we changed our reportable segments due to changes in our organization. Our operations include three business segments: refining, WNRL and retail. See Note 3, Segment Information, for further discussion of our business segments.

Demand for gasoline is generally higher during the summer months than during the winter months. As a result, our operating results for the first and fourth calendar quarters are generally lower than those for the second and third calendar quarters of each year. During 2016, 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.

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.

We own 100% of NTI's general partner and, subsequent to the NTI Merger, we own 100% of the limited partner interest in NTI. We own a 52.6% limited partner interest in WNRL and 100% of WNRL's general partner. As the general partner of WNRL, we have the ability to direct the activities of WNRL that most significantly impact its respective economic performance. We have reported a non-controlling interest for WNRL as of December 31, 2016, of $600.1 million and non-controlling interests for NTI and WNRL of $1,646.6 million as of December 31, 2015, in our Consolidated Balance Sheets. Investments in significant non-controlled entities over which we have the ability to exercise significant influence are accounted for using the equity method.

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 at December 31, 2015 reported in our Consolidated Balance Sheets relates to net proceeds from the sale of Western's TexNew Mex Pipeline System to WNRL. This cash was used to invest in capital assets.

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

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, $0.2 million and $0.5 million for the years ended December 31, 2016, 2015 and 2014, respectively. Additions, deductions and balances for the reserve for doubtful accounts for the three years ended December 31, 2016, are presented below:

	Year Ended December 31,
	2016			2015			2014
	(In thousands)
Balance at January 1	$	169		$	484		$	906
Additions	803			367			3,095
Reductions	(737		)	(682		)	(3,517		)
Balance at December 31	$	235		$	169		$	484

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.

Refined products inventories held by our refineries and SuperAmerica retail are valued under the LIFO valuation method. Our refined product inventories for Southwest Retail, our Mid-Atlantic business and WNRL wholesale are valued using the first-in, first-out (“FIFO”) inventory valuation method. Retail merchandise inventory is valued using the retail inventory method.

Equity Method Investment

We own a 17% common equity interest in Minnesota Pipe Line Company, LLC ("MPL"). 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, 2016 and 2015 and is included in other non-current assets in our Consolidated Balance Sheets.

Property, Plant and Equipment

Property, plant and equipment are stated at cost. We capitalize interest on expenditures for capital projects in process greater than six months and greater than $1 million until such projects are ready for their intended use.

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

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

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

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

Goodwill

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

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

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.

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

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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 and various other assets that are related to our general operation and are stated at cost.

Impairment of Long-Lived Assets

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

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

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

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

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 and service parts and labor. Retail cost of products sold includes costs for motor fuels and for merchandise. Motor fuel cost of products sold represents net cost for purchased fuel. Net cost of purchased fuel excludes transportation and motor fuel taxes. Merchandise cost of products sold includes merchandise purchases, net of merchandise rebates and inventory shrinkage.

Refining direct operating expenses include direct costs of labor, maintenance materials and services, chemicals and catalysts, natural gas, utilities and other direct operating expenses. 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

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of labor, maintenance materials and services, natural gas, additives, utilities, insurance expense, property taxes and other direct operating expenses.

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 ("RSU"). The fair value of each restricted share or RSU 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 RSUs 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.

Effective upon the closing of the NTI Merger, Western adopted and assumed NTI's equity compensation plan and amended and renamed the plan as the Amended and Restated Northern Tier Energy LP 2012 Long-Term Incentive Plan ("NTI LTIP"). Modifications to the NTI LTIP include, among other things, a change to the unit of equity from an NTI common unit to a share of Western common stock. The amendment changes the administrator of the NTI LTIP from the board of directors of NTI's general partner to Western's board of directors or its applicable committee. Consistent with the terms of the NTI Merger Agreement, all unvested equity awards at the time of the NTI Merger were exchanged for Western phantom stock awards and performance cash awards under the NTI LTIP.

Financial Instruments and Fair Value

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

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

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

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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 are required to recognize certain obligations for the retirement of our tangible long-lived assets that result from acquisition, construction, development and normal operation. A retirement obligation exists if a party is required to settle an obligation as a result of an existing or enacted law, statute, ordinance or written or oral contract or by legal construction of a contract under the doctrine of promissory estoppel. We record the fair value of a liability for an asset retirement obligation (“ARO”) in the period in which it is incurred if a reasonable estimate of fair value can be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. The increase in the ARO due to the passage of time is recorded as an operating expense (accretion expense). See Note 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 may be discounted dependent upon specific circumstances related to each environmental liability acquired. The majority of our environmental obligations are recorded on an undiscounted basis. The timing and magnitude of these accruals generally are based on the completion of investigations or other studies or a commitment to a formal plan of action. Current regulations are applied in determining environmental liabilities and are based on best estimates of probable undiscounted future costs over the estimated period of time expected to complete the remediation activities using currently available technology as well as our internal environmental policies. Environmental liabilities are difficult to assess and estimate due to uncertainties related to the magnitude of possible remediation and the timing of such remediation. Such estimates are subject to change due to many factors, including the identification of new sites requiring remediation, changes in environmental laws and regulations and their interpretation, additional information related to the extent and nature of remediation efforts and potential improvements in remediation technologies. Amounts recorded for environmental liabilities are not reduced by possible recoveries from third parties. Recoveries of environmental remediation costs from other parties are recorded as assets when we deem their receipt probable.

Income Taxes

Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized to reflect temporary differences between the basis of assets and liabilities for financial reporting purposes and income tax purposes. Generally, deferred tax assets represent future income tax reductions while deferred tax liabilities represent income taxes that we expect to pay in the future. Deferred tax assets and liabilities are measured using enacted tax rates expected to

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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 WNRL due to our ownership of the general partner. WNRL is a publicly held master limited partnership, which is not taxable for federal income tax. We record income taxes on the portion of income or loss attributable to our respective ownership of 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.

Recent Accounting Pronouncements

Effective January 1, 2016, we adopted the revised accounting and reporting requirements included in the Accounting Standards Codification ("ASC") for consolidation of limited partnerships or similar entities. We have applied the new standards retrospectively. The adoption of these revised standards did not result in any change to our consolidation conclusions or impact our financial position, results of operations or cash flows. We have added disclosures for WNRL as required for entities not previously included in the reporting entity as a variable interest entity.

For interim and annual periods beginning after December 15, 2016, the requirements related to employee share-based payment accounting were modified. The revised requirements involve several aspects of accounting for share-based payment transactions, including income tax consequences, classification of awards as either equity or liabilities, classification in the statement of cash flows and forfeiture rate calculations. The updated guidance is effective as of January 1, 2017. The impact of this guidance will not be material to our financial position, results of operations or cash flows when implemented.

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. The revised standard also addresses principal versus agent considerations and indicators related to transfer of control over specified goods. These provisions are effective January 1, 2018, and can be adopted using either a full retrospective approach or a modified approach, with early adoption permitted for periods beginning after December 15, 2016, and interim periods thereafter.

We have been evaluating and continue to evaluate the provisions of this standard and its impact on our business processes, business and accounting systems, and financial statements and related disclosures. A multi-disciplined implementation team has gained an understanding of the standard’s revenue recognition model, is reviewing and documenting our contracts, and is analyzing whether enhancements are needed to our business and accounting systems. We currently plan to adopt this standard on January 1, 2018.

• Lease accounting - the requirements were amended with regard to recognizing lease assets and lease liabilities on the balance sheet and disclosing information about leasing arrangements. The core principle is that a lessee should

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recognize the assets and liabilities that arise from leases. These provisions are effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Early adoption is permitted. We have been evaluating and continue to evaluate the provisions of this standard and its impact on our business processes, business and accounting systems, and financial statements and related disclosures.

• Cash flow statement - the requirements address certain classification issues related to the statement of cash flows. These provisions are effective for annual periods beginning after December 15, 2017, including interim periods within those annual periods. Early adoption is permitted in any interim or annual period.

• Recognition of breakage for certain prepaid stored-value products - the requirements align recognition of the financial liabilities related to prepaid stored-value products with the revenue recognition standard discussed above for non-financial liabilities. Certain of these liabilities may be extinguished proportionally in earnings as redemptions occur, or when redemption is remote if issuers are not entitled to the unredeemed stored value. This guidance is effective for fiscal years, and interim periods within those years, beginning after December 15, 2017 with early adoption permitted subject to certain requirements.

• Contingent put and call options in debt instruments - the requirements will reduce diversity of practice in identifying embedded derivatives in debt instruments and clarify the nature of an exercise contingency is not subject to the “clearly and closely” criteria for purposes of assessing whether the call or put option must be separated from the debt instrument and accounted for separately as a derivative. This guidance is effective for fiscal years, and interim periods within those years, beginning after December 15, 2016, with early adoption permitted subject to certain requirements.

• Cash flow statement - the requirements provide guidance on presentation in the statement of cash flows for cash, cash equivalents and restricted cash or restricted cash equivalents in order to address diversity in practice among entities. The Update would result in presentation of restricted cash as a component of beginning-of-the-period and end-of-the-period cash and cash equivalents within the statement of cash flows. This guidance is effective for fiscal years, and interim periods within those years, beginning after December 15, 2018 with early adoption permitted subject to certain requirements.

• Business Combinations - the requirements clarify the definition of a business and provide a framework that gives entities a basis for making reasonable judgments about whether a transaction involves an asset or a business. This guidance is effective in annual periods beginning after December 15, 2017, including interim periods therein. It must be applied prospectively on or after the effective date with early adoption permitted subject to certain requirements, and no disclosures for a change in accounting principle are required at transition.

• Goodwill - the requirements change the accounting for goodwill impairments by eliminating step 2 from the goodwill impairment test. Instead, if the carrying amount of a reporting unit exceeds its fair value, an impairment loss shall be recognized in an amount equal to that excess, limited to the total amount of goodwill allocated to that reporting unit. This guidance is effective for annual and any interim impairment tests for periods beginning after December 15, 2019. Early adoption is allowed for all entities as of January 1, 2017, for annual and any interim impairment tests occurring after January 1, 2017.

3. Segment Information

We have organized our operations into threereportable 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. Prior to the NTI Merger on June 23, 2016, we also reported NTI as a separate reportable segment. Following the completion of the NTI Merger, NTI became a wholly-owned subsidiary of Western and, as a result, we have moved its net assets and operations into our refining segment, retail segment and other category. Beginning on July 1, 2016, our management team, led by our chief operating decision maker, began monitoring our business and allocating resources based on these three reportable segments. We have retrospectively adjusted the historical segment financial data for the periods presented to reflect our revised segment presentation. See Note 24, Concentration of Risk, for a discussion on significant customers.

We treated the St. Paul Park Logistics Assets we sold to WNRL 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. We moved the St. Paul Park Logistics Assets from the refining segment to the WNRL segment.

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A description of each segment and the principal products follows:

Refining. Our refining segment includes operations of three refineries. The El Paso refinery in El Paso, Texas, has a crude oil throughput capacity of 135,000 barrels per day ("bpd"), the Gallup refinery, near Gallup, New Mexico has a 25,000 bpd capacity and the St. Paul Park refinery, in St. Paul Park, Minnesota has a 102,000 bpd capacity. Our refineries produce 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 year ended December 31, 2014 includes $5.8 million in business interruption recoveries related to processing outages that occurred during the first and fourth quarters of 2011 at our El Paso refinery.

We had a 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 $4.1 million and $1.8 million in assets at December 31, 2016, and 2015, respectively, related to this supply agreement in our Consolidated Balance Sheets. The revenues and costs recorded under the supply agreement included $8.7 million, $48.7 million and $34.6 million in net hedging gains for the years ended December 31, 2016, 2015 and 2014. This supply agreement expired on December 31, 2016. On that date, we acquired $46.0 million in finished product inventories valued at market related to our Mid-Atlantic operations and now realize 100% of the operating results.

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 and Upper Great Plains regions, including 705 miles of pipelines and 12.4 million barrels of active storage capacity. The majority of WNRL's logistics assets are integral to the operations of the El Paso, Gallup and St. Paul Park 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, asphalt and refined product delivery trucks. WNRL distributes commercial wholesale petroleum products primarily in Arizona, Colorado, Nevada, New Mexico and Texas. WNRL purchases petroleum fuels and lubricants from our refining segment and from third-party suppliers.

Retail. Our retail segment operates retail networks located in the Southwest region ("Southwest Retail") and the Upper Great Plains of the U.S. ("SuperAmerica"). Each of our retail networks sells 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, 2016, the retail segment operated 259 service stations and convenience stores or kiosks located in Arizona, Colorado, New Mexico and Texas compared to 258 and 230 service stations and convenience stores or kiosks at December 31, 2015 and 2014, respectively. The Southwest Retail stores were added primarily under various operating and capital leases. At December 31, 2016, the retail segment operated 51 cardlocks located in Arizona and New Mexico compared to 52 and 50 cardlocks at December 31, 2015 and 2014, respectively.

As of December 31, 2016, SuperAmerica operated 170 retail convenience stores and supported the operations of 115 franchised retail convenience stores primarily in Minnesota and Wisconsin, compared to 168 and 109 at December 31, 2015 and 165 and 89 at December 31, 2014. SuperAmerica obtains the majority of its gasoline and diesel for its Minnesota and Wisconsin retail convenience stores from the St. Paul Park refinery.

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 reportable 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

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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.

Disclosures regarding our reportable segments with reconciliations to consolidated totals for the three years ended December 31, 2016, are presented below:

	Year Ended
	December 31, 2016			December 31, 2015			December 31, 2014
	(In thousands)
Operating Results:
Refining
Net sales	$	6,918,931		$	8,777,196		$	14,196,564
Intersegment eliminations	2,819,844			3,072,806			4,291,617
Net refining sales to external customers	4,099,087			5,704,390			9,904,947
WNRL
Net sales	2,222,718			2,599,867			3,501,888
Intersegment eliminations	702,157			786,324			1,011,575
Net WNRL sales to external customers	1,520,561			1,813,543			2,490,313
Retail
Net sales	2,159,946			2,279,737			2,776,782
Intersegment eliminations	36,381			10,634			19,575
Net retail sales to external customers	2,123,565			2,269,103			2,757,207
Other
Other revenue, net	—			—			1,106
Intersegment eliminations	—			—			—
Net other sales to external customers	—			—			1,106
Consolidated net sales to external customers	$	7,743,213		$	9,787,036		$	15,153,573
Operating income (loss)
Refining (1) (2)	$	357,610		$	930,531		$	1,140,580
WNRL (2)	70,095			55,794			35,607
Retail (1)	25,146			41,279			42,087
Other	(109,426		)	(97,479		)	(121,761		)
Operating income	343,425			930,125			1,096,513
Other income (expense), net	(101,551		)	(91,739		)	(93,837		)
Consolidated income before income taxes	$	241,874		$	838,386		$	1,002,676
Depreciation and amortization
Refining (2)	$	150,989		$	142,108		$	137,715
WNRL (2)	39,242			35,384			28,934
Retail	23,193			23,197			19,869
Other	3,363			4,602			4,048
Consolidated depreciation and amortization	$	216,787		$	205,291		$	190,566

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	Year Ended
	December 31, 2016		December 31, 2015		December 31, 2014
	(In thousands)
Capital expenditures
Refining (2)	$	248,863	$	201,249	$	119,416
WNRL (2)	29,161		65,635		79,338
Retail	20,308		20,895		22,056
Other	2,637		3,084		2,461
Consolidated capital expenditures	$	300,969	$	290,863	$	223,271
Total assets
Refining (2) (including $1,267,455 of goodwill)	$	4,312,212	$	4,024,131	$	4,126,005
WNRL (2)	533,952		566,209		552,253
Retail (including $21,988 of goodwill)	435,030		444,382		417,269
Other	279,203		798,671		546,659
Consolidated total assets	$	5,560,397	$	5,833,393	$	5,642,186

(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 $18.9 million in net realized and unrealized economic hedging losses for the year ended December 31, 2016 and $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. Cost of products sold included net non-cash LCM recoveries in our refining segment of $132.0 million for the year ended December 31, 2016 and charges of $95.8 million and $77.1 million for the years ended December 31, 2015 and 2014, respectively, and recoveries in our retail segment of $1.4 million for the year ended December 31, 2016 and charges of $0.7 million and $1.4 million for the years ended December 31, 2015 and 2014, respectively.

(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, 2016. The information contained herein for WNRL has been retrospectively adjusted, to include the historical results of the St. Paul Park Logistics Assets.

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, 2016, and December 31, 2015, 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 $60.0 million and $70.1 million consisting of short-term money market deposits and commercial paper were included in the Consolidated Balance Sheets as of December 31, 2016 and 2015, 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, 2016 and 2015, and the basis for that measurement:

	Carrying Value at December 31, 2016			Fair Value Measurement at December 31, 2016 Using							Netting Adjustments			Recorded Value at December 31, 2016
				Level 1		Level 2			Level 3
	(In thousands)
Gross financial assets:
Other current assets	$	18,929		$	—	$	18,929		$	—	$	(5,280	)	$	13,649
Other assets	677			—		677			—		(669		)	8
Gross financial liabilities:
Accrued liabilities	(17,547		)	—		(17,547		)	—		6,720			(10,827		)
Other long-term liabilities	—			—		—			—		(771		)	(771		)
	$	2,059		$	—	$	2,059		$	—	$	—		$	2,059

	Carrying Value at December 31, 2015			Fair Value Measurement at December 31, 2015 Using								Netting Adjustments			Recorded Value at December 31, 2015
				Level 1		Level 2			Level 3
	(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

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, 2016 and 2015.

	December 31,
	2016			2015
	(In thousands)
Asset (liability) balance at beginning of period	$	(5,756	)	$	330
Change in fair value of Level 3 trades open at the beginning of the period	—			—
Fair value of trades entered into during the period	—			(5,756		)
Fair value reclassification from Level 3 to Level 2	5,756			(330		)
Asset (liability) balance at end of period	$	—		$	(5,756	)

As of December 31, 2016, we had no outstanding commodity price swap contracts.

As of December 31, 2016 and 2015, the carrying amount and estimated fair value of our debt was as follows:

	December 31,
	2016		2015
	(In thousands)
Western obligations:
Carrying amount	$	1,256,000	$	889,000
Fair value	1,277,956		867,178
NTI obligations:
Carrying amount	$	349,980	$	350,000
Fair value	363,542		360,500
WNRL obligations:
Carrying amount	$	320,300	$	445,000
Fair value	345,050		439,000

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 based on prices from recent trade activity and is categorized in Level 2 of the fair value hierarchy.

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,
	2016		2015
	(In thousands)
Refined products (1)	$	325,889	$	201,928
Crude oil and other raw materials	395,131		288,403
Lubricants	10,121		14,996
Retail store merchandise	40,848		42,211
Inventories	$	771,989	$	547,538

(1) Includes $50.5 million and $14.5 million of inventory valued using the FIFO valuation method at December 31, 2016 and 2015, respectively.

As of December 31, 2016 and 2015, refined products valued under the LIFO method and crude oil and other raw materials totaled 10.9 million barrels and 10.0 million barrels, respectively. At December 31, 2016 and 2015, the excess of the

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LIFO cost over the current cost of these crude oil, refined product and other feedstock and blendstock inventories was $140.1 million and $198.4 million, respectively.

Cost of products sold included net non-cash charges of $58.3 million during the year ended December 31, 2016 and net non-cash recoveries of $170.0 million and $222.0 million during the years ended December 31, 2015 and 2014, respectively, from changes in our LIFO reserves.

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 $41.7 million and $175.1 million at December 31, 2016 and 2015, respectively. Cost of products sold included net non-cash LCM recoveries of $133.4 million for the year ended December 31, 2016 and charges of $96.5 million and $78.6 million for the years ended 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,
	2016			2015			2014
	(In thousands, except per share amount)
Increase (decrease) in operating income	$	(2,868	)	$	(16,111	)	$	1,097
Increase (decrease) in net income	(2,218		)	(11,808		)	777
Increase (decrease) in earnings per diluted share	$	(0.02	)	$	(0.12	)	$	0.01

Average LIFO cost per barrel of our refined products and crude oil and other raw materials inventories as of December 31, 2016 and 2015, was as follows:

	December 31,
	2016					2015
	Barrels	LIFO Cost		Average LIFO Cost Per Barrel		Barrels	LIFO Cost		Average LIFO Cost Per Barrel
	(In thousands, except cost per barrel)
Refined products	4,259	$	303,968	$	71.37	3,536	$	259,722	$	73.45
Crude oil and other	6,641	394,798		59.45		6,490	391,237		60.28
	10,900	$	698,766	64.11		10,026	$	650,959	64.93

6. Prepaid Expenses

Prepaid expenses were as follows:

	December 31,
	2016		2015
	(In thousands)
Prepaid crude oil and other raw materials inventories	$	49,405	$	23,793
Prepaid insurance	12,726		5,904
RINs	12,722		21,174
Prepaid income taxes	456		3,099
Other	20,046		19,243
Prepaid expenses	$	95,355	$	73,213

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7. Other Current Assets

Other current assets were as follows:

	December 31,
	2016		2015
	(In thousands)
Material and chemical inventories	$	49,915	$	54,053
Excise and other taxes receivable	19,644		21,801
Margin account deposits	14,852		—
Fair value of open commodity hedging positions, net	13,649		78,125
Exchange and other receivables	15,361		15,749
Other current assets	$	113,421	$	169,728

8. Equity Method Investment

We own a 17% common equity interest in MPL. The carrying value of this equity method investment was $102.7 million and $97.5 million at December 31, 2016 and 2015, respectively.

Summarized financial information for MPL for the years ended December 31, 2016, 2015 and 2014 and as of December 31, 2016 and 2015, was as follows:

	Year Ended December 31,
	2016		2015		2014
	(In thousands)
Revenues	$	215,564	$	206,195	$	184,712
Operating costs and expenses	57,444		88,909		141,250
Income from operations	158,120		117,286		43,462
Net income	137,476		96,485		22,821
Net income attributable to MPL unitholders	127,823		86,832		13,168

	December 31, 2016		December 31, 2015
	(In thousands)
Current assets	$	14,882	$	24,020
Noncurrent assets	491,955		441,825
Total assets	$	506,837	$	465,845
Current liabilities	$	26,827	$	17,658
Noncurrent liabilities	—		—
Total liabilities	$	26,827	$	17,658
Equity	$	480,010	$	448,187

As of December 31, 2016 and 2015, respectively, the carrying amount of the equity method investment was $21.1 million and $21.3 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 $16.3 million, $13.1 million and $7.5 million, respectively, for the years ended December 31, 2016, 2015 and 2014. Equity income from MPL was $21.7 million, $14.8 million and $2.2 million, respectively, for the years ended December 31, 2016, 2015 and 2014, 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,
	2016			2015
	(In thousands)
Refinery facilities and related equipment	$	2,260,351		$	2,113,650
Pipelines, terminals and transportation equipment	560,478			427,854
Retail facilities and related equipment	333,187			324,686
Wholesale facilities and related equipment	52,284			59,875
Corporate	53,566			50,607
	3,259,866			2,976,672
Accumulated depreciation	(1,118,477		)	(923,415		)
	2,141,389			2,053,257
Construction in progress	223,093			251,914
Property, plant and equipment, net	$	2,364,482		$	2,305,171

Depreciation expense was $213.5 million, $201.2 million and $187.1 million for the years ended December 31, 2016, 2015 and 2014, respectively.

10. Goodwill

At December 31, 2016 and 2015, we had goodwill of $1,289.4 million relating to the 2013 NTI Acquisition. 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 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, 2016							December 31, 2015							Weighted Average Amortization Period (Years)
	Gross Carrying Value		Accumulated Amortization			Net Carrying Value		Gross Carrying Value		Accumulated Amortization			Net Carrying Value
	(In thousands)
Amortizable assets:
Licenses and permits	$	20,427	$	(15,307	)	$	5,120	$	20,427	$	(13,729	)	$	6,698	3.3
Customer relationships	7,172		(4,234		)	2,938		7,551		(3,921		)	3,630		5.5
Rights-of-way and other	8,538		(3,242		)	5,296		6,839		(1,797		)	5,042		5.0
	36,137		(22,783		)	13,354		34,817		(19,447		)	15,370
Unamortizable assets:
Franchise rights and trademarks	50,500		—			50,500		50,500		—			50,500
Liquor licenses	19,958		—			19,958		19,075		—			19,075
Intangible assets, net	$	106,595	$	(22,783	)	$	83,812	$	104,392	$	(19,447	)	$	84,945

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Intangible asset amortization expense was $3.0 million, $2.9 million and $2.8 million for the years ended December 31, 2016, 2015 and 2014, 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):

2017	$	2,880
2018	2,880
2019	2,212
2020	1,268
2021	980

12. Other Assets

Other assets were as follows:

	December 31,
	2016		2015
	(In thousands)
Capital spare parts	$	12,717	$	8,112
Purchase agreement	9,762		16,067
Cost method investment	7,864		7,872
Notes receivable	4,366		4,586
Deposits	3,582		3,747
Fair value of open commodity hedging positions, net	8		11,881
Other	9,159		12,732
Other assets	$	47,458	$	64,997

13. Accrued and Other Long-Term Liabilities

Accrued liabilities were as follows:

	December 31,
	2016		2015
	(In thousands)
Excise and other taxes	$	68,116	$	67,932
Payroll and related costs	66,021		77,482
Professional and other	24,146		28,093
Property taxes	23,387		20,175
Interest	17,248		17,093
Fair value of open commodity hedging positions, net	10,827		10,273
Environmental reserves	6,945		10,099
Banking fees and other financing	2,718		189
Income taxes	199		—
Margin and other customer deposits	—		17,059
Accrued liabilities	$	219,607	$	248,395

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Other long-term liabilities were as follows:

	December 31,
	2016		2015
	(In thousands)
Unrecognized tax benefits	$	58,317	$	42,049
Retiree plan obligations and other	18,725		10,529
Asset retirement obligations	8,484		7,822
Environmental reserves	6,839		8,195
Fair value of open commodity hedging positions, net	771		—
Other long-term liabilities	$	93,136	$	68,595

The table below summarizes changes in our environmental liability accruals:

	December 31, 2015		Increase (Decrease)		Payments			December 31, 2016
	(In thousands)
Discounted liabilities	$	3,633	$	300	$	(433	)	$	3,500
Undiscounted liabilities	14,661		626		(5,003		)	10,284
Total environmental liabilities	$	18,294	$	926	$	(5,436	)	$	13,784

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, 2016:

	December 31,
	2016			2015			2014
	(In thousands)
Liability, beginning of period	$	7,822		$	7,539		$	7,327
Liabilities incurred	566			58			17
Liabilities acquired	—			—			—
Liabilities settled	(479		)	(187		)	(313		)
Accretion expense	575			412			508
Liability, end of period	$	8,484		$	7,822		$	7,539

Our ARO liability excludes $0.2 million of ARO classified as accrued liabilities as of December 31, 2016 and 2015, respectively.

15. Long-Term Debt

Long-term debt was as follows:

	December 31,
	2016			2015
	(In thousands)
Western obligations:
Revolving Credit Facility due 2019	$	—		$	—
Term Loan - 5.25% Credit Facility due 2020	533,500			539,000
6.25% Senior Unsecured Notes due 2021	350,000			350,000
Term Loan - 5.50% Credit Facility due 2023	372,500			—
Total Western obligations	1,256,000			889,000
NTI obligations:
Revolving Credit Facility due 2019	—			—
7.125% Senior Secured Notes, due November 2020	349,980			350,000
Total NTI obligations	349,980			350,000
WNRL obligations:
Revolving Credit Facility due 2018	20,300			145,000
7.5% Senior Notes due 2023	300,000			300,000
Total WNRL obligations	320,300			445,000
Less unamortized discount, premium and debt issuance costs	43,975			33,606
Long-term debt	1,882,305			1,650,394
Current portion of long-term debt	(10,500		)	(5,500		)
Long-term debt, net of current portion	$	1,871,805		$	1,644,894

As of December 31, 2016, annual long-term debt maturities in 2017, 2018, 2019, 2020 and 2021 are $10.5 million, $30.8 million, $10.5 million, $872.0 million and $355.0 million, respectively. Thereafter, total long-term debt maturities are $647.5 million.

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Interest and debt expense were as follows:

	Year Ended December 31,
	2016			2015			2014
	(In thousands)
Contractual interest:
Western obligations	$	62,893		$	45,248		$	51,114
NTI obligations	24,462			24,474			20,342
WNRL obligations	24,325			21,079			1,096
	111,680			90,801			72,552
Amortization of loan fees	9,125			7,561			7,786
Amortization of original issuance discount	790			—			7,352
Other interest expense	12,377			9,059			11,717
Capitalized interest	(10,681		)	(1,818		)	(2,345		)
Interest and debt expense	$	123,291		$	105,603		$	97,062

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.

Tesoro Merger

In anticipation of the merger with Western, Tesoro has incurred additional indebtedness to redeem or repay in full, as applicable, the outstanding debt of Western Refining and certain of its subsidiaries. Following completion of the Tesoro Merger, WNRL's 7.5% Senior Notes and any amounts outstanding under its revolving credit facility are expected to remain outstanding.

Western Obligations

Revolving Credit Facility

On May 27, 2016, we entered into the Second Amendment to the Third Amended and Restated Revolving Credit Agreement (the "Western 2019 Revolving Credit Facility"). The amendment amended the Western 2019 Revolving Credit Facility by, among other things, (i) permitting us to incur up to $500.0 million of additional secured indebtedness secured on a pari passu basis with the loans under the Western 2020 Term Loan Credit Facility (in the form of incremental term loans or bonds secured on a pari passu basis with the term loans) beyond what was permitted under the Western 2019 Revolving Credit Facility and (ii) modifying several triggers and thresholds based on borrowing availability under the Western 2019 Revolving Credit Facility.

On October 2, 2014, we entered into the Third Amended and Restated Revolving Credit Agreement. 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. 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, 2016, we had no direct borrowings under the Western 2019 Revolving Credit Agreement, and we had net availability under the Western 2019 Revolving Credit Facility of $266.6 million. This availability is net of $92.9 million in outstanding letters of credit.

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Term Loan Credit Agreement - 5.25%

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. On May 27, 2016, the Company entered into a third amendment of the Western 2020 Term Loan Credit Facility. The revised terms under the amendment provide for additional capacity to make restricted payments including dividends and repurchase of the Company’s outstanding common stock, inclusion of equity interests of master limited partnership subsidiaries as “replacement assets” for purposes of asset sale mandatory prepayment and changes to the use of proceeds of the incremental term loan available under the Western 2020 Term Loan Credit Facility. The third amendment also increased the incremental availability under the Western 2020 Term Loan Credit Facility from $200.0 million, prior to the amendment, to $700.0 million.

Following the third amendment, 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 2.25% or the LIBOR Rate (as defined in the Western 2020 Term Loan Credit Facility) plus 4.25% (subject to a LIBOR Rate floor of 1.00%). The current interest rate based on these criteria is 5.25%. Our effective rate of interest, including contractual interest and amortization of loan fees, for the Western 2020 Term Loan Credit Facility was 5.80% as of December 31, 2016.

The Western 2020 Term Loan Credit Facility is secured by the El Paso and Gallup refineries and the equity of NT InterHoldCo LLC, a 100% owned subsidiary of Western, and is fully and unconditionally guaranteed on a joint and several basis by certain of Western's material 100% owned subsidiaries. The Western 2020 Term Loan Credit Facility contains customary restrictive covenants including limitations on debt, investments and dividends and does not contain any financial maintenance covenants.

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 100% 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 effective rate of interest, including contractual interest and amortization of loan fees, for the Western 2021 Senior Unsecured Notes was 6.52% as of December 31, 2016.

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.

Term Loan Credit Agreement - 5.50%

On June 23, 2016, as an incremental supplement to the Western 2020 Term Loan Credit Facility, we incurred $500.0 million in new term debt that matures on June 23, 2023 (the "Western 2023 Term Loan Credit Facility"). The proceeds from the Western 2023 Term Loan Credit Facility were net of original issue discount and other fees totaling $17.0 million. We used these proceeds to partially fund the cash portion of the NTI Merger consideration. The Western 2023 Term Loan Credit Facility provides for quarterly principal payments of $1.3 million payable on the last business day of each March, June, September and December, with the remaining principal amount due on June 23, 2023. The Western 2023 Term Loan Credit Facility is secured by both the El Paso and Gallup refineries and by the equity of NT InterHoldCo LLC and is fully and unconditionally guaranteed on a joint and several basis by certain of Western's material 100% owned subsidiaries. The Western 2023 Term Loan Credit Facility bears interest at a rate based either on the base rate plus 3.50% or the LIBOR Rate plus 4.50%

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(subject to a LIBOR Rate floor of 1.00%). On December 29, 2016, we made a non-mandatory prepayment of $125.0 million under our Western 2023 Term Loan Credit Facility. The effective rate of interest, including contractual interest and amortization of original issue discount and other loan fees, for the Western 2023 Term Loan Credit Facility was 6.30% as of December 31, 2016.

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 the 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 the 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 the 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 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 Western 2021 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.

As of December 31, 2016, the availability under the NTI Revolving Credit Facility was $214.9 million. This availability is net of $70.6 million in outstanding letters of credit. There were no borrowings under the NTI Revolving Credit Facility at December 31, 2016.

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

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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 and financing costs are both amortized to interest expense over the remaining life of the notes. The effective rate of interest, including contractual interest and amortization of debt premium and of loan fees, for the NTI 2020 Secured Notes was 6.91% as of December 31, 2016.

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 100% owned domestic subsidiaries of NTI LLC. The indenture governing the NTI 2020 Secured Notes contains covenants that limit or restrict dividends or other payments from restricted subsidiaries. Indebtedness under the NTI 2020 Secured Notes is guaranteed by NTI and certain of their subsidiaries.

WNRL Obligations

Revolving Credit Facility

On October 16, 2013, WNRL entered into a $300.0 million senior secured revolving credit facility (the "WNRL Revolving Credit Facility"). On September 15, 2016, in connection with the St. Paul Park Logistics Transaction, WNRL entered into an agreement to increase the total commitment of the WNRL Revolving Credit Facility (the "Amendment") to $500.0 million. WNRL has the ability to increase the total commitment of the WNRL Revolving Credit Facility by up to $150.0 million for a total facility size of up to $650.0 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.

In addition to the increased facility size, the Amendment amended the WNRL Revolving Credit Facility by, among other things, (a) adding an anti-cash hoarding provision and (b) permitting WNRL to increase the Total Leverage Ratio permitted thereunder from 4.50:1.00 to 5.00:1.00 following any material permitted acquisition through the last day of the second full fiscal quarter following such acquisition. The incremental commitments established by the Amendment benefit from the same covenants, events of default, guarantees and security as the existing commitments under 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. During the year ended December 31, 2016, WNRL repaid $179.1 million of its outstanding direct borrowings under the WNRL Revolving Credit Facility using the proceeds generated through our equity issuances during the period. On September 15, 2016, to partially fund the purchase of the St. Paul Park Logistics Assets, WNRL borrowed $20.3 million under the WNRL Revolving Credit Facility.

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, 2016, the availability under the WNRL Revolving Credit Facility was $479.0 million, net of $20.3 million direct borrowings and $0.7 million in outstanding letters of credit. The interest rate for the borrowings under the WNRL Revolving Credit Facility was 4.75% as of December 31, 2016. The effective rate of interest, including contractual interest and amortization of loan fees, for the WNRL Revolving Credit Facility was 3.77% as of December 31, 2016.

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 100% owned subsidiary of the Partnership (“Finance Corp.” and together with the Partnership, the “Issuers”), the Guarantors named therein and U.S. Bank National Association, as trustee (the “Trustee”) under which the Issuers issued $300.0 million in aggregate principal amount of 7.5% Senior Notes due 2023. The Partnership will pay

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interest on the 7.5% Senior Notes semi-annually in cash in arrears on February 15 and August 15 of each year, beginning on August 15, 2015. The 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 effective rate of interest, including contractual interest and amortization of loan fees, for the 7.5% Senior Notes was 7.78% as of December 31, 2016.

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

16. Income Taxes

The following is an analysis of our consolidated income tax expense for the three years ended December 31, 2016:

	Year Ended December 31,
	2016			2015			2014
	(In thousands)
Current:
Federal	$	63,421		$	228,457		$	187,320
State	7,231			30,222			32,581
Total current	70,652			258,679			219,901
Deferred:
Federal	(7,262		)	(27,876		)	63,182
State	(8,522		)	(6,848		)	9,521
Total deferred	(15,784		)	(34,724		)	72,703
Provision for income taxes	$	54,868		$	223,955		$	292,604

We paid income tax, net of refunds, of $38.2 million, $283.3 million and $228.0 million for the years ended December 31, 2016, 2015 and 2014, respectively.

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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, 2016:

	Year Ended December 31,
	2016			2015			2014
	(In thousands)
Taxes at the federal statutory rate	$	84,656		$	293,435		$	350,937
State income taxes, net of federal tax benefit (1)	3,601			13,637			31,477
Valuation allowance for state net operating losses	(3,848		)	—			(2,887		)
Domestic Activity Production deduction	(2,843		)	(14,000		)	(11,900		)
Non-controlling interests	(21,723		)	(70,214		)	(50,044		)
Federal tax credit for production of ultra low sulfur diesel	—			—			(15,486		)
UTP releases	(10,823		)	(1,138		)	(2,266		)
Federal tax credit for increasing research activities	(3,780		)	1,176			(2,256		)
Impact of allocating deferred taxes associated with investment in NTI	8,132			—			—
Other, net	1,496			1,059			(4,971		)
Total income tax expense	$	54,868		$	223,955		$	292,604

(1) State income taxes, net of federal tax benefit, include $0.2 million, $5.0 million and $0.8 million in unrecognized tax benefits for the years ended December 31, 2016, 2015 and 2014, respectively.

The effective tax rates for 2016, 2015 and 2014 were 22.7%, 26.7% and 29.2%, respectively, as compared to the federal statutory rate of 35% in all years.

The following is a reconciliation of unrecognized tax benefits for the three years ended December 31, 2016:

	December 31,
	2016			2015			2014
	(In thousands)
Unrecognized tax benefits at beginning of year	$	40,174		$	13,762		$	10,571
Increases related to current year tax positions	36,281			1,100			1,500
Increases related to prior year tax positions	2,651			26,329			3,845
Decreases related to prior year tax positions	(19,180		)	(1,017		)	(2,154		)
Decreases resulting from the expiration of the statute of limitations	(4,142		)	—			—
Unrecognized tax benefits at end of year	$	55,784		$	40,174		$	13,762

We recorded unrecognized tax benefits as of December 31, 2016 of $55.8 million, of which $13.4 million would affect our effective tax rate if recognized. We believe that it is reasonably possible that a decrease of up to $2.1 million in unrecognized tax benefits related to federal exposures may be necessary within the coming year. We had accrued interest or penalties of $0.7 million with respect to the unrecognized tax benefit.

The Internal Revenue Service (the "IRS") has finalized examinations of our tax years ending December 31, 2011, 2010, 2009, 2008 and 2007. We are subject to examination by the IRS for tax years ending December 31, 2013, or after, and by various state and local taxing jurisdictions for tax years ending December 31, 2012, or after.

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

	December 31,
	2016									2015
	Assets			Liabilities			Net			Assets			Liabilities			Net
	(In thousands)
Inventories	$	—		$	(61,850	)	$	(61,850	)	$	—		$	(28,411	)	$	(28,411	)
Stock-based compensation	3,388			—			3,388			1,614			—			1,614
Property, plant and equipment	—			(357,044		)	(357,044		)	—			(261,476		)	(261,476		)
Investment in WNRL	147,625			—			147,625			77,824			—			77,824
Investment in NTI (1)	—			—			—			—			(81,789		)	(81,789		)
Postretirement obligations	2,117			—			2,117			2,595			—			2,595
Commodity hedging activities	—			(671		)	(671		)	—			(33,260		)	(33,260		)
Environmental and retirement obligations	3,975			—			3,975			3,742			—			3,742
Other, net	—			(1,750		)	(1,750		)	6,247			—			6,247
Net operating loss and tax credit carryforwards	20,897			—			20,897			20,828			—			20,828
Valuation allowance	(16,980		)	—			(16,980		)	(20,828		)	—			(20,828		)
Net deferred taxes	$	161,022		$	(421,315	)	$	(260,293	)	$	92,022		$	(404,936	)	$	(312,914	)

(1) Following the NTI Merger on June 23, 2016, our deferred tax liability associated with our investment in NTI was allocated amongst the individual temporary differences presented in this table.

At December 31, 2016, 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	$	(4,833	)	$	(243	)	2023
Virginia and Maryland	(17,200		)	(737		)	2024
Virginia and Maryland	(503		)	(22		)	2026
Virginia and Maryland	(31,219		)	(1,337		)	2028
Virginia and Maryland	(56,838		)	(2,435		)	2029
Virginia and Maryland	(98,316		)	(4,212		)	2030
Virginia and Maryland	(132,582		)	(5,680		)	2031
Virginia and Maryland	(129,268		)	(5,503		)	2032
Other	(1,070		)	(221		)	2027
Texas	(507		)	(507		)	2035
Total state NOL carryforwards	(472,336		)	(20,897		)
Less valuation allowance for operating loss carryforwards	395,130			16,980
Total credits and NOL carryforwards	$	(77,206	)	$	(3,917	)

In assessing the realizability of deferred tax assets, we determined that a valuation allowance of $17.0 million was appropriate against the deferred tax assets relating to the NOL carryforwards at December 31, 2016. We have decreased the valuation allowance for the NOL carryforwards by $3.8 million from December 31, 2015.

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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

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. The Cash Balance Plan was amended as of December 31, 2016 to eliminate all future pay credits under the plan. This plan change was recognized as a curtailment during the year ended December 31, 2016.

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 ten years of service and be between the ages of 55 and 65 years old.

The following tables set forth significant information about the Cash Balance Plan and the Retiree Medical Plan. The reconciliation of the benefit obligation, plan assets, funded status and significant assumptions are based upon an annual measurement date of December 31, 2016:

	Cash Balance Plan						Retiree Medical Plan
	As of December 31,
	2016			2015			2016			2015
	(In thousands)
Benefit obligation at beginning of period	$	8,927		$	6,965		$	345		$	3,098
Service cost	2,196			2,326			—			315
Interest cost	488			366			8			135
Actuarial (gain) loss	490			(151		)	(197		)	(697		)
Plan amendments	—			—			—			(2,463		)
Plan participants' contributions	—			—			12			26
Benefits paid	(675		)	(579		)	(42		)	(69		)
Curtailments	(149		)	—			—			—
Benefit obligation at end of period	$	11,277		$	8,927		$	126		$	345
Fair value of plan assets at beginning of period	$	5,932		$	4,319		$	—		$	—
Employer contribution	2,748			2,200			30			43
Actual return on plan assets	134			(8		)	—			—
Benefits paid	(675		)	(579		)	(42		)	(69		)
Plan participants' contributions	—			—			12			26
Fair value of plan assets at end of period	$	8,139		$	5,932		$	—		$	—
Current liabilities	—			—			31			61
Non-current liabilities	3,138			2,995			95			284
Underfunded status recognized in the consolidated balance sheets	$	3,138		$	2,995		$	126		$	345
Accumulated benefit obligation	$	11,277		$	8,927		$	126		$	345

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

	Cash Balance Plan									Retiree Medical Plan
	As of December 31,
	2016			2015			2014			2016			2015			2014
	(In thousands)
Net periodic benefit cost includes:
Service cost	$	2,196		$	2,326		$	2,054		$	—		$	315		$	231
Interest cost	488			366			327			8			135			116
Expected return on assets	(273		)	(165		)	(218		)	—			—			—
Recognized net actuarial loss	12			22			—			13			32			—
Amortization of prior service cost	25			24			25			(291		)	137			137
Curtailments	270			—			—			—			—			—
Net periodic benefit cost	$	2,718		$	2,573		$	2,188		$	(270	)	$	619		$	484
Changes recognized in other comprehensive income:
Prior service cost amortization	$	(24	)	$	(24	)	$	(24	)	$	291		$	(137	)	$	(137	)
Recognized net actuarial loss	(12		)	—			—			(13		)	(32		)	—
Prior service credit	—			—			—			—			(2,463		)	—
Net actuarial loss (gain)	629			22			687			(197		)	(697		)	675
Prior service cost amortization - curtailment	(271		)	—			—			—			—			—
Net curtailment gain	(149		)	—			—			—			—			—
Pre-tax unrecognized net loss (gain) included in accumulated other comprehensive income at end of period	$	173		$	(2	)	$	663		$	81		$	(3,329	)	$	538

	Cash Balance Plan						Retiree Medical Plan
	As of December 31,
	2016		2015		2014		2016		2015		2014
Weighted average assumptions used to determine benefit obligations at December 31:
Discount rate	4.00	%	4.50	%	4.00	%	2.75	%	2.50	%	4.00	%
Rate of compensation increase	3.00		3.00		3.00		N/A		N/A		N/A
Weighted average assumptions used to determine net periodic benefit cost:
Discount rate (1)	4.50% / 3.75%		4.00		5.00		2.50		4.00		5.00
Expected long-term return on assets (1)	4.25% / 3.50%		3.75		4.75		N/A		N/A		N/A
Rate of compensation increase	3.00		3.00		4.00		N/A		N/A		N/A

(1) The rates for 2016 are disclosed pre-curtailment and post-curtailment, respectively.

The health care cost trend rate for the Retiree Medical Plan for 2016 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.

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Employer contributions to the Cash Balance Plan of $2.7 million, $2.2 million and $0.2 million were made during the period ended December 31, 2016, 2015 and 2014, 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. we expect funding requirements of approximately $2.3 million during the year ended December 31, 2017.

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

	Cash Balance Plan		Retiree Medical Plan
2017	$	1,150	$	31
2018	439		14
2019	493		15
2020	544		16
2021	528		17
2022 - 2026	2,849		46

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 4.37% and 4.43% at December 31, 2016 and 2015, respectively, to determine the benefit obligation, the components of the postretirement obligation were:

	As of December 31,
	2016			2015
	(In thousands)
Benefit obligation at beginning of year	$	5,893		$	6,735
Service cost	104			124
Interest cost	212			251
Benefits paid	(145		)	(182		)
Actuarial gain	(1,157		)	(1,035		)
Benefit obligation at end of year	$	4,907		$	5,893
Underfunded status	$	4,907		$	5,893
Current liabilities	$	150		$	202
Non-current liabilities	4,757			5,691
Underfunded status recognized in the consolidated balance sheets	$	4,907		$	5,893

	Year Ended December 31,
	2016			2015			2014
	(In thousands)
Net periodic benefit cost includes:
Service cost	$	104		$	124		$	92
Interest cost	212			251			264
Amortization of net actuarial loss (gain)	(11		)	23			20
Net periodic benefit cost	$	305		$	398		$	376
Pre-tax unrecognized net loss included in accumulated other comprehensive income at beginning of year	$	538		$	1,596		$	784
Net actuarial loss (gain)	(1,157		)	(1,035		)	792
Amortization of net actuarial loss (gain)	11			(23		)	20
Pre-tax unrecognized net loss (gain) included in accumulated other comprehensive income at end of year	$	(608	)	$	538		$	1,596

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The weighted average discount rates used to determine net periodic benefit costs were 4.43%, 4.09% and 4.88% for 2016, 2015 and 2014, respectively. The following benefit payments (in thousands) are expected to be paid in the year indicated:

2017	$	153
2018	158
2019	164
2020	173
2021	181
2022 - 2026	1,092

The health care cost trend rate for the plan covering El Paso employees for 2016 and future years is capped at 4.00%. The health care cost trend rate for the plan covering Yorktown employees for 2016 is 4.50% and 4.50% in 2017. 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	$	(46	)
Effect on accumulated benefit obligation	13		(560		)

(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,
	2016			2015			2014
	(In thousands)
Beginning of period balance	$	651		$	(1,291	)	$	(350	)
Amortization of net prior service cost	(183		)	83			63
Net prior service credit	—			945			—
Reclassification of loss to income	—			50			21
Pension plan termination adjustment	420			—			—
Actuarial gain (loss)	724			1,267			(1,320		)
Income tax	(386		)	(403		)	295
End of period balance	$	1,226		$	651		$	(1,291	)

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 $10.2 million, $10.0 million and $9.1 million in connection with this plan for the years ended December 31, 2016, 2015 and 2014, respectively.

We sponsor a qualified defined contribution plan for eligible NTI employees. Eligibility is based upon a minimum age requirement and a minimum level of service. Participants may make contributions of a percentage of their annual compensation subject to Internal Revenue Service limits. In 2016, we provided a non-matching contribution of 3.0% of eligible compensation and a matching contribution at the rate of 100% of a participant's contribution up to 6.0%. Total contributions were $7.5 million, $7.4 million and $7.1 million for the years ended December 31, 2016, 2015 and 2014, respectively.

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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 2016, 2015 and 2014, we entered into net forward, fixed-price contracts to physically receive and deliver crude oil that qualify as normal purchases and normal sales and are exempt from derivative reporting requirements.

We use crude oil and refined products futures, swap contracts or options to mitigate the change in value for a portion of our LIFO inventory volumes subject to market price fluctuations and swap contracts to fix the margin on a portion of our future gasoline and distillate production. The physical volumes are not exchanged; 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.

The following tables summarize our economic hedging activity recognized within cost of products sold for the three years ended December 31, 2016, and open commodity hedging positions as of December 31, 2016, and December 31, 2015:

	Year Ended December 31,
	2016			2015			2014
	(In thousands)
Economic hedging activities recognized within cost of products sold:
Realized hedging gain, net	$	58,773		$	93,699		$	95,331
Unrealized hedging gain (loss), net	(77,674		)	(50,233		)	194,423
Total hedging gain (loss), net	$	(18,901	)	$	43,466		$	289,754

	December 31, 2016			December 31, 2015
	(In thousands)
Open commodity hedging instruments (barrels):
Crude oil differential swaps, net long positions	2,124			5,155
Crude oil futures, net short positions	(1,703		)	(562		)
Refined product price and crack spread swaps, net short positions	(6,632		)	(5,645		)
Total open commodity hedging instruments, net short positions	(6,211		)	(1,052		)
Fair value of outstanding contracts, net:
Other current assets	$	13,649		$	78,125
Other assets	8			11,881
Accrued liabilities	(10,827		)	(10,273		)
Other long-term liabilities	(771		)	—
Fair value of outstanding contracts - unrealized gain, net	$	2,059		$	79,733

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, 2016 and 2015:

	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, 2016
	(In thousands)
Gross financial assets:
Other current assets	$	18,929		$	(5,280	)	$	13,649
Other assets	677			(669		)	8
Gross financial liabilities:
Accrued liabilities	(17,547		)	6,720			(10,827		)
Other long-term liabilities	—			(771		)	(771		)
	$	2,059		$	—		$	2,059

	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
	(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

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, 2016, we had the following outstanding crude oil and refined product hedging instruments that were entered into as economic hedges. Settlement prices for our distillate crack spread swaps range from $15.06 to $16.62 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
	2017		2018		2019
Inventory positions (futures and swaps):
Crude oil differential swaps, net long positions	2,124		—		—
Crude oil futures, net short positions	(1,703	)	—		—
Distillate - net short positions	(150	)	—		—
Refined products - net short positions	(1,403	)	—		—
Natural gas futures - net long positions	301		—		—
Refined product positions (crack spread swaps):
Distillate - net short positions	(2,730	)	(1,800	)	—
Unleaded gasoline - net short positions	(850	)	—		—

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19. Stock-Based Compensation

Tesoro Merger

Effective upon the closing of the Tesoro Merger, each of the outstanding RSUs that were granted prior to December 31, 2016 will vest and be settled in cash. Each of the outstanding phantom stock awards under the NTI LTIP and 123,570 RSUs granted on January 18, 2017 will be automatically converted into the right to acquire or receive benefits measured by the value of the number of shares of Tesoro common stock, rounded down to the nearest whole number, equal to the number of shares of our common stock subject to such award immediately prior to the effective time of the First Tesoro Merger multiplied by the exchange ratio. See Note 31, Tesoro Merger, for additional information.

Western Incentive Plans

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 RSUs among other forms of awards. As of December 31, 2016, there were 19,856 and 2,391,711 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, 2016, there were 658,506 unvested RSUs outstanding. The final vesting for remaining restricted share awards occurred during the first quarter of 2014.

We incurred equity-based compensation expense related to RSUs of $6.3 million, $4.2 million and $4.3 million for the years ended December 31, 2016, 2015 and 2014, respectively.

As of December 31, 2016, the aggregate fair value at grant date of outstanding RSUs was $21.2 million. The aggregate intrinsic value of RSUs was $24.9 million. The unrecognized compensation cost of outstanding RSUs was $14.9 million. Unrecognized compensation cost for RSUs will be recognized over a weighted average period of approximately 2.41 years.

The excess tax deficiency related to the RSUs that vested during the year ended December 31, 2016 was $0.4 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, 2016 was $4.1 million. The related aggregate intrinsic value of these RSUs was $3.0 million at the vesting date.

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.

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The following table summarizes our RSU and restricted share activity for the three years ended December 31, 2016:

	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, 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		—		—
Awards granted	375,774		28.52		—		—
Awards vested	(109,634	)	37.63		—		—
Awards forfeited	(6,848	)	43.81		—		—
Not vested at December 31, 2016	658,506		32.25		—		—

Amended and Restated Northern Tier Energy LP 2012 Long-Term Incentive Plan

Effective upon the closing of the NTI Merger, Western adopted and assumed NTI's equity compensation plan. Modifications to the NTI LTIP include, among other things, a change to the unit of equity from an NTI common unit to a share of Western common stock. The amendment changes the administrator of the NTI LTIP from the board of directors of NTI's general partner to Western's board of directors or its applicable committee. Consistent with the terms of the NTI Merger Agreement, all unvested equity awards at the time of the NTI Merger were exchanged for Western phantom stock awards and performance cash awards under the NTI LTIP.

We incurred equity-based compensation expense related to phantom stock awards of $13.6 million, $10.3 million and $14.0 million for the years ended December 31, 2016, 2015 and 2014, respectively.

The NTI LTIP provides, among other awards, for grants of stock options, restricted stock, phantom stock, dividend equivalent rights, stock appreciation rights and other awards that derive their value from the market price of Western's common stock. As of December 31, 2016, there was 330,018 common share equivalents reserved for future grants under the NTI LTIP.

We determined the fair value of the phantom stock based on the closing price of Western common stock on the grant date. We amortize the estimated fair value of the phantom stock on a straight-line basis over the scheduled vesting periods of individual awards.

The aggregate grant date fair value of non-vested phantom stock outstanding as of December 31, 2016, was $13.4 million. The aggregate intrinsic value of such phantom stock was $25.1 million. Total unrecognized compensation cost related to unvested phantom stock totaled $5.8 million as of December 31, 2016, that is expected to be recognized over a weighted-average period of 1.6 years.

The excess tax benefit related to the phantom stock that vested during the year ended December 31, 2016, was $1.0 million using a statutory blended rate of 38.1%. The aggregate grant date fair value of the phantom stock that vested during the year ended December 31, 2016, was $3.4 million. The related aggregate intrinsic value of the vested phantom stock was $6.0 million at the vesting date.

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A summary of our phantom stock award activity under the NTI LTIP for the three years ended December 31, 2016, is set forth below:

	Number of Phantom Stock		Weighted Average Grant Date Fair Value
Not vested at December 31, 2015	—		—
Awards granted	848,267		20.25
Awards vested	(167,342	)	20.25
Awards forfeited	(18,553	)	20.25
Not vested at December 31, 2016	662,372		20.25

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, 2016, there were 4,098,368 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 $2.7 million, $2.0 million and $1.6 million for the years ended December 31, 2016, 2015 and 2014, respectively.

The fair value at grant date of non-vested phantom units outstanding as of December 31, 2016, was $7.5 million. The aggregate intrinsic value of phantom units was $6.1 million. Total unrecognized compensation cost related to our non-vested phantom units totaled $5.6 million as of December 31, 2016, that is expected to be recognized over a weighted-average period of approximately 2.36 years.

A summary of WNRL's unit award activity for the three years ended December 31, 2016, is set forth below:

	Number of Phantom Units		Weighted Average Grant Date Fair Value
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
Awards granted	101,955		22.69
Awards vested	(86,406	)	25.80
Awards forfeited	(10,181	)	31.87
Not vested at December 31, 2016	285,155		26.42

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

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.

Pursuant to the NTI Merger Agreement, we issued 17.1 million shares of Western common stock including 11.6 million treasury shares on June 23, 2016. See Note 30, NTI, for further discussion of the NTI Merger.

Effective upon the closing of the Tesoro Merger, each share of our common stock may be converted into and become exchangeable for, at the election of the holder of each share of our common stock, either (a) $37.30 in cash or (b) 0.4350 shares of Tesoro common stock, in each case without interest, subject to the terms and conditions. See Note 31, Tesoro Merger, for further discussion of the Tesoro Merger.

Between July 18, 2012 and December 31, 2016, 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. Our board of directors approved a share repurchase program in September of 2015 that expired on December 31, 2016. Through December 31, 2016, we purchased 23.0 million shares of our common stock under our share repurchase programs. On December 31, 2016, we had no active share repurchase program.

The following table summarizes our share repurchase activity for our share repurchase programs.

	January 2014 Program			November 2014 Program			September 2015 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)
Shares purchased at December 31, 2013	—	$	—	—	$	—	—	$	—
Shares purchased during 2014 (1)	4,976,039	200,000		1,492,874	59,222		—	—
Shares purchased at December 31, 2014	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	4,976,039	200,000		4,140,614	164,222		—	—
Shares purchased during 2016 (2)	—	—		—	—		2,462,350	75,000
Shares purchased at December 31, 2016	4,976,039	$	200,000	4,140,614	$	164,222	2,462,350	$	75,000

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

(2) The shares purchased during 2016 were issued on June 23, 2016 pursuant to the NTI Merger Agreement.

Dividends

Our ability to pay dividends to our shareholders is subject to certain restrictions in the Western 2019 Revolving Credit Facility, Western 2020 Term Loan Credit Facility, Western 2023 Term Loan Credit Facility and the Western 2021 Indenture governing the Western 2021 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.

Under the Tesoro Merger Agreement, we have agreed that, until the completion of the Tesoro Merger, we will not declare, set aside, make or pay any dividend or other distribution in respect of any of our capital stock, except for regular quarterly cash dividends to the holders of shares of our common stock in an amount not in excess of $0.38 per share.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

The table below summarizes our 2016 cash dividend declarations, payments and scheduled payments:

	Declaration Date	Record Date	Payment Date	Dividend per common share		Total Payment(in thousands)
First quarter	January 6	January 20	February 4	$	0.38	$	35,601
Second quarter	April 8	April 18	May 2	0.38		34,685
Third quarter	July 15	July 25	August 9	0.38		41,202
Fourth quarter	October 13	October 24	November 8	0.38		41,202
Total						$	152,690

On January 4, 2017, our board of directors approved a cash dividend for the first quarter of 2017 of $0.38 per share of common stock in an aggregate payment of $41.3 million that was paid on February 2, 2017 to holders of record on January 18, 2017.

NTI Distributions

The table below summarizes NTI's 2016 quarterly distribution declarations, payments and scheduled payments:

Declaration Date	Record Date	Payment Date	Distribution per Unit
February 3	February 12	February 19	$	0.38
June 13	June 23	June 23	0.18
Total			$	0.56

WNRL Distributions

The table below summarizes WNRL's 2016 quarterly distribution declarations, payments and scheduled payments:

Declaration Date	Record Date	Payment Date	Distribution per Common and Subordinated Unit
January 30	February 13	February 23	$	0.3925
May 1	May 15	May 26	0.4025
July 31	August 14	August 24	0.4125
October 30	November 13	November 23	0.4225
			$	1.6300

In addition to its quarterly distributions, WNRL paid incentive distributions of $4.4 million and $1.1 million for the years ended December 31, 2016 and 2015, respectively, to Western as its General Partner and holder of its incentive distribution rights.

On January 31, 2017, WNRL declared a quarterly distribution of $0.4375 per unit to common unitholders of record on February 13, 2017, payable on March 1, 2017.

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 and phantom stock. 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 or phantom stock 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 as follows:

	Year Ended December 31,
	2016			2015			2014
	(In thousands, except per share data)
Basic earnings per common share:
Allocation of earnings:
Net income attributable to Western Refining, Inc.	$	124,939		$	406,756		$	559,926
Distributed earnings	(153,691		)	(129,211		)	(293,746		)
Income allocated to participating securities	—			—			(3		)
Distributed earnings allocated to participating securities	—			—			3
Undistributed income (loss) available to Western Refining, Inc.	$	(28,752	)	$	277,545		$	266,180
Weighted average number of common shares outstanding (1)	100,473			94,899			90,708
Basic earnings per common share:
Distributed earnings per share	$	1.53		$	1.36		$	3.24
Undistributed earnings (loss) per share	(0.29		)	2.92			2.93
Basic earnings per common share	$	1.24		$	4.28		$	6.17

(1) Excludes the weighted average number of common shares outstanding associated with participating securities of 884 shares for the year ended December 31, 2014.

	Year Ended December 31,
	2016		2015		2014
	(In thousands, except per share data)
Diluted earnings per common share:
Net income attributable to Western Refining, Inc.	$	124,939	$	406,756	$	559,926
Tax effected interest related to convertible debt	—		—		8,010
Net income available to Western Refining, Inc., assuming dilution	$	124,939	$	406,756	$	567,936
Weighted average number of diluted shares outstanding	100,868		94,999		101,190
Diluted earnings per common share	$	1.24	$	4.28	$	5.61

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

	Year Ended December 31,
	2016	2015	2014
	(In thousands)
Weighted average number of common shares outstanding	100,473	94,899	90,708
Common equivalent shares from Convertible Senior Notes	—	—	10,349
Restricted shares, restricted share units and phantom stock	395	100	133
Weighted average number of diluted shares outstanding	100,868	94,999	101,190

A shareholder's interest in our common stock could become diluted as a result of vestings of RSUs, phantom stock 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 and phantom stock that have not vested and common equivalent shares related to the Western Convertible Notes. We include unvested RSUs and phantom stock 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 were generally included in our diluted earnings calculation when net income exceeds certain thresholds above which the effect of the shares became 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,
	2016		2015		2014
	(In thousands)
Non-cash operating activities were as follows:
Income taxes paid	$	38,227	$	283,330	$	227,953
Interest paid, excluding amounts capitalized	124,037		95,012		83,943
Non-cash investing activities were as follows:
Accrued capital expenditures	$	28,934	$	53,361	$	9,189
Assets acquired through capital lease obligations	4,644		29,082		—
PP&E derecognized from sale leaseback continuing involvement release	2,799		1,773		—
Transfer of capital spares	860		1,490		—
Non-cash financing activities were as follows:
Reduction of long-term debt proceeds for original issuance discount	$	10,250	$	—	$	—
Treasury stock issuance	438,168		—		—
Accrued financing costs	67		—		—
Issuance of common shares for redemption of Western Convertible Notes	—		—		357,608
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, 2016, and 2015, we had consolidated environmental accruals of $13.8 million and $18.3 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

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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 $6.5 million remained as of December 31, 2016. 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 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 incurred $0.1 million, $0.1 million and $1.9 million for the years ended December 31, 2016, 2015 and 2014, respectively, to complete an FCC emission offset project. We paid penalties between 2009 and 2012 totaling $2.7 million. For 2017, we have budgeted capital projects specifically designed to address our compliance with the 2005 NMED Amended Agreement regarding air emissions from waste handling at our Gallup refinery.

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 operations 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.

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.

Gallup 2017 EPA RCRA Order: In February 2017, we received from the EPA a draft administrative order with a proposed penalty of $0.1 million to settle alleged violations of the RCRA regulations noted during an EPA inspection of the Gallup refinery in August 2014. We are evaluating the draft order and expect to enter into a settlement with the EPA. The draft settlement does not contain requirements for groundwater clean-up or capital expenditure.

St. Paul Park Refinery

At December 31, 2016, and 2015, liabilities for remediation and closure obligations at the St. Paul Park refinery totaled $3.4 million and $8.6 million, respectively, of which $2.5 million and $2.6 million, respectively, are recorded on a discounted basis. These discounted liabilities are expected to be settled over at least the next 21 years. At December 31, 2016, the estimated future cash flows to settle these discounted liabilities totaled $3.1 million and are discounted at a rate of 2.82%. 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 at December 31, 2016, and 2015.

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 the review of the test results and additional discussions with MPCA, we plan to close the remaining lagoon. At December 31, 2016 and 2015, we estimated the remediation and closure costs to be approximately $0.9 million and $6.0 million, respectively. 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.

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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 NTI Merger, Evercore Group, L.L.C. (“Evercore”), and MergerCo (collectively, “Defendants”) (the “NTI Merger Litigation”). The NTI Merger Litigation appears to challenge the adequacy of disclosures made in connection with the NTI Merger. Plaintiff seeks monetary damages and attorneys’ fees. The NTI Merger Litigation is in the earliest stages of litigation. Western believes the NTI Merger Litigation is without merit and intends to vigorously defend against it.

As of February 8, 2017, Western was named as defendants in five substantially similar purported stockholder class actions by Western stockholders (the “Tesoro Merger Litigation”). The suits challenge the adequacy of the disclosures made in connection with the Tesoro Merger. Among other remedies, the plaintiffs seek to enjoin the merger until additional information relating to the transaction is disclosed. The Tesoro Merger Litigation is in the earliest stages of litigation. Western believes the Tesoro Merger Litigation is without merit, intends to vigorously defend against it and on February 23, 2017, Western and the members of its board of directors filed a motion to dismiss the operative complaint in the consolidated proceedings.

Tax Matters

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

Union Matters

During 2016, we negotiated a new collective bargaining agreement covering employees in St. Paul Park, scheduled to expire in 2020. SuperMom's bakery has 26 employees associated with its operations that are covered by a collective bargaining agreement that expires in August 2017. During 2015, we negotiated a new collective bargaining agreement covering employees at the El Paso refinery that is scheduled to expire in April of 2021. During 2014, we negotiated a collective bargaining agreement covering employees at the Gallup refinery that expires in 2020.

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.

Other Matters

The EPA has issued Renewable Fuels Standards ("RFS") that require refiners to blend renewable fuels into the refined products produced at their refineries. Annually, the EPA is required to establish a volume of renewable fuels that refineries must blend into their refined petroleum fuels. To the extent we are unable to blend at the rate necessary to satisfy the EPA mandated volume, we purchase Renewable Identification Numbers ("RIN"). The purchase price for RINs is volatile and may vary significantly from period to period. The net cost of meeting our estimated renewable volume obligations was $65.4 million, $35.5 million and $28.2 million for the year ended December 31, 2016, 2015 and 2014, respectively. The supply and demand environment for RINs is uncertain and we cannot predict the impact of RIN purchases on our results of operations in any given period.

In addition, the EPA has investigated and brought enforcement actions against companies it believes produced invalid RINs. We have purchased RINs that the EPA determined were invalid. Previously, we have entered into settlements 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.

24. Concentration of Risk

We sell a variety of refined products to a diverse customer base. No single customer accounted for more than 10% of consolidated net sales for the years ended December 31, 2016, 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 6.0%, 6.3% and 5.5% of consolidated sales during the years ended December 31, 2016, 2015 and 2014, respectively.

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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 2040. 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 are 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 logistic 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 Veolia North America, Inc. (“Veolia”), Veolia owns and operates two sulfuric acid regeneration units on property we lease to Veolia 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. 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 38 capital leases, with initial terms of 20 years, expiring in 2017 through 2036. The current portion of our capital lease obligation of $1.3 million and $1.0 million is included in accrued liabilities and the non-current portion of $54.2 million and $53.2 million is included in lease financing obligations in the accompanying Consolidated Balance Sheets as of December 31, 2016 and 2015, respectively. The capital lease obligations include a deferred gain of $0.2 million. These capital leases were discounted using annual rates of 3.24% to 10.51%. Total remaining interest related to these leases was $40.0 million and $44.1 million at December 31, 2016, and 2015, respectively. Annual payments, including interest, for the next five years are approximately $5.6 million annually with the remaining $67.1 million due through 2036.

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, 2016:

	Operating		Capital
2017	$	55,675	$	5,419
2018	52,509		5,444
2019	47,269		5,553
2020	42,420		5,744
2021	43,284		5,891
2022 and thereafter	305,646		67,139
Total minimum lease payments	$	546,803	95,190
Less amount that represents interest			39,960
Present value of net minimum capital lease payments			$	55,230

Total rent expense was $71.6 million, $64.7 million and $53.7 million for the years ended December 31, 2016, 2015 and 2014, respectively. Contingent rentals and subleases were not significant in any year.

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. Under the terms of the lease, we make annual payments of $0.2 million. For the years ended December 31, 2016, 2015 and 2014, we made rental payments under this lease to the related party of $0.2 million. We have no amounts due as of December 31, 2016, related to this lease agreement. This lease agreement expired in January 2017.

Beginning on September 30, 2014, we began paying MPL for transportation services at published tariff rates. We incurred $52.2 million, $55.4 million and $12.6 million in crude transportation costs with MPL for the years ended December 31, 2016, 2015 and 2014, respectively. Prior to September 30, 2014, we had a crude oil supply and logistics agreement with a third-party

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and had no direct supply transactions with MPL prior to this date. Western's President and Chief Operating 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, 2016, the Parent and certain 100% owned 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 St. Paul Park Logistics 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.

As of December 31, 2016, we owned a 100% limited partnership interest in NTI and a 52.6% 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 WNRL through our 100% ownership of its general partner. Accordingly, NTI and WNRL are consolidated with the other accounts of Western.

NTI's long-term debt is comprised of the 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, NTI's general partner. We have 100% ownership of the general partner of NTI. 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; for transporting crude oil and asphalt through its 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.

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

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CONDENSED CONSOLIDATING BALANCE SHEETS

As of December 31, 2016

(In thousands)

	Parent		Guarantor Subsidiaries		Non-Guarantors		Eliminations			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	21	$	224,431	$	44,129	$	—		$	268,581
Accounts receivable, trade, net of a reserve for doubtful accounts	—		117,007		306,164		—			423,171
Accounts receivable, affiliate	16,832		72,760		3,736		(93,328		)	—
Inventories	—		448,012		323,977		—			771,989
Prepaid expenses	—		80,199		15,156		—			95,355
Other current assets	—		74,832		38,589		—			113,421
Total current assets	16,853		1,017,241		731,751		(93,328		)	1,672,517
Equity method investment	—		—		102,685		—			102,685
Property, plant and equipment, net	—		1,117,958		1,246,524		—			2,364,482
Goodwill	—		—		1,289,443		—			1,289,443
Intangible assets, net	—		31,516		52,296		—			83,812
Investment in subsidiaries	5,348,171		—		—		(5,348,171		)	—
Due from affiliate	—		2,443,306		—		(2,443,306		)	—
Other assets	—		27,425		20,033		—			47,458
Total assets	$	5,365,024	$	4,637,446	$	3,442,732	$	(7,884,805	)	$	5,560,397
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable, trade	$	—	$	372,570	$	381,363	$	—		$	753,933
Accounts payable, affiliate	—		—		93,328		(93,328		)	—
Accrued liabilities	5,655		124,628		89,324		—			219,607
Current portion of long-term debt	10,500		—		—		—			10,500
Total current liabilities	16,155		497,198		564,015		(93,328		)	984,040
Long-term liabilities:
Long-term debt, less current portion	1,208,703		—		663,102		—			1,871,805
Due to affiliate	2,443,306		—		—		(2,443,306		)	—
Lease financing obligation	—		45,007		9,156		—			54,163
Deferred income tax liability, net	—		222,372		37,921		—			260,293
Deficit in subsidiaries	—		501,776		—		(501,776		)	—
Other liabilities	—		79,501		13,635		—			93,136
Total long-term liabilities	3,652,009		848,656		723,814		(2,945,082		)	2,279,397
Equity:
Equity - Western	1,696,860		3,291,592		1,554,803		(4,846,395		)	1,696,860
Equity - Non-controlling interest	—		—		600,100		—			600,100
Total equity	1,696,860		3,291,592		2,154,903		(4,846,395		)	2,296,960
Total liabilities and equity	$	5,365,024	$	4,637,446	$	3,442,732	$	(7,884,805	)	$	5,560,397

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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	3,790,958		—		—		(3,790,958		)	—
Due from affiliate	—		1,623,427		—		(1,623,427		)	—
Other assets	—		42,166		22,831		—			64,997
Total assets	$	3,790,979	$	4,203,423	$	3,312,431	$	(5,473,440	)	$	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	1,623,427		—		—		(1,623,427		)	—
Lease financing obligation	—		42,168		11,064		—			53,232
Deferred income tax liability, net	—		275,634		37,280		—			312,914
Deficit in subsidiaries	—		287,761		—		(287,761		)	—
Other liabilities	—		63,674		4,921		—			68,595
Total long-term liabilities	2,479,754		669,237		841,832		(1,911,188		)	2,079,635
Equity:
Equity - Western	1,299,297		3,129,379		373,818		(3,503,197		)	1,299,297
Equity - Non-controlling interest	—		—		1,646,609		—			1,646,609
Total equity	1,299,297		3,129,379		2,020,427		(3,503,197		)	2,945,906
Total liabilities and equity	$	3,790,979	$	4,203,423	$	3,312,431	$	(5,473,440	)	$	5,833,393

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS AND COMPREHENSIVE INCOME

For the Year Ended December 31, 2016

(In thousands)

	Parent			Guarantor Subsidiaries			Non-Guarantors			Eliminations			Consolidated
Net sales	$	—		$	6,178,382		$	5,270,300		$	(3,705,469	)	$	7,743,213
Operating costs and expenses:
Cost of products sold (exclusive of depreciation and amortization)	—			5,298,962			4,385,318			(3,705,469		)	5,978,811
Direct operating expenses (exclusive of depreciation and amortization)	—			453,750			474,273			—			928,023
Selling, general and administrative expenses	185			111,268			106,408			—			217,861
Merger and reorganization costs	—			7,759			4,681			—			12,440
Loss (gain) and impairments on disposal of assets, net	—			(207		)	(1,064		)	—			(1,271		)
Maintenance turnaround expense	—			1,372			45,765			—			47,137
Depreciation and amortization	—			106,753			110,034			—			216,787
Total operating costs and expenses	185			5,979,657			5,125,415			(3,705,469		)	7,399,788
Operating income (loss)	(185		)	198,725			144,885			—			343,425
Other income (expense):
Equity in earnings of subsidiaries	201,150			16,603			—			(217,753		)	—
Interest income	—			426			266			—			692
Interest and debt expense	(72,110		)	(3,087		)	(48,094		)	—			(123,291		)
Loss on extinguishment of debt	(3,916		)	—			—			—			(3,916		)
Other, net	—			1,799			23,165			—			24,964
Income before income taxes	124,939			214,466			120,222			(217,753		)	241,874
Provision for income taxes	—			(52,253		)	(2,615		)	—			(54,868		)
Net income	124,939			162,213			117,607			(217,753		)	187,006
Less net income attributed to non-controlling interests	—			—			62,067			—			62,067
Net income attributable to Western Refining, Inc.	$	124,939		$	162,213		$	55,540		$	(217,753	)	$	124,939
Comprehensive income attributable to Western Refining, Inc.	$	124,939		$	162,973		$	55,355		$	(217,753	)	$	125,514

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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 of subsidiaries	461,049			11,551			—			(472,600		)	—
Interest income	—			389			314			—			703
Interest and debt expense	(54,104		)	(2,717		)	(48,782		)	—			(105,603		)
Other, net	—			492			12,669			—			13,161
Income before income taxes	406,756			530,934			373,296			(472,600		)	838,386
Provision for income taxes	—			(223,908		)	(47		)	—			(223,955		)
Net income	406,756			307,026			373,249			(472,600		)	614,431
Less net income attributed to non-controlling interests	—			—			207,675			—			207,675
Net income attributable to Western Refining, Inc.	$	406,756		$	307,026		$	165,574		$	(472,600	)	$	406,756
Comprehensive income attributable to Western Refining, Inc.	$	406,756		$	307,681		$	166,861		$	(472,600	)	$	408,698

124

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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
Merger and reorganization 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 of subsidiaries	630,407			17,059			—			(647,466		)	—
Interest income	—			795			393			—			1,188
Interest and debt expense	(70,286		)	(1,044		)	(25,732		)	—			(97,062		)
Loss on extinguishment of debt	(9		)	—			—			—			(9		)
Other, net	—			(604		)	2,650			—			2,046
Income before income taxes	559,926			799,025			291,191			(647,466		)	1,002,676
Provision for income taxes	—			(292,145		)	(459		)	—			(292,604		)
Net income	559,926			506,880			290,732			(647,466		)	710,072
Less net income attributed to non-controlling interests	—			—			150,146			—			150,146
Net income attributable to Western Refining, Inc.	$	559,926		$	506,880		$	140,586		$	(647,466	)	$	559,926
Comprehensive income attributable to Western Refining, Inc.	$	559,926		$	506,403		$	140,122		$	(647,466	)	$	558,985

125

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

For the Year Ended December 31, 2016

(In thousands)

	Parent			Guarantor Subsidiaries			Non-Guarantors			Eliminations			Consolidated
Cash flows from operating activities:
Net cash provided by operating activities	$	(41,614	)	$	331,819		$	182,302		$	(88,760	)	$	383,747
Cash flows from investing activities:
Capital expenditures	—			(145,760		)	(156,356		)	1,147			(300,969		)
Return of capital from equity method investment	97,379			—			—			(97,379		)	—
Contributions to affiliate	—			(689,063		)	(20,092		)	709,155			—
Proceeds from the sale of assets	—			1,365			5,303			(1,147		)	5,521
Increase in restricted cash	—			—			(195,000		)	—			(195,000		)
Use of restricted cash	—			69,106			195,000			—			264,106
Net cash provided by (used in) investing activities	97,379			(764,352		)	(171,145		)	611,776			(226,342		)
Cash flows from financing activities:
Additions to long-term debt	500,000			—			—			—			500,000
Payments on long-term debt and capital lease obligations	(133,000		)	(1,035		)	(1,357		)	—			(135,392		)
Borrowings on revolving credit facility	—			—			466,900			—			466,900
Repayments of revolving credit facility	—			—			(591,600		)	—			(591,600		)
Payments for NTI units related to merger	(859,893		)	—			—			—			(859,893		)
Transaction costs for NTI merger	(11,741		)	—			—			—			(11,741		)
Contributions from affiliate	689,063			—			20,092			(709,155		)	—
Distribution to non-controlling interest holders	—			—			(66,311		)	—			(66,311		)
Deferred financing costs	(11,503		)	—			(1,224		)	—			(12,727		)
Distribution to affiliate	—			—			(186,139		)	186,139			—
Purchases of common stock for treasury	(75,000		)	—			—			—			(75,000		)
Dividends paid	(153,691		)	—			—			—			(153,691		)
Proceeds from issuance of WNRL common units	—			—			277,751			—			277,751
Offering costs for issuance of WNRL common units	—			—			(655		)	—			(655		)
Excess tax benefit from stock-based compensation	—			1,033			—			—			1,033
Net cash provided by (used in) financing activities	(55,765		)	(2		)	(82,543		)	(523,016		)	(661,326		)
Net increase (decrease) in cash and cash equivalents	—			(432,535		)	(71,386		)	—			(503,921		)
Cash and cash equivalents at beginning of year	21			656,966			115,515			—			772,502
Cash and cash equivalents at end of year	$	21		$	224,431		$	44,129		$	—		$	268,581

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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 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		)
Proceeds from the sale of assets	—			2,028			643			(1,557		)	1,114
Contributions to affiliate	—			(178,243		)	(27,888		)	206,131			—
Increase in restricted cash	—			(170,000		)	—			—			(170,000		)
Use of restricted cash	—			267,903			—			—			267,903
Net cash used in investing activities	—			(235,912		)	(162,065		)	206,131			(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			—			53,784			(206,131		)	—
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		)
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			(367,248		)	(25,311		)	(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

127

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

For the Year Ended December 31, 2014

(In thousands)

	Parent			Guarantor Subsidiaries			Non-Guarantors			Eliminations			Consolidated
Cash flows from operating activities:
Net cash provided by (used in) operating activities	$	(54,846	)	$	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		)	(119,147		)	797,775			—
Increase in restricted cash	—			(320,000		)	—			—			(320,000		)
Use of restricted cash	—			152,991			—			—			152,991
Net cash used in investing activities	—			(943,581		)	(235,058		)	797,775			(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
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			—
Contributions from affiliate	618,564			93,546			85,665			(797,775		)	—
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			(197,021		)	(666,195		)	(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

128

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Due to the change in the guarantor structure resulting from the St. Paul Park Logistics 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, 2015

(In thousands)

	As Previously Reported			Adjustment			Revised
Parent	$	3,964,578		$	(173,620	)	$	3,790,958
Guarantor subsidiaries	(395,774		)	108,013			(287,761		)
Non-guarantor subsidiaries	—			—			—
Eliminations	(3,568,804		)	65,607			(3,503,197		)
Investment (deficit) in subsidiaries	$	—		$	—		$	—
Parent	$	3,964,599		$	(173,620	)	$	3,790,979
Guarantor subsidiaries	4,377,043			(173,620		)	4,203,423
Non-guarantor subsidiaries	3,312,431			—			3,312,431
Eliminations	(5,820,680		)	347,240			(5,473,440		)
Total assets	$	5,833,393		$	—		$	5,833,393
Parent	$	2,665,302		$	(173,620	)	$	2,491,682
Guarantor subsidiaries	1,182,057			(108,013		)	1,074,044
Non-guarantor subsidiaries	1,292,004			—			1,292,004
Eliminations	(2,251,876		)	281,633			(1,970,243		)
Total liabilities	$	2,887,487		$	—		$	2,887,487
Parent	$	1,299,297		$	—		$	1,299,297
Guarantor subsidiaries	3,194,986			(65,607		)	3,129,379
Non-guarantor subsidiaries	2,020,427			—			2,020,427
Eliminations	(3,568,804		)	65,607			(3,503,197		)
Total equity	$	2,945,906		$	—		$	2,945,906

129

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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)

	As Previously Reported			Adjustment			Revised
Parent	$	461,049		$	—		$	461,049
Guarantor subsidiaries	42,470			(30,919		)	11,551
Non-guarantor subsidiaries	—			—			—
Eliminations	(503,519		)	30,919			(472,600		)
Equity in earnings (loss) of subsidiaries	$	—		$	—		$	—
Parent	406,756			—			406,756
Guarantor subsidiaries	337,945			(30,919		)	307,026
Non-guarantor subsidiaries	165,574			—			165,574
Eliminations	(503,519		)	30,919			(472,600		)
Net income (loss) attributable to Western Refining, Inc.	$	406,756		$	—		$	406,756
Parent	$	406,756		$	—		$	406,756
Guarantor subsidiaries	338,600			(30,919		)	307,681
Non-guarantor subsidiaries	166,861			—			166,861
Eliminations	(503,519		)	30,919			(472,600		)
Comprehensive income attributable to Western Refining, Inc.	$	408,698		$	—		$	408,698

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	51,747			(34,688		)	17,059
Non-guarantor subsidiaries	—			—			—
Eliminations	(682,154		)	34,688			(647,466		)
Equity in earnings (loss) of subsidiaries	$	—		$	—		$	—
Parent	559,926			—			559,926
Guarantor subsidiaries	541,568			(34,688		)	506,880
Non-guarantor subsidiaries	140,586			—			140,586
Eliminations	(682,154		)	34,688			(647,466		)
Net income (loss) attributable to Western Refining, Inc.	$	559,926		$	—		$	559,926
Parent	$	559,926		$	—		$	559,926
Guarantor subsidiaries	541,091			(34,688		)	506,403
Non-guarantor subsidiaries	140,122			—			140,122
Eliminations	(682,154		)	34,688			(647,466		)
Comprehensive income attributable to Western Refining, Inc.	$	558,985		$	—		$	558,985

130

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

For the Year Ended December 31, 2015

(In thousands)

	As Previously Reported			Adjustment			Revised
Parent	$	87,364		$	—		$	87,364
Guarantor subsidiaries	433,863			—			433,863
Non-guarantor subsidiaries	502,676			—			502,676
Eliminations	(180,820		)	—			(180,820		)
Net cash provided by (used in) operating activities	$	843,083		$	—		$	843,083
Parent	—			—			—
Guarantor subsidiaries	(235,912		)	—			(235,912		)
Non-guarantor subsidiaries	(134,177		)	(27,888		)	(162,065		)
Eliminations	178,243			27,888			206,131
Net cash provided by (used in) investing activities	$	(191,846	)	$	—		$	(191,846	)
Parent	$	(87,364	)	$	—		$	(87,364	)
Guarantor subsidiaries	170,029			—			170,029
Non-guarantor subsidiaries	(395,136		)	27,888			(367,248		)
Eliminations	2,577			(27,888		)	(25,311		)
Net cash provided by (used in) financing activities	$	(309,894	)	$	—		$	(309,894	)

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	520,972			—			520,972
Non-guarantor subsidiaries	403,087			—			403,087
Eliminations	(131,580		)	—			(131,580		)
Net cash provided by (used in) operating activities	$	737,633		$	—		$	737,633
Parent	—			—			—
Guarantor subsidiaries	(943,581		)	—			(943,581		)
Non-guarantor subsidiaries	(209,457		)	(25,601		)	(235,058		)
Eliminations	772,174			25,601			797,775
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	(222,622		)	25,601			(197,021		)
Eliminations	(640,594		)	(25,601		)	(666,195		)
Net cash provided by (used in) financing activities	$	(393,680	)	$	—		$	(393,680	)

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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 2016 and 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 quarterly financial data for the years ended December 31, 2016, and 2015 is presented below.

	Year Ended December 31, 2016
	Quarter
	First			Second			Third			Fourth
	(Unaudited) (In thousands, except for per share data)
Net sales	$	1,455,504		$	2,107,308		$	2,065,076		$	2,115,325
Operating costs and expenses:
Cost of products sold (exclusive of depreciation and amortization)	1,047,361			1,602,628			1,607,010			1,721,812
Direct operating expenses (exclusive of depreciation and amortization)	223,585			231,169			232,553			240,716
Selling, general and administrative expenses	53,285			56,052			57,320			51,204
Merger and reorganization costs	408			735			2,844			8,453
Gain and impairments on disposal of assets, net	(130		)	(772		)	(279		)	(90		)
Maintenance turnaround expense	125			400			27,208			19,404
Depreciation and amortization	52,651			54,359			54,321			55,456
Total operating costs and expenses	1,377,285			1,944,571			1,980,977			2,096,955
Operating income	78,219			162,737			84,099			18,370
Other income (expense):
Interest income	164			131			141			256
Interest and debt expense	(26,681		)	(26,928		)	(34,456		)	(35,226		)
Loss on extinguishment of debt	—			—			—			(3,916		)
Other, net	6,512			5,076			6,224			7,152
Income (loss) before income taxes	58,214			141,016			56,008			(13,364		)
Provision for income taxes	(18,629		)	(38,152		)	(11,700		)	13,613
Net income	39,585			102,864			44,308			249
Less net income attributable to non-controlling interests	9,047			37,449			5,733			9,838
Net income (loss) attributable to Western Refining, Inc.	$	30,538		$	65,415		$	38,575		$	(9,589	)
Basic earnings (loss) per common share	$	0.34		$	0.70		$	0.36		$	(0.09	)
Diluted earnings (loss) per common share	$	0.33		$	0.70		$	0.35		$	(0.09	)

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	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 and debt expense	(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) attributable 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

29. Western Refining Logistics, LP

WNRL is a publicly held master limited partnership that owns and operates logistic assets consisting of pipeline and gathering, terminalling, storage and transportation assets, providing related services to our refining segment, including 705 miles of pipelines and approximately 12.4 million barrels of active storage capacity. The majority of WNRL's logistics assets are integral to the operations of the El Paso, Gallup and St. Paul Park 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, asphalt, refined product and lubricant delivery trucks. WNRL distributes commercial wholesale petroleum products primarily in Arizona, Colorado, Nevada, New Mexico and Texas. WNRL purchases petroleum fuels and lubricants from our refining segment and from third-party suppliers.

During the fourth quarter of 2016, WNRL completed an evaluation of its lubricant operations. After careful consideration, having concluded that lubricants are not strategic to its core operations, WNRL has taken steps to divest the remaining assets associated with this business. WNRL anticipates a completed sale within the first half of 2017. Assets related to our lubricant operations include $10.1 million in inventories and $7.3 million in property, plant and equipment in our Consolidated Balance Sheet at December 31, 2016. WNRL expects proceeds from this divestiture to result in a gain on disposal of assets; however, no amounts related to this anticipated transaction have been recorded in the Consolidated Statements of Operations for the year ended December 31, 2016.

At December 31, 2016, we held a 52.6% limited partner interest in WNRL including a non-economic general partner interest. This interest included 9,207,847 common partnership units and 22,811,000 subordinated partnership units. As the

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general partner of WNRL, we have the sole ability to direct the activities that most significantly impact WNRL's financial performance, and therefore we consolidate WNRL. All intercompany transactions with WNRL are eliminated upon consolidation.

We are WNRL’s primary logistics customer and a significant wholesale customer through our retail business. WNRL generates revenues by charging tariffs and fees for transporting petroleum products and crude oil though its pipelines, by charging fees for terminalling refined products and other hydrocarbons, and storing and providing other services at its storage tanks and terminals. Additionally, WNRL sells various finished petroleum products to us and other third-party customers. Under our long-term agreements with WNRL (discussed below), we accounted for 31.6%, 30.2% and 28.9% of WNRL’s total revenues for the years ended December 31, 2016, 2015 and 2014, respectively. We do not provide financial or equity support through any liquidity arrangements and/or debt guarantees to WNRL.

WNRL has outstanding debt under a senior secured revolving credit facility and its senior notes. Excluding assets held by Western Refining Logistic GP, LLC, WNRL’s creditors have no recourse to our assets. Any recourse to WNRL’s general partner would be limited to the extent of Western Refining Logistics GP LLC’s assets that other than its investment in WNRL, are not significant.Our creditors have no recourse to the assets of WNRL and its consolidated subsidiaries.

WNRL provides us with various pipeline transportation, terminal distribution and storage services under long-term, fee-based commercial agreements. 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 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 has risk associated with its operations. If a major customer of WNRL were to terminate its contracts or fail to meet desired shipping or throughput levels for an extended period of time, revenue would be reduced and WNRL could suffer substantial losses to the extent that a new customer is not found. In the event that WNRL incurs a loss, our operating results will reflect WNRL’s loss, net of intercompany eliminations, to the extent of our ownership interest in WNRL at that point in time.

St. Paul Park Logistics Transaction

On September 15, 2016, we sold the St. Paul Park Logistics Assets to WNRL in exchange for $195 million in cash and 628,224 common units representing limited partner interests in WNRL.

The St. Paul Park Logistics Assets included approximately 4.0 million barrels of refined product and crude oil storage tanks, a light products terminal, a heavy products loading rack, certain rail and barge facilities, certain other related logistics assets and two crude oil pipeline segments and one pipeline segment not currently in service, each of which is approximately 2.5 miles and extends from Western's refinery in St. Paul Park, Minnesota to Western's tank farm in Cottage Grove, Minnesota.

In connection with the St. Paul Park Logistics Transaction, we entered into a terminalling, transportation and storage services agreement with Western (the "St. Paul Park Terminalling Agreement"). Pursuant to the St. Paul Park Terminalling Agreement, we agreed to provide product storage services, product throughput services and product additive and blending services at the terminal facilities located at or near Western's refinery in St. Paul Park, Minnesota. In exchange for such services, Western has agreed to certain minimum volume commitments and to pay certain fees. The St. Paul Park Terminalling Agreement has an initial term of ten years, which may be extended for up to two renewal terms of five years each upon the mutual agreement of the parties.

TexNew Mex Pipeline System Acquisition

On October 30, 2015, we sold the TexNew Mex Pipeline System to WNRL. We sold these assets to WNRL in exchange for $170 million in cash and 421,031 common units representing limited partner interests in WNRL and 80,000TexNew 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

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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.

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

• Asphalt Trucking Transportation Services Agreement – Western has agreed to utilize WNRL's asphalt trucks and pay a flat rate per mile per ton (with market adjustments) based on the distance between the applicable pick-up and delivery points, plus monthly fuel adjustments and customary applicable surcharges. Volumes of asphalt transported pursuant to this agreement will be credited, on a barrel per barrel basis, towards Western’s contract minimum under the Crude Oil Trucking Transportation Services Agreement.

30. NTI

NTI Merger Agreement

On December 21, 2015, Western entered into the NTI Merger Agreement, by and among Western, MergerCo, NTI and Northern Tier Energy GP LLC, the general partner of NTI and a wholly-owned subsidiary of Western (“NTI GP”). On June 23, 2016, following the approval of the NTI Merger by NTI common unitholders, all closing conditions to the NTI Merger were satisfied, and the NTI Merger was successfully completed. Upon the terms and subject to the conditions set forth in the NTI Merger Agreement, MergerCo merged with and into NTI, the separate limited liability company existence of MergerCo ceased and NTI continued to exist as a limited partnership under Delaware law and as an indirect wholly-owned subsidiary of Western and as the surviving entity in the NTI Merger.

Prior to the NTI Merger, NT InterHoldCo LLC, a Delaware limited liability company and wholly-owned subsidiary of Western ("NT InterHoldCo"), owned 100% of the membership interests in NTI GP and 38.3% of NTI’s outstanding common units representing limited partner interests in NTI (“NTI Common Units”). NT InterHoldCo also owned 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 NTI Merger, NTI GP remained the sole general partner of NTI, the NTI Common Units held by Western and its subsidiaries were unchanged and remained issued and outstanding, and, by virtue of the NTI Merger, all of the membership interests in MergerCo automatically converted into the number of NTI Common Units (excluding any NTI Common Units owned by Western and its subsidiaries) issued and

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

outstanding immediately prior to the effective time of the NTI Merger. Consequently, NT InterHoldCo and its wholly-owned subsidiary, MergerCo HoldCo, became the sole limited partners of NTI.

Pursuant to the NTI Merger Agreement, we paid $859.9 million in cash and issued 17.1 million shares of Western common stock adjusted slightly for cash paid in lieu of fractional shares. We incurred transaction costs related to the NTI Merger of $11.7 million.

The NTI Merger involved a change in WNR’s ownership interest in its subsidiary, NTI, due to the purchase of the remaining ownership interests not already owned by WNR and was accounted for under Accounting Standards Codification 810-10-45-23, Consolidation, which indicates that increases in a parent’s ownership interest while the parent retains its controlling financial interest in its subsidiary shall be accounted for as an equity transaction. Therefore, no gain or loss was realized as a result of the NTI Merger. Any difference between the consideration paid and the amount by which the non-controlling interest is adjusted was recognized in Western shareholders' equity.

NTI common unitholders made consideration elections that resulted in the following allocation of cash and Western common stock among NTI common unitholders.

• NTI common unitholders who made a valid “Mixed Election” (as defined in the NTI Merger Agreement), or who made no election, received $15.00 in cash and 0.2986 of a share of Western common stock for each such NTI common unit held.

• NTI common unitholders who made a valid “Cash Election” (as defined in the NTI Merger Agreement) received $15.357 in cash and 0.28896 of a share of Western common stock as prorated in accordance with the Merger Agreement for each such NTI common unit held.

• NTI common unitholders who made a valid “Stock Election” (as defined in the NTI Merger Agreement) received 0.7036 of a share of Western common stock for each such NTI common unit held.

The consolidated statements of operations include the results of the NTI Merger beginning on June 23, 2016. NTI's net sales and net loss since June 23, 2016 was $1,905.3 million and $20.1 million, respectively. The following unaudited pro forma information assumes that (i) the Merger occurred on January 1, 2015; (ii) $500.0 million was borrowed to fund the NTI Merger consideration on January 1, 2015, resulting in increased interest and debt expense of $16.8 million and $36.1 million for the years ended December 31, 2016 and 2015, respectively; and (iii) income tax expense increased as a result of the increased net income attributable to Western Refining, Inc. offset by increased interest and debt expense of $7.0 million and $57.3 million for the years ended December 31, 2016 and 2015, respectively.

	Year Ended
	December 31,
	2016		2015
	(In thousands, except per share data)
Net sales	$	7,743,213	$	9,787,036
Operating income	343,425		930,125
Net income	163,129		521,014
Net income attributable to Western Refining, Inc.	136,385		499,859
Basic earnings per share	$	1.26	$	4.46
Diluted earnings per share	1.25		4.46

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NTI Merger and Reorganization Expenses

We incurred professional service fees in connection with the NTI Merger transaction. Additionally, we incurred costs associated with initiating a plan of reorganization for various positions during the second half of 2016. In relation to this reorganization plan, it was determined that certain employees would be terminated during 2016 and 2017. We recognized $6.3 million of expense during the year ended December 31, 2016 which included compensation related to the severance of employment and retention bonuses for selected employees. These costs have been included in Merger and reorganization costs in the accompanying Consolidated Statements of Operations and are included in the "Other" category within our segment presentation. We recognize these costs ratably from September 1, 2016, the effective date of the agreements, through the remaining service period, which varies for each employee, but in no case is later than September 1, 2017. As of December 31, 2016, we anticipate that these costs will continue to be recognized through the third quarter of 2017 and for the expenses to be completely paid out by December 31, 2017.

The following table summarizes the expense activity related to the NTI Merger and reorganization for the years ended December 31, 2016, 2015 and 2014:

	Year Ended
	December 31,
	2016			2015			2014
	(In thousands)
Beginning liability for merger and reorganization costs	$	189		$	808		$	—
Third-party professional service fees	1,662			—			—
Reorganization and related personnel costs incurred during period	4,650			—			12,878
Non-cash equity-based awards with accelerated vesting	—			—			(4,789		)
Cash payments to third-party professional service providers	(1,459		)	—			—
Cash payments made to severed employees	(2,468		)	(619		)	(7,281		)
Ending liability for merger and reorganization costs	$	2,574		$	189		$	808

31. Tesoro Merger

Agreement and Plan of Merger

On November 16, 2016, we entered into the Tesoro Merger Agreement with Tesoro, Merger Sub 1 and Merger Sub 2. Subject to the terms and conditions set forth in the Tesoro Merger Agreement, upon consummation of the First Tesoro Merger, each share of our common stock, par value $0.01 per share issued and outstanding immediately prior to the effective time of the First Tesoro Merger (excluding 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 our common stock, either (a) $37.30 in cash or (b) 0.4350 shares of common stock, par value $0.16⅔ per share, of Tesoro (“Tesoro Shares”), in each case without interest.

We recognized $6.1 million of expense related to the Tesoro Merger during the year ended December 31, 2016 which included transaction and consulting costs. These costs have been included in Merger and reorganization costs in the accompanying Consolidated Statements of Operations.

Cash elections will be subject to proration if cash elections are made in respect of more than approximately 10.8 million shares of our common stock. Stock elections are not subject to proration. Western common stock in respect of which no cash election or stock election is validly made will be deemed to be Western common stock in respect of which stock elections have been made.

The Tesoro Merger Agreement permits either the Company or Tesoro to require that the surviving corporation of the First Tesoro Merger be merged with and into Merger Sub 2 immediately following the effective time of the First Tesoro Merger, with Merger Sub 2 being the surviving company from the second merger (the “Second Tesoro Merger” and, if the second merger election is made, collectively with the First Tesoro Merger, the “Tesoro Merger”) if the requiring party reasonably believes, based on legal advice, that the Second Tesoro Merger is necessary to enable the Tesoro Merger to qualify as a “reorganization” within the meaning of Section 368(a) of the Internal Revenue Code.

The completion of the Tesoro Merger is subject to certain customary mutual conditions, including (i) the receipt of the required approvals from Tesoro’s and the Company’s stockholders, (ii) Tesoro’s registration statement on Form S-4 having

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become effective under the Securities Act of 1933, (iii) the Tesoro Shares issuable in connection with the First Tesoro Merger having been approved for listing on the New York Stock Exchange, subject to official notice of issuance, (iv) the expiration or termination of the waiting period under the Hart-Scott-Rodino Act, (v) the absence of any governmental order or law prohibiting the consummation of the Tesoro Merger or the other transactions contemplated by the Tesoro Merger Agreement and (vi) there not having been imposed a burdensome condition in connection with the expiration or termination of the waiting period applicable under the Hart-Scott-Rodino Act. The obligation of each party to consummate the Tesoro Merger is also conditioned upon (i) compliance by the other party in all material respects with its pre-closing obligations under the Tesoro Merger Agreement and (ii) the accuracy of the representations and warranties of the other party as of the date of the Tesoro Merger Agreement and as of the closing (subject to customary materiality qualifiers). Our obligation to complete the Tesoro Merger is additionally subject to Tesoro's receipt of a tax opinion to the effect that the Tesoro Merger qualifies as a “reorganization” within the meaning of Section 368(a) of the Internal Revenue Code.

The Company and Tesoro have made customary representations, warranties and covenants in the Tesoro Merger Agreement. Subject to certain exceptions, the Company and Tesoro have agreed, among other things, to covenants relating to (i) the conduct of their respective businesses during the interim period between the execution of the Tesoro Merger Agreement and the consummation of the First Tesoro Merger, (ii) the use of their respective reasonable best efforts, subject to certain exceptions, to obtain governmental and regulatory approvals, (iii) obligations to facilitate the Company’s stockholders’ consideration of, and voting upon, the adoption of the Tesoro Merger Agreement and certain related matters as applicable and Tesoro’s stockholders’ consideration of, and voting upon, the issuance of Tesoro Shares in the First Tesoro Merger and certain related matters as applicable, (iv) the recommendation by the board of directors of the Company in favor of the adoption by its stockholders of the Tesoro Merger Agreement, subject to certain exceptions, (v) the recommendation by the board of directors of Tesoro in favor of the issuance of Tesoro Shares in the First Tesoro Merger, subject to certain exceptions, (vi) non-solicitation obligations of Tesoro and the Company relating to alternative acquisition proposals and (vii) the use of reasonable best efforts by Tesoro to take certain steps to obtain debt financing at the closing of the Tesoro Merger to the extent the proceeds thereof are needed to pay the cash consideration and all other cash amounts required to be paid in connection with the closing of the Tesoro Merger.

The Tesoro Merger Agreement permits the Company to continue paying a regular quarterly dividend of up to $0.38 per Company Share and permits Tesoro to continue paying a regular quarterly dividend of up to $0.55 per share.

On December 14, 2016, Tesoro filed a preliminary registration statement on Form S-4 (the “Preliminary S-4”) to register the shares of Tesoro Common Stock to be issued and delivered (or, to the extent held in treasury by Tesoro, delivered but not issued) in the Tesoro Merger. The Preliminary S-4 is subject to future amendments depending on review and comments by the Securities and Exchange Commission (the “SEC”). During January and February of 2017, amended Form S-4s were filed with the SEC. On February 16, 2017, Tesoro filed with the SEC, and the SEC declared effective, a registration statement on Form S-4 (Reg. No. 333-215080), containing a joint proxy statement/prospectus of Tesoro and Western, which proxy statement/prospectus was first mailed to Tesoro and Western stockholders on February 17, 2017.

Voting Agreements

On November 16, 2016, concurrently with the execution of the Tesoro Merger Agreement, the Company, Merger Sub 1, Merger Sub 2 and Tesoro entered into three separate voting agreements (each, a “Voting Agreement”) with (i) Paul L. Foster and Franklin Mountain Investments, LP, (ii) Jeff A. Stevens, and (iii) Scott D. Weaver (each, a “Stockholder” and collectively, the “Stockholders”) pursuant to each of which, among other things and subject to the terms and conditions therein, the Stockholder(s) party thereto have agreed to vote all Western common stock beneficially owned by them (the “Covered Shares”) in favor of the adoption of the Tesoro Merger Agreement and the approval of the transactions contemplated by the Tesoro Merger Agreement, including the Tesoro Merger, and to not vote in favor of any alternative acquisition proposal or other action or agreement that would reasonably be expected to adversely affect the Tesoro Merger.

The Voting Agreements also generally prohibit the Stockholders from transferring the Covered Shares. The Voting Agreements terminate upon the earlier of the termination of the Tesoro Merger Agreement and the time the Tesoro Merger becomes effective.

138

Item 9. Changes In and Disagreements With Accountants on Accounting and Financial Disclosure

None.

Item 9A. Controls and Procedures

Western Refining, Inc.

Evaluation of disclosure controls and procedures. Our chief executive officer and chief financial officer, after evaluating the effectiveness of our “disclosure controls and procedures” (as defined in the Securities Exchange Act of 1934 Rules 13a-15(e) and 15d-15(e)) as of December 31, 2016 (the “Evaluation Date”), concluded that as of the Evaluation Date, our disclosure controls and procedures were effective.

Management’s Report on Internal Control Over Financial Reporting. Included herein under the caption "Management’s Report on Internal Control Over Financial Reporting" on page 68 of this report.

Attestation Report of the Registered Public Accounting Firm. Included herein under the caption "Report of Independent Registered Public Accounting Firm" on page 69 of this report.

Changes in internal control over financial reporting. There were no changes in our internal control over financial reporting that occurred during the quarter ended December 31, 2016, that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Northern Tier Energy LP

Evaluation of disclosure controls and procedures. NTI's chief executive officer and chief financial officer, after evaluating the effectiveness of NTI's “disclosure controls and procedures” (as defined in the Securities Exchange Act of 1934 Rules 13a-15(e) and 15d-15(e)) as of December 31, 2016 (the “Evaluation Date”), concluded that as of the Evaluation Date, NTI's disclosure controls and procedures were effective.

Management’s Report on Internal Control Over Financial Reporting. Included herein under the caption "Management’s Report on Internal Control Over Financial Reporting" on page 68 of this report.

Attestation Report of the Registered Public Accounting Firm. Included herein under the caption "Report of Independent Registered Public Accounting Firm" on page 69 of this report.

Changes in internal control over financial reporting. There were no changes in NTI's internal control over financial reporting that occurred during the quarter ended December 31, 2016, that materially affected, or are reasonably likely to materially affect, NTI's internal control over financial reporting.

Item 9B. Other Information

None.

139

PART III

Certain information required in this Part III is incorporated by reference to Western Refining, Inc.’s Definitive Proxy Statement (the "Proxy Statement") to be filed with the Securities and Exchange Commission in accordance to Regulation 14A within 120 days after the end of the fiscal year covered by this report or will be provided in an amendment filed on Form 10-K/A.

Item 10. Directors, Executive Officers and Corporate Governance

Western Refining, Inc.

The information required by this item is incorporated by reference to the information contained in Western Refining, Inc.’s Definitive Proxy Statement under the headings “Election of Directors” and “Executive Compensation and Other Information” or will be provided in an amendment filed on Form 10-K/A.

Northern Tier Energy LP

This information is omitted for NTI pursuant to General Instruction I(2)(c) to Form 10-K.

Item 11. Executive Compensation

Western Refining, Inc.

The information required by this item is incorporated by reference to the information contained in Western Refining, Inc.’s Definitive Proxy Statement under the heading “Executive Compensation and Other Information” or will be provided in an amendment filed on Form 10-K/A.

Northern Tier Energy LP

This information is omitted for NTI pursuant to General Instruction I(2)(c) to Form 10-K.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

Western Refining, Inc.

Security Ownership of Certain Beneficial Owners and Management

The information required by this item is incorporated by reference to the information contained in Western Refining, Inc.’s Definitive Proxy Statement under the heading “Security Ownership of Certain Beneficial Owners and Management” or will be provided in an amendment filed on Form 10-K/A.

Securities Authorized for Issuance Under Equity Compensation Plans

Plan Category	(a) Number of securities to be issued upon exercise of outstanding options, warrants and rights (1)	(b) Weighted average exercise price of outstanding options, warrants and rights (2)	(c) Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))
Equity compensation plans approved by security holders	1,320,878	—	2,741,585
Equity compensation plans not approved by security holders	—	—	—
Total	1,320,878	—	2,741,585

(1) Represents 658,506 shares underlying restricted share unit awards and 662,372 shares underlying phantom stock awards.

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

Northern Tier Energy LP

This information is omitted for NTI pursuant to General Instruction I(2)(c) to Form 10-K.

140

Item 13. Certain Relationships and Related Transactions and Director Independence

Western Refining, Inc.

The information required by this item is incorporated by reference to the information contained in Western Refining, Inc.’s Definitive Proxy Statement under the heading “Certain Relationships and Related Transactions” or will be provided in an amendment filed on Form 10-K/A.

Northern Tier Energy LP

This information is omitted for NTI pursuant to General Instruction I(2)(c) to Form 10-K.

Item 14. Principal Accountant Fees and Services

Western Refining, Inc.

The information required by this item is incorporated by reference to the information contained in Western Refining, Inc.’s Definitive Proxy Statement under the heading “Proposal 2: Ratification of Independent Auditor” or will be provided in an amendment filed on Form 10-K/A.

Northern Tier Energy LP

The following table presents fees for the audit of the NTI’s annual consolidated financial statements for the last two fiscal years and for other services provided by Deloitte & Touche LLP for 2016 and 2015, respectively:

	Year Ended
	December 31,
	2016		2015
	(In thousands)
Audit fees	$	882	$	1,005
Audit related	231		125
Tax fees	415		477
All other fees	2		2
Total	$	1,530	$	1,609

For 2016, audit fees consisted of fees billed for professional services rendered for (i) the audit of the NTI’s 2016 consolidated financial statements, (ii) the audit of the effectiveness of NTI’s internal control over financial reporting as of December 31, 2016, (iii) the review of NTI’s interim consolidated financial statements included in quarterly reports and (iv) other services that were regularly provided by Deloitte & Touche LLP in connection with security offerings. Tax fees include $0.1 million for tax compliance services, $0.2 million for tax planning services and $0.1 million of pass through expenses in connection with acquiring investor data necessary for preparation of Form K-1s.

For 2015, audit fees consisted of fees billed for professional services rendered for (i) the audit of the NTI’s 2015 consolidated financial statements, (ii) the audit of the effectiveness of NTI’s internal control over financial reporting as of December 31, 2015, (iii) the review of NTI’s interim consolidated financial statements included in quarterly reports and (iv) other services that were regularly provided by Deloitte & Touche LLP in connection with security offerings. Tax fees include $0.5 million for tax compliance services, $0.1 million for tax planning services and $0.2 million of pass through expenses in connection with acquiring investor data necessary for preparation of Form K-1s.

Audit Committee Approval of Audit and Non-Audit Services

The Audit Committee of NTI’s general partner has adopted a Pre-Approval Policy with respect to services that may be performed by Deloitte & Touche LLP. This policy lists specific audit-related services as well as any other services that Deloitte & Touche LLP is authorized to perform and sets out specific dollar limits for each specific service, which may not be exceeded without additional Audit Committee authorization. The Audit Committee receives quarterly reports on the status of expenditures pursuant to that Pre-Approval Policy. The Audit Committee reviews the policy at least annually in order to approve services and limits for the current year. Any service that is not clearly enumerated in the policy must receive specific pre-approval by the Audit Committee or by its Chairperson, to whom such authority has been conditionally delegated, prior to engagement. During 2016, all fees reported above were approved in accordance with the Pre-Approval Policy.

141

PART IV

Item 15. Exhibits and Financial Statement Schedules

(a) Financial Statements:

See Index to Financial Statements included in Item 8.

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

Exhibit Index

Western Refining, Inc.***

Number	Exhibit Title
2.1	Agreement and Plan of Merger, dated August 26, 2006, by and among Western Refining, Inc., New Acquisition Corporation and Giant Industries, Inc. (incorporated by reference to Exhibit 2.1 to the Company's Current Report on Form 8-K, filed with the SEC on August 28, 2006).
2.2	Amendment No. 1 to the Agreement and Plan of Merger, dated November 12, 2006, by and among Western Refining, Inc., New Acquisition Corporation and Giant Industries, Inc. (incorporated by reference to Exhibit 2.1 to the Company's Current Report on Form 8-K, filed with the SEC on November 13, 2006).
2.3	Contribution, Conveyance and Assumption Agreement, dated as of October 16, 2013, by and among Western Refining Logistics, LP, Western Refining GP, LLC, Western Refining Southwest, Inc., San Juan Refining Company, LLC, Western Refining Pipeline, LLC, Western Refining Terminals, LLC, Western Refining Company, L.P. and Western Refining, Inc. (incorporated by reference to Exhibit 10.2 to the Company's Current Report on Form 8-K, filed with the SEC on October 22, 2013).
2.4	Contribution, Conveyance and Assumption Agreement, dated as of September 25, 2014, by and among Western Refining, Inc., Western Refining Southwest, Inc., Western Refining Logistics GP, LLC and Western Refining Logistics, LP (incorporated by reference to Exhibit 2.1 to the Company's Current Report on Form 8-K, filed with the SEC on October 1, 2014).
2.5	Amendment No. 1 to the Contribution, Conveyance and Assumption Agreement, dated as of October 15, 2014, by and among Western Refining, Inc., Western Refining Southwest, Inc., Western Refining Logistics GP, LLC and Western Refining Logistics, LP (incorporated by reference to Exhibit 2.2 to the Company's Quarterly Report on Form 10-Q, filed with the SEC on November 6, 2014).
2.6	Contribution, Conveyance and Assumption Agreement, dated as of October 30, 2015, by and among Western Refining, Inc., Western Refining Southwest, Inc., Western Refining Logistics GP, LLC and Western Refining Logistics, LP (incorporated by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K, filed with the SEC on November 2, 2015).
2.7	Agreement and Plan of Merger dated as of December 21, 2015, by and among Western Refining, Inc., Western Acquisition Co, LLC, Northern Tier Energy LP and Northern Tier Energy GP LLC (incorporated by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K, filed with the SEC on December 22, 2015).
2.8	Agreement and Plan of Merger among Western Refining, Inc., Tesoro Corporation, Tahoe Merger Sub 1, Inc. and Tahoe Merger Sub 2, LLC, dated as of November 16, 2016 (incorporated by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K, filed with the SEC on November 17, 2016).
3.1	Certificate of Incorporation, as amended, of Western Refining, Inc. as currently in effect (incorporated by reference to Exhibit 3.1 to the Company's Quarterly Report on Form 10-Q, filed with the SEC on August 7, 2014).
3.2	Bylaws, as amended, of Western Refining, Inc. as currently in effect (incorporated by reference to Exhibit 3.2 to the Company's Current Report on Form 8-K, filed with the SEC on March 30, 2016).
4.1	Specimen of Western Refining, Inc. Common Stock Certificate (incorporated by reference to Exhibit 4.1 to the Company's Registration Statement on Form S-1/A (File No. 333-128629), filed with the SEC on December 5, 2005).
4.2	Registration Rights Agreement, dated January 24, 2006, by and between Western Refining, Inc. and each of the stockholders listed on the signature pages thereto (incorporated by reference to Exhibit 4.1 to the Company's Current Report on Form 8-K, filed with the SEC on January 25, 2006).
4.3	Indenture dated March 25, 2013 among Western Refining, Inc., the Guarantors named therein and U.S. Bank National Association, as trustee, paying agent, registrar and transfer agent (incorporated by reference to Exhibit 4.1 to the Company's Current Report on Form 8-K, filed with the SEC on March 25, 2013).
4.4	Form of 6.25% Senior Note (included in Exhibit 4.6).

142

Number	Exhibit Title
4.5	Registration Rights Agreement dated March 25, 2013 among Western Refining, Inc. and Deutsche Bank Securities Inc., Merrill Lynch, Pierce, Fenner & Smith Incorporated, Credit Suisse Securities (USA) LLC, Goldman, Sachs & Co., RBS Securities Inc., Barclays Capital Inc., Credit Agricole Securities (USA) Inc., PNC Capital Markets, RB International Markets (USA) LLC, Regions Securities LLC, SunTrust Robinson Humphrey, Inc. and U.S. Bancorp Investments, Inc. as the Initial Purchasers (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, filed with the SEC on March 25, 2013).
4.6	Indenture, dated as of November 8, 2012, by and among Northern Tier Energy LLC, Northern Tier Finance Corporation, Northern Tier Energy LP, the subsidiary guarantors party thereto and Deutsche Bank Trust Company Americas (incorporated by reference to Exhibit 4.1 of Northern Tier Energy LP's Current Report on Form 8-K (File No. 001-35612), filed with the SEC on November 13, 2012).
4.7	Form of 7.125% Senior Secured Note (included in Exhibit 4.9).
4.8	Supplemental Indenture, dated September 29, 2014, by and among Northern Tier Energy LLC, Northern Tier Finance Corporation, Northern Tier Energy LP, the subsidiary guarantors party thereto and Deutsche Bank Trust Company Americas (incorporated by reference to Exhibit 4.1 of Northern Tier Energy LP's Current Report on Form 8-K (File No. 001-35612), filed with the SEC on October 3, 2014).
4.9	Indenture, dated February 11, 2015, among Western Refining Logistics, LP, WNRL Finance Corp., the Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 of Western Refining Logistics, LP's Current Report on Form 8-K (File No. 001-36114), filed with the SEC on February 11, 2015).
4.10	Form of 7.50% Senior Note (included in Exhibit 4.12).
10.1	Second Amended and Restated Revolving Credit Agreement, dated as of April 11, 2013 by and among Western Refining, Inc., the several lenders from time to time party thereto and Bank of America, N.A., as Administrative Agent, Swing Line Lender and L/C Issuer (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, filed with the SEC on April 15, 2013).
10.2	Third Amended and Restated Revolving Credit Agreement, dated October 2, 2014 by and among Western Refining, Inc., the several lenders from time to time party thereto and Bank of America, N.A., as Administrative Agent, Swing Line Lender and L/C Issuer (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, filed with the SEC on October 6, 2014).
10.3	Term Loan Credit Agreement dated as of November 12, 2013, by and among Western Refining, Inc., Bank of America, N.A., as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.2 to the Company's Current Report on Form 8-K, filed with the SEC on November 14, 2013).
10.4	First Amendment to the Credit Agreement, dated as of July 17, 2012, by and among the financial institutions party thereto, as the lenders, J.P. Morgan Chase Bank, N.A., as administrative agent and collateral agent, Bank of America, N.A., as syndication agent, and Macquarie Capital (USA) Inc. and SunTrust Bank, as co-documentation agents, and Northern Tier Energy LLC and certain subsidiaries of Northern Tier Energy LLC party thereto (incorporated by reference to Exhibit 10.13 to Amendment No. 6 to Northern Tier Energy LP’s Registration Statement on Form S-1 (File No. 333-178457), filed with the SEC on July 18, 2012).
10.5	Credit Agreement, dated September 29, 2014, among Northern Tier Energy LLC, each subsidiary of Northern Tier Energy LLC party thereto, the several lenders and issuing banks party thereto and J.P. Morgan Chase Bank, N.A. as Administrative Agent and Collateral Agent (incorporated by reference to Exhibit 10.1 to Northern Tier Energy LP's Current Report on Form 8-K (File No. 001-35612), filed with the SEC on October 3, 2014).
10.6	Credit Agreement, dated as of October 16, 2013, by and among Western Refining Logistics, LP, the lenders from time to time party thereto and Well Fargo Bank, National Association, as Administrative Agent, Swingline Lender and L/C Issuer (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K (File No. 001-36114), filed with the SEC on October 22, 2013).
10.7	Purchase Agreement, dated as of November 12, 2013, by and between Northern Tier Investors LLC and Western Refining, Inc. (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, filed with the SEC on November 14, 2013).
10.8	Operating Agreement, dated May 6, 1993, by and between Western Refining LP and Chevron U.S.A. Inc. (incorporated by reference to Exhibit 10.10 to the Company's Registration Statement on Form S-1/A, filed with the SEC on November 3, 2005).
10.9	Purchase and Sale Agreement, dated May 29, 2003, by and among Chevron U.S.A. Inc., Chevron Pipe Line Company, Western Refining LP and Kaston Pipeline Company, L.P. (incorporated by reference to Exhibit 10.11 to the Company's Registration Statement on Form S-1/A (File No. 333-128629), filed with the SEC on November 3, 2005).
10.10	Asset Purchase Agreement, dated November 30, 2011, by and among Western Refining Yorktown, Inc., and Western Refining Yorktown Holding Company as Seller and Plains Marketing, L.P., as Buyer (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, filed with the SEC on December 2, 2011).

143

Number	Exhibit Title
10.11	Asset Purchase Agreement, dated November 30, 2011, by and among Western Refining Pipeline Company as Seller and Plains Pipeline, L.P., as Buyer (incorporated by reference to Exhibit 10.2 to the Company's Current Report on Form 8-K, filed with the SEC on December 2, 2011).
10.12	Omnibus Agreement, dated October 16, 2013, by and among Western Refining Logistics, LP, Western Refining Logistics GP LLC, the Company, Western Refining Southwest, Inc., Western Refining Company, L.P. and Western Refining Wholesale, Inc. (incorporated by reference to Exhibit 10.3 to the Company's Current Report on Form 8-K, filed with the SEC on October 22, 2013).
10.13	Operational Services Agreement, dated October 16, 2013, by and among Western Refining Logistics, LP, Western Refining Company, L.P. and Western Refining Southwest, Inc. (incorporated by reference to Exhibit 10.4 to the Company's Current Report on Form 8-K, filed with the SEC on October 22, 2013).
10.14††	Pipeline and Gathering Services Agreement, dated October 16, 2013, by and among Western Refining Company, L.P., Western Refining Southwest, Inc. and Western Refining Pipeline, LLC (incorporated by reference to Exhibit 10.5 to the Company's Current Report on Form 8-K, filed with the SEC on October 22, 2013).
10.14.1††	Amendment No. 1 to the Pipeline and Gathering Services Agreement, dated October 30, 2015, by and among Western Refining Company, L.P., Western Refining Southwest, Inc. and Western Refining Pipeline, LLC (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K (File No. 001-32721), filed with the SEC on November 2, 2015).
10.15††	Terminalling, Transportation and Storage Services Agreement, dated October 16, 2013, by and among Western Refining Company, L.P., Western Refining Southwest, Inc. and Western Refining Terminals, LLC (incorporated by reference to Exhibit 10.6 to the Company's Current Report on Form 8-K, filed with the SEC on October 22, 2013).
10.16††	Product Supply Agreement, dated October 15, 2014, by and among Western Refining Southwest, Inc., Western Refining Company, L.P. and Western Refining Wholesale, LLC (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, filed with the SEC on October 16, 2014).
10.17††	Fuel Distribution and Supply Agreement, dated October 15, 2014, by and between Western Refining Wholesale, LLC and Western Refining Southwest, Inc. (incorporated by reference to Exhibit 10.2 to the Company's Current Report on Form 8-K, filed with the SEC on October 16, 2014).
10.18††	Crude Oil Trucking Transportation Services Agreement, dated October 15, 2014, by and among Western Refining Wholesale, LLC, Western Refining Company, L.P. and Western Refining Southwest, Inc. (incorporated by reference to Exhibit 10.3 to the Company's Current Report on Form 8-K, filed with the SEC on October 16, 2014).
10.19†	Employment Agreement, dated January 24, 2006, by and between Western Refining GP, LLC and Paul L. Foster (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, filed with the SEC on January 25, 2006).
10.19.1†	First Amendment to the Employment Agreement referred to in Exhibit 10.19, dated December 28, 2006 (incorporated by reference to Exhibit 10.1.1 to the Company's Annual Report on Form 10-K, filed with the SEC on March 8, 2007).
10.19.2†	Second Amendment to the Employment Agreement referred to in Exhibit 10.19, dated December 31, 2008 (incorporated by reference to Exhibit 10.1.2 to the Company's Annual Report on Form 10-K, filed with the SEC on March 13, 2009).
10.19.3†	Termination of Employment Agreement referred to in Exhibit 10.19, dated February 27, 2015, by and between Western Refining GP, LLC and Paul L. Foster (incorporated by reference to Exhibit 10.19.3 to the Company's Annual Report on Form 10-K, filed with the SEC on March 2, 2015).
10.20†	Employment Agreement, dated January 24, 2006, by and between Western Refining GP, LLC and Jeff A. Stevens (incorporated by reference to Exhibit 10.2 to the Company's Current Report on Form 8-K, filed with the SEC on January 25, 2006).
10.20.1†	First Amendment to the Employment Agreement referred to in Exhibit 10.20, dated December 28, 2006 (incorporated by reference to Exhibit 10.2.1 to the Company's Annual Report on Form 10-K, filed with the SEC on March 8, 2007).
10.20.2†	Second Amendment to the Employment Agreement referred to in Exhibit 10.20, dated December 31, 2008 (incorporated by reference to Exhibit 10.2.2 to the Company's Annual Report on Form 10-K, filed with the SEC on March 13, 2009).
10.21†	Employment Agreement, dated January 24, 2006, by and between Western Refining GP, LLC and Gary R. Dalke (incorporated by reference to Exhibit 10.5 to the Company's Current Report on Form 8-K, filed with the SEC on January 25, 2006).
10.21.1†	First Amendment to the Employment Agreement referred to in Exhibit 10.21, dated December 31, 2008 (incorporated by reference to Exhibit 10.4.1 to the Company's Annual Report on Form 10-K, filed with the SEC on March 13, 2009).
10.22†	Employment Agreement, dated January 24, 2006, by and between Western Refining GP, LLC and Lowry Barfield (incorporated by reference to Exhibit 10.6 to the Company's Current Report on Form 8-K, filed with the SEC on January 25, 2006).

144

Number	Exhibit Title
10.22.1†	First Amendment to the Employment Agreement referred to in Exhibit 10.22, dated December 31, 2008 (incorporated by reference to Exhibit 10.5.1 to the Company's Annual Report on Form 10-K, filed with the SEC on March 13, 2009).
10.23†	Employment agreement, effective August 28, 2006, made by and between Western Refining GP, LLC and Mark J. Smith (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, filed with the SEC on August 16, 2006).
10.23.1†	First Amendment to the Employment Agreement referred to in Exhibit 10.23, dated December 31, 2008 (incorporated by reference to Exhibit 10.27.1 to the Company's Annual Report on Form 10-K, filed with the SEC on March 13, 2009).
10.24†	Employment agreement, dated November 4, 2008, made by and between Western Refining GP, LLC and William R. Jewell (incorporated by reference to Exhibit 10.2 to the Company's Quarterly Report on Form 10-Q, filed with the SEC on November 7, 2008).
10.25†	Employment agreement, dated March 9, 2010, made by and between Western Refining GP, LLC and Jeffrey S. Beyersdorfer (incorporated by reference to Exhibit 10.31 to the Company's Annual Report on Form 10-K, filed with the SEC on March 12, 2010).
10.26†	Form of Indemnification Agreement, by and between the Company and each director and officer of the Company party thereto (incorporated by reference to Exhibit 10.7 to the Company's Current Report on Form 8-K, filed with the SEC on January 25, 2006).
10.27†	Western Refining Long-Term Incentive Plan (incorporated by reference to Exhibit 10.17 to the Company's Annual Report on Form 10-K, filed with the SEC on March 24, 2006).
10.27.1†	First Amendment to the Western Refining Long-Term Incentive Plan referred to in Exhibit 10.27, dated December 4, 2007 (incorporated by reference to Exhibit 10.19.1 to the Company's Annual Report on Form 10-K, filed with the SEC on March 13, 2009).
10.27.2†	Second Amendment to the Western Refining Long-Term Incentive Plan referred to in Exhibit 10.27, dated November 20, 2008 (incorporated by reference to Exhibit 10.19.2 to the Company's Annual Report on Form 10-K, filed with the SEC on March 13, 2009).
10.28†	Form of Restricted Stock Grant Agreement under the Western Refining Long-Term Incentive Plan (incorporated by reference to Exhibit 10.20 to the Company's Registration Statement on Form S-1/A (File No.333-128629), filed with the SEC on December 5, 2005).
10.29†	Form of Nonqualified Stock Option Agreement under the Western Refining Long-Term Incentive Plan (incorporated by reference to Exhibit 10.21 to the Company's Registration Statement on Form S-1/A (File No.333-128629), filed with the SEC on December 5, 2005).
10.30†	Amended and Restated 2010 Incentive Plan of Western Refining, Inc. (incorporated by reference to Appendix A of the Company's Proxy Statement, filed with the SEC on April 22, 2015).
10.31†	Form of Performance Unit Award Agreement between the Company and Participant under the 2010 Incentive Plan of Western Refining, Inc. (incorporated by reference to Exhibit 10.32 to the Company's Annual Report on Form 10-K, filed with the SEC on March 8, 2011).
10.32†	Form of Western Refining, Inc. Restricted Share Unit Award Agreement between the Company and Participant under the 2010 Incentive Plan of Western Refining, Inc. (incorporated by reference to Exhibit 10.33 to the Company's Annual Report on Form 10-K, filed with the SEC on March 8, 2011).
10.33†	Form of Western Refining, Inc. Restricted Share Unit Award Agreement between the Company and Non-Employee Director under the 2010 Incentive Plan of Western Refining, Inc. (incorporated by reference to Exhibit 10.3 to the Company's Quarterly Report on Form 10-Q, filed with the SEC on May 6, 2013).
10.34†	Form No. 2 of Western Refining, Inc. Restricted Share Unit Award Agreement between the Company and Participant under the 2010 Incentive Plan of Western Refining, Inc. (incorporated by reference to Exhibit 10.4 to the Company's Quarterly Report on Form 10-Q, filed with the SEC on May 6, 2013).
10.35†	Form of Western Refining, Inc. Restricted Share Unit Award Agreement (DE) between the Company and Non-Employee Director under the 2010 Incentive Plan of Western Refining, Inc. (incorporated by reference to Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q, filed with the SEC on November 4, 2013).
10.36†	Western Refining, Inc. Non-Employee Director Deferred Compensation Plan (incorporated by reference to Exhibit 10.25 to the Company's Annual Report on Form 10-K, filed with the SEC on March 1, 2013).
10.36.1†	Western Refining, Inc. Non-Employee Director Deferred Compensation Plan Adoption Agreement, dated as of January 1, 2009 (incorporated by reference to Exhibit 10.26 to the Company's Annual Report on Form 10-K, filed with the SEC on March 1, 2013).
10.37†	Northern Tier Energy LP 2012 Long Term Incentive Plan (incorporated by reference to Exhibit 10.2 to Northern Tier Energy LP’s Current Report on Form 8-K (File No. 001-35612), filed on July 30, 2012).

145

Number	Exhibit Title
10.38†	Form of Northern Tier Energy LP 2012 Long Term Incentive Plan Restricted Unit Agreement (incorporated by reference to Exhibit 10.1 to Northern Tier Energy LP’s Current Report on Form 8-K (File No. 001-35612), filed on December 17, 2012).
10.39†	Form of Phantom Unit Award Agreement (time-based vesting) (incorporated by reference to Exhibit 10.1 to Northern Tier Energy LP’s Current Report on Form 8-K (File No. 001-35612), filed with the SEC on May 2, 2014).
10.40†	Form of Phantom Unit Agreement (performance-based vesting) (incorporated by reference to Exhibit 10.2 to Northern Tier Energy LP’s Current Report on Form 8-K (File No. 001-35612), filed with the SEC on December 8, 2014).
10.41†	Western Refining Logistics, LP 2013 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.7 to the Company's Current Report on Form 8-K (File No. 001-36114), filed with the SEC on October 22, 2013).
10.42†	Form of Phantom Unit Award Agreement (time-based vesting) (incorporated by reference to Exhibit 10.8 to Western Refining Logistics, LP’s Form S-1 Registration Statement (File No. 333-190135), filed with the SEC on September 27, 2013).
10.43†	Form of Phantom Unit Award Agreement (performance-based vesting) (incorporated by reference to Exhibit 10.9 to Western Refining Logistics, LP’s Form S-1 Registration Statement (File No. 333-190135), filed with the SEC on September 27, 2013).
10.44†	Form of Phantom Unit Award Agreement (time-based vesting) (incorporated by reference to Exhibit 10.1 to Western Refining Logistics, LP’s Quarterly Report on Form 10-Q (File No. 001-36114), filed with the SEC on May 12, 2014).
10.45††	Amendment No. 1 to the Pipeline and Gathering Services Agreement, dated October 30, 2015, by and among Western Refining Company, L.P., Western Refining Southwest, Inc. and Western Refining Pipeline, LLC (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K (File No. 001-32721), filed with the SEC on November 2, 2015).
10.46	Second Amendment to Third Amended and Restated Revolving Credit Agreement, dated as of May 27, 2016, by and among the Company, the other persons party thereto as guarantors, the Lenders signatory thereto and Bank of America, N.A., as Administrative Agent (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K, filed with the SEC on June 3, 2016).
10.47	Amendment No. 3 to the Term Loan Credit Agreement, dated as of May 27, 2016, by and among the Company, the Lenders signatory thereto and Bank of America, N.A., as Administrative Agent and acknowledged by the Guarantors named therein (incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K, filed with the SEC on June 3, 2016).
10.48	Supplement to the Term Loan Credit Agreement, dated as of May 27, 2016, by and among the Company, the Lenders signatory thereto and Bank of America, N.A., as Administrative Agent and acknowledged by the Guarantors named therein (incorporated by reference to Exhibit 10.3 to the Company's Quarterly Report on Form 10-Q, filed with the SEC on August 4, 2016).
10.49	Asphalt Trucking Transportation Services Agreement, dated May 4, 2016 and effective as of January 1, 2016, by and among Western Refining Wholesale, LLC, Western Refining Company, L.P., and, for certain limited purposes stated therein, Western Refining Southwest, Inc. (incorporated by reference to Exhibit 10.4 to the Company's Quarterly Report on Form 10-Q, filed with the SEC on August 4, 2016).
10.50	Contribution, Conveyance and Assumption Agreement, dated as of September 7, 2016, by and among the Company, St. Paul Park Refining Co. LLC, Western Refining Logistics GP, LLC and Western Refining Logistics, LP (incorporated by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K, filed with the SEC on September 7, 2016).
10.51	Terminalling, Transportation and Storage Services Agreement, dated September 15, 2016, by and between St. Paul Park Refining Co. LLC and Western Refining Terminals, LLC (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K, filed with the SEC on September 20, 2016).
10.52	Employment Agreement, effective August 15, 2016, by and between Western Refining GP, LLC and Gary R. Dalke (incorporated by reference to Exhibit 10.3 to the Company's Quarterly Report on Form 10-Q, filed with the SEC on November 3, 2016).
10.53	Voting and Support Agreement by and among Western Refining, Inc., Tesoro Corporation, Tahoe Merger Sub 1, Inc., Tahoe Merger Sub 2, LLC, Franklin Mountain Investments, LP, and Paul L. Foster, dated as of November 16, 2016 (incorporated by reference to Exhibit 99.2 to the Company's Current Report on Form 8-K, filed with the SEC on November 17, 2016).
10.54	Voting and Support Agreement by and among Western Refining, Inc., Tesoro Corporation, Tahoe Merger Sub 1, Inc., Tahoe Merger Sub 2, LLC, and Jeff A. Stevens, dated as of November 16, 2016 (incorporated by reference to Exhibit 99.3 to the Company’s Current Report on Form 8-K, filed with the SEC on November 17, 2016).
10.55	Voting and Support Agreement by and among Western Refining, Inc., Tesoro Corporation, Tahoe Merger Sub 1, Inc., Tahoe Merger Sub 2, LLC, and Scott D. Weaver, dated as of November 16, 2016 (incorporated by reference to Exhibit 99.4 to the Company’s Current Report on Form 8-K, filed with the SEC on November 17, 2016).

146

Number	Exhibit Title
12.1*	Statements of Computation of Ratio of Earnings to Fixed Charges.
21.1*	List of Subsidiaries of the Company.
23.1*	Consent of Deloitte & Touche LLP, dated March 1, 2017.
31.1*	Certification Statement of Chief Executive Officer of the Company pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1**	Certification Statement of Chief Executive Officer of the Company pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101*	Interactive Data Files.

_______________________________________

*	Filed herewith.
**	Furnished herewith.
***	Reports filed by the Company under the Securities Exchange Act of 1934, as amended (including Form 10-K, Form 10-Q and Form 8-K), are filed under File No. 001-32721.
†	Management contract or compensatory plan or arrangement.
††	The SEC has granted confidential treatment for certain portions of this Exhibit pursuant to a confidential treatment order. Such portions have been omitted and filed separately with the SEC.

(c) All financial statement schedules are omitted because the required information is not present or is not present in amounts sufficient to require submission of the schedule, or because the information required is included in the consolidated financial statements or notes thereto.

Our 2016 Annual Report is available upon request. Stockholders may obtain a copy of any exhibits to this Form 10-K at a charge of $0.10 per page. Requests should be made to: Investor Relations, Western Refining, Inc., 212 N. Clark Dr., El Paso, Texas 79905.

Northern Tier Energy LP***

Number	Exhibit Title
2.1	Formation Agreement, dated October 6, 2010, by and among Marathon Petroleum Company LP, Speedway SuperAmerica LLC and Northern Tier Investors, LLC (Incorporated by reference to Exhibit 2.1 to the Registration Statement on Form S-1, File No. 333-178457, filed on December 13, 2011).
2.2	St. Paul Park Refining Co. LLC Contribution Agreement, dated October 6, 2010, by and among Marathon Petroleum Company LP, St. Paul Park Refining Co. LLC and Northern Tier Investors, LLC (Incorporated by reference to Exhibit 2.2 to the Registration Statement on Form S-1, File No. 333-178457, filed on December 13, 2011).
2.3	Northern Tier Retail LLC Contribution Agreement, dated October 6, 2010, by and among Speedway SuperAmerica LLC, Northern Tier Retail LLC and Northern Tier Investors, LLC (Incorporated by reference to Exhibit 2.3 to the Registration Statement on Form S-1, File No. 333-178457, filed on December 13, 2011).
2.4	Northern Tier Bakery LLC Contribution Agreement, dated October 6, 2010, by and among Speedway SuperAmerica LLC, SuperMom’s LLC, Northern Tier Retail LLC and Northern Tier Investors, LLC (Incorporated by reference to Exhibit 2.4 to the Registration Statement on Form S-1, File No. 333-178457, filed on December 13, 2011).
2.5	Agreement and Plan of Merger dated as of December 21, 2015, by and among Western Refining, Inc., Western Acquisition Co, LLC, Northern Tier Energy LP and Northern Tier Energy GP LLC (Incorporated by reference to Exhibit 2.1 to our Current Report on Form 8-K, File No. 001-35612, filed on December 23, 2015).
3.1	Certificate of Limited Partnership of Northern Tier Energy LP (Incorporated by reference to Exhibit 3.1 to the Registration Statement on Form S-1, File No. 333-178457, filed on July 2, 2012).
3.2	First Amended and Restated Agreement of Limited Partnership of Northern Tier Energy LP, dated July 31, 2012 (Incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K, File No. 001-35612, filed on August 2, 2012).
3.3	Third Amended and Restated Limited Liability Company Agreement of Northern Tier Energy GP LLC, dated November 12, 2013. (Incorporated by reference to Exhibit 3.3 to our Annual Report on Form 10-K, File No. 001-35612, filed on February 27, 2014).
4.1	Indenture, dated as of November 8, 2012, by and among Northern Tier Energy LLC, Northern Tier Finance Corporation, Northern Tier Energy LP, the subsidiary guarantors parties thereto and Deutsche Bank Trust Company Americas (Incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K, File No. 001-35612, filed on November 13, 2012).

147

Number	Exhibit Title
4.2	Supplemental Indenture, dated as of November 2, 2012, by and among Northern Tier Energy LLC, Northern Tier Finance Corporation, the subsidiary guarantors party thereto and Deutsche Bank Trust Company Americas, as trustee and collateral agent (Incorporated by reference Exhibit 4.1 to our Current Report on Form 8-K, File No. 001-35612, filed on November 6, 2012).
4.3	Registration Rights Agreement, dated as of November 8, 2012, by and among Northern Tier Energy LLC, Northern Tier Finance Corporation, Northern Tier Energy LP, the subsidiary guarantors parties thereto and Deutsche Bank Trust Company Americas (Incorporated by reference to Exhibit 4.2 to our Current Report on Form 8-K, File No. 001-35612, filed on November 13, 2012).
4.4	Supplemental Indenture, dated November 2, 2012, by and among Northern Tier Energy LLC, Northern Tier Finance Corporation, the guarantors party thereto and Deutsche Bank Trust Company Americas, as trustee (Incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K, File No. 001-35612, filed on October 3, 2014).
4.5	Registration Rights Agreement, dated September 29, 2014, by and among Northern Tier Energy LLC, Northern Tier Finance Corporation, the guarantors party thereto and Deutsche Bank Trust Company Americas, as trustee (Incorporated by reference to Exhibit 4.2 to our Current Report on Form 8-K, File No. 001-35612, filed on October 3, 2014).
10.1	Transaction Agreement, dated July 25, 2012 by and among Northern Tier Holdings LLC, Northern Tier Energy GP LLC, Northern Tier Energy LLC, Northern Tier Energy Holdings LLC, Northern Tier Retail Holdings LLC and Northern Tier Energy LP (Incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K, File No. 001-35612, filed on July 30, 2012).
10.2	Amended and Restated Registration Rights Agreement, dated July 31, 2012, by and among TPG Refining, L.P., ACON Refining Partners, L.L.C., NTI Management Company, L.P., NTR Partners LLC, NTR Partners II LLC, Northern Tier Investors, LLC, Northern Tier Holdings LLC and Northern Tier Energy LP (Incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K, File No. 001-35612, filed on August 2, 2012).
10.3	Credit Agreement, dated December 1, 2010, by and among the financial institutions party thereto, J.P. Morgan Chase Bank, N.A., Bank of America, N.A., Macquarie Capital (USA) Inc., Royal Bank of Canada and SunTrust Bank, St. Paul Park Refining Co. LLC, Northern Tier Bakery LLC, Northern Tier Retail LLC, SuperAmerica Franchising LLC, Northern Tier Energy LLC and each other subsidiary of Northern Tier Energy LLC from time to time party thereto (Incorporated by reference to Exhibit 10.5 to the Registration Statement on Form S-1, File No. 333-178457, filed on December 13, 2011).
10.4†	Employment Agreement between Northern Tier Energy LLC and Hank Kuchta (Incorporated by reference to Exhibit 10.7 to the Registration Statement on Form S-1, File No. 333-178457, filed on December 13, 2011).
10.5†	Retention Letter between Northern Tier Energy LLC and Dave Bonczek, dated December 20, 2013 (Incorporated by reference to Exhibit 10.1 to our current report on Form 8-K, File No. 001-35612, filed on December 26, 2013).
10.6†	Northern Tier Energy LP 2012 Long-Term Incentive Plan (Incorporated by reference Exhibit 10.2 to our Current Report on Form 8-K, File No. 001-35612, filed on July 30, 2012).
10.7††	Amended and Restated Crude Oil Supply Agreement dated March 29, 2012, by and between J.P. Morgan Commodities Canada Corporation and St. Paul Park Refining Co. LLC. (Incorporated by reference to Exhibit 10.9 to Northern Tier Energy LLC’s Registration Statement on Form S-4, File No. 333-178458, filed on April 20, 2012).
10.8	First Amendment to the Credit Agreement, dated as of July 17, 2012, by and among the financial institutions party thereto, as the lenders, J.P. Morgan Chase Bank, N.A., as administrative agent and collateral agent, Bank of America, N.A., as syndication agent, and Macquarie Capital (USA) Inc. and SunTrust Bank, as co-documentation agents, and Northern Tier Energy LLC and certain subsidiaries of Northern Tier Energy LLC party thereto (Incorporated by reference to Exhibit 10.13 to the Registration Statement on Form S-1, File No. 333-178457, filed on July 18, 2012).
10.9†	Form of Restricted Unit Agreement (Incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K, File No. 001-35612, filed on December 17, 2012).
10.10†	Form of 2012 Long Term Incentive Plan Restricted Unit Agreement (Performance-Based) (Incorporated by reference to Exhibit 10.14 to our Annual Report on Form 10-K, File No. 001-35612, filed on February 27, 2014).
10.11†	Form of Time-Based Phantom Unit Award Agreement (Incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K, File No. 001-35612, filed on May 2, 2014).
10.12†	2014 Incentive Compensation Plan (Incorporated by reference to Exhibit 10.2 to our Current Report on Form 8-K, File No. 001-35612, filed on May 2, 2014).
10.13†	Change in Control Severance Agreement between Northern Tier Energy LLC and David L. Lamp, effective March 1, 2014 (Incorporated by reference to Exhibit 10.1 to our Quarterly Report on Form 10-Q, File No. 001-35612, filed on May 7, 2014).

148

Number	Exhibit Title
10.14†	Restricted Unit Agreement (Time-Based) between Northern Tier Energy LP and David L. Lamp, effective March 1, 2014 (Incorporated by reference to Exhibit 10.2 to our Quarterly Report on Form 10-Q, File No. 001-35612, filed on May 7, 2014).
10.15†	Employment Letter Agreement, dated August 4, 2014, by and between Northern Tier Energy LLC and David Bonczek (Incorporated by reference to Exhibit 10.1 to our Quarterly Report on Form 10-Q, File No. 001-35612, filed on August 5, 2014).
10.16	Credit Agreement, dated September 29, 2014, by and among Northern Tier Energy LLC, each subsidiary of Northern Tier Energy LLC party thereto, the lenders party thereto, the issuing banks party thereto and JPMorgan Chase Bank, N.A., as administrative agent (Incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K, File No. 001-35612, filed on October 3, 2014).
10.17	Shared Services Agreement by and among Northern Tier Energy LLC and Western Refining Southwest, Inc. and Western Refining Company, L.P., dated October 30, 2014 (Incorporated by reference to Exhibit 10.2 to our Quarterly Report on Form 10-Q, File No. 001-35612, filed on November 4, 2014).
10.18†	Northern Tier 2015 Performance Bonus Program (Incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K, File No. 001-35612, filed on December 8, 2014).
10.19†	Form of Performance-Based Phantom Unit Agreement (Incorporated by reference to Exhibit 10.2 to our Current Report on Form 8-K, File No. 001-35612, filed on December 8, 2014).
10.20†	Form of Employment Agreement for Executive Officers (Incorporated by reference to Exhibit 10.1 to our Quarterly Report on Form 10-Q, File No. 001-35612, filed on May 6, 2015).
10.21†	Form of Indemnification Agreement for Executive Officers (Incorporated by reference to Exhibit 10.2 to our Current Report on Form 8-K, File No. 001-35612, filed on January 26, 2015).
10.22	Joinder Agreement (Shared Services) by and among Northern Tier Energy LLC, Western Refining Southwest, Inc., Western Refining Company, L.P. and Western Refining Logistics, LP (Incorporated by reference to Exhibit 10.3 to our Quarterly Report on Form 10-Q, File No. 001-35612, filed on May 6, 2015).
10.23	Contribution, Conveyance and Assumption Agreement dated as of September 7, 2016, by and among Western Refining, Inc., St. Paul Park Refining Co. LLC, Western Refining Logistics, GP, LLC and Western Refining Logistics, LP (incorporated by reference to Exhibit 2.1 to the Company's Current Report on Form 8-K, filed with the SEC on September 7, 2016).
10.24	Terminalling, Transportation and Storage Services Agreement, dated September 15, 2016, by and between St. Paul Park Refining Co. LLC and Western Refining Terminals, LLC (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K, filed with the SEC on September 20, 2016).
31.2*	Certification Statement of Chief Financial Officer of the Company pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.2**	Certification Statement of Chief Financial Officer of the Company pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101*	Interactive Data Files.

_______________________________________

*	Filed herewith.
**	Furnished herewith.
***	Reports filed by the Company under the Securities Exchange Act of 1934, as amended (including Form 10-K, Form 10-Q and Form 8-K), are filed under File No. 001-35612.
†	Management contract or compensatory plan or arrangement.
††	The SEC has granted confidential treatment for certain portions of this Exhibit pursuant to a confidential treatment order. Such portions have been omitted and filed separately with the SEC.

Item 16. Form 10-K Summary

None.

149

SIGNATURES

WESTERN REFINING, INC.

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

Signature	Title	Date
/s/ Jeff A. Stevens	Chief Executive Officer and	March 1, 2017
Jeff A. Stevens	President

________________________________________________________________________________________________________________________

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature	Title	Date
/s/ Jeff A. Stevens	Chief Executive Officer, President and Director	March 1, 2017
Jeff A. Stevens	(Principal Executive Officer)
/s/ Karen B. Davis	Chief Financial Officer	March 1, 2017
Karen B. Davis	(Principal Financial Officer and Principal Accounting Officer)
/s/ Paul L. Foster	Executive Chairman and Director	March 1, 2017
Paul L. Foster
/s/ Scott D. Weaver	Director	March 1, 2017
Scott D. Weaver
/s/ Sigmund L. Cornelius	Director	March 1, 2017
Sigmund L. Cornelius
/s/ L. Frederick Francis	Director	March 1, 2017
L. Frederick Francis
/s/ Robert J. Hassler	Director	March 1, 2017
Robert J. Hassler
/s/ Brian J. Hogan	Director	March 1, 2017
Brian J. Hogan

150

NORTHERN TIER ENERGY, LP

BY: NORTHERN TIER ENERGY GP, LLC

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

Northern Tier Energy LP
By:	Northern Tier Energy GP LLC,
	its general partner

By:	/s/ Jeff A. Stevens
Name:	Jeff A. Stevens
Title:	President and Chief Executive Officer of Northern Tier Energy GP LLC (Principal Executive Officer)

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the registrant and in the capacities and on the dates indicated:

Signature	Title	Date
/s/ Jeff A. Stevens	Director and Chief Executive Officer of Northern Tier Energy GP LLC (Principal Executive Officer)	March 1, 2017
Jeff A. Stevens
/s/ Karen B. Davis	Executive Vice President and Chief Financial Officer of Northern Tier Energy GP LLC (Principal Financial Officer and Principal Accounting Officer)	March 1, 2017
Karen B. Davis
/s/ Paul L. Foster	Director and Chairman of Northern Tier Energy GP LLC	March 1, 2017
Paul L. Foster
/s/ Lowry Barfield	Director of Northern Tier Energy GP LLC	March 1, 2017
Lowry Barfield
/s/ Scott Weaver	Director of Northern Tier Energy GP LLC	March 1, 2017
Scott Weaver

151

NORTHERN TIER ENERGY LP

Index to Financial Statements

Report of Independent Registered Accounting Firm	153
Consolidated Balance Sheets	154
Consolidated Statements of Operations and Comprehensive Income	155
Consolidated Statements of Cash Flows	156
Consolidated Statements of Partners’ Capital	157
Notes to Consolidated Financial Statements	158

152

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors, General Partner and Unitholder of

Northern Tier Energy LP

Tempe, Arizona

We have audited the accompanying consolidated balance sheets of Northern Tier Energy LP and subsidiaries (the "Company") as of December 31, 2016 and 2015, and the related consolidated statements of operations and comprehensive income, partners’ capital, and cash flows for each of the three years in the period ended December 31, 2016. 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 Northern Tier Energy LP and subsidiaries at December 31, 2016 and 2015, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2016, in conformity with accounting principles generally accepted in the United States of America.

/s/ Deloitte & Touche LLP

Minneapolis, Minnesota

March 1, 2017

153

PART I

Item 1. Financial Statements and Supplementary Data.

NORTHERN TIER ENERGY LP

CONSOLIDATED BALANCE SHEETS

(in millions, except unit data)

	December 31, 2016			December 31, 2015
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	29.5		$	70.9
Accounts receivable, net	246.4			186.0
Inventories	333.7			241.2
Other current assets	23.3			21.3
Total current assets	632.9			519.4
NON-CURRENT ASSETS
Equity method investments	87.3			82.1
Property, plant and equipment, net	517.8			487.8
Intangible assets	33.8			33.8
Other assets	19.5			14.2
Total Assets	$	1,291.3		$	1,137.3
LIABILITIES AND EQUITY
CURRENT LIABILITIES
Accounts payable	$	393.3		$	301.4
Accrued liabilities	54.6			61.8
Total current liabilities	447.9			363.2
NON-CURRENT LIABILITIES
Long-term debt	344.0			342.0
Lease financing obligation	9.2			11.1
Other liabilities	28.6			27.9
Total liabilities	829.7			744.2
Commitments and contingencies	—			—
EQUITY
Partners' capital (92,947,533 and 92,833,486 units issued and outstanding at December 31, 2016 and 2015, respectively)	461.7			392.9
Accumulated other comprehensive income (loss)	(0.1		)	0.2
Total equity	461.6			393.1
Total Liabilities and Equity	$	1,291.3		$	1,137.3

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

154

NORTHERN TIER ENERGY LP

CONSOLIDATED STATEMENTS OF OPERATIONS

AND COMPREHENSIVE INCOME

(in millions)

	For the year ended December 31,
	2016			2015			2014
REVENUE (a)	$	2,888.6		$	3,405.0		$	5,556.0
COSTS, EXPENSES AND OTHER
Cost of sales (a)	2,311.6			2,613.5			4,835.9
Direct operating expenses	314.3			297.8			288.8
Turnaround and related expenses	45.8			10.6			14.9
Depreciation and amortization	46.5			44.0			41.9
Selling, general and administrative expenses	82.5			82.9			87.8
Reorganization and related costs	—			—			12.9
Merger-related expenses	4.7			2.5			—
Income from equity method investments	(21.9		)	(14.8		)	(2.2		)
Other (income) loss, net	(0.5		)	0.4			0.7
OPERATING INCOME	105.6			368.1			275.3
Interest expense, net	(24.8		)	(28.7		)	(26.6		)
INCOME BEFORE INCOME TAXES	80.8			339.4			248.7
Income tax provision	(4.3		)	(8.4		)	(7.1		)
NET INCOME	76.5			331.0			241.6
Other comprehensive income (loss), net of tax:
Post-employment benefit plans gain (loss)	(0.3		)	3.4			(1.2		)
COMPREHENSIVE INCOME	$	76.2		$	334.4		$	240.4
SUPPLEMENTAL INFORMATION:
(a) Excise taxes included in revenue and cost of sales	$	432.2		$	402.9		$	396.4

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

155

NORTHERN TIER ENERGY LP

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)

	For the year ended December 31,
	2016			2015			2014
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	76.5		$	331.0		$	241.6
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	46.5			44.0			41.9
Non-cash interest expense	2.0			2.0			2.8
Equity-based compensation expense	13.6			10.3			14.0
Deferred income tax (benefit) expense	(1.8		)	2.8			2.6
Loss (gain) from the change in fair value of outstanding derivatives	(7.8		)	4.7			2.8
Equity investment earnings, net of dividends	(5.3		)	(1.7		)	—
Change in lower of cost or market inventory adjustment	(92.7		)	60.8			73.6
Changes in assets and liabilities, net:
Accounts receivable	(60.4		)	48.9			6.0
Inventories	(0.4		)	(49.9		)	(152.3		)
Other current assets	3.1			(7.3		)	9.8
Accounts payable and accrued expenses	91.5			(39.2		)	(28.5		)
Other, net	(9.2		)	0.7			5.3
Net cash provided by operating activities	55.6			407.1			219.6
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures	(127.9		)	(71.8		)	(44.8		)
Increase in restricted cash	(195.0		)	—			—
Decrease in restricted cash	195.0			—			—
Return of capital from investments	—			—			5.3
Net cash used in investing activities	(127.9		)	(71.8		)	(39.5		)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from senior secured notes	—			—			79.2
Borrowings from revolving credit arrangement	412.5			—			30.0
Repayments of revolving credit arrangement	(412.5		)	—			(30.0		)
Proceeds from sale to entity under common control	195.0			—			—
Financing costs	—			—			(5.4		)
Equity distributions	(164.1		)	(352.3		)	(251.8		)
Net cash provided by (used in) financing activities	30.9			(352.3		)	(178.0		)
CASH AND CASH EQUIVALENTS
Change in cash and cash equivalents	(41.4		)	(17.0		)	2.1
Cash and cash equivalents at beginning of period	70.9			87.9			85.8
Cash and cash equivalents at end of period	$	29.5		$	70.9		$	87.9

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

156

NORTHERN TIER ENERGY LP

CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL

(in millions, except unit and per unit data)

	Partners' Capital				Accumulated Other Comprehensive Income (Loss)
	Common Units	Value						Total
Balance at December 31, 2013	92,100,363	$	403.1		$	(2.0	)	$	401.1
Net income	—	241.6			—			241.6
Distributions to limited partners ($2.71 per unit)	—	(251.8		)	—			(251.8		)
Other comprehensive loss	—	—			(1.2		)	(1.2		)
Equity-based compensation, net of forfeitures	612,381	14.0			—			14.0
Balance at December 31, 2014	92,712,744	406.9			(3.2		)	403.7
Net income	—	331.0			—			331.0
Distributions to limited partners ($3.80 per unit)	—	(355.3		)	—			(355.3		)
Other comprehensive income	—	—			3.4			3.4
Equity-based compensation, net of forfeitures	120,742	10.3			—			10.3
Balance at December 31, 2015	92,833,486	392.9			0.2			393.1
Net income	—	76.5			—			76.5
Distributions to limited partners ($1.74 per unit)	—	(163.6		)	—			(163.6		)
Asset sale to entity under common control	—	146.3			—			146.3
Other comprehensive loss	—	—			(0.3		)	(0.3		)
Equity-based compensation, net of forfeitures	114,047	12.5			—			12.5
Other	—	(2.9		)	—			(2.9		)
Balance at December 31, 2016	92,947,533	$	461.7		$	(0.1	)	$	461.6

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

157

NORTHERN TIER ENERGY LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. DESCRIPTION OF THE BUSINESS AND BASIS OF PRESENTATION

Description of the Business

Northern Tier Energy LP ("NTE LP", "NTI", "Northern Tier" or the "Company") is a wholly-owned subsidiary of Western Refining, Inc. ("Western") operating as a downstream energy company with refining, retail and logistics operations that serve the Petroleum Administration for Defense District II ("PADD II") region of the United States. NTE LP holds 100% of the membership interest in Northern Tier Energy LLC ("NTE LLC").

NTE LP includes the operations of NTE LLC, St. Paul Park Refining Co. LLC ("SPPR"), Northern Tier Retail Holdings LLC ("NTRH") and Northern Tier Oil Transport LLC ("NTOT"). NTRH is the parent company of Northern Tier Retail LLC ("NTR") and Northern Tier Bakery LLC ("NTB"). NTR is the parent company of SuperAmerica Franchising LLC ("SAF"). NTRH has elected to be treated as a corporation for income tax purposes in order to preserve the limited partnership tax status of NTE LP. SPPR owns a 17% interest in MPL Investments Inc. ("MPLI"), a 17% interest in Minnesota Pipe Line Company, LLC (“MPL”) and a 1.0% interest in Western Refining Logistics, LP ("WNRL"). MPL Investments owns 100% of the preferred interest in MPL, which owns and operates a 465,000 barrel per day (“bpd”) crude oil pipeline in Minnesota (see Note 6). NTOT is a crude oil trucking business in North Dakota that collects crude oil directly from wellheads in the Bakken shale and transports it to regional pipeline and rail facilities.

Western indirectly owns 100% of both Northern Tier Energy GP LLC ("NTE GP") and NTE LP. Western, through its subsidiary NT InterHold Co LLC, a Delaware limited liability company ("NT InterHold Co") as the owner of the general partner of NTE LP, has the ability to appoint all of the members of the NTE GP's board of directors.

On December 21, 2015, Western and NTE LP announced that they had entered into an Agreement and Plan of Merger dated as of December 21, 2015 ("the Merger Agreement"), with NTE GP and Western Acquisition Co, LLC, a Delaware limited liability company and wholly-owned subsidiary of Western ("MergerCo") whereby Western would acquire all of Northern Tier's outstanding common units not already owned by Western (the "Merger").

Based upon the consideration elections made by NTI common unitholders, this cash and Western common stock was allocated among NTI common unitholders as follows:

• NTI common unitholders who made a valid "Mixed Election" (as defined in the Merger Agreement), or who made no election, received $15.00 in cash and 0.2986 of a share of Western common stock for each such NTI common unit held.

• NTI common unitholders who made a valid "Cash Election" (as defined in the Merger Agreement) received $15.357 in cash and 0.28896 of a share of Western common stock as prorated in accordance with the Merger Agreement for each such NTI common unit held.

• NTI common unitholders who made a valid "Stock Election" (as defined in the Merger Agreement) received 0.7036 of a share of Western common stock for each such NTI common unit held.

On June 23, 2016, following the approval of the Merger by NTI common unitholders, all closing conditions to the Merger were satisfied, and the Merger was successfully completed. The transaction resulted in approximately 17.1 million additional shares of WNR common stock outstanding. Subsequent to this transaction, NTI continues to exist as a limited partnership and became an indirect wholly-owned subsidiary of Western (see Note 20).

Refining Business

As of December 31, 2016, the St. Paul Park refinery owned by SPPR, which is located in St. Paul Park, Minnesota, had total crude oil throughput capacity of 102,000 barrels per stream day. 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 primarily in the Upper Great Plains of the United States.

On September 7, 2016, SPPR entered into a Contribution, Conveyance and Assumption Agreement (the "Contribution Agreement") by and among Western, SPPR, WNRL and Western Refining Logistics GP, LLC, the general partner of WNRL. Pursuant to the terms of the Contribution Agreement, SPPR sold certain tank, terminal, rack, transportation facilities and other logistics assets to WNRL in exchange for $195 million cash and 628,224 common units representing limited partner interests in WNRL. Concurrent with the Contribution Agreement, SPPR and WNRL entered into a terminalling, transportation and storage

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services agreement with an initial term of ten years whereby SPPR will pay fees to WNRL for storage, product throughput and blending services. See Note 3 for further discussion of this transaction.

Retail Business

As of December 31, 2016, NTR operated 170 convenience stores under the SuperAmerica brand and SAF supported 115 franchised stores which also utilize the SuperAmerica brand. These 285 SuperAmerica stores are primarily located in Minnesota and Wisconsin and sell gasoline, merchandise and, in some locations, diesel fuel. There is a wide range of merchandise sold at the stores including prepared foods, beverages and non-food items. The merchandise sold includes a significant number of proprietary items. NTB prepares and distributes food products under the SuperMom's brand primarily to SuperAmerica branded retail outlets.

Basis of Presentation

The accompanying consolidated financial statements have been prepared in accordance with U.S. generally accepted accounting principles ("GAAP") for interim financial information.

2. SUMMARY OF PRINCIPAL ACCOUNTING POLICIES

Principles of Consolidation

NTE LP is a Delaware limited partnership which consolidates all accounts of NTE LLC and its subsidiaries, including SPPR, NTRH and NTOT. All intercompany accounts have been eliminated in these consolidated financial statements.

The Company’s common equity interests in MPL and WNRL are accounted for using the equity method of accounting. Although SPPR owns only 1.0% of WNRL's common equity, its indirect parent company, Western, owns 52.6%. Because of Western’s controlling influence over WNRL, the investment provides the Company significant influence over WNRL and the Company accounts for its ownership interest in WNRL under the equity method. Equity income from MPL and WNRL represent the Company’s proportionate share of net income available to common equity owners generated by MPL and WNRL. See Note 3for further discussion of the Company's ownership interests in MPL and WNRL.

The equity method investments are 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 operating income. See Note 6 for further information on the Company’s equity method investment.

MPLI owns all of the preferred membership units of MPL. This investment in MPLI, which provides the Company no significant influence over MPLI, is accounted for as a cost method investment. The investment in MPLI is carried at a value of $6.8 million at both December 31, 2016 and 2015, and is included in other noncurrent assets within the consolidated balance sheets.

Use of Estimates

The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities as of the date of the consolidated financial statements and the reported amounts of revenues and expenses during the respective reporting periods. Actual results could differ from those estimates.

Operating Segments

The Company has two reportable operating segments; Refining and Retail (see Note19 for further information on the Company’s operating segments). The Refining and Retail operating segments consist of the following:

• Refining – operates the St. Paul Park, Minnesota refinery, NTOT and includes the Company's interest in MPL and MPLI, and

• Retail – comprised 170 Company-operated convenience stores and 115 franchisee operated convenience stores as of December 31, 2016, primarily in Minnesota and Wisconsin. The retail segment also includes the operation of NTB.

Cash and Cash Equivalents

The Company considers all highly liquid investments with maturities of three months or less from the date of purchase to be cash equivalents.

Receivables and Allowance for Doubtful Accounts

Receivables of the Company primarily consist of customer accounts receivable. The accounts receivable are due from a diverse base including companies in the petroleum industry, airlines and governmental entities. The allowance for doubtful accounts is reviewed regularly for collectability. All customer receivables are recorded at the invoiced amounts and generally do not bear

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interest. When it becomes probable the receivable will not be collected, the balances for customer receivables are charged directly to bad debt expense. The allowance for doubtful accounts was zero at both December 31, 2016 and 2015.

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. Ending inventory costs in excess of market value are written down to net realizable market values and charged to cost of sales in the period recorded. In subsequent periods, a new LCM determination is made based upon current circumstances relative to, and not to exceed, the original LCM reserve that was established in fourth quarter 2014. However, in no case would the LCM reserve be reversed beyond zero. The Company has LIFO pools for crude oil and other feedstocks and for refined products in its Refining segment and a LIFO pool for refined products inventory held by the retail stores in its Retail segment. Retail merchandise inventory is valued using the average cost method.

Property, Plant and Equipment

Property, plant and equipment is recorded at cost and depreciated on a straight-line basis over the estimated useful lives of the assets. Such assets or asset groups are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If the sum of the expected undiscounted future cash flows from the use of the asset and its eventual disposition is less than the carrying amount of the asset, an impairment loss is recognized based on the fair value of the asset. The amortization of capital lease assets is presented in depreciation and amortization.

When property, plant and equipment depreciated on an individual basis is sold or otherwise disposed of, any gains or losses are reported in the consolidated statements of operations and comprehensive income. Gains on the disposal of property, plant and equipment are recognized when earned, which is generally at the time of sale. If a loss on disposal is expected, such losses are generally recognized when the assets are classified as held for sale.

Expenditures for routine maintenance and repair costs are expensed when incurred. Refinery process units require periodic major maintenance and repairs that are commonly referred to as "turnarounds." Turnaround cycles vary from unit to unit but can be as short as one year for catalyst changes to as long as six years. Turnaround costs are expensed as incurred.

Derivative Financial Instruments

The Company is exposed to earnings and cash flow volatility due to fluctuations in crude oil, refined products, and natural gas prices. The timing of certain commodity purchases and sales also subject the Company to earnings and cash flow volatility. To manage these risks, the Company may use derivative instruments associated with the purchase or sale of crude oil, refined products, and natural gas to hedge volatility in our refining and operating margins. The Company may use futures, options, and swaps contracts to manage price risks associated with inventory quantities above or below target levels. Crack spread and crude differential futures and swaps contracts may also be used to hedge the volatility of refining margins.

All derivative instruments, except for those that meet the normal purchases and normal sales exception, are recorded in the consolidated balance sheets at fair value and are classified depending on the maturity date of the underlying contracts. Changes in the fair value of the Company's contracts are accounted for by marking them to market and recognizing any resulting gains or losses in the consolidated statements of operations and comprehensive income. Gains and losses from derivative activity specific to managing price risk on inventory quantities both above and below target levels are included within cost of sales. Derivative gains and losses are reported as operating activities within the consolidated statements of cash flows.

The Company enters into crude oil forward contracts to facilitate the supply of crude oil to the refinery. These contracts may qualify for the normal purchases and normal sales exception because the Company physically receives and delivers the crude oil under the contracts and when the Company enters into these contracts, the quantities are expected to be used or sold over a reasonable period of time in the normal course of business. These transactions are reflected in the period that delivery of the crude oil takes place. When forward contracts do not qualify for the normal purchases and sales exception, the contracts are marked to market each period through the settlement date, which is generally no longer than one to three months.

Intangible Assets

Intangible assets primarily include a retail marketing trade name and franchise agreements. These assets have an indefinite life and therefore are not amortized, but rather are tested for impairment annually or when events or changes in circumstances indicate that the fair value of the intangible asset has been reduced below carrying value. If the estimated fair value is less than the carrying amount of the asset, an impairment loss is recognized based on the estimated fair value of the asset. Significant assumptions in determining the estimated fair value of the indefinite lived intangibles include projected store growth, estimated market royalty rates, market growth rates and the estimated discount rate.

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Renewable Identification Numbers

The Company is subject to obligations to generate or purchase Renewable Identification Numbers ("RINs") required to comply with the Renewable Fuels Standard. The Company's overall RINs obligation is based on a percentage of domestic shipments of on-road fuels as established by the Environmental Protection Agency ("EPA"). To the degree the Company is unable to blend the required amount of biofuels to satisfy its RINs obligation, RINs must be purchased on the open market to avoid penalties and fines. The Company records its RINs obligation on a net basis in accrued liabilities when its RINs liability is greater than the amount of RINs earned and purchased in a given period and in other current assets when the amount of RINs earned and purchased is greater than the RINs liability.

Future changes to existing laws and regulations could increase the minimum volumes of renewable fuels that must be blended with refined petroleum fuels. Because the Company does not produce renewable fuels, increasing the volume of renewable fuels that must be blended into its products could displace an increasing volume of the Company's refineries' product pool, potentially resulting in lower earnings and materially adversely affecting our ability to issue dividends to the Company's unitholders. 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 upon the Company's operating results.

Financing Costs

Financing origination fees on the Company's senior secured notes and ABL Facility are deferred and classified within long-term debt on the consolidated balance sheets. Additionally, financing origination fees on the Company's sales-leaseback transaction covering a majority of its retail stores were also deferred and are classified within other assets on the consolidated balance sheets. Amortization on these deferred costs are provided on a straight-line basis over the term of the agreement, which approximates the effective interest method.

Revenue Recognition

Revenues are recognized when products are shipped or services are provided to customers, title is transferred, the sales price is fixed or determinable and collectability is reasonably assured. Revenues are recorded net of discounts granted to customers. Shipping and other transportation costs billed to customers are presented on a gross basis in revenues and cost of sales.

Prior to October 1, 2014, the Company maintained a crude oil supply and logistics agreement with J.P. Morgan Commodities Canada Corporation ("JPM CCC") pursuant to which JPM CCC assisted the Company in the purchase of substantially all of its crude oil needs for the refinery. As discussed in Note 5, JPM CCC and the Company mutually agreed to terminate this agreement. In the fourth quarter of 2014, subsequent to the termination of this agreement, the Company significantly increased its crude procurement activities and related exchange and buy/sell activity to manage the volumes, grade, timing, and locations of such crude. Such activities are similar to the buy/sell crude oil transactions noted above and are recorded net in cost of sales.

Nonmonetary product exchanges and certain buy/sell crude oil transactions, which are entered into in contemplation one with another, are included on a net cost basis in cost of sales. The Company also enters into agreements to purchase and sell crude oil to third parties and certain of these activities are recorded on a gross basis.

Product Exchanges

The Company enters into exchange contracts whereby it agrees to deliver a particular quantity and quality of crude oil or refined products at a specified location and date to a particular counterparty and to receive from the same counterparty a particular quantity and quality of crude oil or refined products at a specified location on the same or another specified date. The exchange receipts and deliveries are nonmonetary transactions, with the exception of associated grade or location differentials that are settled in cash. These transactions are recorded net in cost of sales because they involve the exchange of inventories held in the ordinary course of business to facilitate sales to customers or delivery of feedstocks to our refinery. The exchange transactions are recognized at the carrying amount of the inventory transferred plus or minus any cash settlement due to grade or location differentials.

Cost of Sales

Cost of sales in the consolidated statements of operations and comprehensive income excludes depreciation and amortization of refinery assets and the direct labor and overhead costs related to the operation of the refinery. These costs are included in the consolidated statements of operations and comprehensive income in the depreciation and amortization and direct operating expenses line items, respectively.

Excise Taxes

The Company is required by various governmental authorities, including federal and state, to collect and remit taxes on certain products. Such taxes are presented on a gross basis in revenue and cost of sales in the consolidated statements of operations and comprehensive income. These taxes totaled $432.2 million, $402.9 million and $396.4 million for the years ended December 31, 2016, 2015 and 2014, respectively.

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Advertising

The Company expenses the costs of advertising as incurred. Advertising expense was $2.9 million, $2.9 million and $2.3 million for the years ended December 31, 2016, 2015 and 2014, respectively.

Asset Retirement Obligations

The fair value of asset retirement obligations is recognized in the period in which the obligations are incurred if a reasonable estimate of fair value can be made. Conditional asset retirement obligations for removal and disposal of fire-retardant material from certain refining assets have been recognized. The amounts recorded for such obligations are based on the most probable current cost projections. Asset retirement obligations have not been recognized for the removal of materials and equipment from or the closure of certain refinery, pipeline, terminal and retail marketing assets because the fair value cannot be reasonably estimated since the settlement dates of the obligations are indeterminable. Current inflation rates and credit-adjusted-risk-free interest rates are used to estimate the fair value of asset retirement obligations. Depreciation of capitalized asset retirement costs and accretion of asset retirement obligations are recorded over time. Depreciation is determined on a straight-line basis, while accretion escalates over the lives of the assets. See further information on our asset retirement obligations in Note 13.

Environmental Costs

Environmental expenditures are capitalized if the costs mitigate or prevent future contamination or if the costs improve environmental safety or efficiency of the existing assets. The Company provides for remediation costs and penalties when the responsibility to remediate is probable and the amount of associated costs can be reasonably estimated. The timing of remediation accruals coincides with completion of feasibility studies, investigations or the commitment to a formal plan of action. 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. Remediation liabilities are accrued based on estimates of known environmental exposure and are discounted when the estimated amounts are reasonably fixed and determinable. If recoveries of remediation costs from third parties are probable, a receivable is recorded and is discounted to net present value when the estimated amount is reasonably fixed and determinable.

Defined Benefit Plans

The Company has a cash balance plan and a retiree medical plan that are considered defined benefit plans. Expenses and liabilities related to defined benefit plans 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.

Cash balance and retiree medical 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 could have a significant effect on our pension and retiree medical liabilities and costs. See further information on our plans in Note 15.

Equity-Based Compensation

The Company recognizes compensation expense for equity-based awards issued over the requisite service period. Equity-based compensation costs are measured at the date of grant, based on the fair value of the award. Prior to our Merger, the Company granted equity awards indexed to Northern Tier Energy, LP common units. Concurrent with the Merger, all unvested equity-based awards were converted to new awards indexed to Western Refining, Inc. common stock. Both prior to and subsequent to the Merger, the Company has awarded equity-based phantom awards which, at the discretion of the board of directors of our general partner, may be settled in either cash or common equity. All equity-based phantom awards that vested through December 31, 2016 have been settled in common equity. We anticipate that the remaining unvested phantom awards will also be satisfied with common equity and have therefore classified the accrual of the service cost as equity. However, if our general partner's board elects to settle the phantom awards with cash, it could cause us to remeasure the fair value of those awards resulting in an adjustment to earnings for the cumulative difference between the fair value at the date of grant and date of the remeasurement.

Comprehensive Income

The Company has unrecognized prior service cost related to both its defined benefit cash balance plan as of December 31, 2016, 2015 and 2014 and unrecognized actuarial losses and prior service cost related to its retiree medical plan as of December 31, 2016 and 2015 (see Note 15). The accumulated unrecognized income (loss) related to these plans amounted to $(0.1) million and $0.2 million as of December 31, 2016 and 2015, respectively. These gains/(losses) of $(0.3) million, $3.4

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million and $(1.2) million were recognized directly to equity as an element of other comprehensive income (loss) in the years ended December 31, 2016, 2015 and 2014, respectively.

Concentrations of Risk

The Company is exposed to credit risk in the event of nonpayment by customers. The creditworthiness of customers is subject to continuing review. No single non-related party customer accounts for more than 10% of annual revenues.

Crude oil is the principal raw material for the Company and the majority of the crude oil processed is delivered to the refinery through a pipeline that is owned by MPL, a related party. A prolonged disruption of that pipeline's operations would materially impact the Company's ability to economically obtain raw materials.

The Company is exposed to concentrated geographical risk as most of its operations are conducted in the Upper Great Plains of the United States.

Recent Accounting Pronouncements

In February 2016, the FASB issued ASU 2016-02 "Leases," which replaces the existing guidance in Accounting Standards Codification ("ASC") 840. This new guidance is effective for fiscal years, and interim periods within those years, beginning after December 15, 2018 with early adoption permitted. The guidance requires a dual approach for lessee accounting under which a lessee would account for leases as finance leases or operating leases. Both finance leases and operating leases will result in the lessee recognizing a right-of-use ("ROU") asset and a corresponding lease liability. For finance leases the lessee would recognize interest expense and amortization of the ROU asset and for operating leases the lessee would recognize a straight-line total lease expense. The Company is currently assessing the impact that adoption of this guidance will have on its consolidated financial statements and footnote disclosures.

In March 2016, the FASB issued ASU No. 2016-04 "Liabilities – Extinguishment of Liabilities (Subtopic 405-20): Recognition of Breakage for Certain Prepaid Stored-Value Products," which aligns recognition of the financial liabilities related to prepaid stored-value products (for example, prepaid gift cards), with Topic 606, Revenues from Contracts with Customers, for non-financial liabilities. In general, certain of these liabilities may be extinguished proportionally in earnings as redemptions occur, or when redemption is remote if issuers are not entitled to the unredeemed stored value. This guidance is effective for fiscal years, and interim periods within those years, beginning after December 15, 2017 with early adoption permitted subject to certain requirements. The Company is currently assessing the impact that adopting this new accounting standard will have on its consolidated financial statements and footnote disclosures.

In March 2016, the FASB issued ASU No. 2016-06 "Derivatives and Hedging (Topic 815) – Contingent Put and Call Options in Debt Instruments" which will reduce diversity of practice in identifying embedded derivatives in debt instruments. ASU 2016-06 clarifies that the nature of an exercise contingency is not subject to the "clearly and closely" criteria for purposes of assessing whether the call or put option must be separated from the debt instrument and accounted for separately as a derivative. This guidance is effective for fiscal years, and interim periods within those years, beginning after December 15, 2016, with early adoption permitted subject to certain requirements. The Company is currently assessing the impact that adopting this new accounting standard will have on its consolidated financial statements and footnote disclosures.

In March 2016, the FASB issued ASU No. 2016-08 "Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net)," which clarifies the implementation guidance on principal versus agent considerations. The guidance includes indicators to assist an entity in determining whether it controls a specified good or service before it is transferred to the customers. The effective date and transition requirements for the amendments in this Update are the same as the effective date and transition requirements of ASU 2014-09.

The Company has been evaluating and continues to evaluate the provisions of this standard and its impact on its business processes, business and accounting systems, and financial statements and related disclosures. A multi-disciplined implementation team has gained an understanding of the standard’s revenue recognition model, is reviewing and documenting the Company's contracts, and is analyzing whether enhancements are needed to its business and accounting systems. The Company currently plans on adopting this standard on January 1, 2018. The Company does not expect the adoption of this standard to have a material impact on its consolidated financial statements.

In March 2016, the FASB issued ASU No. 2016-09 "Compensation – Stock Compensation," which identifies areas for simplification involving several aspects of accounting for equity-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, an option to recognize gross stock compensation expense with actual forfeitures recognized as they occur, as well as certain classifications on the statement of cash flows. This guidance is effective for fiscal years, and interim periods within those years, beginning after December 15, 2016, with early adoption permitted subject to certain requirements. The Company is currently assessing the impact that adopting this new accounting standard will have on its consolidated financial statements and footnote disclosures.

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In August 2016, the FASB issued ASU No. 2016-15 "Classification of Certain Cash Receipts and Cash Payments," which provides guidance on presentation in the statement of cash flows on eight subject areas where there current GAAP either is unclear or does not include specific guidance, resulting in diversity in practice. This guidance is effective for fiscal years, and interim periods within those years, beginning after December 15, 2017 with early adoption permitted subject to certain requirements. The Company is currently assessing the impact that adopting this new accounting standard will have on its consolidated financial statements and footnote disclosures.

In November 2016, the FASB issued ASU No. 2016-18 "Statement of Cash Flows (Topic 230)," which provides guidance on presentation in the statement of cash flows for cash, cash equivalents and amounts generally described as restricted cash or restricted cash equivalents in order to address diversity in practice among entities. The Update would result in presentation of restricted cash as a component of beginning-of-the-period and end-of-the-period cash and cash equivalents within the statement of cash flows. This guidance is effective for fiscal years, and interim periods within those years, beginning after December 15, 2018 with early adoption permitted subject to certain requirements. The Company is currently assessing the impact that adopting this new accounting standard will have on its consolidated financial statements and footnote disclosures.

3. RELATED PARTY TRANSACTIONS

As of December 31, 2016, Western indirectly owns 100% of both Northern Tier Energy GP LLC ("NTE GP") and NTE LP. On December 21, 2015, Western and NTE LP announced that they had entered into the Merger Agreement with MergerCo and NTE GP whereby Western would acquire all of NTE LP's outstanding common units not already owned by Western (see Note 20). The transaction closed on June 23, 2016 (see Note 20).

On September 15, 2016, Western executed the Contribution Agreement by and among Western, SPPR, WNRL and Western Refining Logistics GP, LLC, the general partner of WNRL. Pursuant to the terms of the Contribution Agreement, SPPR has agreed to sell to WNRL approximately four million barrels of refined product and crude oil storage tanks, a light products terminal, a heavy products loading rack, certain rail and barge facilities, certain other related logistics assets, and two crude oil pipeline segments and one pipeline segment not currently in service, each of which is approximately 2.5 miles and extends from SPPR's refinery in St. Paul Park, Minnesota to SPPR's tank farm in Cottage Grove, Minnesota, in exchange for $195 million in cash and 628,224 of common units representing limited partner interests in WNRL. The Company's book value on the date of sale of the property, plant and equipment, certain assets under construction and additive inventory used in the terminal operations amounted to $48.7 million. The proceeds from this transaction, reduced by the book value of the assets sold was $146.3 million. The Company treated the transaction as a transfer of assets between entities under common control and, as such, accounted for the transfer at the historical book value of the assets as required by GAAP. We recognized the difference between the proceeds and the book value of the assets as an increase in equity.

In connection with the closing of the Contribution Agreement, SPPR entered into a terminalling, transportation and storage services agreement (the "Terminalling Agreement") with Western Refining Terminals, LLC ("WRT"), an indirect, wholly-owned subsidiary of WNRL. Pursuant to the Terminalling Agreement, WRT has agreed to provide product storage services, product throughput services and product additive and blending services at the terminal facilities located at or near SPPR's refinery in St. Paul Park, Minnesota. In exchange for such services, SPPR has agreed to certain minimum volume commitments and to pay certain fees. The Terminalling Agreement will have an initial term of ten years, which may be extended for up to two renewal terms of five years each upon the mutual agreement of the parties.

The Company has engaged in several types of transactions with Western and its subsidiaries including crude and feedstock purchases, asphalt purchases, finished product purchases, railcar leases and tank and terminal service fee. Additionally, the Company is party to a shared services agreement with Western and WNRL whereby the Company both receives and provides administrative support services. The shared services agreement was entered into with Western as of September 1, 2014, and was approved by the Conflicts Committee of the board of directors of NTE GP. On May 4, 2015, WNRL joined as a party to this agreement. The services covered by the shared services agreement include assistance with treasury, risk management and commercial operations, environmental compliance, information technology support, internal audit and legal.

MPL is also a related party of the Company. Prior to September 30, 2014, the Company had a crude oil supply and logistics agreement with a third party and therefore had no direct supply transactions with MPL prior to that date. Beginning on September 30, 2014, the Company began paying MPL for transportation services at published tariff rates. Additionally, the Company owns a 17% interest in MPL (see Note 6) and generally receives quarterly cash distributions related to this investment. The Company's Chief Executive Officer is a member of MPL's board of managers.

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In addition to the Contribution Agreement, the Company engaged in the following related party transactions with unconsolidated affiliates for the years ended December 31, 2016, 2015 and 2014:

		For the year ended December 31,
(in millions)	Location in Statement of Operations and Comprehensive Income	2016		2015		2014
Western Refining:
Asphalt sales	Revenue	$	32.0	$	46.6	$	19.0
Feedstock sales	Revenue	—		0.6		—
Railcar rental	Revenue	0.2		0.2		0.1
Crude and feedstock purchases	Cost of sales	—		—		6.3
Refined product purchases	Cost of sales	—		1.5		—
Shared services purchases	Selling, general and administrative expenses	0.6		3.6		1.1
Western Refining Logistics:
Tank and terminal service fees	Cost of sales	13.6		—		—
Shared services purchases	Selling, general and administrative expenses	0.4		—		—
Minnesota Pipe Line Company:
Pipeline transportation purchases	Cost of sales	52.2		55.4		12.6

The Company had the following outstanding receivables and payables with non-consolidated related parties at December 31, 2016 and December 31, 2015:

(in millions)	Balance Sheet Location	December 31, 2016			December 31, 2015
Net receivable (payable) with related party:
Western Refining, Inc.	Accounts receivable, net	$	3.7		$	2.8
Western Refining Logistics, LP	Accounts payable	(2.0		)	—
Minnesota Pipe Line Company	Accounts payable	(1.5		)	(2.7		)

4. INCOME TAXES

NTE LP is treated as a partnership for federal and state income tax purposes. However, NTRH, the parent company of NTR and NTB, is taxed as a corporation for federal and state income tax purposes. No provision for income tax is calculated on the earnings of the Company or its subsidiaries, other than NTRH, as these entities are pass-through entities for tax purposes.

On July 31, 2012, NTRH was established as the parent company of NTR and NTB. NTRH elected to be taxed as a corporation for federal and state income tax purposes effective August 1, 2012. Prior to that, no provision for income tax was calculated on earnings of the Company or its subsidiaries as all entities were non-taxable.

	Year Ended December 31,
(in millions)	2016		2015		2014
Current tax expense	$	2.5	$	5.6	$	4.5
Deferred tax expense	$	1.8	$	2.8	$	2.6
Income tax provision	$	4.3	$	8.4	$	7.1

The Company's effective tax rate for the years ended December 31, 2016, 2015 and 2014 was 5.3%, 2.5% and 2.9%, respectively, as compared to the Company's consolidated federal and state expected statutory tax rate of 40.4%, 41.4% and 40.4% for the years ended December 31, 2016, 2015 and 2014, respectively. The Company's effective tax rate was lower than the statutory rate for the years ended December 31, 2016, 2015 and 2014 primarily due to the fact that only the retail operations of the Company are taxable entities.

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The following is a reconciliation of income tax expense to income taxes computed by applying the applicable statutory federal income tax rate of 34% for 2016 and 35% for 2015 and 2014 to income before income taxes for the applicable periods:

	Year Ended December 31,
(in millions)	2016			2015			2014
Federal statutory rate applied to income before taxes	$	27.5		$	118.8		$	87.0
Taxes on earnings attributable to flow-through entities	(24.2		)	(112.4		)	(81.0		)
State and local income taxes, net of federal income tax effects	0.6			1.2			1.0
Work opportunity tax credit	(0.2		)	(0.4		)	(0.3		)
Other, net	0.6			1.2			0.4
Income tax provision	$	4.3		$	8.4		$	7.1

As a result of the Company's analysis, management has determined that the Company does not have any material uncertain tax positions. As of December 31, 2016 and 2015, the Company had no deferred tax assets arising from net operating losses. The Company is subject to U.S. federal and state income tax examinations for periods subsequent to 2012. The Company classifies interest to be paid on an underpayment of income taxes and any related penalties as income tax expense.

The net deferred tax assets (liabilities) as of December 31, 2016 and 2015 consisted of the following components:

		December 31,
(in millions)		2016			2015
Deferred tax assets:
	Lease financing obligations	$	2.3		$	2.2
	Customer loyalty accrual	0.6			0.4
	Annual bonus	0.4			0.5
	UNICAP	0.6			0.2
	Other	0.1			0.3
Deferred tax assets		4.0			3.6
Deferred tax liabilities:
	Accelerated depreciation	(5.2		)	(6.3		)
	Intangible assets	(12.1		)	(12.0		)
	LIFO	(0.7		)	(1.1		)
	Other	(0.3		)	(0.3		)
Deferred tax liabilities		(18.3		)	(19.7		)
Total deferred taxes, net		$	(14.3	)	$	(16.1	)

The net deferred tax assets (liabilities) are included in the December 31, 2016 and 2015 balance sheets as components of other liabilities.

5. INVENTORIES

	December 31,
(in millions)	2016			2015
Crude oil and refinery feedstocks	$	174.3		$	171.8
Refined products	160.2			162.0
Merchandise	22.1			22.8
Supplies and sundry items	18.8			19.0
	375.4			375.6
Lower of cost or market inventory reserve	(41.7		)	(134.4		)
Total	$	333.7		$	241.2

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Inventories accounted for under the LIFO method comprised 89% of the total inventory value at both December 31, 2016 and 2015, prior to the application of the lower of cost or market reserve.

In order to state the Company's inventories at market values that were lower than its LIFO costs, the Company reduced the carrying values of its inventory through LCM reserves of $41.7 million and $134.4 million at December 31, 2016 and 2015, respectively.

6. EQUITY METHOD INVESTMENT

The Company has a 17% common equity interest in MPL. Additionally, in the third quarter of 2016, the Company received a 1.0% common equity interest in WNRL in connection with the Contribution Agreement (see Note 3), which was recorded at its historical cost given the transaction was treated as a transfer of assets under common control. The carrying value of these equity method investments was $87.3 million and $82.1 million at December 31, 2016 and 2015, respectively. The quoted market value of the Company's investment in WNRL at December 31, 2016 was $13.4 million.

Summarized financial information for MPL is as follows:

	Year Ended December 31,
(in millions)	2016		2015		2014
Revenues	$	215.6	$	206.2	$	184.7
Operating costs and expenses	57.5		88.9		141.3
Income from operations	158.1		117.3		43.4
Net income	137.5		96.5		22.8
Net income available to MPL common members	127.8		86.8		13.1

			December 31,
(in millions)			2016		2015
Balance sheet data:
	Current assets		$	14.8	$	24.0
	Noncurrent assets		492.0		441.8
		Total assets	$	506.8	$	465.8
	Current liabilities		$	26.8	$	17.7
	Noncurrent liabilities		—		—
		Total liabilities	26.8		17.7
	Members capital		$	480.0	$	448.1

As of December 31, 2016 and 2015, the carrying amount of the equity method investment in MPL was $5.7 million and $5.9 million higher, respectively, than the underlying net assets of the investee. The Company is amortizing this difference over the remaining life of MPL's primary asset (the fixed asset life of the pipeline).

The Company recorded $16.6 million, $13.1 million and $7.5 million in distributions for the years ended December 31, 2016, 2015 and 2014, respectively. Equity income from the Company's equity method investments was $21.9 million, $14.8 million and $2.2 million for the years ended December 31, 2016, 2015 and 2014, respectively.

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7. PROPERTY, PLANT AND EQUIPMENT

Major classes of property, plant and equipment ("PP&E") consisted of the following:

	Estimated	December 31,
(in millions)	Useful Lives	2016			2015
Land		$	7.7		$	9.0
Retail stores and equipment	2 - 22 years	80.5			72.3
Refinery and equipment	5 - 24 years	487.0			457.2
Buildings and building improvements	25 years	18.7			11.7
Software	5 years	18.9			18.9
Vehicles	5 years	3.2			5.6
Other equipment	2 - 7 years	10.8			10.4
Precious metals		10.4			10.2
Assets under construction		78.6			73.3
		715.8			668.6
Less: Accumulated depreciation		(198.0		)	(180.8		)
Property, plant and equipment, net		$	517.8		$	487.8

PP&E includes gross assets acquired under capital leases of $10.8 million and $13.3 million at December 31, 2016 and 2015, respectively, with related accumulated depreciation of $2.3 million and $2.0 million, respectively. The Company had depreciation expense related to capitalized software of $2.9 million, $3.7 million and $3.7 million for years ended December 31, 2016, 2015 and 2014, respectively. The Company capitalized interest expense related to capital projects within the refining segment of $6.4 million, $1.4 million and zero for the years ended December 31, 2016, 2015 and 2014, respectively.

8. INTANGIBLE ASSETS

Intangible assets are comprised of franchise rights and trade names amounting to $33.8 million at both December 31, 2016 and 2015. At both December 31, 2016 and 2015, the franchise rights and trade name intangible asset values were $12.4 million and $21.4 million, respectively. These assets have an indefinite life and are not amortized, but rather are tested for impairment annually or when events or changes in circumstances indicate that the fair value of the intangible asset has been reduced below carrying value. Based on the testing performed as of June 30, 2016, the Company noted no indications of impairment.

9. DERIVATIVES

The Company is exposed to market risks related to the volatility in the price of crude oil, refined products (primarily gasoline and distillate), and natural gas used in its operations. To reduce the impact of price volatility on its results of operations and cash flows, the Company uses commodity derivative instruments, including forwards, futures, swaps, and options. The Company uses the futures markets for the available liquidity, which provides greater flexibility in transacting in these instruments. The Company uses swaps primarily to manage its price and margin exposure. The positions in commodity derivative instruments are monitored and managed on a daily basis by a risk control group to ensure compliance with the Company's stated commercial risk management policy. The Company considers these transactions economic hedges of market risk but has elected not to designate these instruments as hedges for financial reporting purposes.

The Company recognizes all derivative instruments, except for those that qualify for the normal purchase and normal sales exception, as either assets or liabilities at fair value on the consolidated balance sheets and any related net gain or loss is recorded as a gain or loss in the consolidated statements of operations and comprehensive income. Observable quoted prices for similar assets or liabilities in active markets (Level 2 as described in Note 12) are considered to determine the fair values for the purpose of marking to market the derivative instruments at each period end.

Risk Management Activities by Type of Risk

The Company periodically uses futures and swaps contracts to manage price risks associated with inventory quantities both above and below target levels. The Company also periodically uses crack spread and crude differential futures and swaps contracts to manage refining margins. Under the Company's risk mitigation strategy, it may buy or sell an amount equal to a fixed price times a certain number of barrels, and to buy or sell in return an amount equal to a specified variable price times the same amount of barrels. Physical volumes are not exchanged and these contracts are net settled with cash.

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The objective of the Company's economic hedges pertaining to crude oil and refined products is to hedge price volatility in certain refining inventories and firm commitments to purchase crude oil inventories. The level of activity for the Company's economic hedges is based on the level of operating inventories, and generally represents the amount by which inventories differ from established target inventory levels. The objective of the Company's economic hedges pertaining to natural gas is to lock in the price for a portion of the Company's forecasted natural gas requirements at existing market prices that are deemed favorable.

At December 31, 2016 and 2015, the Company had open commodity derivative instruments as follows:

	December 31, 2016	December 31, 2015
Crude oil and refined products (thousands of barrels):
Futures - long	30	90
Futures - short	1,270	933
Swaps - long	1,073	5,155
Swaps - short	530	525
Forwards - long	4,382	4,445
Forwards - short	3,101	2,572
Natural gas (thousands of MMBTUs):
Swaps	1,169	1,554

The information below presents the notional volume of outstanding contracts by type of instrument and year of maturity at December 31, 2016:

	Notional Contract Volumes by Year of Maturity
	2017
Crude oil and refined products (thousands of barrels):
Futures - long	30
Futures - short	1,270
Swaps - long	1,073
Swaps - short	530
Forwards - long	4,382
Forwards - short	3,101
Natural gas (thousands of MMBTUs):
Swaps	1,169

Fair Value of Derivative Instruments

The following tables provide information about the fair values of the Company's derivative instruments as of December 31, 2016 and December 31, 2015 and the line items in the consolidated balance sheets in which the fair values are reflected. See Note 12 for additional information related to the fair values of derivative instruments.

The Company is required to post margin collateral with a counterparty in support of our hedging activities. Funds posted as collateral were $7.6 million and $6.0 million as of December 31, 2016 and December 31, 2015, respectively. The margin collateral posted is required by counterparties and cannot be offset against the fair value of open contracts except in the event of default. The Company nets fair value amounts recognized for multiple similar derivative contracts executed with the same counterparty under master netting arrangements, including cash collateral assets and obligations. The tables below, however, are presented on a gross asset and gross liability basis.

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		December 31, 2016
(in millions)	Balance Sheet Location	Assets		Liabilities
Commodity instruments:
Swaps	Other current assets	$	1.1	$	—
Swaps	Accrued liabilities	0.1		0.4
Futures	Accrued liabilities	0.2		1.2
Forwards	Other current assets	5.2		—
Forwards	Accrued liabilities	—		4.7
Total		$	6.6	$	6.3
		December 31, 2015
(in millions)	Balance Sheet Location	Assets		Liabilities
Commodity instruments:
Swaps	Accrued liabilities	$	—	$	7.9
Futures	Other current assets	0.4		—
Forwards	Other current assets	1.5		—
Forwards	Accrued liabilities	—		1.5
Total		$	1.9	$	9.4

Effect of Derivative Instruments on Income

All derivative contracts are marked to market at period end and the resulting gains and losses are recognized in earnings. The following tables provide information about the gain or loss recognized in income on the Company's derivative instruments and the line items in the financial statements in which such gains and losses are reflected.

Recognized gains and losses on derivatives were as follows:

	Year Ended December 31,
(in millions)	2016			2015			2014
Gain (loss) on the change in fair value of outstanding derivatives	$	7.8		$	(4.7	)	$	(2.8	)
Settled derivative gains (losses)	(19.8		)	1.5			12.4
Total recognized gain (loss)	$	(12.0	)	$	(3.2	)	$	9.6
Gain (loss) recognized in cost of sales	$	(13.3	)	$	(0.5	)	$	9.6
Gain (loss) recognized in operating expenses	1.3			(2.7		)	—
Total recognized net gain (loss) on derivatives	$	(12.0	)	$	(3.2	)	$	9.6

Market and Counterparty Risk

The Company is exposed to credit risk in the event of nonperformance by counterparties on its risk mitigating arrangements. The counterparties are large financial institutions with long-term credit ratings of at least A by Standard and Poor's and A2 by Moody's. In the event of default, the Company may be subject to losses on a derivative instrument's mark-to-market gains. The Company does not expect nonperformance of the counterparties involved in its risk mitigation arrangements.

10. DEBT

ABL Facility

On September 29, 2014, NTE LLC and its subsidiaries entered into an amended and restated asset-based ABL Facility with JPMorgan Chase Bank, N.A., as administrative agent for the lenders and as collateral agent for the other secured parties (the "ABL Facility"). The borrowers under the ABL Facility are SPPR, NTB, NTR and SAF, each of which is a wholly owned subsidiary of NTE LLC.

Lenders under the ABL Facility hold commitments totaling $500 million, which is subject to a borrowing base comprised of eligible accounts receivable and inventory. The ABL 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

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provide such additional commitments). The ABL Facility matures on September 29, 2019. The Company incurred financing costs associated with the new ABL Facility of $3.0 million which will be amortized to Interest expense, net through the date of maturity.

The ABL Facility is guaranteed, on a joint and several basis, by NTE LLC and its subsidiaries and will be guaranteed by any newly acquired or formed subsidiaries, subject to certain limited exceptions. The ABL Facility and such guarantees are secured on a first priority basis by substantially all of NTE LLC's and such subsidiaries' cash and cash equivalents, accounts receivable and inventory and on a second priority basis by NTE LLC's and such subsidiaries' fixed assets (other than real property).

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 ABL 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.

Borrowing availability under the ABL Facility is tied to a borrowing base dependent upon the amount of eligible accounts receivable and inventory. As of December 31, 2016, the borrowing base under the ABL Facility was $285.5 million and availability under the ABL Facility was $214.9 million. This availability is net of $70.6 million in outstanding letters of credit. The borrowers under the ABL Facility had no borrowings outstanding under the ABL Facility at December 31, 2016.

2020 Secured Notes

As of December 31, 2016 and 2015, the Company had $350.0 million of outstanding aggregate principal of our 7.125% senior secured notes due 2020 (the "2020 Secured Notes'). On September 29, 2014, the Company issued an additional $75.0 million of the 2020 Secured Notes at 105.75% of par for gross proceeds of $79.2 million. This offering was issued under the same indenture and associated terms as the existing 2020 Secured Notes. The issuance premium of $4.2 million and financing costs of $2.5 million associated with this offering are both being amortized to Interest expense, net over the remaining term of the notes.

The 2020 Secured Notes are guaranteed, jointly and severally, on a senior secured basis by all of the Company's existing and future 100% direct and indirect subsidiaries on a full and unconditional basis; however, there are certain obligations not guaranteed on a full and unconditional basis as a result of subsidiaries being released as guarantors. A subsidiary guarantee can be released under customary circumstances, including (a) the sale of the subsidiary, (b) the subsidiary being declared "unrestricted," (c) the legal or covenant defeasance or satisfaction and discharge of the indenture, or (d) liquidation or dissolution of the subsidiary. Separate condensed consolidated financial information is not included as the guarantor company, NTE LP, does not have independent assets or operations. The 2020 Secured Notes and the subsidiary note guarantees are secured on a pari passu basis with certain hedging agreements by a first-priority security interest in substantially all present and hereinafter acquired tangible and intangible assets of NTE LLC and each of the subsidiary guarantors and by a second-priority security interest in the inventory, accounts receivable, investment property, general intangibles, deposit accounts and cash and cash equivalents collateralized by a $500 million secured asset-based ABL Facility with a maturity date of September 29, 2019. Additionally, the 2020 Secured Notes are fully and unconditionally guaranteed on a senior unsecured basis by NTE LP. NTE LP's creditors have no recourse to the assets of Western and its subsidiaries. Western's creditors have no recourse to the assets of NTE LP and its subsidiaries. The Company is required to make interest payments on May 15 and November 15 of each year, which commenced on May 15, 2013. There are no scheduled principal payments required prior to the 2020 Secured Notes maturing on November 15, 2020. The outstanding $350.0 million in 2020 Secured Notes are registered with SEC through two separate registrations occurring in October 2013 and January 2015.

At any time prior to the maturity date of the notes, the Company may, at its option, redeem all or any portion of the notes for the outstanding principal amount plus unpaid interest and a make-whole premium as defined in the indenture. If the Company experiences a change in control or makes certain asset dispositions, as defined under the indenture, the Company may be required to repurchase all or part of the notes plus unpaid interest and, in certain cases, pay a redemption premium.

The 2020 Secured Notes contain certain covenants that, among other things, limit the ability, subject to certain exceptions, of the Company to incur additional debt or issue preferred equity interests, to purchase, redeem or otherwise acquire or retire its equity interests, to make certain investments, loans and advances, to sell, lease or transfer any of its property or assets, to merge, consolidate, lease or sell substantially all of the Company's assets, to suffer a change of control or to enter into new lines of business. Following the Company's sale of its terminal and tank assets to WNRL in September 2016 (see Note 3), the Company commenced a tender offer in October 2016 to all holders of the 2020 Secured Notes. This tender offer allowed noteholders to require the Company to purchase outstanding notes at par plus accrued interest. Notes totaling $0.02 million were tendered for redemption.

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11. EQUITY

Western indirectly owns 100% of Northern Tier Energy GP LLC and 100% of the limited partnership interest in NTE LP.

Merger with Western

On December 21, 2015, Western and NTE LP announced that they had entered into an Agreement and Plan of Merger dated as of December 21, 2015 ("the Merger Agreement"), with NTE GP and Western Acquisition Co, LLC, a Delaware limited liability company and wholly-owned subsidiary of Western ("MergerCo") whereby Western would acquire all of Northern Tier's outstanding common units not already owned by Western (the "Merger").

Based upon the consideration elections made by NTI common unitholders, this cash and Western common stock was allocated among NTI common unitholders as follows:

• NTI common unitholders who made a valid "Mixed Election" (as defined in the Merger Agreement), or who made no election, received $15.00 in cash and 0.2986 of a share of Western common stock for each such NTI common unit held.

• NTI common unitholders who made a valid "Cash Election" (as defined in the Merger Agreement) received $15.357 in cash and 0.28896 of a share of Western common stock as prorated in accordance with the Merger Agreement for each such NTI common unit held.

• NTI common unitholders who made a valid "Stock Election" (as defined in the Merger Agreement) received 0.7036 of a share of Western common stock for each such NTI common unit held.

On June 23, 2016, following the approval of the Merger by NTI common unitholders, all closing conditions to the Merger were satisfied, and the Merger was successfully completed. The transaction resulted in approximately 17.1 million additional shares of WNR common stock outstanding. Subsequent to this transaction, NTI continues to exist as a limited partnership and became an indirect wholly-owned subsidiary of Western (see Note 20).

Distribution Policy

Prior to our merger with Western, the Company generally made distributions, if any, within 60 days after the end of each quarter to unitholders of record as of the applicable record date. The board of directors of the Company's general partner adopted a policy pursuant to which distributions for each quarter, if any, would equal the amount of available cash the Company generates in such quarter. Distributions on the Company's units were in cash. Available cash for each quarter, if any, was determined by the board of directors of the Company's general partner following the end of such quarter. Distributions were expected to be based on the amount of available cash generated in such quarter. Available cash for each quarter was generally equal the Company's cash flow from operations for the quarter, excluding working capital changes, less cash required for maintenance and regulatory capital expenditures, reimbursement of expenses incurred by the Company's general partner and its affiliates, debt service and other contractual obligations and reserves for future operating or capital needs that the board of directors of our general partner deemed necessary or appropriate, including reserves for turnaround and related expenses, working capital, and organic growth projects. Pursuant to the terms of the Merger Agreement, the Company declared and paid a prorated quarterly distribution for the period April 1, 2016, to June 13, 2016, which was paid on June 23, 2016, to unitholders of record as of immediately prior to the Effective Time of the Merger (as defined in the Merger Agreement).

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The following table details the quarterly distributions paid to common unitholders (in millions, except per unit amounts):

Date Declared	Date Paid	Common Units and equivalents at record date (in millions)	Distribution per common unit and equivalent		Total Distribution (in millions)
2014 Distributions:
February 7, 2014	February 28, 2014	92.7	$	0.41	$	38.0
May 6, 2014	May 30, 2014	93.0	$	0.77	71.6
August 5, 2014	August 29, 2014	93.0	$	0.53	49.3
November 4, 2014	November 25, 2014	93.1	$	1.00	92.9
Total distributions paid during 2014			$	2.71	$	251.8
2015 Distributions:
February 5, 2015	February 27, 2015	93.7	$	0.49	$	45.9
May 5, 2015	May 29, 2015	93.7	$	1.08	100.8
August 4, 2015	August 28, 2015	93.7	$	1.19	111.3
November 3, 2015	November 25, 2015	93.7	$	1.04	97.3
Total distributions paid during 2015			$	3.80	$	355.3
2016 Distributions:
February 3, 2016	February 19, 2016	94.2	$	0.38	$	36.0
June 13, 2016	June 23, 2016	93.0	$	0.18	$	16.7
Total distributions paid prior to our merger			$	0.56	$	52.7

Subsequent to our merger with Western, we declared a distribution for $110.0 million which was paid in the fourth quarter 2016.

12. FAIR VALUE MEASUREMENTS

As defined in GAAP, fair value is the price that would be received for the sale of an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. GAAP describes three approaches to measuring the fair value of assets and liabilities: the market approach, the income approach and the cost approach, each of which includes multiple valuation techniques. The market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities. The income approach uses valuation techniques to measure fair value by converting future amounts, such as cash flows or earnings, into a single present value amount using current market expectations about those future amounts. The cost approach is based on the amount that would currently be required to replace the service capacity of an asset. This is often referred to as current replacement cost. The cost approach assumes that the fair value would not exceed what it would cost a market participant to acquire or construct a substitute asset of comparable utility, adjusted for obsolescence.

Accounting guidance does not prescribe which valuation technique should be used when measuring fair value and does not prioritize among the techniques. Accounting guidance establishes a fair value hierarchy that prioritizes the inputs used in applying the various valuation techniques. Inputs broadly refer to the assumptions that market participants use to make pricing decisions, including assumptions about risk. Level 1 inputs are given the highest priority in the fair value hierarchy while Level 3 inputs are given the lowest priority. The three levels of the fair value hierarchy are as follows:

• Level 1 – Observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active markets as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

• Level 2 – Observable market-based inputs or unobservable inputs that are corroborated by market data. These are inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date.

• Level 3 – Unobservable inputs that are not corroborated by market data and may be used with internally developed methodologies that result in management’s best estimate of fair value.

The Company uses a market or income approach for recurring fair value measurements and endeavors to use the best information available. Accordingly, valuation techniques that maximize the use of observable inputs are favored. The

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assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement of assets and liabilities within the levels of the fair value hierarchy.

The Company's current asset and liability accounts contain certain financial instruments, the most significant of which are trade accounts receivables and trade payables. The Company believes the carrying values of its current assets and liabilities approximate fair value. The Company's fair value assessment incorporates a variety of considerations, including the short-term duration of the instruments, the Company's historical incurrence of insignificant bad debt expense and the Company's expectation of future insignificant bad debt expense, which includes an evaluation of counterparty credit risk.

The following table provides the assets and liabilities carried at fair value measured on a recurring basis at December 31, 2016 and 2015:

	Balance at		Quoted prices in active markets		Significant other observable inputs		Unobservable inputs
(in millions)	December 31, 2016		(Level 1)		(Level 2)		(Level 3)
ASSETS
Cash and cash equivalents	$	29.5	$	29.5	$	—	$	—
Other current assets
Derivative asset - current	6.3		—		6.3		—
	$	35.8	$	29.5	$	6.3	$	—
LIABILITIES
Accrued liabilities
Derivative liability - current	$	6.0	$	—	$	6.0	$	—
	$	6.0	$	—	$	6.0	$	—

	Balance at		Quoted prices in active markets		Significant other observable inputs		Unobservable inputs
(in millions)	December 31, 2015		(Level 1)		(Level 2)		(Level 3)
ASSETS
Cash and cash equivalents	$	70.9	$	70.9	$	—	$	—
Other current assets
Derivative asset - current	1.9		—		1.9		—
	$	72.8	$	70.9	$	1.9	$	—
LIABILITIES
Accrued liabilities
Derivative liability - current	$	9.4	$	—	$	9.4	$	—
	$	9.4	$	—	$	9.4	$	—

As of December 31, 2016 and 2015, the Company had no Level 3 fair value assets or liabilities.

The Company's policy is to recognize transfers in and transfers out as of the actual date of the event or of the change in circumstances that caused the transfer. For the years ended December 31, 2016 and 2015, there were no transfers in or out of Levels 1, 2 or 3.

Assets not recorded at fair value on a recurring basis, such as property, plant and equipment, intangible assets and cost method investments, are recognized at fair value when they are impaired. During the years ended December 31, 2016, 2015 and 2014 there were no impairments of such assets.

The carrying value of debt, which is reported on the Company's consolidated balance sheets, reflects the cash proceeds received upon issuance, net of subsequent repayments. The fair value of the 2020 Secured Notes disclosed below was determined based on quoted prices in active markets (Level 1).

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	December 31, 2016				December 31, 2015
(in millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
2020 Secured Notes	$	350.0	$	363.5	$	350.0	$	360.5

13. ASSET RETIREMENT OBLIGATIONS

The following table summarizes the changes in asset retirement obligations:

	Year Ended December 31,
(in millions)	2016			2015			2014
Asset retirement obligation balance at beginning of period	$	2.4		$	2.4		$	2.2
Costs incurred to remediate	(0.2		)	(0.3		)	—
Accretion expense	0.2			0.3			0.2
Asset retirement obligation balance at end of period	$	2.4		$	2.4		$	2.4

14. EQUITY-BASED COMPENSATION

Prior to Northern Tier's merger with Western, the Company maintained the 2012 Long-Term Incentive Plan ("LTIP"). Effective upon the closing of the Merger, Western's board of directors adopted and assumed the LTIP and amended and renamed the LTIP to the Northern Tier Energy LP Amended and Restated 2012 Long-Term Incentive Plan ("Amended LTIP"). The Amended LTIP changed, among other things, the unit of equity from a unit of NTI common partnership interest to a share of Western common stock and the administrator of the plan was changed from the board of directors of the NTE GP to the board of directors of Western or its applicable committee. All unvested equity awards at the time of the Merger with Western were exchanged for new awards under the Amended LTIP consistent with the terms of the Merger Agreement.

The Company recognized equity-based compensation expense of $13.6 million, $10.3 million and $14.0 million for the years ended December 31, 2016, 2015 and 2014, respectively, related to these plans. This expense is included in selling, general and administrative expenses in the consolidated statements of operations and comprehensive income.

AMENDED LTIP

Approximately 0.3 million Western common share equivalents are reserved for issuance under the Amended LTIP as of December 31, 2016. The Amended LTIP permits the award of stock options, restricted stocks, phantom stocks, dividend equivalent rights, stock appreciation rights and other awards that derive their value from the market price of Western’s common stock. As of December 31, 2016, approximately 0.7 million shares of equity denominated awards and approximately $9.0 million in cash denominated awards were outstanding under the Amended LTIP. The Company recognized the expense on all LTIP awards ratably from the grant date until all units vested. Service-based awards generally vested ratably over a three-year period beginning on the award's first anniversary date and performance-based awards generally vested following the end of the measurement period which, for the performance-based phantom awards, had traditionally been three years after the commencement of the measurement period. Compensation expense related to service-based phantom awards was 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. Compensation expense related to performance-based phantom awards was based on the grant date fair value as determined by either the closing price on the grant date and management's estimates on the number of units that ultimately vested in the case of awards with company performance based criteria or by third-party valuation experts in the case of awards with market based criteria. For awards to employees, the Company estimates a forfeiture rate which is subject to revision depending on the actual forfeiture experience.

As of December 31, 2016 and 2015, the total unrecognized compensation cost for stock and cash awards under the Amended LTIP was $8.6 million and $16.1 million, respectively.

Restricted Common Units

Legacy NTI Service-based Restricted Common Unit Awards

As of December 31, 2016, the Company had no restricted common units outstanding as all restricted common units were exchanged upon the Merger with Western. As a replacement for these awards, for every one unvested outstanding restricted common unit, 1.0323 shares of Western phantom stock were issued to the participant with all vesting dates remaining unchanged.

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A summary of the service-based restricted common unit activity is set forth below:

	Number of		Weighted		Weighted Average Term
	restricted common units		Average Grant		Until Maturity
	(in thousands)		Date Price		(years)
Nonvested at December 31, 2014	396.2		$	24.73	1.3
Awarded	1.0		24.90		2.0
Vested	(205.7	)	24.71		—
Nonvested at December 31, 2015	191.5		24.75		1.0
Forfeited	(12.3	)	25.57		—
Vested	(34.5	)	26.83		—
Exchanged due to merger	(144.7	)	24.18		0.5
Nonvested at December 31, 2016	—		—		—

Phantom Common Units

Legacy NTI Service-based Restricted Common Unit Awards

As of December 31, 2016, the Company had no service-based phantom common units outstanding as all service-based phantom common units were exchanged in accordance with the Merger. For every one unvested service-based phantom common units outstanding, 1.0323 shares of Western phantom stock were issued to the participant with all vesting dates remaining unchanged.

A summary of the service-based phantom common unit activity is set forth below:

	Number of phantom common units						Weighted		Weighted
	(in thousands)						Average Grant		Average Term
	Service-Based		Performance-Based		Total		Date Value		Until Maturity
Nonvested at December 31, 2014	337.7		—		337.7		$	26.99	2.0
Awarded	447.9		182.4		630.3		23.37		1.9
Incremental performance units	—		80.4		80.4		23.06		1.7
Forfeited	(91.3	)	(2.1	)	(93.4	)	26.22		—
Vested	(112.4	)	—		(112.4	)	27.02		—
Nonvested at December 31, 2015	581.9		260.7		842.6		24.00		1.5
Awarded	381.0		163.6		544.6		25.87		2.5
Incremental performance units	—		231.8		231.8		27.82		2.0
Forfeited	(16.5	)	(19.1	)	(35.6	)	25.36		—
Vested	(269.2	)	(1.8	)	(271.0	)	24.10		—
Exchanged due to merger	(677.2	)	(635.2	)	(1,312.4	)	25.45		2.0
Nonvested at December 31, 2016	—		—		—		—		—

Western Service-based Phantom Stock Awards

As a result of the Merger, both the previously outstanding service-based restricted and phantom common unit awards were exchanged with 0.8 million service based awards of Western phantom stock. Upon vesting, Western may settle these awards in common stock, cash or a combination of both, in the discretion of the board of directors of Western or its applicable committee. The new Western phantom stock awards participate in dividends on an equal basis with Western's common shareholders. However, dividends for phantom stock awards are paid in cash only upon vesting. In the event that unvested phantom stock awards are forfeited or canceled, any unpaid dividends on the underlying awards are also forfeited by the grantee. For phantom stock awards outstanding at December 31, 2016, the forfeiture rates ranged from zero to 30%, depending on the employee pay grade classification.

Legacy NTI Performance-based Phantom Common Awards

As of December 31, 2016, the Company had no performance-based phantom common units outstanding as all performance-based phantom common units were exchanged in accordance with the Merger. Western issued (a) fixed-value cash denominated awards for the pre-merger time period pertaining to the legacy NTI performance-based phantom common unit awards based

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upon the performance multiples achieved through March 31, 2016 (the most recently completed quarter prior to the Merger date) and (b) variable-value cash denominated awards for the post-merger time period pertaining to the legacy NTI performance-based phantom common unit awards. Both the fixed value and variable value awards were converted to cash denominated awards at a rate of $21.1049 in cash for every one unvested outstanding performance-based phantom common unit prior to the Merger.

Pre-Merger Period Service-Based Cash Denominated Awards

As of December 31, 2016, Western had $4.4 million in unvested fixed value, cash denominated awards applicable to the Company's pre-merger period ("Legacy Performance Awards"). The vesting dates of the Legacy Performance Awards remained unchanged and are now subject only to service conditions. These awards have a weighted average term until maturity of 1.0 years. The related expense is amortized over the remaining service period using the straight-line method and recognized in selling, general and administrative expenses. In the event that unvested Legacy Performance Awards are forfeited or canceled, all dividend rights associated with the grant are also forfeited by the grantee. The forfeiture rates on the Legacy Performance Awards range from 5% to 20%, depending on the employee's pay grade classification.

Post-Merger Period Performance-Based Cash Denominated Awards

As of December 31, 2016, the Western had $4.6 million in unvested variable value, cash denominated awards applicable to the Company's post-merger period (the "Performance Cash Award"). Assuming a threshold EBITDA is achieved and the participant meets the service conditions throughout the vesting term, participants are entitled to a payout under the Performance Cash Award based on the Company’s achievement of two criteria compared to the performance peer group selected by the compensation committee of Western's board of directors over the performance period: (a) return on capital employed, referred to as a performance condition, and (b) total shareholder return, referred to as a market condition. The average of these two conditions is then multiplied by a third condition relating to Western's average safety rate over the performance period relative to the comparable average safety rate of the refining industry as published by the Bureau of Labor Statistics, and can range between 85% for relatively poor safety performance to 115% for relatively superior safety performance.

The Company accounts for the performance and market conditions in each Performance Cash Award as separate liability awards and remeasures the expected liability each period.

15. EMPLOYEE BENEFIT PLANS

Defined Contribution Plans

The Company sponsors one qualified defined contribution plan for eligible employees. Eligibility is based upon a minimum age requirement and a minimum level of service. Participants may make contributions of a percentage of their annual compensation subject to Internal Revenue Service limits. In 2016, the Company provides a non-matching contribution of 3.0% of eligible compensation and a matching contribution at the rate of 100% of a participant's contribution up to 6.0%. Total Company contributions to the Retirement Savings Plans were $7.5 million, $7.4 million and $7.1 million for the years ended December 31, 2016, 2015 and 2014, respectively.

Cash Balance Plan

The Company sponsors a defined benefit cash balance pension plan (the "Cash Balance Plan") for eligible employees. In the fourth quarter 2016, the Company curtailed this benefit effective January 1, 2017 whereby the Company will no longer credit employees for service or interest related to service years after 2016. The Company will continue to sponsor the plan until all benefit obligations are exhausted. Prior to this change, Company contributions made to the cash account of the participants were equal to 5.0% of eligible compensation. Participants' cash accounts also received 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.

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Funded Status and Net Period Benefit Costs

The changes to the benefit obligation, fair value of plan assets and funded status of the Cash Balance Plan for the years ended December 31, 2016, 2015 and 2014 were as follows:

			Cash Balance Plan
			Year Ended December 31,
(in millions)			2016			2015			2014
Change in benefit obligation:
	Benefit obligation at beginning of year		$	8.9		$	7.0		$	4.6
		Service cost	2.2			2.3			2.1
		Interest cost	0.5			0.4			0.3
		Actuarial loss (gain)	0.5			(0.2		)	0.6
		Curtailments	(0.1		)	—			—
		Benefits paid	(0.7		)	(0.6		)	(0.6		)
	Benefit obligation at end of year		11.3			8.9			7.0
Change in plan assets:
	Fair value of plan assets at beginning of year		5.9			4.3			4.6
		Employer contributions	2.8			2.2			0.2
		Return on plan assets	0.1			—			0.1
		Benefits paid	(0.7		)	(0.6		)	(0.6		)
	Fair value of plan assets at end of year		8.1			5.9			4.3
Reconciliation of funded status:
	Fair value of plan assets at end of year		8.1			5.9			4.3
	Benefit obligation at end of year		11.3			8.9			7.0
	Underfunded status at end of year		$	(3.2	)	$	(3.0	)	$	(2.7	)

At December 31, 2016 and 2015, the projected benefit obligations exceeded the fair value of the Cash Balance Plan assets by $3.2 million and $3.0 million, respectively. This underfunded obligation is classified in other liabilities on the consolidated balance sheets.

Our cash balance plan held investments in mutual funds of $8.1 million and $5.9 million at December 31, 2016 and 2015, respectively, that were valued using level 1 inputs from the fair value hierarchy (see Note 12).

The components of net periodic benefit cost and other amounts recognized in equity related to the Cash Balance Plan for the years ended December 31, 2016, 2015 and 2014 were as follows:

		Cash Balance Plan
		Year Ended December 31,
(in millions)		2016			2015			2014
Components of net periodic benefit cost:
	Service cost	$	2.2		$	2.3		$	2.1
	Interest cost	0.5			0.4			0.3
	Expected return on plan assets	(0.2		)	(0.1		)	(0.2		)
	Net periodic benefit cost	$	2.5		$	2.6		$	2.2
Changes recognized in other comprehensive (income) loss:
	Actuarial (gain) loss	—			—			0.7
	Net credit due to curtailment	(0.4		)	—			—
	Experience loss	0.6			—			—
	Total changes recognized in other comprehensive (income) loss	$	0.2		$	—		$	0.7

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Assumptions

The weighted average assumptions used to determine the Company's benefit obligations are as follows:

	Cash Balance Plan
	Year Ended December 31,
	2016	2015	2014
Discount rate	4.00%	4.50%	4.00%
Rate of compensation increase	N/A	3.00%	3.00%

The weighted average assumptions used to determine the net periodic benefit cost are as follows:

	Cash Balance Plan
	Year Ended December 31,
	2016	2015	2014
Discount rate (1)	4.50% / 3.75%	4.00%	5.00%
Expected long-term rate of return on plan assets (1)	4.25% / 3.50%	3.75%	4.75%
Rate of compensation increase	3.00%	3.00%	4.00%

(1) 2016 rates are disclosed pre-curtailment and post-curtailment, respectively.

The assumptions used to determine of the Company's 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 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.

Contributions, Plan Assets and Estimated Future Benefit Payments

Employer contributions to the Cash Balance Plan of $2.8 million, $2.2 million and $0.2 million were made during the years ended December 31, 2016, 2015 and 2014, respectively. These contributions were invested into equity and bond mutual funds and money market funds which are deemed Level 1 assets as described in Note 12. The Company expects funding requirements of approximately $2.3 million during the year ending December 31, 2017.

At December 31, 2016, anticipated benefit payments to participants from the Cash Balance Plan in future years are as follows:

(in millions)	Cash Balance Plan
2017	$	1.1
2018	0.4
2019	0.5
2020	0.5
2021	0.5
2022-2026	2.9

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16. SUPPLEMENTAL CASH FLOW INFORMATION

Supplemental cash flow information is as follows:

	Year Ended December 31,
(in millions)	2016		2015		2014
Net cash from operating activities included:
Interest paid	$	28.6	$	29.0	$	22.5
Income taxes paid	0.1		6.1		5.0
Noncash investing activities included:
Capital expenditures included in accounts payable	$	11.4	$	13.8	$	2.9
PP&E derecognized in sale leaseback	2.8		1.8		—
Book value of tank and terminal related assets sold to WNRL	48.7		—		—
PP&E additions resulting from a capital lease	0.3		4.5		1.7
Noncash financing activities included:
Distributions accrued on unvested equity awards	$	—	$	4.2	$	—
Increase in equity due to proceeds received exceeding book value of assets sold to WNRL	146.3		—		—

17. LEASING ARRANGEMENTS

Concurrent with our formation in 2010, certain acquired assets (including real property interests and land related to 135 of the SuperAmerica convenience stores and the SuperMom's bakery) were sold to a third party equity real estate investment trust. In connection with the closing of the Marathon Acquisition, the Company assumed the leasing of these properties from the real estate investment trust on a long-term basis. All stores owned at the conclusion of these transactions were sold and leased back from the equity real estate investment trust. As of December 31, 2016, 133 of the SuperAmerica convenience stores and the SuperMom's Bakery remain under the lease with the equity real estate investment trust.

In accordance with ASC Topic 840 "Sale Leaseback Transactions," the Company determined that subsequent to this sale, it had a continuing involvement for a portion of these property interests due to potential environmental obligations or due to subleasing arrangements. For these respective properties, the fair value of the assets and the related lease obligation will remain on the Company's consolidated balance sheet until the end of the lease term or until the continuing involvement is resolved. The assets are included in property, plant and equipment and are being depreciated over their remaining useful lives. The lease payments relating to these property interests are recognized as interest expense. Subsequent to the initial transaction, the Company's continuing involvement ended for a subset of these stores and, as such, the related fair value of the assets and the lease obligation for these stores have been removed from the Company's consolidated balance sheet.

The remainder of properties sold to the third party real estate investment trust are treated as operating leases. The Company also leases a variety of facilities and equipment under other operating leases, including land and building space, office equipment, vehicles, rail tracks for storage of rail tank cars near the refinery and numerous rail tank cars. Many of our operating leases have renewal options at various future dates and some of our leases have escalation clauses which are indexed to CPI or other inflation related measures.

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Future minimum commitments for operating lease obligations having an initial or remaining non-cancelable lease terms in excess of one year are as follows:

(in millions)	Capital Leases			Operating Leases		Total Leases
2017	$	1.1		$	27.8	$	28.9
2018	1.0			27.5		28.5
2019	1.1			26.2		27.3
2020	1.1			25.6		26.7
2021	1.1			27.2		28.3
Thereafter	12.2			139.2		151.4
Total	17.6			273.5		291.1
Less: amount representing interest	(8.4		)	—		(8.4		)
Present value of net minimum lease payments	$	9.2		$	273.5	$	282.7

Rental expense was $28.3 million, $25.1 million, $25.4 million for the years ended December 31, 2016, 2015 and 2014, respectively.

18. COMMITMENTS AND CONTINGENCIES

The Company is the subject of, or party to, contingencies and commitments involving a variety of matters. Certain of these matters are discussed below. While the results of these commitments and contingencies cannot be predicted with certainty, the Company believes that the final resolution of the foregoing would not, individually or in the aggregate, have a material adverse effect on the Company's consolidated financial statements as a whole.

Legal Matters

On February 20, 2015, a customer served a complaint in the United States District Court for the District of Minnesota alleging violations of the Telephone Consumer Protection Act. We denied and continue to deny all material allegations in the complaint. On December 29, 2016, we entered into a settlement which will require a payment to the plaintiff class of between $2.2 million and $3.5 million. The parties are awaiting court approval of the settlement terms.

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. The Company believes the Merger Litigation is without merit and intends to vigorously defend against it.

Environmental Matters

The Company is subject to federal, state, local and foreign laws and regulations relating to the environment. These laws generally provide for control of pollutants released into the environment and require responsible parties to undertake remediation of hazardous waste disposal sites. Penalties may be imposed for noncompliance. At December 31, 2016 and 2015, accruals for remediation and closure obligations totaled $3.4 million and $8.6 million, respectively. Of the $3.4 million and $8.6 million accrued, $2.5 million and $2.6 million are recorded on a discounted basis as of December 31, 2016 and 2015, respectively. These discounted liabilities are expected to be settled over at least the next 21 years. At December 31, 2016, the estimated future cash flows to settle these discounted liabilities totaled $3.1 million, and are discounted at a rate of 2.82%. 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 at both December 31, 2016 and 2015. Costs associated with environmental remediation are recorded in direct operating expenses in the statement of operations.

On June 3, 2014, SPPR was issued a National Pollutant Discharge Elimination Permit/State Disposal System Permit by the Minnesota Pollution Control Agency ("MPCA") relating to its upgraded wastewater treatment plant at its St. Paul Park refinery. This permit required the refinery to conduct additional testing of its remaining lagoon. The testing was completed in the fourth quarter of 2014 and following the Company's review of the test results and additional discussions with the MPCA, the Company plans to close the remaining lagoon. The MPCA accepted the Company's remediation plan in the fourth quarter of 2015. At December 31, 2016, and 2015, the Company estimates the remaining remediation costs to be approximately $0.9 million and $6.0 million, respectively. In connection with the Company's December 2010 acquisition of the St. Paul Park refinery, among other assets, from Marathon Petroleum Company LP ("Marathon"), the Company entered into an agreement with Marathon which required Marathon to share in the future remediation costs of this Lagoon, should they be required.

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During the three months ended September 30, 2015, the Company entered into a settlement and release agreement with Marathon and received $3.5 million pursuant to this settlement which was recorded as a reduction of direct operating expenses.

Future estimated cash outflows to remediate environmental matters are as follows:

(in millions)	Groundwater Contamination			Wastewater Lagoon		Total
2017	$	0.5		$	0.9	$	1.4
2018	0.3			—		0.3
2019	0.1			—		0.1
2020	0.1			—		0.1
2021	0.1			—		0.1
Thereafter	2.0			—		2.0
Total	3.1			0.9		4.0
Less: amount representing interest	(0.6		)	—		(0.6		)
Present value of estimated future cash flows	$	2.5		$	0.9	$	3.4

It is not presently possible to estimate the ultimate amount of all remediation costs that might be incurred by the Company or the penalties that may be imposed. Furthermore, environmental remediation costs may vary from estimates for which a liability has been recorded either in accrued liabilities or other liabilities in the balance sheet because of changes in laws, regulations and their interpretation; additional information on the extent and nature of site contamination; and improvements in technology.

Franchise Agreements

In the normal course of its business, SAF enters into ten-year license agreements with the operators of franchised SuperAmerica brand retail outlets. These agreements obligate SAF or its affiliates to provide certain services including information technology support, maintenance, credit card processing and signage for specified monthly fees.

19. SEGMENT INFORMATION

The Company has two reportable operating segments: Refining and Retail. Each of these segments is organized and managed based upon the nature of the products and services they offer. The segment disclosures reflect management's current organizational structure.

• Refining – operates the St. Paul Park, Minnesota refinery, terminal, NTOT and related assets, and includes the Company's interest in MPL and MPLI, and

• Retail – operates 170 convenience stores primarily in Minnesota and Wisconsin. The retail segment also includes the operations of NTB and SAF.

Operating results for the Company's operating segments are as follows:

	Year ended December 31, 2016
(in millions)	Refining		Retail		Other			Total
Revenues
Customer	$	1,857.8	$	1,030.8	$	—		$	2,888.6
Intersegment	563.6		—		—			563.6
Segment revenues	2,421.4		1,030.8		—			3,452.2
Elimination of intersegment revenues	—		—		(563.6		)	(563.6		)
Total revenues	$	2,421.4	$	1,030.8	$	(563.6	)	$	2,888.6
Income (loss) from operations	$	121.5	$	10.7	$	(26.6	)	$	105.6
Income from equity method investment	$	21.9	$	—	$	—		$	21.9
Depreciation and amortization	$	37.4	$	8.3	$	0.8		$	46.5
Capital expenditures	$	120.4	$	7.3	$	0.2		$	127.9

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	Year ended December 31, 2015
(in millions)	Refining		Retail		Other			Total
Revenues
Customer	$	2,289.1	$	1,115.9	$	—		$	3,405.0
Intersegment	647.7		—		—			647.7
Segment revenues	2,936.8		1,115.9		—			4,052.7
Elimination of intersegment revenues	—		—		(647.7		)	(647.7		)
Total revenues	$	2,936.8	$	1,115.9	$	(647.7	)	$	3,405.0
Income (loss) from operations	$	374.8	$	19.2	$	(25.9	)	$	368.1
Income from equity method investment	$	14.8	$	—	$	—		$	14.8
Depreciation and amortization	$	35.4	$	7.7	$	0.9		$	44.0
Capital expenditures	$	63.8	$	7.7	$	0.3		$	71.8

	Year ended December 31, 2014 (1)
(in millions)	Refining		Retail		Other			Total
Revenues
Customer	$	4,165.6	$	1,390.4	$	—		$	5,556.0
Intersegment	932.1		—		—			932.1
Segment revenues	5,097.7		1,390.4		—			6,488.1
Elimination of intersegment revenues	—		—		(932.1		)	(932.1		)
Total revenues	$	5,097.7	$	1,390.4	$	(932.1	)	$	5,556.0
Income (loss) from operations	$	303.5	$	22.9	$	(51.1	)	$	275.3
Income from equity method investment	$	2.2	$	—	$	—		$	2.2
Depreciation and amortization	$	33.7	$	7.3	$	0.9		$	41.9
Capital expenditures	$	35.4	$	8.8	$	0.6		$	44.8

(1) In 2015, the Company modified the methodology whereby corporate costs are allocated to the Refining and Retail segments. This modification resulted in additional costs being allocated to the Refining and Retail segments from the Other segment. The table below presents the increase or (decrease) in Income (loss) from operations the year ended December 31, 2014 that would have occurred as a result of this modification if the adjustments had been applied retroactively:

	Year ended December 31, 2014
(in millions)	Refining		Retail		Other	Total
Increase (decrease)	(7.7	)	(4.4	)	12.1	—

Intersegment sales from the refining segment to the retail segment consist primarily of sales of refined products which are recorded based on contractual prices that are market-based. Revenues from external customers are nearly all in the United States.

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Total assets by segment were as follows:

(in millions)	Refining		Retail		Corporate/Other		Total
At December 31, 2016	$	1,113.8	$	137.5	$	40.0	$	1,291.3
At December 31, 2015	$	917.4	$	138.7	$	81.2	$	1,137.3

The Company has equity method investments included in the refining segment's assets that had a carrying value of $87.3 million and $82.1 million at December 31, 2016 and 2015, respectively. See Note 6 for further information on the Company's equity method investments.

Total assets for the refining and retail segments exclude all intercompany balances. All cash and cash equivalents are included as corporate/other assets. All property, plant and equipment are located in the United States.

20. MERGER TRANSACTION

Description of the Transaction

On December 21, 2015, Western entered into the Merger Agreement, by and among Western, MergerCo, NTI and Northern Tier Energy GP LLC, the general partner of NTI and a wholly-owned subsidiary of Western ("NTI GP"). On June 23, 2016, following the approval of the Merger by NTI common unitholders, all closing conditions to the Merger were satisfied, and the Merger was successfully completed. Upon the terms and subject to the conditions set forth in the Merger Agreement, MergerCo merged with and into NTI, the separate limited liability company existence of MergerCo ceased and NTI continued 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.

Prior to the Merger, NT InterHoldCo LLC, a Delaware limited liability company and wholly-owned subsidiary of Western ("NT InterHoldCo"), owned 100% of the membership interests in NTI GP and 38.3% of NTI’s outstanding common units representing limited partner interests in NTI ("NTI Common Units"). NT InterHoldCo also owned 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 remained the sole general partner of NTI, the NTI Common Units held by Western and its subsidiaries were unchanged and remained issued and outstanding, and, by virtue of the Merger, all of the membership interests in MergerCo automatically 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. Consequently, NT InterHoldCo and its wholly-owned subsidiary, MergerCo HoldCo, became the sole limited partners of NTI.

Pursuant to the Merger Agreement, Western paid $859.9 million in cash and issued 17.1 million shares of Western Common Stock adjusted slightly for cash paid in lieu of fractional shares. NTI common unitholders made consideration elections that resulted in the following allocation of cash and Western common stock among NTI common unitholders.

• NTI common unitholders who made a valid "Mixed Election" (as defined in the Merger Agreement), or who made no election, received $15.00 in cash and 0.2986 of a share of Western common stock for each such NTI common unit held.

• NTI common unitholders who made a valid "Cash Election" (as defined in the Merger Agreement) received $15.357 in cash and 0.28896 of a share of Western common stock as prorated in accordance with the Merger Agreement for each such NTI common unit held.

• NTI common unitholders who made a valid "Stock Election" (as defined in the Merger Agreement) received 0.7036 of a share of Western common stock for each such NTI common unit held.

Merger and Reorganization expenses

The Company incurred professional service fees in connection with the Merger transaction. Additionally, the Company incurred costs associated with initiating a plan of reorganization for various positions in the third quarter of 2016. In relation to this reorganization plan, it was determined that certain employees would be terminated during 2016 and 2017. The Company recognized $4.7 million and $2.5 million of expense during the years ended December 31, 2016 and 2015, respectively, which included compensation related to the severance of employment and retention bonuses for selected employees. These costs are recognized in the merger-related expenses line within the consolidated statements of operations and comprehensive income. All reorganization and related costs are recognized in the Other segment. The Company recognizes these costs ratably from September 1, 2016, the effective date of the agreements, through the remaining service period, which varies for each employee,

184

but in no case is later than September 1, 2017. As of December 31, 2016, the Company anticipates that these costs will continue to be recognized through the third quarter of 2017 and for the expenses to be completely paid out by December 31, 2017.

The following table summarizes the merger-related and reorganization expense activity for the years ended December 31, 2016, 2015 and 2014:

	Year Ended December 31,
(in millions)	2016			2015			2014
Beginning liability for merger and reorganization costs	$	0.2		$	0.8		$	—
Third-party professional service fees	1.7			—			—
Reorganization and related personnel costs incurred during period	3.0			—			12.9
Less: non-cash equity-based awards with accelerated vesting	—			—			(4.8		)
Cash payments to third-party professional service providers	(1.4		)	—			—
Cash payments made to severed employees	(1.0		)	(0.6		)	(7.3		)
Ending liability for merger and reorganization costs	$	2.5		$	0.2		$	0.8

21. SUPPLEMENTARY 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 2016 and 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.

(in millions, except per unit data)		First Quarter		Second Quarter		Third Quarter		Fourth Quarter			Total
2016
	Revenue	$	604.4	$	812.3	$	732.3	$	739.6		$	2,888.6
	Operating income	21.8		77.7		11.6		(5.5		)	105.6
	Net income	14.7		70.6		3.6		(12.4		)	76.5
	Earnings per common unit - basic	$	0.16	N/A		N/A		N/A			N/A
	Earnings per common unit - diluted	$	0.16	N/A		N/A		N/A			N/A
2015
	Revenue	$	793.8	$	959.8	$	891.6	$	759.8		$	3,405.0
	Operating income	119.5		139.3		114.6		(5.3		)	368.1
	Net income	111.2		128.9		103.5		(12.6		)	331.0
	Earnings per common unit - basic	$	1.20	$	1.39	$	1.11	$	(0.14	)	$	3.58
	Earnings per common unit - diluted	$	1.20	$	1.39	$	1.11	$	(0.14	)	$	3.56

185

EX-12.1

Exhibit 12.1

Computation of Earnings to Fixed Charges

	Year Ended December 31,
	2016		2015		2014		2013		2012
	(In thousands)
Income before income taxes	$	241,874	$	838,386	$	1,002,676	$	453,479	$	617,087
Add:
Interest expense and other financing costs	123,291		105,603		97,062		74,581		88,209
Amortization of capitalized interest	2,327		1,911		1,590		1,580		1,479
Interest component of rental expense	22,053		19,941		16,525		7,271		7,857
Earnings as adjusted	$	389,545	$	965,841	$	1,117,853	$	536,911	$	714,632
Fixed charges:
Interest expense and other financing costs	$	123,291	$	105,603	$	97,062	$	74,581	$	88,209
Capitalized interest	10,681		1,818		2,345		1,948		2,359
Interest component of rental expense	22,053		19,941		16,525		7,271		7,857
Fixed charges	$	156,025	$	127,362	$	115,932	$	83,800	$	98,425
Ratio of earnings to fixed charges	2.50		7.58		9.64		6.41		7.26
Coverage deficiency	$	—	$	—	$	—	$	—	$	—

EX-21.1

Exhibit 21.1

SUBSIDIARIES OF

WESTERN REFINING, INC.

Name of Subsidiary	State of Incorporation or Organization
Ascarate Group LLC	Delaware
Ciniza Production Company	New Mexico
Dial Oil Co., LLC	New Mexico
Empire Oil Co.	California
Giant Four Corners, LLC	Delaware
Giant Industries, Inc.	Delaware
Giant Stop-N-Go of New Mexico, LLC	New Mexico
Minnesota Pipe Line Company, LLC*	Delaware
MPL Investments, Inc.*	Delaware
Navajo Convenient Stores Co., LLC*	New Mexico
Northern Tier Bakery LLC	Delaware
Northern Tier Energy GP LLC	Delaware
Northern Tier Energy LLC	Delaware
Northern Tier Energy LP	Delaware
Northern Tier Finance Corporation	Delaware
Northern Tier Oil Transport LLC	Delaware
Northern Tier Retail Holdings LLC	Delaware
Northern Tier Retail LLC	Delaware
NT InterHoldCo LLC	Delaware
San Juan Refining Company, LLC	New Mexico
St. Paul Park Refining Co. LLC	Delaware
SuperAmerica Franchising LLC	Delaware
Western Acquisition Holdings, LLC	Delaware
Western Refining Company, L.P.	Delaware
Western Refining GP, LLC	Delaware
Western Refining Logistics GP, LLC	Delaware
Western Refining Logistics, LP*	Delaware
Western Refining LP, LLC	Delaware
Western Refining Pipeline, LLC*	New Mexico
Western Refining Product Transport, LLC*	Delaware
Western Refining Retail, LLC†	Delaware
Western Refining Southwest, Inc.††	Arizona
Western Refining Terminals, LLC*	Delaware
Western Refining Texas Retail Services, LLC	Texas
Western Refining TRS I, LLC	Texas
Western Refining TRS II, LLC	Texas
Western Refining Wholesale, LLC*	Delaware
Western Refining Yorktown Holding Company	Delaware
Western Refining Yorktown, Inc.	Delaware
Wingate-Gallup Pipeline, LLC	Delaware
WNRL Energy GP, LLC*	Delaware
WNRL Energy, LLC*	Delaware
WNRL Finance Corp.*	Delaware
York River Fuels, LLC	Delaware

* Indicates a company that is not wholly-owned directly by Western Refining, Inc.

† Western Refining Retail, LLC also does business as Howdy's.

†† Western Refining Southwest, Inc. also does business as Giant Service Stations, Howdy's, and Firebird Fuel Company.

EX-23.1

Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in Registration Statement Nos. 333‑168018, 333‑132854 and 333-212208 on Form S-8 and Tesoro Corporation’s Registration Statement No. 333-215080 on Form S-4 of our reports dated March 1, 2017, relating to the consolidated financial statements of Western Refining, Inc. and subsidiaries, and the effectiveness of Western Refining, Inc. and subsidiaries’ internal control over financial reporting, appearing in this Annual Report on Form 10‑K of Western Refining, Inc. for the year ended December 31, 2016.

/s/ DELOITTE AND TOUCHE LLP

Phoenix, Arizona

March 1, 2017

EX-31.1

Exhibit 31.1

CERTIFICATION BY CHIEF EXECUTIVE OFFICER

Pursuant to Rule 13a-14(a) and 15d-14(a)

I, Jeff A. Stevens, certify that:

1. I have reviewed this annual report on Form 10-K of Western Refining, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: March 1, 2017

/s/ Jeff A. Stevens

Jeff A. Stevens

Chief Executive Officer

CERTIFICATION BY CHIEF FINANCIAL OFFICER

Pursuant to Rule 13a-14(a) and 15d-14(a)

I, Karen B. Davis, certify that:

1. I have reviewed this annual report on Form 10-K of Western Refining, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: March 1, 2017

/s/ Karen B. Davis

Karen B. Davis

Executive Vice President and Chief Financial Officer

EX-31.2

Exhibit 31.2

CERTIFICATION BY CHIEF EXECUTIVE OFFICER

Pursuant to Rule 13a-14(a) and 15d-14(a)

I, Jeff A. Stevens, certify that:

1. I have reviewed this annual report on Form 10-K of Northern Tier Energy LP;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: March 1, 2017

/s/ Jeff A. Stevens

Jeff A. Stevens

Chief Executive Officer of

Northern Tier Energy GP LLC

CERTIFICATION BY CHIEF FINANCIAL OFFICER

Pursuant to Rule 13a-14(a) and 15d-14(a)

I, Karen B. Davis, certify that:

1. I have reviewed this annual report on Form 10-K of Northern Tier Energy LP;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: March 1, 2017

/s/ Karen B. Davis

Karen B. Davis

Executive Vice President and Chief Financial Officer of

Northern Tier Energy GP LLC

EX-32.1

Exhibit 32.1

CERTIFICATION

Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

I, Jeff A. Stevens, Chief Executive Officer, and Karen B. Davis, Executive Vice President and Chief Financial Officer, of Western Refining, Inc. (the “Company”), each certifies, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, 18 U.S.C. Section 1350, that:

1. The Annual Report on Form 10-K of the Company for the annual period ended December 31, 2016 (the “Report”) fully complies with the requirements of Section 13(a) or Section 15(d) of the Securities Exchange Act of 1934, as amended; and

2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: March 1, 2017

/s/ Jeff A. Stevens

Jeff A. Stevens

Chief Executive Officer

/s/ Karen B. Davis

Karen B. Davis

Executive Vice President and Chief Financial Officer

EX-32.2

Exhibit 32.2

CERTIFICATION

Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

I, Jeff A. Stevens, Chief Executive Officer, and Karen B. Davis, Executive Vice President and Chief Financial Officer, of the general partner of Northern Tier Energy LP, (the “Partnership”), each certifies, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, 18 U.S.C. Section 1350, that:

1. The Annual Report on Form 10-K of the Company for the annual period ended December 31, 2016 (the “Report”) fully complies with the requirements of Section 13(a) or Section 15(d) of the Securities Exchange Act of 1934, as amended; and

2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: March 1, 2017

/s/ Jeff A. Stevens

Jeff A. Stevens

Chief Executive Officer of

Northern Tier Energy GP LLC

/s/ Karen B. Davis

Karen B. Davis

Executive Vice President and Chief Financial Officer of

Northern Tier Energy GP LLC

XML

Document and Entity Information Document - USD ($)	12 Months Ended
	Dec. 31, 2016	Feb. 24, 2017	Jun. 30, 2016
Entity Information [Line Items]
Entity Registrant Name	Western Refining, Inc.
Entity Central Index Key	0001339048
Document Type	10-K
Document Period End Date	Dec. 31, 2016
Amendment Flag	false
Document Fiscal Year Focus	2016
Document Fiscal Period Focus	FY
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Public Float			$ 1,723,259,136
Entity Common Stock, Shares Outstanding		108,698,435
Northern Tier Energy LP [Member]
Entity Information [Line Items]
Entity Registrant Name	Northern Tier Energy LP
Entity Central Index Key	0001533454
Entity Filer Category	Non-accelerated Filer

XML

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Current assets:
Cash and cash equivalents	$ 268,581	$ 772,502
Accounts receivable, trade, net of a reserve for doubtful accounts of $235 and $169, respectively	423,171	359,237
Inventories	771,989	547,538
Prepaid expenses	95,355	73,213
Other current assets	113,421	169,728
Total current assets	1,672,517	1,922,218
Restricted cash	0	69,106
Equity method investment	102,685	97,513
Property, plant and equipment, net	2,364,482	2,305,171
Goodwill	1,289,443	1,289,443
Intangible assets, net	83,812	84,945
Other assets	47,458	64,997
Total assets	5,560,397	5,833,393
Current liabilities:
Accounts payable	753,933	553,957
Accrued liabilities	219,607	248,395
Current portion of long-term debt	10,500	5,500
Total current liabilities	984,040	807,852
Long-term debt, less current portion	1,871,805	1,644,894
Lease financing obligation	54,163	53,232
Deferred income tax liability, net	260,293	312,914
Other liabilities	93,136	68,595
Liabilities		2,887,487
Total long-term liabilities	2,279,397	2,079,635
Commitments and contingencies
Equity:
Common stock, par value $0.01, 240,000,000 shares authorized; 108,512,228 and 102,773,705 shares issued, respectively	1,085	1,028
Preferred stock, par value $0.01, 10,000,000 shares authorized; no shares issued and outstanding	0	0
Additional paid-in capital	633,381	492,848
Retained earnings	1,061,168	1,167,938
Accumulated other comprehensive income, net of tax	1,226	651
Treasury stock, 9,089,623 shares at cost	0	(363,168)
Total equity	1,696,860	1,299,297
Non-controlling interest	600,100	1,646,609
Total equity	2,296,960	2,945,906
Total liabilities and equity	5,560,397	5,833,393
Northern Tier Energy LP [Member]
Current assets:
Cash and cash equivalents	29,500	70,900
Accounts receivable, trade, net of a reserve for doubtful accounts of $235 and $169, respectively	246,400	186,000
Inventories	333,700	241,200
Other current assets	23,300	21,300
Total current assets	632,900	519,400
Equity method investment	87,300	82,100
Property, plant and equipment, net	517,800	487,800
Intangible assets, net	33,800	33,800
Other assets	19,500	14,200
Total assets	1,291,300	1,137,300
Current liabilities:
Accounts payable	393,300	301,400
Accrued liabilities	54,600	61,800
Total current liabilities	447,900	363,200
Long-term debt, less current portion	344,000	342,000
Lease financing obligation	9,200	11,100
Other liabilities	28,600	27,900
Liabilities	829,700	744,200
Commitments and contingencies	0	0
Limited Partners' Capital Account	461,700	392,900
Equity:
Accumulated other comprehensive income, net of tax	(100)	200
Total equity	461,600	393,100
Total liabilities and equity	$ 1,291,300	$ 1,137,300

XML

Consolidated Balance Sheets (Parentheticals) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Allowance for Doubtful Accounts Receivable		$ 235	$ 169
Common Stock, Par or Stated Value Per Share	$ 0.01	$ 0.01	$ 0.01
Common Stock, Shares Authorized		240,000,000	240,000,000
Common Stock, Shares, Issued		108,512,228	102,773,705
Preferred Stock, Par or Stated Value Per Share		$ 0.01	$ 0.01
Preferred Stock, Shares Authorized		10,000,000	10,000,000
Preferred Stock, Shares Issued		0	0
Preferred Stock, Shares Outstanding		0	0
Treasury Stock, Shares		0	9,089,623
Cash and cash equivalents	$ 268,581	$ 772,502	$ 431,159
Accounts receivable, trade, net of a reserve for doubtful accounts	423,171	359,237
Inventories	771,989	547,538
Prepaid expenses	95,355	73,213
Other current assets	113,421	169,728
Property, plant and equipment, net	2,364,482	2,305,171
Intangible assets, net	83,812	84,945
Other Assets, Noncurrent	47,458	64,997
Accounts Payable, Current	753,933	553,957
Accrued liabilities	219,607	248,395
Long-term debt, less current portion	1,871,805	1,644,894
Deferred income tax liability, net	260,293	312,914
Other liabilities	93,136	68,595
Western Refining Logistics, LP [Member]
Cash and cash equivalents	14,652	44,605
Accounts receivable, trade, net of a reserve for doubtful accounts	65,240	55,053
Inventories	10,144	15,200
Prepaid expenses	6,421	4,133
Other current assets	6,403	5,943
Property, plant and equipment, net	419,448	430,141
Intangible assets, net	6,515	7,757
Other Assets, Noncurrent	3,233	3,376
Accounts Payable, Current	9,186	10,501
Accrued liabilities	39,599	30,624
Long-term debt, less current portion	313,032	437,467
Deferred income tax liability, net	641	0
Other liabilities	$ 9	$ 9
Northern Tier Energy LP [Member]
Limited Partners' Capital Account, Units Issued	92,947,533	92,833,486
Allowance for Doubtful Accounts Receivable	$ 0	$ 0
Cash and cash equivalents	29,500	70,900	$ 87,900
Accounts receivable, trade, net of a reserve for doubtful accounts	246,400	186,000
Inventories	333,700	241,200
Other current assets	23,300	21,300
Property, plant and equipment, net	517,800	487,800
Intangible assets, net	33,800	33,800
Other Assets, Noncurrent	19,500	14,200
Accounts Payable, Current	393,300	301,400
Accrued liabilities	54,600	61,800
Long-term debt, less current portion	344,000	342,000
Other liabilities	$ 28,600	$ 27,900
Limited Partners' Capital Account, Units Outstanding	92,947,533	92,833,486

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Consolidated Statements of Operations - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Net sales	$ 7,743,213	$ 9,787,036	$ 15,153,573
Operating costs and expenses:
Cost of products sold (exclusive of depreciation and amortization)	5,978,811	7,521,375	12,719,963
Direct operating expenses (exclusive of depreciation and amortization)	928,023	902,925	850,634
Selling, general and administrative expenses	217,861	225,245	226,020
Merger and reorganization costs	12,440	0	12,878
Loss (gain) and impairments on disposal of assets, net	(1,271)	51	8,530
Maintenance turnaround expense	47,137	2,024	48,469
Income (Loss) from Equity Method Investments	0	0	0
Depreciation and amortization	216,787	205,291	190,566
Total operating costs and expenses	7,399,788	8,856,911	14,057,060
Operating income	343,425	930,125	1,096,513
Other income (expense):
Interest income	692	703	1,188
Interest and debt expense	(123,291)	(105,603)	(97,062)
Loss on extinguishment of debt	(3,916)	0	(9)
Other, net	24,964	13,161	2,046
Income before income taxes	241,874	838,386	1,002,676
Provision for income taxes	(54,868)	(223,955)	(292,604)
Net income	187,006	614,431	710,072
Less net income attributed to non-controlling interests	62,067	207,675	150,146
Net income attributable to Western Refining, Inc.	$ 124,939	$ 406,756	$ 559,926
Net earnings per share:
Basic	$ 1.24	$ 4.28	$ 6.17
Diluted	$ 1.24	$ 4.28	$ 5.61
Weighted average common shares outstanding:
Basic	100,473	94,899	90,708
Diluted	100,868	94,999	101,190
Comprehensive Income (Loss), Net of Tax, Attributable to Parent [Abstract]
Comprehensive income attributable to Western Refining, Inc.	$ 125,514	$ 408,698	$ 558,985
Northern Tier Energy LP [Member]
Revenues	2,888,600	3,405,000	5,556,000
Operating costs and expenses:
Cost of Goods Sold	2,311,600	2,613,500	4,835,900
Direct Operating Costs	314,300	297,800	288,800
Selling, general and administrative expenses	82,500	82,900	87,800
Merger and reorganization costs	4,700	2,500	0
Maintenance turnaround expense	(500)	400	700
Turnaround And Related Expenses	45,800	10,600	14,900
Income (Loss) from Equity Method Investments	21,900	14,800	2,200
Depreciation and amortization	46,500	44,000	41,900
Depreciation, Depletion and Amortization, Nonproduction	46,500	44,000	41,900
Other Restructuring Costs	0	0	12,900
Operating income	105,600	368,100	275,300
Other income (expense):
Interest and debt expense	(24,800)	(28,700)	(26,600)
Income before income taxes	80,800	339,400	248,700
Provision for income taxes	(4,300)	(8,400)	(7,100)
Net income attributable to Western Refining, Inc.	76,500	$ 331,000	241,600
Net earnings per share:
Basic		$ 3.58
Diluted		$ 3.56
Comprehensive Income (Loss), Net of Tax, Attributable to Parent [Abstract]
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Net Prior Service Cost (Credit) Arising During Period, Net of Tax	300	$ (3,400)	1,200
Comprehensive income attributable to Western Refining, Inc.	76,200	334,400	240,400
Supplemental Income Statement Elements [Abstract]
Excise and Sales Taxes	$ 432,200	$ 402,900	$ 396,400

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Consolidated Statements of Comprehensive Income - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Net income	$ 187,006	$ 614,431	$ 710,072
Benefit plans:
Amortization of net prior service cost	(253)	215	161
Reclassification of loss to income	0	50	21
Other Comprehensive Income (Loss), Finalization of Pension and Other Postretirement Benefit Plan Valuation, before Tax	420	0	0
Actuarial gain (loss)	724	1,683	(2,157)
Net prior service credit	0	(2,463)	0
Other comprehensive income (loss) before tax	891	4,411	(1,975)
Income tax	(386)	(403)	295
Other comprehensive income (loss), net of tax	505	4,008	(1,680)
Comprehensive income	187,511	618,439	708,392
Less comprehensive income attributed to non-controlling interests	61,997	209,741	149,407
Comprehensive income attributable to Western Refining, Inc.	$ 125,514	$ 408,698	$ 558,985

XML

Consolidated Statements of Changes in Equity - USD ($) $ in Thousands	Total	Common Stock [Member]	Additional Paid-in Capital [Member]	Retained Earnings [Member]	Accumulated Other Comprehensive Income (Loss) [Member]	Treasury Stock [Member]	Noncontrolling Interest [Member]	Northern Tier Energy LP [Member]	Accumulated Other Comprehensive Income (Loss) [Member] Northern Tier Energy LP [Member]	Common Units [Member] Northern Tier Energy LP [Member]
Total equity at Dec. 31, 2013	$ 2,570,587	$ 918	$ 625,825	$ 624,213	$ (350)	$ (356,554)	$ 1,676,535
Beginning Balance, Shares at Dec. 31, 2013		(91,827,731)				(12,102,169)
Stock-based compensation	19,903		4,338	0			15,565
Restricted share unit and phantom stock vesting		184,765
Restricted share and share unit vesting	0	$ (2)	2
Excess tax benefit from stock-based compensation	1,144		1,144
Cash dividends declared of $1.52 per share	(293,746)			(293,746)
Net income	710,072			559,926			150,146
Other comprehensive income (loss), net of tax	(1,680)				(941)		(739)	$ (1,200)	$ (1,200)
Adjustments to Additional Paid in Capital, Equity Component of Convertible Debt	214,157	$ 106	(143,557)			$ 357,608
Stock Issued During Period, Shares, Conversion of Convertible Securities		10,630,044				12,129,199
Distribution to non-controlling interest holders	(173,637)						(173,637)
Treasury stock, at cost, shares						(6,468,913)
Treasury stock, at cost	(259,222)					$ (259,222)
Other	66						66
Total equity at Dec. 31, 2014	2,787,644	$ 1,026	487,748	890,393	(1,291)	$ (258,168)	1,667,936
Ending Balance, Shares at Dec. 31, 2014		(102,642,540)				(6,441,883)
Limited Partners' Capital Account, Units Outstanding at Dec. 31, 2013										92,100,363
Partners' Capital at Dec. 31, 2013								401,100	(2,000)	$ 403,100
Net income attributable to Western Refining, Inc.	559,926							241,600		241,600
Distribution Made to Limited Partner, Cash Distributions Paid								(251,800)		$ 251,800
Stock Issued During Period, Shares, Share-based Compensation, Net of Forfeitures										612,381
Stock Granted, Value, Share-based Compensation, Net of Forfeitures								14,000		$ 14,000
Limited Partners' Capital Account, Units Outstanding at Dec. 31, 2014										92,712,744
Partners' Capital at Dec. 31, 2014								403,700	(3,200)	$ 406,900
Stock-based compensation	15,960		4,231				11,729
Restricted share unit and phantom stock vesting		131,165
Restricted share and share unit vesting	0	$ (2)	2
Excess tax benefit from stock-based compensation	871		871
Cash dividends declared of $1.52 per share	(129,211)			(129,211)
Net income	614,431			406,756			207,675
Other comprehensive income (loss), net of tax	4,008				1,942		2,066	3,400	3,400
Distribution to non-controlling interest holders	(242,576)						(242,576)
Treasury stock, at cost, shares						(2,647,740)
Treasury stock, at cost	(105,000)					$ (105,000)
Other	(221)						(221)
Total equity at Dec. 31, 2015	2,945,906	$ 1,028	492,848	1,167,938	651	$ (363,168)	1,646,609
Ending Balance, Shares at Dec. 31, 2015		(102,773,705)				(9,089,623)
Net income attributable to Western Refining, Inc.	406,756							331,000		331,000
Distribution Made to Limited Partner, Cash Distributions Paid								(355,300)		$ 355,300
Stock Issued During Period, Shares, Share-based Compensation, Net of Forfeitures										120,742
Stock Granted, Value, Share-based Compensation, Net of Forfeitures								$ 10,300		$ 10,300
Limited Partners' Capital Account, Units Outstanding at Dec. 31, 2015								92,833,486		92,833,486
Partners' Capital at Dec. 31, 2015								$ 393,100	200	$ 392,900
Total equity at Dec. 31, 2015	2,945,906	$ 1,028	492,848	1,167,938	651	$ (363,168)	1,646,609
Beginning Balance, Shares at Dec. 31, 2015		(102,773,705)				(9,089,623)
Noncontrolling Interest, Increase from Subsidiary Equity Issuance	277,751						277,751
Stock-based compensation	13,361		7,513				5,848
Restricted share unit and phantom stock vesting		174,102
Restricted share and share unit vesting	0	$ (1)	1
Excess tax benefit from stock-based compensation	573		573
Cash dividends declared of $1.52 per share	(153,691)			(153,691)
Stock Issued During Period, Shares, Acquisitions		5,564,421				11,551,973
Stock Issued During Period, Value, Acquisitions	(824,953)	$ 56	144,189	(78,018)		$ 438,168	(1,329,348)
Adjustments to Additional Paid in Capital, Stock Issued, Issuance Costs	(11,741)		(11,741)
Net income	187,006			124,939			62,067
Other comprehensive income (loss), net of tax	505				575		(70)	(300)	(300)
Distribution to non-controlling interest holders	(62,102)						(62,102)
Treasury stock, at cost, shares						(2,462,350)
Treasury stock, at cost	(75,000)					$ (75,000)
Other	(655)						(655)	$ (2,900)
Total equity at Dec. 31, 2016	2,296,960	$ 1,085	633,381	1,061,168	1,226	$ 0	600,100
Ending Balance, Shares at Dec. 31, 2016		(108,512,228)				0
Limited Partners' Capital Account, Units Outstanding at Dec. 31, 2015								92,833,486		92,833,486
Partners' Capital at Dec. 31, 2015								$ 393,100	200	$ 392,900
Net income attributable to Western Refining, Inc.	124,939							76,500		76,500
Distribution Made to Limited Partner, Cash Distributions Paid								(163,600)		$ 163,600
excess of proceeds over book value in asset sale under common control								146,300
Stock Issued During Period, Shares, Share-based Compensation, Net of Forfeitures										114,047
Stock Granted, Value, Share-based Compensation, Net of Forfeitures								$ 12,500		$ 12,500
Limited Partners' Capital Account, Units Outstanding at Dec. 31, 2016								92,947,533		92,947,533
Partners' Capital at Dec. 31, 2016								$ 461,600	(100)	$ 461,700
Net income	249
Total equity at Dec. 31, 2016	2,296,960	$ 1,085	$ 633,381	$ 1,061,168	$ 1,226	$ 0	$ 600,100
Ending Balance, Shares at Dec. 31, 2016		(108,512,228)				0
Net income attributable to Western Refining, Inc.	$ (9,589)							$ (12,400)
Limited Partners' Capital Account, Units Outstanding at Dec. 31, 2016								92,947,533		92,947,533
Partners' Capital at Dec. 31, 2016								$ 461,600	$ (100)	$ 461,700

XML

Consolidated Statements of Changes in Equity (Parentheticals) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Other Comprehensive Income (Loss), Tax, Portion Attributable to Parent	$ 386	$ 403	$ (295)
Cash dividends declared per common share	$ 1.52	$ 1.36	$ 3.08
Northern Tier Energy LP [Member]
Distribution Made to Limited Partner, Distributions Declared, Per Unit	$ 1.74	$ 3.80	$ 2.71

XML

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Cash flows from operating activities:
Net income attributable to Western Refining, Inc.	$ 124,939	$ 406,756	$ 559,926
Net income	187,006	614,431	710,072
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	216,787	205,291	190,566
Changes in fair value of commodity hedging instruments	77,674	50,233	(194,423)
Reserve for doubtful accounts	66	(315)	296
Amortization of loan fees and original issue discount	8,766	6,450	14,496
Loss on extinguishment of debt	3,916	0	9
Stock-based compensation expense	22,523	16,505	19,903
Deferred income taxes	(17,679)	(41,895)	71,827
Change in lower of cost or market reserve	(133,414)	96,536	78,554
Excess tax benefit from stock-based compensation	(1,033)	(871)	(1,144)
Income from equity method investment, net of dividends	5,410	1,672	2,238
Loss (gain) and impairments on disposal of assets, net	(1,271)	51	8,530
Changes in operating assets and liabilities:
Accounts receivable	(64,810)	108,604	132,107
Inventories	(91,037)	(14,837)	(150,403)
Prepaid expenses	(22,142)	15,202	23,722
Other assets	(4,372)	(41,187)	22,312
Accounts payable and accrued liabilities	193,389	(198,707)	(190,209)
Other long-term liabilities	(14,788)	(29,264)	(3,656)
Net cash provided by operating activities	383,747	843,083	737,633
Cash flows from investing activities:
Capital expenditures	(300,969)	(290,863)	(223,271)
Proceeds from the sale of assets	5,521	1,114	1,936
Return of capital on equity method investment	0	0	7,480
Increase in restricted cash	(195,000)	(170,000)	(320,000)
Use of restricted cash	264,106	267,903	152,991
Net Cash Provided by (Used in) Investing Activities	(226,342)	(191,846)	(380,864)
Cash flows from financing activities:
Additions to long-term debt	500,000	300,000	79,311
Payments on long-term debt and capital lease obligations	(135,392)	(7,368)	(6,072)
Borrowings on revolving credit facility	466,900	145,000	269,000
Repayments of revolving credit facility	(591,600)	(269,000)	0
Payments to Acquire Additional Interest in Subsidiaries	(859,893)	0	0
Other Payments to Acquire Businesses	(11,741)	0	0
Distribution to non-controlling interest holders	(66,311)	(238,366)	(173,637)
Deferred financing costs	(12,727)	(6,820)	(9,649)
Payments of Capital Distribution		0	0
Payments of Stock Issuance Costs	(655)	0	0
Purchases of common stock for treasury	(75,000)	(105,000)	(259,222)
Dividends paid	(153,691)	(129,211)	(293,746)
Convertible debt redemption	0	0	(809)
Proceeds from issuance of WNRL common units	277,751	0	0
Excess tax benefit from stock-based compensation	1,033	871	1,144
Net cash used in financing activities	(661,326)	(309,894)	(393,680)
Net increase (decrease) in cash and cash equivalents	(503,921)	341,343	(36,911)
Cash and cash equivalents at beginning of year	772,502	431,159	468,070
Cash and cash equivalents at end of year	268,581	772,502	431,159
Northern Tier Energy LP [Member]
Cash flows from operating activities:
Net income attributable to Western Refining, Inc.	76,500	331,000	241,600
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	46,500	44,000	41,900
Depreciation, Depletion and Amortization, Nonproduction	46,500	44,000	41,900
Unrealized Gain (Loss) on Derivatives	7,800	(4,700)	(2,800)
Stock-based compensation expense	13,600	10,300	14,000
Deferred income taxes	(1,800)	2,800	2,600
Income from equity method investment, net of dividends	5,300	1,700	0
Inventory Write-down	(92,700)	60,800	73,600
Other Noncash Income (Expense)	(2,000)	(2,000)	(2,800)
Changes in operating assets and liabilities:
Accounts receivable	(60,400)	48,900	6,000
Inventories	(400)	(49,900)	(152,300)
Increase (Decrease) in Other Current Assets	(3,100)	7,300	(9,800)
Accounts payable and accrued liabilities	91,500	(39,200)	(28,500)
Increase (Decrease) in Other Operating Assets and Liabilities, Net	9,200	(700)	(5,300)
Net cash provided by operating activities	55,600	407,100	219,600
Cash flows from investing activities:
Capital expenditures	(127,900)	(71,800)	(44,800)
Return of capital on equity method investment	0	0	5,300
Increase in restricted cash		0	0
Use of restricted cash	195,000	0	0
Net Cash Provided by (Used in) Investing Activities	(127,900)	(71,800)	(39,500)
Cash flows from financing activities:
Proceeds from Issuance of Senior Long-term Debt	0	0	79,200
Borrowings on revolving credit facility	412,500	0	30,000
Proceeds from (Repayments of) Lines of Credit	(412,500)	0	(30,000)
Proceeds from sale of assets to entity under common control	195,000	0	0
Deferred financing costs	0	0	(5,400)
Payments of Capital Distribution	164,100	352,300	251,800
Net cash used in financing activities	30,900	(352,300)	(178,000)
Net increase (decrease) in cash and cash equivalents	(41,400)	(17,000)	2,100
Cash and cash equivalents at beginning of year	70,900	87,900	85,800
Cash and cash equivalents at end of year	$ 29,500	$ 70,900	$ 87,900

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Organization and Basis of Presentation

12 Months Ended

Dec. 31, 2016

Segment Reporting Information [Line Items]

Organization and Basis of Presentation

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 our refineries in El Paso, Texas; near Gallup, New Mexico and 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 544 company-owned and franchised retail sites in the United States.

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 Tesoro (“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 Tesoro Merger,” and, if a second merger election as discussed below is not made, the “Tesoro Merger”), with the Company surviving the First Tesoro 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 Tesoro Merger, each share of our common stock, par value $0.01 per share issued and outstanding immediately prior to the effective time of the First Tesoro Merger (excluding our common stock 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 each share of our common stock, either (a) $37.30 in cash or (b) 0.4350 shares of Tesoro common stock, par value $0.16⅔ per share, in each case without interest. See Note 31, Tesoro Merger, for additional information.

At December 31, 2016, we own 100% of the limited partner interest in Northern Tier Energy LP ("NTI") and 100% of its general partner. We entered into an Agreement and Plan of Merger dated as of December 21, 2015 (the “NTI Merger Agreement”), with Western Acquisition Co, LLC (“MergerCo”) which is a wholly-owned subsidiary of Western, NTI and Northern Tier Energy GP LLC, to acquire all of NTI’s outstanding common units not already held by us (the “NTI Merger”). On June 23, 2016, following the approval of the NTI Merger Agreement by NTI common unitholders, all closing conditions to the NTI Merger were satisfied, and the NTI Merger was successfully completed. We incurred $500 million of additional secured indebtedness under our amended term loan credit agreement to partially fund the NTI Merger consideration. See Note 30, NTI, for additional information.

We formed Western Refining Logistics, LP ("WNRL") as a Delaware master limited partnership to own, operate, develop and acquire terminals, storage tanks, pipelines and other logistics assets and related businesses. At December 31, 2016, we owned a 52.6% limited partner interest in WNRL and the public held a 47.4% 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 September 15, 2016, we sold certain assets consisting of terminals, transportation and storage assets and the related land located 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 (the "St. Paul Park Logistics Assets"). 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. We refer to this transaction as the "St. Paul Park Logistics Transaction." The St. Paul Park Logistics Transaction was a reorganization of entities under common control. See Note 29, Western Refining Logistics, LP, for additional information on this transaction.

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. The option 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.

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." The TexNew Mex Pipeline Transaction was a reorganization of entities under common control. See Note 29, Western Refining Logistics, LP, for additional information on this transaction.

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 "Wholesale Acquisition"). 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.

The WNRL financial and operational data presented includes the historical results of all assets acquired from Western in the St. Paul Park Logistics Transaction, the TexNew Mex Pipeline Transaction and the Wholesale Acquisition. These acquisitions from Western were transfers of assets between entities under common control. We have retrospectively adjusted historical financial and operational data of WNRL, for all periods presented, to reflect the purchase and consolidation of the purchased assets into WNRL.

During the third quarter of 2016, we changed our reportable segments due to changes in our organization. Our operations include three business segments: refining, WNRL and retail. See Note 3, Segment Information, for further discussion of our business segments.

Demand for gasoline is generally higher during the summer months than during the winter months. As a result, our operating results for the first and fourth calendar quarters are generally lower than those for the second and third calendar quarters of each year. During 2016, 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.

Northern Tier Energy LP [Member]

Segment Reporting Information [Line Items]

Organization and Basis of Presentation

1. DESCRIPTION OF THE BUSINESS AND BASIS OF PRESENTATION

Description of the Business

Northern Tier Energy LP ("NTE LP", "NTI", "Northern Tier" or the "Company") is a wholly-owned subsidiary of Western Refining, Inc. ("Western") operating as a downstream energy company with refining, retail and logistics operations that serve the Petroleum Administration for Defense District II ("PADD II") region of the United States. NTE LP holds 100% of the membership interest in Northern Tier Energy LLC ("NTE LLC").

NTE LP includes the operations of NTE LLC, St. Paul Park Refining Co. LLC ("SPPR"), Northern Tier Retail Holdings LLC ("NTRH") and Northern Tier Oil Transport LLC ("NTOT"). NTRH is the parent company of Northern Tier Retail LLC ("NTR") and Northern Tier Bakery LLC ("NTB"). NTR is the parent company of SuperAmerica Franchising LLC ("SAF"). NTRH has elected to be treated as a corporation for income tax purposes in order to preserve the limited partnership tax status of NTE LP. SPPR owns a 17% interest in MPL Investments Inc. ("MPLI"), a 17% interest in Minnesota Pipe Line Company, LLC (“MPL”) and a 1.0% interest in Western Refining Logistics, LP ("WNRL"). MPL Investments owns 100% of the preferred interest in MPL, which owns and operates a 465,000 barrel per day (“bpd”) crude oil pipeline in Minnesota (see Note 6). NTOT is a crude oil trucking business in North Dakota that collects crude oil directly from wellheads in the Bakken shale and transports it to regional pipeline and rail facilities.

Western indirectly owns 100% of both Northern Tier Energy GP LLC ("NTE GP") and NTE LP. Western, through its subsidiary NT InterHold Co LLC, a Delaware limited liability company ("NT InterHold Co") as the owner of the general partner of NTE LP, has the ability to appoint all of the members of the NTE GP's board of directors.

On December 21, 2015, Western and NTE LP announced that they had entered into an Agreement and Plan of Merger dated as of December 21, 2015 ("the Merger Agreement"), with NTE GP and Western Acquisition Co, LLC, a Delaware limited liability company and wholly-owned subsidiary of Western ("MergerCo") whereby Western would acquire all of Northern Tier's outstanding common units not already owned by Western (the "Merger").

Based upon the consideration elections made by NTI common unitholders, this cash and Western common stock was allocated among NTI common unitholders as follows:

• NTI common unitholders who made a valid "Mixed Election" (as defined in the Merger Agreement), or who made no election, received $15.00 in cash and 0.2986 of a share of Western common stock for each such NTI common unit held.

• NTI common unitholders who made a valid "Cash Election" (as defined in the Merger Agreement) received $15.357 in cash and 0.28896 of a share of Western common stock as prorated in accordance with the Merger Agreement for each such NTI common unit held.

• NTI common unitholders who made a valid "Stock Election" (as defined in the Merger Agreement) received 0.7036 of a share of Western common stock for each such NTI common unit held.

On June 23, 2016, following the approval of the Merger by NTI common unitholders, all closing conditions to the Merger were satisfied, and the Merger was successfully completed. The transaction resulted in approximately 17.1 million additional shares of WNR common stock outstanding. Subsequent to this transaction, NTI continues to exist as a limited partnership and became an indirect wholly-owned subsidiary of Western (see Note 20).

Refining Business

As of December 31, 2016, the St. Paul Park refinery owned by SPPR, which is located in St. Paul Park, Minnesota, had total crude oil throughput capacity of 102,000 barrels per stream day. 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 primarily in the Upper Great Plains of the United States.

On September 7, 2016, SPPR entered into a Contribution, Conveyance and Assumption Agreement (the "Contribution Agreement") by and among Western, SPPR, WNRL and Western Refining Logistics GP, LLC, the general partner of WNRL. Pursuant to the terms of the Contribution Agreement, SPPR sold certain tank, terminal, rack, transportation facilities and other logistics assets to WNRL in exchange for $195 million cash and 628,224 common units representing limited partner interests in WNRL. Concurrent with the Contribution Agreement, SPPR and WNRL entered into a terminalling, transportation and storage services agreement with an initial term of ten years whereby SPPR will pay fees to WNRL for storage, product throughput and blending services. See Note 3 for further discussion of this transaction.

Retail Business

As of December 31, 2016, NTR operated 170 convenience stores under the SuperAmerica brand and SAF supported 115 franchised stores which also utilize the SuperAmerica brand. These 285 SuperAmerica stores are primarily located in Minnesota and Wisconsin and sell gasoline, merchandise and, in some locations, diesel fuel. There is a wide range of merchandise sold at the stores including prepared foods, beverages and non-food items. The merchandise sold includes a significant number of proprietary items. NTB prepares and distributes food products under the SuperMom's brand primarily to SuperAmerica branded retail outlets.

Basis of Presentation

The accompanying consolidated financial statements have been prepared in accordance with U.S. generally accepted accounting principles ("GAAP") for interim financial information.

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Summary of Accounting Policies

12 Months Ended

Dec. 31, 2016

Segment Reporting Information [Line Items]

Summary of Accounting Policies

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.

We own 100% of NTI's general partner and, subsequent to the NTI Merger, we own 100% of the limited partner interest in NTI. We own a 52.6% limited partner interest in WNRL and 100% of WNRL's general partner. As the general partner of WNRL, we have the ability to direct the activities of WNRL that most significantly impact its respective economic performance. We have reported a non-controlling interest for WNRL as of December 31, 2016, of $600.1 million and non-controlling interests for NTI and WNRL of $1,646.6 million as of December 31, 2015, in our Consolidated Balance Sheets. Investments in significant non-controlled entities over which we have the ability to exercise significant influence are accounted for using the equity method.

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 at December 31, 2015 reported in our Consolidated Balance Sheets relates to net proceeds from the sale of Western's TexNew Mex Pipeline System to WNRL. This cash was used to invest in capital assets.

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, $0.2 million and $0.5 million for the years ended December 31, 2016, 2015 and 2014, respectively. Additions, deductions and balances for the reserve for doubtful accounts for the three years ended December 31, 2016, are presented below:

	Year Ended December 31,
	2016			2015			2014
	(In thousands)
Balance at January 1	$	169		$	484		$	906
Additions	803			367			3,095
Reductions	(737		)	(682		)	(3,517		)
Balance at December 31	$	235		$	169		$	484

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.

Refined products inventories held by our refineries and SuperAmerica retail are valued under the LIFO valuation method. Our refined product inventories for Southwest Retail, our Mid-Atlantic business and WNRL wholesale are valued using the first-in, first-out (“FIFO”) inventory valuation method. Retail merchandise inventory is valued using the retail inventory method.

Equity Method Investment

We own a 17% common equity interest in Minnesota Pipe Line Company, LLC ("MPL"). 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, 2016 and 2015 and is included in other non-current assets in our Consolidated Balance Sheets.

Property, Plant and Equipment

Property, plant and equipment are stated at cost. We capitalize interest on expenditures for capital projects in process greater than six months and greater than $1 million until such projects are ready for their intended use.

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

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

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

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

Goodwill

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

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

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.

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 and various other assets that are related to our general operation and are stated at cost.

Impairment of Long-Lived Assets

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

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

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

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

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 and service parts and labor. Retail cost of products sold includes costs for motor fuels and for merchandise. Motor fuel cost of products sold represents net cost for purchased fuel. Net cost of purchased fuel excludes transportation and motor fuel taxes. Merchandise cost of products sold includes merchandise purchases, net of merchandise rebates and inventory shrinkage.

Refining direct operating expenses include direct costs of labor, maintenance materials and services, chemicals and catalysts, natural gas, utilities and other direct operating expenses. 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.

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 ("RSU"). The fair value of each restricted share or RSU 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 RSUs 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.

Effective upon the closing of the NTI Merger, Western adopted and assumed NTI's equity compensation plan and amended and renamed the plan as the Amended and Restated Northern Tier Energy LP 2012 Long-Term Incentive Plan ("NTI LTIP"). Modifications to the NTI LTIP include, among other things, a change to the unit of equity from an NTI common unit to a share of Western common stock. The amendment changes the administrator of the NTI LTIP from the board of directors of NTI's general partner to Western's board of directors or its applicable committee. Consistent with the terms of the NTI Merger Agreement, all unvested equity awards at the time of the NTI Merger were exchanged for Western phantom stock awards and performance cash awards under the NTI LTIP.

Financial Instruments and Fair Value

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

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

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

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

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

Pension and Other Postretirement Obligations

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

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

Asset Retirement Obligations

We are required to recognize certain obligations for the retirement of our tangible long-lived assets that result from acquisition, construction, development and normal operation. A retirement obligation exists if a party is required to settle an obligation as a result of an existing or enacted law, statute, ordinance or written or oral contract or by legal construction of a contract under the doctrine of promissory estoppel. We record the fair value of a liability for an asset retirement obligation (“ARO”) in the period in which it is incurred if a reasonable estimate of fair value can be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. The increase in the ARO due to the passage of time is recorded as an operating expense (accretion expense). See Note 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 may be discounted dependent upon specific circumstances related to each environmental liability acquired. The majority of our environmental obligations are recorded on an undiscounted basis. The timing and magnitude of these accruals generally are based on the completion of investigations or other studies or a commitment to a formal plan of action. Current regulations are applied in determining environmental liabilities and are based on best estimates of probable undiscounted future costs over the estimated period of time expected to complete the remediation activities using currently available technology as well as our internal environmental policies. Environmental liabilities are difficult to assess and estimate due to uncertainties related to the magnitude of possible remediation and the timing of such remediation. Such estimates are subject to change due to many factors, including the identification of new sites requiring remediation, changes in environmental laws and regulations and their interpretation, additional information related to the extent and nature of remediation efforts and potential improvements in remediation technologies. Amounts recorded for environmental liabilities are not reduced by possible recoveries from third parties. Recoveries of environmental remediation costs from other parties are recorded as assets when we deem their receipt probable.

Income Taxes

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

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

We consolidate 100% of the activity of WNRL due to our ownership of the general partner. WNRL is a publicly held master limited partnership, which is not taxable for federal income tax. We record income taxes on the portion of income or loss attributable to our respective ownership of 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.

Recent Accounting Pronouncements

Effective January 1, 2016, we adopted the revised accounting and reporting requirements included in the Accounting Standards Codification ("ASC") for consolidation of limited partnerships or similar entities. We have applied the new standards retrospectively. The adoption of these revised standards did not result in any change to our consolidation conclusions or impact our financial position, results of operations or cash flows. We have added disclosures for WNRL as required for entities not previously included in the reporting entity as a variable interest entity.

For interim and annual periods beginning after December 15, 2016, the requirements related to employee share-based payment accounting were modified. The revised requirements involve several aspects of accounting for share-based payment transactions, including income tax consequences, classification of awards as either equity or liabilities, classification in the statement of cash flows and forfeiture rate calculations. The updated guidance is effective as of January 1, 2017. The impact of this guidance will not be material to our financial position, results of operations or cash flows when implemented.

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. The revised standard also addresses principal versus agent considerations and indicators related to transfer of control over specified goods. These provisions are effective January 1, 2018, and can be adopted using either a full retrospective approach or a modified approach, with early adoption permitted for periods beginning after December 15, 2016, and interim periods thereafter.

We have been evaluating and continue to evaluate the provisions of this standard and its impact on our business processes, business and accounting systems, and financial statements and related disclosures. A multi-disciplined implementation team has gained an understanding of the standard’s revenue recognition model, is reviewing and documenting our contracts, and is analyzing whether enhancements are needed to our business and accounting systems. We currently plan to adopt this standard on January 1, 2018.

• Lease accounting - the requirements were amended with regard to recognizing lease assets and lease liabilities on the balance sheet and disclosing information about leasing arrangements. The core principle is that a lessee should recognize the assets and liabilities that arise from leases. These provisions are effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Early adoption is permitted. We have been evaluating and continue to evaluate the provisions of this standard and its impact on our business processes, business and accounting systems, and financial statements and related disclosures.

• Cash flow statement - the requirements address certain classification issues related to the statement of cash flows. These provisions are effective for annual periods beginning after December 15, 2017, including interim periods within those annual periods. Early adoption is permitted in any interim or annual period.

• Recognition of breakage for certain prepaid stored-value products - the requirements align recognition of the financial liabilities related to prepaid stored-value products with the revenue recognition standard discussed above for non-financial liabilities. Certain of these liabilities may be extinguished proportionally in earnings as redemptions occur, or when redemption is remote if issuers are not entitled to the unredeemed stored value. This guidance is effective for fiscal years, and interim periods within those years, beginning after December 15, 2017 with early adoption permitted subject to certain requirements.

• Contingent put and call options in debt instruments - the requirements will reduce diversity of practice in identifying embedded derivatives in debt instruments and clarify the nature of an exercise contingency is not subject to the “clearly and closely” criteria for purposes of assessing whether the call or put option must be separated from the debt instrument and accounted for separately as a derivative. This guidance is effective for fiscal years, and interim periods within those years, beginning after December 15, 2016, with early adoption permitted subject to certain requirements.

• Cash flow statement - the requirements provide guidance on presentation in the statement of cash flows for cash, cash equivalents and restricted cash or restricted cash equivalents in order to address diversity in practice among entities. The Update would result in presentation of restricted cash as a component of beginning-of-the-period and end-of-the-period cash and cash equivalents within the statement of cash flows. This guidance is effective for fiscal years, and interim periods within those years, beginning after December 15, 2018 with early adoption permitted subject to certain requirements.

• Business Combinations - the requirements clarify the definition of a business and provide a framework that gives entities a basis for making reasonable judgments about whether a transaction involves an asset or a business. This guidance is effective in annual periods beginning after December 15, 2017, including interim periods therein. It must be applied prospectively on or after the effective date with early adoption permitted subject to certain requirements, and no disclosures for a change in accounting principle are required at transition.

• Goodwill - the requirements change the accounting for goodwill impairments by eliminating step 2 from the goodwill impairment test. Instead, if the carrying amount of a reporting unit exceeds its fair value, an impairment loss shall be recognized in an amount equal to that excess, limited to the total amount of goodwill allocated to that reporting unit. This guidance is effective for annual and any interim impairment tests for periods beginning after December 15, 2019. Early adoption is allowed for all entities as of January 1, 2017, for annual and any interim impairment tests occurring after January 1, 2017.

Northern Tier Energy LP [Member]

Segment Reporting Information [Line Items]

Summary of Accounting Policies

2. SUMMARY OF PRINCIPAL ACCOUNTING POLICIES

Principles of Consolidation

NTE LP is a Delaware limited partnership which consolidates all accounts of NTE LLC and its subsidiaries, including SPPR, NTRH and NTOT. All intercompany accounts have been eliminated in these consolidated financial statements.

The Company’s common equity interests in MPL and WNRL are accounted for using the equity method of accounting. Although SPPR owns only 1.0% of WNRL's common equity, its indirect parent company, Western, owns 52.6%. Because of Western’s controlling influence over WNRL, the investment provides the Company significant influence over WNRL and the Company accounts for its ownership interest in WNRL under the equity method. Equity income from MPL and WNRL represent the Company’s proportionate share of net income available to common equity owners generated by MPL and WNRL. See Note 3for further discussion of the Company's ownership interests in MPL and WNRL.

The equity method investments are 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 operating income. See Note 6 for further information on the Company’s equity method investment.

MPLI owns all of the preferred membership units of MPL. This investment in MPLI, which provides the Company no significant influence over MPLI, is accounted for as a cost method investment. The investment in MPLI is carried at a value of $6.8 million at both December 31, 2016 and 2015, and is included in other noncurrent assets within the consolidated balance sheets.

Use of Estimates

The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities as of the date of the consolidated financial statements and the reported amounts of revenues and expenses during the respective reporting periods. Actual results could differ from those estimates.

Operating Segments

The Company has two reportable operating segments; Refining and Retail (see Note19 for further information on the Company’s operating segments). The Refining and Retail operating segments consist of the following:

• Refining – operates the St. Paul Park, Minnesota refinery, NTOT and includes the Company's interest in MPL and MPLI, and

• Retail – comprised 170 Company-operated convenience stores and 115 franchisee operated convenience stores as of December 31, 2016, primarily in Minnesota and Wisconsin. The retail segment also includes the operation of NTB.

Cash and Cash Equivalents

The Company considers all highly liquid investments with maturities of three months or less from the date of purchase to be cash equivalents.

Receivables and Allowance for Doubtful Accounts

Receivables of the Company primarily consist of customer accounts receivable. The accounts receivable are due from a diverse base including companies in the petroleum industry, airlines and governmental entities. The allowance for doubtful accounts is reviewed regularly for collectability. All customer receivables are recorded at the invoiced amounts and generally do not bear interest. When it becomes probable the receivable will not be collected, the balances for customer receivables are charged directly to bad debt expense. The allowance for doubtful accounts was zero at both December 31, 2016 and 2015.

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. Ending inventory costs in excess of market value are written down to net realizable market values and charged to cost of sales in the period recorded. In subsequent periods, a new LCM determination is made based upon current circumstances relative to, and not to exceed, the original LCM reserve that was established in fourth quarter 2014. However, in no case would the LCM reserve be reversed beyond zero. The Company has LIFO pools for crude oil and other feedstocks and for refined products in its Refining segment and a LIFO pool for refined products inventory held by the retail stores in its Retail segment. Retail merchandise inventory is valued using the average cost method.

Property, Plant and Equipment

Property, plant and equipment is recorded at cost and depreciated on a straight-line basis over the estimated useful lives of the assets. Such assets or asset groups are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If the sum of the expected undiscounted future cash flows from the use of the asset and its eventual disposition is less than the carrying amount of the asset, an impairment loss is recognized based on the fair value of the asset. The amortization of capital lease assets is presented in depreciation and amortization.

When property, plant and equipment depreciated on an individual basis is sold or otherwise disposed of, any gains or losses are reported in the consolidated statements of operations and comprehensive income. Gains on the disposal of property, plant and equipment are recognized when earned, which is generally at the time of sale. If a loss on disposal is expected, such losses are generally recognized when the assets are classified as held for sale.

Expenditures for routine maintenance and repair costs are expensed when incurred. Refinery process units require periodic major maintenance and repairs that are commonly referred to as "turnarounds." Turnaround cycles vary from unit to unit but can be as short as one year for catalyst changes to as long as six years. Turnaround costs are expensed as incurred.

Derivative Financial Instruments

The Company is exposed to earnings and cash flow volatility due to fluctuations in crude oil, refined products, and natural gas prices. The timing of certain commodity purchases and sales also subject the Company to earnings and cash flow volatility. To manage these risks, the Company may use derivative instruments associated with the purchase or sale of crude oil, refined products, and natural gas to hedge volatility in our refining and operating margins. The Company may use futures, options, and swaps contracts to manage price risks associated with inventory quantities above or below target levels. Crack spread and crude differential futures and swaps contracts may also be used to hedge the volatility of refining margins.

All derivative instruments, except for those that meet the normal purchases and normal sales exception, are recorded in the consolidated balance sheets at fair value and are classified depending on the maturity date of the underlying contracts. Changes in the fair value of the Company's contracts are accounted for by marking them to market and recognizing any resulting gains or losses in the consolidated statements of operations and comprehensive income. Gains and losses from derivative activity specific to managing price risk on inventory quantities both above and below target levels are included within cost of sales. Derivative gains and losses are reported as operating activities within the consolidated statements of cash flows.

The Company enters into crude oil forward contracts to facilitate the supply of crude oil to the refinery. These contracts may qualify for the normal purchases and normal sales exception because the Company physically receives and delivers the crude oil under the contracts and when the Company enters into these contracts, the quantities are expected to be used or sold over a reasonable period of time in the normal course of business. These transactions are reflected in the period that delivery of the crude oil takes place. When forward contracts do not qualify for the normal purchases and sales exception, the contracts are marked to market each period through the settlement date, which is generally no longer than one to three months.

Intangible Assets

Intangible assets primarily include a retail marketing trade name and franchise agreements. These assets have an indefinite life and therefore are not amortized, but rather are tested for impairment annually or when events or changes in circumstances indicate that the fair value of the intangible asset has been reduced below carrying value. If the estimated fair value is less than the carrying amount of the asset, an impairment loss is recognized based on the estimated fair value of the asset. Significant assumptions in determining the estimated fair value of the indefinite lived intangibles include projected store growth, estimated market royalty rates, market growth rates and the estimated discount rate.

Renewable Identification Numbers

The Company is subject to obligations to generate or purchase Renewable Identification Numbers ("RINs") required to comply with the Renewable Fuels Standard. The Company's overall RINs obligation is based on a percentage of domestic shipments of on-road fuels as established by the Environmental Protection Agency ("EPA"). To the degree the Company is unable to blend the required amount of biofuels to satisfy its RINs obligation, RINs must be purchased on the open market to avoid penalties and fines. The Company records its RINs obligation on a net basis in accrued liabilities when its RINs liability is greater than the amount of RINs earned and purchased in a given period and in other current assets when the amount of RINs earned and purchased is greater than the RINs liability.

Future changes to existing laws and regulations could increase the minimum volumes of renewable fuels that must be blended with refined petroleum fuels. Because the Company does not produce renewable fuels, increasing the volume of renewable fuels that must be blended into its products could displace an increasing volume of the Company's refineries' product pool, potentially resulting in lower earnings and materially adversely affecting our ability to issue dividends to the Company's unitholders. 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 upon the Company's operating results.

Financing Costs

Financing origination fees on the Company's senior secured notes and ABL Facility are deferred and classified within long-term debt on the consolidated balance sheets. Additionally, financing origination fees on the Company's sales-leaseback transaction covering a majority of its retail stores were also deferred and are classified within other assets on the consolidated balance sheets. Amortization on these deferred costs are provided on a straight-line basis over the term of the agreement, which approximates the effective interest method.

Revenue Recognition

Revenues are recognized when products are shipped or services are provided to customers, title is transferred, the sales price is fixed or determinable and collectability is reasonably assured. Revenues are recorded net of discounts granted to customers. Shipping and other transportation costs billed to customers are presented on a gross basis in revenues and cost of sales.

Prior to October 1, 2014, the Company maintained a crude oil supply and logistics agreement with J.P. Morgan Commodities Canada Corporation ("JPM CCC") pursuant to which JPM CCC assisted the Company in the purchase of substantially all of its crude oil needs for the refinery. As discussed in Note 5, JPM CCC and the Company mutually agreed to terminate this agreement. In the fourth quarter of 2014, subsequent to the termination of this agreement, the Company significantly increased its crude procurement activities and related exchange and buy/sell activity to manage the volumes, grade, timing, and locations of such crude. Such activities are similar to the buy/sell crude oil transactions noted above and are recorded net in cost of sales.

Nonmonetary product exchanges and certain buy/sell crude oil transactions, which are entered into in contemplation one with another, are included on a net cost basis in cost of sales. The Company also enters into agreements to purchase and sell crude oil to third parties and certain of these activities are recorded on a gross basis.

Product Exchanges

The Company enters into exchange contracts whereby it agrees to deliver a particular quantity and quality of crude oil or refined products at a specified location and date to a particular counterparty and to receive from the same counterparty a particular quantity and quality of crude oil or refined products at a specified location on the same or another specified date. The exchange receipts and deliveries are nonmonetary transactions, with the exception of associated grade or location differentials that are settled in cash. These transactions are recorded net in cost of sales because they involve the exchange of inventories held in the ordinary course of business to facilitate sales to customers or delivery of feedstocks to our refinery. The exchange transactions are recognized at the carrying amount of the inventory transferred plus or minus any cash settlement due to grade or location differentials.

Cost of Sales

Cost of sales in the consolidated statements of operations and comprehensive income excludes depreciation and amortization of refinery assets and the direct labor and overhead costs related to the operation of the refinery. These costs are included in the consolidated statements of operations and comprehensive income in the depreciation and amortization and direct operating expenses line items, respectively.

Excise Taxes

The Company is required by various governmental authorities, including federal and state, to collect and remit taxes on certain products. Such taxes are presented on a gross basis in revenue and cost of sales in the consolidated statements of operations and comprehensive income. These taxes totaled $432.2 million, $402.9 million and $396.4 million for the years ended December 31, 2016, 2015 and 2014, respectively.

Advertising

The Company expenses the costs of advertising as incurred. Advertising expense was $2.9 million, $2.9 million and $2.3 million for the years ended December 31, 2016, 2015 and 2014, respectively.

Asset Retirement Obligations

The fair value of asset retirement obligations is recognized in the period in which the obligations are incurred if a reasonable estimate of fair value can be made. Conditional asset retirement obligations for removal and disposal of fire-retardant material from certain refining assets have been recognized. The amounts recorded for such obligations are based on the most probable current cost projections. Asset retirement obligations have not been recognized for the removal of materials and equipment from or the closure of certain refinery, pipeline, terminal and retail marketing assets because the fair value cannot be reasonably estimated since the settlement dates of the obligations are indeterminable. Current inflation rates and credit-adjusted-risk-free interest rates are used to estimate the fair value of asset retirement obligations. Depreciation of capitalized asset retirement costs and accretion of asset retirement obligations are recorded over time. Depreciation is determined on a straight-line basis, while accretion escalates over the lives of the assets. See further information on our asset retirement obligations in Note 13.

Environmental Costs

Environmental expenditures are capitalized if the costs mitigate or prevent future contamination or if the costs improve environmental safety or efficiency of the existing assets. The Company provides for remediation costs and penalties when the responsibility to remediate is probable and the amount of associated costs can be reasonably estimated. The timing of remediation accruals coincides with completion of feasibility studies, investigations or the commitment to a formal plan of action. 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. Remediation liabilities are accrued based on estimates of known environmental exposure and are discounted when the estimated amounts are reasonably fixed and determinable. If recoveries of remediation costs from third parties are probable, a receivable is recorded and is discounted to net present value when the estimated amount is reasonably fixed and determinable.

Defined Benefit Plans

The Company has a cash balance plan and a retiree medical plan that are considered defined benefit plans. Expenses and liabilities related to defined benefit plans 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.

Cash balance and retiree medical 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 could have a significant effect on our pension and retiree medical liabilities and costs. See further information on our plans in Note 15.

Equity-Based Compensation

The Company recognizes compensation expense for equity-based awards issued over the requisite service period. Equity-based compensation costs are measured at the date of grant, based on the fair value of the award. Prior to our Merger, the Company granted equity awards indexed to Northern Tier Energy, LP common units. Concurrent with the Merger, all unvested equity-based awards were converted to new awards indexed to Western Refining, Inc. common stock. Both prior to and subsequent to the Merger, the Company has awarded equity-based phantom awards which, at the discretion of the board of directors of our general partner, may be settled in either cash or common equity. All equity-based phantom awards that vested through December 31, 2016 have been settled in common equity. We anticipate that the remaining unvested phantom awards will also be satisfied with common equity and have therefore classified the accrual of the service cost as equity. However, if our general partner's board elects to settle the phantom awards with cash, it could cause us to remeasure the fair value of those awards resulting in an adjustment to earnings for the cumulative difference between the fair value at the date of grant and date of the remeasurement.

Comprehensive Income

The Company has unrecognized prior service cost related to both its defined benefit cash balance plan as of December 31, 2016, 2015 and 2014 and unrecognized actuarial losses and prior service cost related to its retiree medical plan as of December 31, 2016 and 2015 (see Note 15). The accumulated unrecognized income (loss) related to these plans amounted to $(0.1) million and $0.2 million as of December 31, 2016 and 2015, respectively. These gains/(losses) of $(0.3) million, $3.4 million and $(1.2) million were recognized directly to equity as an element of other comprehensive income (loss) in the years ended December 31, 2016, 2015 and 2014, respectively.

Concentrations of Risk

The Company is exposed to credit risk in the event of nonpayment by customers. The creditworthiness of customers is subject to continuing review. No single non-related party customer accounts for more than 10% of annual revenues.

Crude oil is the principal raw material for the Company and the majority of the crude oil processed is delivered to the refinery through a pipeline that is owned by MPL, a related party. A prolonged disruption of that pipeline's operations would materially impact the Company's ability to economically obtain raw materials.

The Company is exposed to concentrated geographical risk as most of its operations are conducted in the Upper Great Plains of the United States.

Recent Accounting Pronouncements

In February 2016, the FASB issued ASU 2016-02 "Leases," which replaces the existing guidance in Accounting Standards Codification ("ASC") 840. This new guidance is effective for fiscal years, and interim periods within those years, beginning after December 15, 2018 with early adoption permitted. The guidance requires a dual approach for lessee accounting under which a lessee would account for leases as finance leases or operating leases. Both finance leases and operating leases will result in the lessee recognizing a right-of-use ("ROU") asset and a corresponding lease liability. For finance leases the lessee would recognize interest expense and amortization of the ROU asset and for operating leases the lessee would recognize a straight-line total lease expense. The Company is currently assessing the impact that adoption of this guidance will have on its consolidated financial statements and footnote disclosures.

In March 2016, the FASB issued ASU No. 2016-04 "Liabilities – Extinguishment of Liabilities (Subtopic 405-20): Recognition of Breakage for Certain Prepaid Stored-Value Products," which aligns recognition of the financial liabilities related to prepaid stored-value products (for example, prepaid gift cards), with Topic 606, Revenues from Contracts with Customers, for non-financial liabilities. In general, certain of these liabilities may be extinguished proportionally in earnings as redemptions occur, or when redemption is remote if issuers are not entitled to the unredeemed stored value. This guidance is effective for fiscal years, and interim periods within those years, beginning after December 15, 2017 with early adoption permitted subject to certain requirements. The Company is currently assessing the impact that adopting this new accounting standard will have on its consolidated financial statements and footnote disclosures.

In March 2016, the FASB issued ASU No. 2016-06 "Derivatives and Hedging (Topic 815) – Contingent Put and Call Options in Debt Instruments" which will reduce diversity of practice in identifying embedded derivatives in debt instruments. ASU 2016-06 clarifies that the nature of an exercise contingency is not subject to the "clearly and closely" criteria for purposes of assessing whether the call or put option must be separated from the debt instrument and accounted for separately as a derivative. This guidance is effective for fiscal years, and interim periods within those years, beginning after December 15, 2016, with early adoption permitted subject to certain requirements. The Company is currently assessing the impact that adopting this new accounting standard will have on its consolidated financial statements and footnote disclosures.

In March 2016, the FASB issued ASU No. 2016-08 "Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net)," which clarifies the implementation guidance on principal versus agent considerations. The guidance includes indicators to assist an entity in determining whether it controls a specified good or service before it is transferred to the customers. The effective date and transition requirements for the amendments in this Update are the same as the effective date and transition requirements of ASU 2014-09.

The Company has been evaluating and continues to evaluate the provisions of this standard and its impact on its business processes, business and accounting systems, and financial statements and related disclosures. A multi-disciplined implementation team has gained an understanding of the standard’s revenue recognition model, is reviewing and documenting the Company's contracts, and is analyzing whether enhancements are needed to its business and accounting systems. The Company currently plans on adopting this standard on January 1, 2018. The Company does not expect the adoption of this standard to have a material impact on its consolidated financial statements.

In March 2016, the FASB issued ASU No. 2016-09 "Compensation – Stock Compensation," which identifies areas for simplification involving several aspects of accounting for equity-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, an option to recognize gross stock compensation expense with actual forfeitures recognized as they occur, as well as certain classifications on the statement of cash flows. This guidance is effective for fiscal years, and interim periods within those years, beginning after December 15, 2016, with early adoption permitted subject to certain requirements. The Company is currently assessing the impact that adopting this new accounting standard will have on its consolidated financial statements and footnote disclosures.

In August 2016, the FASB issued ASU No. 2016-15 "Classification of Certain Cash Receipts and Cash Payments," which provides guidance on presentation in the statement of cash flows on eight subject areas where there current GAAP either is unclear or does not include specific guidance, resulting in diversity in practice. This guidance is effective for fiscal years, and interim periods within those years, beginning after December 15, 2017 with early adoption permitted subject to certain requirements. The Company is currently assessing the impact that adopting this new accounting standard will have on its consolidated financial statements and footnote disclosures.

In November 2016, the FASB issued ASU No. 2016-18 "Statement of Cash Flows (Topic 230)," which provides guidance on presentation in the statement of cash flows for cash, cash equivalents and amounts generally described as restricted cash or restricted cash equivalents in order to address diversity in practice among entities. The Update would result in presentation of restricted cash as a component of beginning-of-the-period and end-of-the-period cash and cash equivalents within the statement of cash flows. This guidance is effective for fiscal years, and interim periods within those years, beginning after December 15, 2018 with early adoption permitted subject to certain requirements. The Company is currently assessing the impact that adopting this new accounting standard will have on its consolidated financial statements and footnote disclosures.

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Segment Information

12 Months Ended

Dec. 31, 2016

Segment Reporting Information [Line Items]

Segment Information

3. Segment Information

We have organized our operations into threereportable 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. Prior to the NTI Merger on June 23, 2016, we also reported NTI as a separate reportable segment. Following the completion of the NTI Merger, NTI became a wholly-owned subsidiary of Western and, as a result, we have moved its net assets and operations into our refining segment, retail segment and other category. Beginning on July 1, 2016, our management team, led by our chief operating decision maker, began monitoring our business and allocating resources based on these three reportable segments. We have retrospectively adjusted the historical segment financial data for the periods presented to reflect our revised segment presentation. See Note 24, Concentration of Risk, for a discussion on significant customers.

We treated the St. Paul Park Logistics Assets we sold to WNRL 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. We moved the St. Paul Park Logistics Assets from the refining segment to the WNRL segment.

A description of each segment and the principal products follows:

Refining. Our refining segment includes operations of three refineries. The El Paso refinery in El Paso, Texas, has a crude oil throughput capacity of 135,000 barrels per day ("bpd"), the Gallup refinery, near Gallup, New Mexico has a 25,000 bpd capacity and the St. Paul Park refinery, in St. Paul Park, Minnesota has a 102,000 bpd capacity. Our refineries produce 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 year ended December 31, 2014 includes $5.8 million in business interruption recoveries related to processing outages that occurred during the first and fourth quarters of 2011 at our El Paso refinery.

We had a 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 $4.1 million and $1.8 million in assets at December 31, 2016, and 2015, respectively, related to this supply agreement in our Consolidated Balance Sheets. The revenues and costs recorded under the supply agreement included $8.7 million, $48.7 million and $34.6 million in net hedging gains for the years ended December 31, 2016, 2015 and 2014. This supply agreement expired on December 31, 2016. On that date, we acquired $46.0 million in finished product inventories valued at market related to our Mid-Atlantic operations and now realize 100% of the operating results.

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 and Upper Great Plains regions, including 705 miles of pipelines and 12.4 million barrels of active storage capacity. The majority of WNRL's logistics assets are integral to the operations of the El Paso, Gallup and St. Paul Park 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, asphalt and refined product delivery trucks. WNRL distributes commercial wholesale petroleum products primarily in Arizona, Colorado, Nevada, New Mexico and Texas. WNRL purchases petroleum fuels and lubricants from our refining segment and from third-party suppliers.

Retail. Our retail segment operates retail networks located in the Southwest region ("Southwest Retail") and the Upper Great Plains of the U.S. ("SuperAmerica"). Each of our retail networks sells 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, 2016, the retail segment operated 259 service stations and convenience stores or kiosks located in Arizona, Colorado, New Mexico and Texas compared to 258 and 230 service stations and convenience stores or kiosks at December 31, 2015 and 2014, respectively. The Southwest Retail stores were added primarily under various operating and capital leases. At December 31, 2016, the retail segment operated 51 cardlocks located in Arizona and New Mexico compared to 52 and 50 cardlocks at December 31, 2015 and 2014, respectively.

As of December 31, 2016, SuperAmerica operated 170 retail convenience stores and supported the operations of 115 franchised retail convenience stores primarily in Minnesota and Wisconsin, compared to 168 and 109 at December 31, 2015 and 165 and 89 at December 31, 2014. SuperAmerica obtains the majority of its gasoline and diesel for its Minnesota and Wisconsin retail convenience stores from the St. Paul Park refinery.

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 reportable 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.

Disclosures regarding our reportable segments with reconciliations to consolidated totals for the three years ended December 31, 2016, are presented below:

	Year Ended
	December 31, 2016			December 31, 2015			December 31, 2014
	(In thousands)
Operating Results:
Refining
Net sales	$	6,918,931		$	8,777,196		$	14,196,564
Intersegment eliminations	2,819,844			3,072,806			4,291,617
Net refining sales to external customers	4,099,087			5,704,390			9,904,947
WNRL
Net sales	2,222,718			2,599,867			3,501,888
Intersegment eliminations	702,157			786,324			1,011,575
Net WNRL sales to external customers	1,520,561			1,813,543			2,490,313
Retail
Net sales	2,159,946			2,279,737			2,776,782
Intersegment eliminations	36,381			10,634			19,575
Net retail sales to external customers	2,123,565			2,269,103			2,757,207
Other
Other revenue, net	—			—			1,106
Intersegment eliminations	—			—			—
Net other sales to external customers	—			—			1,106
Consolidated net sales to external customers	$	7,743,213		$	9,787,036		$	15,153,573
Operating income (loss)
Refining (1) (2)	$	357,610		$	930,531		$	1,140,580
WNRL (2)	70,095			55,794			35,607
Retail (1)	25,146			41,279			42,087
Other	(109,426		)	(97,479		)	(121,761		)
Operating income	343,425			930,125			1,096,513
Other income (expense), net	(101,551		)	(91,739		)	(93,837		)
Consolidated income before income taxes	$	241,874		$	838,386		$	1,002,676
Depreciation and amortization
Refining (2)	$	150,989		$	142,108		$	137,715
WNRL (2)	39,242			35,384			28,934
Retail	23,193			23,197			19,869
Other	3,363			4,602			4,048
Consolidated depreciation and amortization	$	216,787		$	205,291		$	190,566

	Year Ended
	December 31, 2016		December 31, 2015		December 31, 2014
	(In thousands)
Capital expenditures
Refining (2)	$	248,863	$	201,249	$	119,416
WNRL (2)	29,161		65,635		79,338
Retail	20,308		20,895		22,056
Other	2,637		3,084		2,461
Consolidated capital expenditures	$	300,969	$	290,863	$	223,271
Total assets
Refining (2) (including $1,267,455 of goodwill)	$	4,312,212	$	4,024,131	$	4,126,005
WNRL (2)	533,952		566,209		552,253
Retail (including $21,988 of goodwill)	435,030		444,382		417,269
Other	279,203		798,671		546,659
Consolidated total assets	$	5,560,397	$	5,833,393	$	5,642,186

(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 $18.9 million in net realized and unrealized economic hedging losses for the year ended December 31, 2016 and $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. Cost of products sold included net non-cash LCM recoveries in our refining segment of $132.0 million for the year ended December 31, 2016 and charges of $95.8 million and $77.1 million for the years ended December 31, 2015 and 2014, respectively, and recoveries in our retail segment of $1.4 million for the year ended December 31, 2016 and charges of $0.7 million and $1.4 million for the years ended December 31, 2015 and 2014, respectively.

(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, 2016. The information contained herein for WNRL has been retrospectively adjusted, to include the historical results of the St. Paul Park Logistics Assets.

Northern Tier Energy LP [Member]

Segment Reporting Information [Line Items]

Segment Information

19. SEGMENT INFORMATION

The Company has two reportable operating segments: Refining and Retail. Each of these segments is organized and managed based upon the nature of the products and services they offer. The segment disclosures reflect management's current organizational structure.

• Refining – operates the St. Paul Park, Minnesota refinery, terminal, NTOT and related assets, and includes the Company's interest in MPL and MPLI, and

• Retail – operates 170 convenience stores primarily in Minnesota and Wisconsin. The retail segment also includes the operations of NTB and SAF.

Operating results for the Company's operating segments are as follows:

	Year ended December 31, 2016
(in millions)	Refining		Retail		Other			Total
Revenues
Customer	$	1,857.8	$	1,030.8	$	—		$	2,888.6
Intersegment	563.6		—		—			563.6
Segment revenues	2,421.4		1,030.8		—			3,452.2
Elimination of intersegment revenues	—		—		(563.6		)	(563.6		)
Total revenues	$	2,421.4	$	1,030.8	$	(563.6	)	$	2,888.6
Income (loss) from operations	$	121.5	$	10.7	$	(26.6	)	$	105.6
Income from equity method investment	$	21.9	$	—	$	—		$	21.9
Depreciation and amortization	$	37.4	$	8.3	$	0.8		$	46.5
Capital expenditures	$	120.4	$	7.3	$	0.2		$	127.9

	Year ended December 31, 2015
(in millions)	Refining		Retail		Other			Total
Revenues
Customer	$	2,289.1	$	1,115.9	$	—		$	3,405.0
Intersegment	647.7		—		—			647.7
Segment revenues	2,936.8		1,115.9		—			4,052.7
Elimination of intersegment revenues	—		—		(647.7		)	(647.7		)
Total revenues	$	2,936.8	$	1,115.9	$	(647.7	)	$	3,405.0
Income (loss) from operations	$	374.8	$	19.2	$	(25.9	)	$	368.1
Income from equity method investment	$	14.8	$	—	$	—		$	14.8
Depreciation and amortization	$	35.4	$	7.7	$	0.9		$	44.0
Capital expenditures	$	63.8	$	7.7	$	0.3		$	71.8

	Year ended December 31, 2014 (1)
(in millions)	Refining		Retail		Other			Total
Revenues
Customer	$	4,165.6	$	1,390.4	$	—		$	5,556.0
Intersegment	932.1		—		—			932.1
Segment revenues	5,097.7		1,390.4		—			6,488.1
Elimination of intersegment revenues	—		—		(932.1		)	(932.1		)
Total revenues	$	5,097.7	$	1,390.4	$	(932.1	)	$	5,556.0
Income (loss) from operations	$	303.5	$	22.9	$	(51.1	)	$	275.3
Income from equity method investment	$	2.2	$	—	$	—		$	2.2
Depreciation and amortization	$	33.7	$	7.3	$	0.9		$	41.9
Capital expenditures	$	35.4	$	8.8	$	0.6		$	44.8

(1) In 2015, the Company modified the methodology whereby corporate costs are allocated to the Refining and Retail segments. This modification resulted in additional costs being allocated to the Refining and Retail segments from the Other segment. The table below presents the increase or (decrease) in Income (loss) from operations the year ended December 31, 2014 that would have occurred as a result of this modification if the adjustments had been applied retroactively:

	Year ended December 31, 2014
(in millions)	Refining		Retail		Other	Total
Increase (decrease)	(7.7	)	(4.4	)	12.1	—

Intersegment sales from the refining segment to the retail segment consist primarily of sales of refined products which are recorded based on contractual prices that are market-based. Revenues from external customers are nearly all in the United States.

Total assets by segment were as follows:

(in millions)	Refining		Retail		Corporate/Other		Total
At December 31, 2016	$	1,113.8	$	137.5	$	40.0	$	1,291.3
At December 31, 2015	$	917.4	$	138.7	$	81.2	$	1,137.3

The Company has equity method investments included in the refining segment's assets that had a carrying value of $87.3 million and $82.1 million at December 31, 2016 and 2015, respectively. See Note 6 for further information on the Company's equity method investments.

Total assets for the refining and retail segments exclude all intercompany balances. All cash and cash equivalents are included

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Fair Value Measurement

12 Months Ended

Dec. 31, 2016

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Fair Value Measurement

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, 2016, and December 31, 2015, 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 $60.0 million and $70.1 million consisting of short-term money market deposits and commercial paper were included in the Consolidated Balance Sheets as of December 31, 2016 and 2015, respectively.

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

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, 2016 and 2015, and the basis for that measurement:

	Carrying Value at December 31, 2016			Fair Value Measurement at December 31, 2016 Using							Netting Adjustments			Recorded Value at December 31, 2016
				Level 1		Level 2			Level 3
	(In thousands)
Gross financial assets:
Other current assets	$	18,929		$	—	$	18,929		$	—	$	(5,280	)	$	13,649
Other assets	677			—		677			—		(669		)	8
Gross financial liabilities:
Accrued liabilities	(17,547		)	—		(17,547		)	—		6,720			(10,827		)
Other long-term liabilities	—			—		—			—		(771		)	(771		)
	$	2,059		$	—	$	2,059		$	—	$	—		$	2,059

	Carrying Value at December 31, 2015			Fair Value Measurement at December 31, 2015 Using								Netting Adjustments			Recorded Value at December 31, 2015
				Level 1		Level 2			Level 3
	(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

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.

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, 2016 and 2015.

	December 31,
	2016			2015
	(In thousands)
Asset (liability) balance at beginning of period	$	(5,756	)	$	330
Change in fair value of Level 3 trades open at the beginning of the period	—			—
Fair value of trades entered into during the period	—			(5,756		)
Fair value reclassification from Level 3 to Level 2	5,756			(330		)
Asset (liability) balance at end of period	$	—		$	(5,756	)

As of December 31, 2016, we had no outstanding commodity price swap contracts.

As of December 31, 2016 and 2015, the carrying amount and estimated fair value of our debt was as follows:

	December 31,
	2016		2015
	(In thousands)
Western obligations:
Carrying amount	$	1,256,000	$	889,000
Fair value	1,277,956		867,178
NTI obligations:
Carrying amount	$	349,980	$	350,000
Fair value	363,542		360,500
WNRL obligations:
Carrying amount	$	320,300	$	445,000
Fair value	345,050		439,000

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 based on prices from recent trade activity and is categorized in Level 2 of the fair value hierarchy.

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).

Northern Tier Energy LP [Member]

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Fair Value Measurement

12. FAIR VALUE MEASUREMENTS

As defined in GAAP, fair value is the price that would be received for the sale of an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. GAAP describes three approaches to measuring the fair value of assets and liabilities: the market approach, the income approach and the cost approach, each of which includes multiple valuation techniques. The market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities. The income approach uses valuation techniques to measure fair value by converting future amounts, such as cash flows or earnings, into a single present value amount using current market expectations about those future amounts. The cost approach is based on the amount that would currently be required to replace the service capacity of an asset. This is often referred to as current replacement cost. The cost approach assumes that the fair value would not exceed what it would cost a market participant to acquire or construct a substitute asset of comparable utility, adjusted for obsolescence.

Accounting guidance does not prescribe which valuation technique should be used when measuring fair value and does not prioritize among the techniques. Accounting guidance establishes a fair value hierarchy that prioritizes the inputs used in applying the various valuation techniques. Inputs broadly refer to the assumptions that market participants use to make pricing decisions, including assumptions about risk. Level 1 inputs are given the highest priority in the fair value hierarchy while Level 3 inputs are given the lowest priority. The three levels of the fair value hierarchy are as follows:

• Level 1 – Observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active markets as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

• Level 2 – Observable market-based inputs or unobservable inputs that are corroborated by market data. These are inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date.

• Level 3 – Unobservable inputs that are not corroborated by market data and may be used with internally developed methodologies that result in management’s best estimate of fair value.

The Company uses a market or income approach for recurring fair value measurements and endeavors to use the best information available. Accordingly, valuation techniques that maximize the use of observable inputs are favored. The assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement of assets and liabilities within the levels of the fair value hierarchy.

The Company's current asset and liability accounts contain certain financial instruments, the most significant of which are trade accounts receivables and trade payables. The Company believes the carrying values of its current assets and liabilities approximate fair value. The Company's fair value assessment incorporates a variety of considerations, including the short-term duration of the instruments, the Company's historical incurrence of insignificant bad debt expense and the Company's expectation of future insignificant bad debt expense, which includes an evaluation of counterparty credit risk.

The following table provides the assets and liabilities carried at fair value measured on a recurring basis at December 31, 2016 and 2015:

	Balance at		Quoted prices in active markets		Significant other observable inputs		Unobservable inputs
(in millions)	December 31, 2016		(Level 1)		(Level 2)		(Level 3)
ASSETS
Cash and cash equivalents	$	29.5	$	29.5	$	—	$	—
Other current assets
Derivative asset - current	6.3		—		6.3		—
	$	35.8	$	29.5	$	6.3	$	—
LIABILITIES
Accrued liabilities
Derivative liability - current	$	6.0	$	—	$	6.0	$	—
	$	6.0	$	—	$	6.0	$	—

	Balance at		Quoted prices in active markets		Significant other observable inputs		Unobservable inputs
(in millions)	December 31, 2015		(Level 1)		(Level 2)		(Level 3)
ASSETS
Cash and cash equivalents	$	70.9	$	70.9	$	—	$	—
Other current assets
Derivative asset - current	1.9		—		1.9		—
	$	72.8	$	70.9	$	1.9	$	—
LIABILITIES
Accrued liabilities
Derivative liability - current	$	9.4	$	—	$	9.4	$	—
	$	9.4	$	—	$	9.4	$	—

As of December 31, 2016 and 2015, the Company had no Level 3 fair value assets or liabilities.

The Company's policy is to recognize transfers in and transfers out as of the actual date of the event or of the change in circumstances that caused the transfer. For the years ended December 31, 2016 and 2015, there were no transfers in or out of Levels 1, 2 or 3.

Assets not recorded at fair value on a recurring basis, such as property, plant and equipment, intangible assets and cost method investments, are recognized at fair value when they are impaired. During the years ended December 31, 2016, 2015 and 2014 there were no impairments of such assets.

The carrying value of debt, which is reported on the Company's consolidated balance sheets, reflects the cash proceeds received upon issuance, net of subsequent repayments. The fair value of the 2020 Secured Notes disclosed below was determined based on quoted prices in active markets (Level 1).

	December 31, 2016				December 31, 2015
(in millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
2020 Secured Notes	$	350.0	$	363.5	$	350.0	$	360.5

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Inventories

12 Months Ended

Dec. 31, 2016

Inventory [Line Items]

Inventories

5. Inventories

Inventories were as follows:

	December 31,
	2016		2015
	(In thousands)
Refined products (1)	$	325,889	$	201,928
Crude oil and other raw materials	395,131		288,403
Lubricants	10,121		14,996
Retail store merchandise	40,848		42,211
Inventories	$	771,989	$	547,538

(1) Includes $50.5 million and $14.5 million of inventory valued using the FIFO valuation method at December 31, 2016 and 2015, respectively.

As of December 31, 2016 and 2015, refined products valued under the LIFO method and crude oil and other raw materials totaled 10.9 million barrels and 10.0 million barrels, respectively. At December 31, 2016 and 2015, the excess of the LIFO cost over the current cost of these crude oil, refined product and other feedstock and blendstock inventories was $140.1 million and $198.4 million, respectively.

Cost of products sold included net non-cash charges of $58.3 million during the year ended December 31, 2016 and net non-cash recoveries of $170.0 million and $222.0 million during the years ended December 31, 2015 and 2014, respectively, from changes in our LIFO reserves.

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 $41.7 million and $175.1 million at December 31, 2016 and 2015, respectively. Cost of products sold included net non-cash LCM recoveries of $133.4 million for the year ended December 31, 2016 and charges of $96.5 million and $78.6 million for the years ended 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,
	2016			2015			2014
	(In thousands, except per share amount)
Increase (decrease) in operating income	$	(2,868	)	$	(16,111	)	$	1,097
Increase (decrease) in net income	(2,218		)	(11,808		)	777
Increase (decrease) in earnings per diluted share	$	(0.02	)	$	(0.12	)	$	0.01

Average LIFO cost per barrel of our refined products and crude oil and other raw materials inventories as of December 31, 2016 and 2015, was as follows:

	December 31,
	2016					2015
	Barrels	LIFO Cost		Average LIFO Cost Per Barrel		Barrels	LIFO Cost		Average LIFO Cost Per Barrel
	(In thousands, except cost per barrel)
Refined products	4,259	$	303,968	$	71.37	3,536	$	259,722	$	73.45
Crude oil and other	6,641	394,798		59.45		6,490	391,237		60.28
	10,900	$	698,766	64.11		10,026	$	650,959	64.93

Northern Tier Energy LP [Member]

Inventory [Line Items]

Inventories

5. INVENTORIES

	December 31,
(in millions)	2016			2015
Crude oil and refinery feedstocks	$	174.3		$	171.8
Refined products	160.2			162.0
Merchandise	22.1			22.8
Supplies and sundry items	18.8			19.0
	375.4			375.6
Lower of cost or market inventory reserve	(41.7		)	(134.4		)
Total	$	333.7		$	241.2

Inventories accounted for under the LIFO method comprised 89% of the total inventory value at both December 31, 2016 and 2015, prior to the application of the lower of cost or market reserve.

In order to state the Company's inventories at market values that were lower than its LIFO costs, the Company reduced the carrying values of its inventory through LCM reserves of $41.7 million and $134.4 million at December 31, 2016 and 2015, respectively.

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Prepaid Expenses

12 Months Ended

Dec. 31, 2016

Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]

Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Table Text Block]

6. Prepaid Expenses

Prepaid expenses were as follows:

	December 31,
	2016		2015
	(In thousands)
Prepaid crude oil and other raw materials inventories	$	49,405	$	23,793
Prepaid insurance	12,726		5,904
RINs	12,722		21,174
Prepaid income taxes	456		3,099
Other	20,046		19,243
Prepaid expenses	$	95,355	$	73,213

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Other Current Assets

12 Months Ended

Dec. 31, 2016

Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]

Other Current Assets [Text Block]

7. Other Current Assets

Other current assets were as follows:

	December 31,
	2016		2015
	(In thousands)
Material and chemical inventories	$	49,915	$	54,053
Excise and other taxes receivable	19,644		21,801
Margin account deposits	14,852		—
Fair value of open commodity hedging positions, net	13,649		78,125
Exchange and other receivables	15,361		15,749
Other current assets	$	113,421	$	169,728

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Equity Method Investment

12 Months Ended

Dec. 31, 2016

Schedule of Equity Method Investments [Line Items]

Equity Method Investments and Joint Ventures Disclosure [Text Block]

8. Equity Method Investment

We own a 17% common equity interest in MPL. The carrying value of this equity method investment was $102.7 million and $97.5 million at December 31, 2016 and 2015, respectively.

Summarized financial information for MPL for the years ended December 31, 2016, 2015 and 2014 and as of December 31, 2016 and 2015, was as follows:

	Year Ended December 31,
	2016		2015		2014
	(In thousands)
Revenues	$	215,564	$	206,195	$	184,712
Operating costs and expenses	57,444		88,909		141,250
Income from operations	158,120		117,286		43,462
Net income	137,476		96,485		22,821
Net income attributable to MPL unitholders	127,823		86,832		13,168

	December 31, 2016		December 31, 2015
	(In thousands)
Current assets	$	14,882	$	24,020
Noncurrent assets	491,955		441,825
Total assets	$	506,837	$	465,845
Current liabilities	$	26,827	$	17,658
Noncurrent liabilities	—		—
Total liabilities	$	26,827	$	17,658
Equity	$	480,010	$	448,187

As of December 31, 2016 and 2015, respectively, the carrying amount of the equity method investment was $21.1 million and $21.3 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 $16.3 million, $13.1 million and $7.5 million, respectively, for the years ended December 31, 2016, 2015 and 2014. Equity income from MPL was $21.7 million, $14.8 million and $2.2 million, respectively, for the years ended December 31, 2016, 2015 and 2014, and has been included in other, net in the accompanying Consolidated Statement of Operations.

Northern Tier Energy LP [Member]

Schedule of Equity Method Investments [Line Items]

Equity Method Investments and Joint Ventures Disclosure [Text Block]

6. EQUITY METHOD INVESTMENT

The Company has a 17% common equity interest in MPL. Additionally, in the third quarter of 2016, the Company received a 1.0% common equity interest in WNRL in connection with the Contribution Agreement (see Note 3), which was recorded at its historical cost given the transaction was treated as a transfer of assets under common control. The carrying value of these equity method investments was $87.3 million and $82.1 million at December 31, 2016 and 2015, respectively. The quoted market value of the Company's investment in WNRL at December 31, 2016 was $13.4 million.

Summarized financial information for MPL is as follows:

	Year Ended December 31,
(in millions)	2016		2015		2014
Revenues	$	215.6	$	206.2	$	184.7
Operating costs and expenses	57.5		88.9		141.3
Income from operations	158.1		117.3		43.4
Net income	137.5		96.5		22.8
Net income available to MPL common members	127.8		86.8		13.1

			December 31,
(in millions)			2016		2015
Balance sheet data:
	Current assets		$	14.8	$	24.0
	Noncurrent assets		492.0		441.8
		Total assets	$	506.8	$	465.8
	Current liabilities		$	26.8	$	17.7
	Noncurrent liabilities		—		—
		Total liabilities	26.8		17.7
	Members capital		$	480.0	$	448.1

As of December 31, 2016 and 2015, the carrying amount of the equity method investment in MPL was $5.7 million and $5.9 million higher, respectively, than the underlying net assets of the investee. The Company is amortizing this difference over the remaining life of MPL's primary asset (the fixed asset life of the pipeline).

The Company recorded $16.6 million, $13.1 million and $7.5 million in distributions for the years ended December 31, 2016, 2015 and 2014, respectively. Equity income from the Company's equity method investments was $21.9 million, $14.8 million and $2.2 million for the years ended December 31, 2016, 2015 and 2014, respectively.

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Property, Plant and Equipment, Net

12 Months Ended

Dec. 31, 2016

Property, Plant and Equipment [Line Items]

Property, Plant, and Equipment, Net

9. Property, Plant and Equipment, Net

Property, plant and equipment, net was as follows:

	December 31,
	2016			2015
	(In thousands)
Refinery facilities and related equipment	$	2,260,351		$	2,113,650
Pipelines, terminals and transportation equipment	560,478			427,854
Retail facilities and related equipment	333,187			324,686
Wholesale facilities and related equipment	52,284			59,875
Corporate	53,566			50,607
	3,259,866			2,976,672
Accumulated depreciation	(1,118,477		)	(923,415		)
	2,141,389			2,053,257
Construction in progress	223,093			251,914
Property, plant and equipment, net	$	2,364,482		$	2,305,171

Depreciation expense was $213.5 million, $201.2 million and $187.1 million for the years ended December 31, 2016, 2015 and 2014, respectively.

Northern Tier Energy LP [Member]

Property, Plant and Equipment [Line Items]

Property, Plant, and Equipment, Net

7. PROPERTY, PLANT AND EQUIPMENT

Major classes of property, plant and equipment ("PP&E") consisted of the following:

	Estimated	December 31,
(in millions)	Useful Lives	2016			2015
Land		$	7.7		$	9.0
Retail stores and equipment	2 - 22 years	80.5			72.3
Refinery and equipment	5 - 24 years	487.0			457.2
Buildings and building improvements	25 years	18.7			11.7
Software	5 years	18.9			18.9
Vehicles	5 years	3.2			5.6
Other equipment	2 - 7 years	10.8			10.4
Precious metals		10.4			10.2
Assets under construction		78.6			73.3
		715.8			668.6
Less: Accumulated depreciation		(198.0		)	(180.8		)
Property, plant and equipment, net		$	517.8		$	487.8

PP&E includes gross assets acquired under capital leases of $10.8 million and $13.3 million at December 31, 2016 and 2015, respectively, with related accumulated depreciation of $2.3 million and $2.0 million, respectively. The Company had depreciation expense related to capitalized software of $2.9 million, $3.7 million and $3.7 million for years ended December 31, 2016, 2015 and 2014, respectively. The Company capitalized interest expense related to capital projects within the refining segment of $6.4 million, $1.4 million and zero for the years ended December 31, 2016, 2015 and 2014, respectively.

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Goodwill

12 Months Ended

Dec. 31, 2016

Goodwill and Intangible Assets Disclosure [Abstract]

Goodwill Disclosure [Text Block]

10. Goodwill

At December 31, 2016 and 2015, we had goodwill of $1,289.4 million relating to the 2013 NTI Acquisition. 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 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.

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Intangible Assets, Net

12 Months Ended

Dec. 31, 2016

Indefinite-lived Intangible Assets [Line Items]

Intangible Assets, Net

11. Intangible Assets, Net

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

	December 31, 2016							December 31, 2015							Weighted Average Amortization Period (Years)
	Gross Carrying Value		Accumulated Amortization			Net Carrying Value		Gross Carrying Value		Accumulated Amortization			Net Carrying Value
	(In thousands)
Amortizable assets:
Licenses and permits	$	20,427	$	(15,307	)	$	5,120	$	20,427	$	(13,729	)	$	6,698	3.3
Customer relationships	7,172		(4,234		)	2,938		7,551		(3,921		)	3,630		5.5
Rights-of-way and other	8,538		(3,242		)	5,296		6,839		(1,797		)	5,042		5.0
	36,137		(22,783		)	13,354		34,817		(19,447		)	15,370
Unamortizable assets:
Franchise rights and trademarks	50,500		—			50,500		50,500		—			50,500
Liquor licenses	19,958		—			19,958		19,075		—			19,075
Intangible assets, net	$	106,595	$	(22,783	)	$	83,812	$	104,392	$	(19,447	)	$	84,945

Intangible asset amortization expense was $3.0 million, $2.9 million and $2.8 million for the years ended December 31, 2016, 2015 and 2014, 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):

2017	$	2,880
2018	2,880
2019	2,212
2020	1,268
2021	980

Northern Tier Energy LP [Member]

Indefinite-lived Intangible Assets [Line Items]

Intangible Assets, Net

8. INTANGIBLE ASSETS

Intangible assets are comprised of franchise rights and trade names amounting to $33.8 million at both December 31, 2016 and 2015. At both December 31, 2016 and 2015, the franchise rights and trade name intangible asset values were $12.4 million and $21.4 million, respectively. These assets have an indefinite life and are not amortized, but rather are tested for impairment annually or when events or changes in circumstances indicate that the fair value of the intangible asset has been reduced below carrying value. Based on the testing performed as of June 30, 2016, the Company noted no indications of impairment.

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Other Assets

12 Months Ended

Dec. 31, 2016

Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]

Investments and Other Noncurrent Assets [Text Block]

12. Other Assets

Other assets were as follows:

	December 31,
	2016		2015
	(In thousands)
Capital spare parts	$	12,717	$	8,112
Purchase agreement	9,762		16,067
Cost method investment	7,864		7,872
Notes receivable	4,366		4,586
Deposits	3,582		3,747
Fair value of open commodity hedging positions, net	8		11,881
Other	9,159		12,732
Other assets	$	47,458	$	64,997

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Accrued and Other Long-Term Liabilities

12 Months Ended

Dec. 31, 2016

Accrued Liabilities and Other Liabilities [Abstract]

Accounts Payable and Accrued Liabilities Disclosure [Text Block]

13. Accrued and Other Long-Term Liabilities

Accrued liabilities were as follows:

	December 31,
	2016		2015
	(In thousands)
Excise and other taxes	$	68,116	$	67,932
Payroll and related costs	66,021		77,482
Professional and other	24,146		28,093
Property taxes	23,387		20,175
Interest	17,248		17,093
Fair value of open commodity hedging positions, net	10,827		10,273
Environmental reserves	6,945		10,099
Banking fees and other financing	2,718		189
Income taxes	199		—
Margin and other customer deposits	—		17,059
Accrued liabilities	$	219,607	$	248,395

Other long-term liabilities were as follows:

	December 31,
	2016		2015
	(In thousands)
Unrecognized tax benefits	$	58,317	$	42,049
Retiree plan obligations and other	18,725		10,529
Asset retirement obligations	8,484		7,822
Environmental reserves	6,839		8,195
Fair value of open commodity hedging positions, net	771		—
Other long-term liabilities	$	93,136	$	68,595

The table below summarizes changes in our environmental liability accruals:

	December 31, 2015		Increase (Decrease)		Payments			December 31, 2016
	(In thousands)
Discounted liabilities	$	3,633	$	300	$	(433	)	$	3,500
Undiscounted liabilities	14,661		626		(5,003		)	10,284
Total environmental liabilities	$	18,294	$	926	$	(5,436	)	$	13,784

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Asset Retirement Obligations

12 Months Ended

Dec. 31, 2016

Guarantor Obligations [Line Items]

Asset Retirement Obligations

14. Asset Retirement Obligations

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

We have identified the following AROs:

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

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

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

The following table reconciles the beginning and ending aggregate carrying amount of our AROs for the three years ended December 31, 2016:

	December 31,
	2016			2015			2014
	(In thousands)
Liability, beginning of period	$	7,822		$	7,539		$	7,327
Liabilities incurred	566			58			17
Liabilities acquired	—			—			—
Liabilities settled	(479		)	(187		)	(313		)
Accretion expense	575			412			508
Liability, end of period	$	8,484		$	7,822		$	7,539

Our ARO liability excludes $0.2 million of ARO classified as accrued liabilities as of December 31, 2016 and 2015, respectively.

Northern Tier Energy LP [Member]

Guarantor Obligations [Line Items]

Asset Retirement Obligations

13. ASSET RETIREMENT OBLIGATIONS

The following table summarizes the changes in asset retirement obligations:

	Year Ended December 31,
(in millions)	2016			2015			2014
Asset retirement obligation balance at beginning of period	$	2.4		$	2.4		$	2.2
Costs incurred to remediate	(0.2		)	(0.3		)	—
Accretion expense	0.2			0.3			0.2
Asset retirement obligation balance at end of period	$	2.4		$	2.4		$	2.4

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Long-Term Debt

12 Months Ended

Dec. 31, 2016

Debt Instrument [Line Items]

Long-term Debt [Text Block]

15. Long-Term Debt

Long-term debt was as follows:

	December 31,
	2016			2015
	(In thousands)
Western obligations:
Revolving Credit Facility due 2019	$	—		$	—
Term Loan - 5.25% Credit Facility due 2020	533,500			539,000
6.25% Senior Unsecured Notes due 2021	350,000			350,000
Term Loan - 5.50% Credit Facility due 2023	372,500			—
Total Western obligations	1,256,000			889,000
NTI obligations:
Revolving Credit Facility due 2019	—			—
7.125% Senior Secured Notes, due November 2020	349,980			350,000
Total NTI obligations	349,980			350,000
WNRL obligations:
Revolving Credit Facility due 2018	20,300			145,000
7.5% Senior Notes due 2023	300,000			300,000
Total WNRL obligations	320,300			445,000
Less unamortized discount, premium and debt issuance costs	43,975			33,606
Long-term debt	1,882,305			1,650,394
Current portion of long-term debt	(10,500		)	(5,500		)
Long-term debt, net of current portion	$	1,871,805		$	1,644,894

As of December 31, 2016, annual long-term debt maturities in 2017, 2018, 2019, 2020 and 2021 are $10.5 million, $30.8 million, $10.5 million, $872.0 million and $355.0 million, respectively. Thereafter, total long-term debt maturities are $647.5 million.

Interest and debt expense were as follows:

	Year Ended December 31,
	2016			2015			2014
	(In thousands)
Contractual interest:
Western obligations	$	62,893		$	45,248		$	51,114
NTI obligations	24,462			24,474			20,342
WNRL obligations	24,325			21,079			1,096
	111,680			90,801			72,552
Amortization of loan fees	9,125			7,561			7,786
Amortization of original issuance discount	790			—			7,352
Other interest expense	12,377			9,059			11,717
Capitalized interest	(10,681		)	(1,818		)	(2,345		)
Interest and debt expense	$	123,291		$	105,603		$	97,062

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.

Tesoro Merger

In anticipation of the merger with Western, Tesoro has incurred additional indebtedness to redeem or repay in full, as applicable, the outstanding debt of Western Refining and certain of its subsidiaries. Following completion of the Tesoro Merger, WNRL's 7.5% Senior Notes and any amounts outstanding under its revolving credit facility are expected to remain outstanding.

Western Obligations

Revolving Credit Facility

On May 27, 2016, we entered into the Second Amendment to the Third Amended and Restated Revolving Credit Agreement (the "Western 2019 Revolving Credit Facility"). The amendment amended the Western 2019 Revolving Credit Facility by, among other things, (i) permitting us to incur up to $500.0 million of additional secured indebtedness secured on a pari passu basis with the loans under the Western 2020 Term Loan Credit Facility (in the form of incremental term loans or bonds secured on a pari passu basis with the term loans) beyond what was permitted under the Western 2019 Revolving Credit Facility and (ii) modifying several triggers and thresholds based on borrowing availability under the Western 2019 Revolving Credit Facility.

On October 2, 2014, we entered into the Third Amended and Restated Revolving Credit Agreement. 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. 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, 2016, we had no direct borrowings under the Western 2019 Revolving Credit Agreement, and we had net availability under the Western 2019 Revolving Credit Facility of $266.6 million. This availability is net of $92.9 million in outstanding letters of credit.

Term Loan Credit Agreement - 5.25%

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. On May 27, 2016, the Company entered into a third amendment of the Western 2020 Term Loan Credit Facility. The revised terms under the amendment provide for additional capacity to make restricted payments including dividends and repurchase of the Company’s outstanding common stock, inclusion of equity interests of master limited partnership subsidiaries as “replacement assets” for purposes of asset sale mandatory prepayment and changes to the use of proceeds of the incremental term loan available under the Western 2020 Term Loan Credit Facility. The third amendment also increased the incremental availability under the Western 2020 Term Loan Credit Facility from $200.0 million, prior to the amendment, to $700.0 million.

Following the third amendment, 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 2.25% or the LIBOR Rate (as defined in the Western 2020 Term Loan Credit Facility) plus 4.25% (subject to a LIBOR Rate floor of 1.00%). The current interest rate based on these criteria is 5.25%. Our effective rate of interest, including contractual interest and amortization of loan fees, for the Western 2020 Term Loan Credit Facility was 5.80% as of December 31, 2016.

The Western 2020 Term Loan Credit Facility is secured by the El Paso and Gallup refineries and the equity of NT InterHoldCo LLC, a 100% owned subsidiary of Western, and is fully and unconditionally guaranteed on a joint and several basis by certain of Western's material 100% owned subsidiaries. The Western 2020 Term Loan Credit Facility contains customary restrictive covenants including limitations on debt, investments and dividends and does not contain any financial maintenance covenants.

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 100% 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 effective rate of interest, including contractual interest and amortization of loan fees, for the Western 2021 Senior Unsecured Notes was 6.52% as of December 31, 2016.

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.

Term Loan Credit Agreement - 5.50%

On June 23, 2016, as an incremental supplement to the Western 2020 Term Loan Credit Facility, we incurred $500.0 million in new term debt that matures on June 23, 2023 (the "Western 2023 Term Loan Credit Facility"). The proceeds from the Western 2023 Term Loan Credit Facility were net of original issue discount and other fees totaling $17.0 million. We used these proceeds to partially fund the cash portion of the NTI Merger consideration. The Western 2023 Term Loan Credit Facility provides for quarterly principal payments of $1.3 million payable on the last business day of each March, June, September and December, with the remaining principal amount due on June 23, 2023. The Western 2023 Term Loan Credit Facility is secured by both the El Paso and Gallup refineries and by the equity of NT InterHoldCo LLC and is fully and unconditionally guaranteed on a joint and several basis by certain of Western's material 100% owned subsidiaries. The Western 2023 Term Loan Credit Facility bears interest at a rate based either on the base rate plus 3.50% or the LIBOR Rate plus 4.50% (subject to a LIBOR Rate floor of 1.00%). On December 29, 2016, we made a non-mandatory prepayment of $125.0 million under our Western 2023 Term Loan Credit Facility. The effective rate of interest, including contractual interest and amortization of original issue discount and other loan fees, for the Western 2023 Term Loan Credit Facility was 6.30% as of December 31, 2016.

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 the 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 the 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 the 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 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 Western 2021 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.

As of December 31, 2016, the availability under the NTI Revolving Credit Facility was $214.9 million. This availability is net of $70.6 million in outstanding letters of credit. There were no borrowings under the NTI Revolving Credit Facility at December 31, 2016.

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 and financing costs are both amortized to interest expense over the remaining life of the notes. The effective rate of interest, including contractual interest and amortization of debt premium and of loan fees, for the NTI 2020 Secured Notes was 6.91% as of December 31, 2016.

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 100% owned domestic subsidiaries of NTI LLC. The indenture governing the NTI 2020 Secured Notes contains covenants that limit or restrict dividends or other payments from restricted subsidiaries. Indebtedness under the NTI 2020 Secured Notes is guaranteed by NTI and certain of their subsidiaries.

WNRL Obligations

Revolving Credit Facility

On October 16, 2013, WNRL entered into a $300.0 million senior secured revolving credit facility (the "WNRL Revolving Credit Facility"). On September 15, 2016, in connection with the St. Paul Park Logistics Transaction, WNRL entered into an agreement to increase the total commitment of the WNRL Revolving Credit Facility (the "Amendment") to $500.0 million. WNRL has the ability to increase the total commitment of the WNRL Revolving Credit Facility by up to $150.0 million for a total facility size of up to $650.0 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.

In addition to the increased facility size, the Amendment amended the WNRL Revolving Credit Facility by, among other things, (a) adding an anti-cash hoarding provision and (b) permitting WNRL to increase the Total Leverage Ratio permitted thereunder from 4.50:1.00 to 5.00:1.00 following any material permitted acquisition through the last day of the second full fiscal quarter following such acquisition. The incremental commitments established by the Amendment benefit from the same covenants, events of default, guarantees and security as the existing commitments under 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. During the year ended December 31, 2016, WNRL repaid $179.1 million of its outstanding direct borrowings under the WNRL Revolving Credit Facility using the proceeds generated through our equity issuances during the period. On September 15, 2016, to partially fund the purchase of the St. Paul Park Logistics Assets, WNRL borrowed $20.3 million under the WNRL Revolving Credit Facility.

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, 2016, the availability under the WNRL Revolving Credit Facility was $479.0 million, net of $20.3 million direct borrowings and $0.7 million in outstanding letters of credit. The interest rate for the borrowings under the WNRL Revolving Credit Facility was 4.75% as of December 31, 2016. The effective rate of interest, including contractual interest and amortization of loan fees, for the WNRL Revolving Credit Facility was 3.77% as of December 31, 2016.

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 100% 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 effective rate of interest, including contractual interest and amortization of loan fees, for the 7.5% Senior Notes was 7.78% as of December 31, 2016.

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.

Northern Tier Energy LP [Member]

Debt Instrument [Line Items]

Long-term Debt [Text Block]

10. DEBT

ABL Facility

On September 29, 2014, NTE LLC and its subsidiaries entered into an amended and restated asset-based ABL Facility with JPMorgan Chase Bank, N.A., as administrative agent for the lenders and as collateral agent for the other secured parties (the "ABL Facility"). The borrowers under the ABL Facility are SPPR, NTB, NTR and SAF, each of which is a wholly owned subsidiary of NTE LLC.

Lenders under the ABL Facility hold commitments totaling $500 million, which is subject to a borrowing base comprised of eligible accounts receivable and inventory. The ABL 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). The ABL Facility matures on September 29, 2019. The Company incurred financing costs associated with the new ABL Facility of $3.0 million which will be amortized to Interest expense, net through the date of maturity.

The ABL Facility is guaranteed, on a joint and several basis, by NTE LLC and its subsidiaries and will be guaranteed by any newly acquired or formed subsidiaries, subject to certain limited exceptions. The ABL Facility and such guarantees are secured on a first priority basis by substantially all of NTE LLC's and such subsidiaries' cash and cash equivalents, accounts receivable and inventory and on a second priority basis by NTE LLC's and such subsidiaries' fixed assets (other than real property).

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 ABL 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.

Borrowing availability under the ABL Facility is tied to a borrowing base dependent upon the amount of eligible accounts receivable and inventory. As of December 31, 2016, the borrowing base under the ABL Facility was $285.5 million and availability under the ABL Facility was $214.9 million. This availability is net of $70.6 million in outstanding letters of credit. The borrowers under the ABL Facility had no borrowings outstanding under the ABL Facility at December 31, 2016.

2020 Secured Notes

As of December 31, 2016 and 2015, the Company had $350.0 million of outstanding aggregate principal of our 7.125% senior secured notes due 2020 (the "2020 Secured Notes'). On September 29, 2014, the Company issued an additional $75.0 million of the 2020 Secured Notes at 105.75% of par for gross proceeds of $79.2 million. This offering was issued under the same indenture and associated terms as the existing 2020 Secured Notes. The issuance premium of $4.2 million and financing costs of $2.5 million associated with this offering are both being amortized to Interest expense, net over the remaining term of the notes.

The 2020 Secured Notes are guaranteed, jointly and severally, on a senior secured basis by all of the Company's existing and future 100% direct and indirect subsidiaries on a full and unconditional basis; however, there are certain obligations not guaranteed on a full and unconditional basis as a result of subsidiaries being released as guarantors. A subsidiary guarantee can be released under customary circumstances, including (a) the sale of the subsidiary, (b) the subsidiary being declared "unrestricted," (c) the legal or covenant defeasance or satisfaction and discharge of the indenture, or (d) liquidation or dissolution of the subsidiary. Separate condensed consolidated financial information is not included as the guarantor company, NTE LP, does not have independent assets or operations. The 2020 Secured Notes and the subsidiary note guarantees are secured on a pari passu basis with certain hedging agreements by a first-priority security interest in substantially all present and hereinafter acquired tangible and intangible assets of NTE LLC and each of the subsidiary guarantors and by a second-priority security interest in the inventory, accounts receivable, investment property, general intangibles, deposit accounts and cash and cash equivalents collateralized by a $500 million secured asset-based ABL Facility with a maturity date of September 29, 2019. Additionally, the 2020 Secured Notes are fully and unconditionally guaranteed on a senior unsecured basis by NTE LP. NTE LP's creditors have no recourse to the assets of Western and its subsidiaries. Western's creditors have no recourse to the assets of NTE LP and its subsidiaries. The Company is required to make interest payments on May 15 and November 15 of each year, which commenced on May 15, 2013. There are no scheduled principal payments required prior to the 2020 Secured Notes maturing on November 15, 2020. The outstanding $350.0 million in 2020 Secured Notes are registered with SEC through two separate registrations occurring in October 2013 and January 2015.

At any time prior to the maturity date of the notes, the Company may, at its option, redeem all or any portion of the notes for the outstanding principal amount plus unpaid interest and a make-whole premium as defined in the indenture. If the Company experiences a change in control or makes certain asset dispositions, as defined under the indenture, the Company may be required to repurchase all or part of the notes plus unpaid interest and, in certain cases, pay a redemption premium.

The 2020 Secured Notes contain certain covenants that, among other things, limit the ability, subject to certain exceptions, of the Company to incur additional debt or issue preferred equity interests, to purchase, redeem or otherwise acquire or retire its equity interests, to make certain investments, loans and advances, to sell, lease or transfer any of its property or assets, to merge, consolidate, lease or sell substantially all of the Company's assets, to suffer a change of control or to enter into new lines of business. Following the Company's sale of its terminal and tank assets to WNRL in September 2016 (see Note 3), the Company commenced a tender offer in October 2016 to all holders of the 2020 Secured Notes. This tender offer allowed noteholders to require the Company to purchase outstanding notes at par plus accrued interest. Notes totaling $0.02 million were tendered for redemption.

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Income Taxes

12 Months Ended

Dec. 31, 2016

Operating Loss Carryforwards [Line Items]

Income Taxes

16. Income Taxes

The following is an analysis of our consolidated income tax expense for the three years ended December 31, 2016:

	Year Ended December 31,
	2016			2015			2014
	(In thousands)
Current:
Federal	$	63,421		$	228,457		$	187,320
State	7,231			30,222			32,581
Total current	70,652			258,679			219,901
Deferred:
Federal	(7,262		)	(27,876		)	63,182
State	(8,522		)	(6,848		)	9,521
Total deferred	(15,784		)	(34,724		)	72,703
Provision for income taxes	$	54,868		$	223,955		$	292,604

We paid income tax, net of refunds, of $38.2 million, $283.3 million and $228.0 million for the years ended December 31, 2016, 2015 and 2014, 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, 2016:

	Year Ended December 31,
	2016			2015			2014
	(In thousands)
Taxes at the federal statutory rate	$	84,656		$	293,435		$	350,937
State income taxes, net of federal tax benefit (1)	3,601			13,637			31,477
Valuation allowance for state net operating losses	(3,848		)	—			(2,887		)
Domestic Activity Production deduction	(2,843		)	(14,000		)	(11,900		)
Non-controlling interests	(21,723		)	(70,214		)	(50,044		)
Federal tax credit for production of ultra low sulfur diesel	—			—			(15,486		)
UTP releases	(10,823		)	(1,138		)	(2,266		)
Federal tax credit for increasing research activities	(3,780		)	1,176			(2,256		)
Impact of allocating deferred taxes associated with investment in NTI	8,132			—			—
Other, net	1,496			1,059			(4,971		)
Total income tax expense	$	54,868		$	223,955		$	292,604

(1) State income taxes, net of federal tax benefit, include $0.2 million, $5.0 million and $0.8 million in unrecognized tax benefits for the years ended December 31, 2016, 2015 and 2014, respectively.

The effective tax rates for 2016, 2015 and 2014 were 22.7%, 26.7% and 29.2%, respectively, as compared to the federal statutory rate of 35% in all years.

The following is a reconciliation of unrecognized tax benefits for the three years ended December 31, 2016:

	December 31,
	2016			2015			2014
	(In thousands)
Unrecognized tax benefits at beginning of year	$	40,174		$	13,762		$	10,571
Increases related to current year tax positions	36,281			1,100			1,500
Increases related to prior year tax positions	2,651			26,329			3,845
Decreases related to prior year tax positions	(19,180		)	(1,017		)	(2,154		)
Decreases resulting from the expiration of the statute of limitations	(4,142		)	—			—
Unrecognized tax benefits at end of year	$	55,784		$	40,174		$	13,762

We recorded unrecognized tax benefits as of December 31, 2016 of $55.8 million, of which $13.4 million would affect our effective tax rate if recognized. We believe that it is reasonably possible that a decrease of up to $2.1 million in unrecognized tax benefits related to federal exposures may be necessary within the coming year. We had accrued interest or penalties of $0.7 million with respect to the unrecognized tax benefit.

The Internal Revenue Service (the "IRS") has finalized examinations of our tax years ending December 31, 2011, 2010, 2009, 2008 and 2007. We are subject to examination by the IRS for tax years ending December 31, 2013, or after, and by various state and local taxing jurisdictions for tax years ending December 31, 2012, or after.

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

	December 31,
	2016									2015
	Assets			Liabilities			Net			Assets			Liabilities			Net
	(In thousands)
Inventories	$	—		$	(61,850	)	$	(61,850	)	$	—		$	(28,411	)	$	(28,411	)
Stock-based compensation	3,388			—			3,388			1,614			—			1,614
Property, plant and equipment	—			(357,044		)	(357,044		)	—			(261,476		)	(261,476		)
Investment in WNRL	147,625			—			147,625			77,824			—			77,824
Investment in NTI (1)	—			—			—			—			(81,789		)	(81,789		)
Postretirement obligations	2,117			—			2,117			2,595			—			2,595
Commodity hedging activities	—			(671		)	(671		)	—			(33,260		)	(33,260		)
Environmental and retirement obligations	3,975			—			3,975			3,742			—			3,742
Other, net	—			(1,750		)	(1,750		)	6,247			—			6,247
Net operating loss and tax credit carryforwards	20,897			—			20,897			20,828			—			20,828
Valuation allowance	(16,980		)	—			(16,980		)	(20,828		)	—			(20,828		)
Net deferred taxes	$	161,022		$	(421,315	)	$	(260,293	)	$	92,022		$	(404,936	)	$	(312,914	)

(1) Following the NTI Merger on June 23, 2016, our deferred tax liability associated with our investment in NTI was allocated amongst the individual temporary differences presented in this table.

At December 31, 2016, 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	$	(4,833	)	$	(243	)	2023
Virginia and Maryland	(17,200		)	(737		)	2024
Virginia and Maryland	(503		)	(22		)	2026
Virginia and Maryland	(31,219		)	(1,337		)	2028
Virginia and Maryland	(56,838		)	(2,435		)	2029
Virginia and Maryland	(98,316		)	(4,212		)	2030
Virginia and Maryland	(132,582		)	(5,680		)	2031
Virginia and Maryland	(129,268		)	(5,503		)	2032
Other	(1,070		)	(221		)	2027
Texas	(507		)	(507		)	2035
Total state NOL carryforwards	(472,336		)	(20,897		)
Less valuation allowance for operating loss carryforwards	395,130			16,980
Total credits and NOL carryforwards	$	(77,206	)	$	(3,917	)

In assessing the realizability of deferred tax assets, we determined that a valuation allowance of $17.0 million was appropriate against the deferred tax assets relating to the NOL carryforwards at December 31, 2016. We have decreased the valuation allowance for the NOL carryforwards by $3.8 million from December 31, 2015.

Northern Tier Energy LP [Member]

Operating Loss Carryforwards [Line Items]

Income Taxes

4. INCOME TAXES

NTE LP is treated as a partnership for federal and state income tax purposes. However, NTRH, the parent company of NTR and NTB, is taxed as a corporation for federal and state income tax purposes. No provision for income tax is calculated on the earnings of the Company or its subsidiaries, other than NTRH, as these entities are pass-through entities for tax purposes.

On July 31, 2012, NTRH was established as the parent company of NTR and NTB. NTRH elected to be taxed as a corporation for federal and state income tax purposes effective August 1, 2012. Prior to that, no provision for income tax was calculated on earnings of the Company or its subsidiaries as all entities were non-taxable.

	Year Ended December 31,
(in millions)	2016		2015		2014
Current tax expense	$	2.5	$	5.6	$	4.5
Deferred tax expense	$	1.8	$	2.8	$	2.6
Income tax provision	$	4.3	$	8.4	$	7.1

The Company's effective tax rate for the years ended December 31, 2016, 2015 and 2014 was 5.3%, 2.5% and 2.9%, respectively, as compared to the Company's consolidated federal and state expected statutory tax rate of 40.4%, 41.4% and 40.4% for the years ended December 31, 2016, 2015 and 2014, respectively. The Company's effective tax rate was lower than the statutory rate for the years ended December 31, 2016, 2015 and 2014 primarily due to the fact that only the retail operations of the Company are taxable entities.

The following is a reconciliation of income tax expense to income taxes computed by applying the applicable statutory federal income tax rate of 34% for 2016 and 35% for 2015 and 2014 to income before income taxes for the applicable periods:

	Year Ended December 31,
(in millions)	2016			2015			2014
Federal statutory rate applied to income before taxes	$	27.5		$	118.8		$	87.0
Taxes on earnings attributable to flow-through entities	(24.2		)	(112.4		)	(81.0		)
State and local income taxes, net of federal income tax effects	0.6			1.2			1.0
Work opportunity tax credit	(0.2		)	(0.4		)	(0.3		)
Other, net	0.6			1.2			0.4
Income tax provision	$	4.3		$	8.4		$	7.1

As a result of the Company's analysis, management has determined that the Company does not have any material uncertain tax positions. As of December 31, 2016 and 2015, the Company had no deferred tax assets arising from net operating losses. The Company is subject to U.S. federal and state income tax examinations for periods subsequent to 2012. The Company classifies interest to be paid on an underpayment of income taxes and any related penalties as income tax expense.

The net deferred tax assets (liabilities) as of December 31, 2016 and 2015 consisted of the following components:

		December 31,
(in millions)		2016			2015
Deferred tax assets:
	Lease financing obligations	$	2.3		$	2.2
	Customer loyalty accrual	0.6			0.4
	Annual bonus	0.4			0.5
	UNICAP	0.6			0.2
	Other	0.1			0.3
Deferred tax assets		4.0			3.6
Deferred tax liabilities:
	Accelerated depreciation	(5.2		)	(6.3		)
	Intangible assets	(12.1		)	(12.0		)
	LIFO	(0.7		)	(1.1		)
	Other	(0.3		)	(0.3		)
Deferred tax liabilities		(18.3		)	(19.7		)
Total deferred taxes, net		$	(14.3	)	$	(16.1	)

The net deferred tax assets (liabilities) are included in the December 31, 2016 and 2015 balance sheets as components of other liabilities.

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Retirement Plans

12 Months Ended

Dec. 31, 2016

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Retirement Plans

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

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. The Cash Balance Plan was amended as of December 31, 2016 to eliminate all future pay credits under the plan. This plan change was recognized as a curtailment during the year ended December 31, 2016.

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 ten years of service and be between the ages of 55 and 65 years old.

The following tables set forth significant information about the Cash Balance Plan and the Retiree Medical Plan. The reconciliation of the benefit obligation, plan assets, funded status and significant assumptions are based upon an annual measurement date of December 31, 2016:

	Cash Balance Plan						Retiree Medical Plan
	As of December 31,
	2016			2015			2016			2015
	(In thousands)
Benefit obligation at beginning of period	$	8,927		$	6,965		$	345		$	3,098
Service cost	2,196			2,326			—			315
Interest cost	488			366			8			135
Actuarial (gain) loss	490			(151		)	(197		)	(697		)
Plan amendments	—			—			—			(2,463		)
Plan participants' contributions	—			—			12			26
Benefits paid	(675		)	(579		)	(42		)	(69		)
Curtailments	(149		)	—			—			—
Benefit obligation at end of period	$	11,277		$	8,927		$	126		$	345
Fair value of plan assets at beginning of period	$	5,932		$	4,319		$	—		$	—
Employer contribution	2,748			2,200			30			43
Actual return on plan assets	134			(8		)	—			—
Benefits paid	(675		)	(579		)	(42		)	(69		)
Plan participants' contributions	—			—			12			26
Fair value of plan assets at end of period	$	8,139		$	5,932		$	—		$	—
Current liabilities	—			—			31			61
Non-current liabilities	3,138			2,995			95			284
Underfunded status recognized in the consolidated balance sheets	$	3,138		$	2,995		$	126		$	345
Accumulated benefit obligation	$	11,277		$	8,927		$	126		$	345

	Cash Balance Plan									Retiree Medical Plan
	As of December 31,
	2016			2015			2014			2016			2015			2014
	(In thousands)
Net periodic benefit cost includes:
Service cost	$	2,196		$	2,326		$	2,054		$	—		$	315		$	231
Interest cost	488			366			327			8			135			116
Expected return on assets	(273		)	(165		)	(218		)	—			—			—
Recognized net actuarial loss	12			22			—			13			32			—
Amortization of prior service cost	25			24			25			(291		)	137			137
Curtailments	270			—			—			—			—			—
Net periodic benefit cost	$	2,718		$	2,573		$	2,188		$	(270	)	$	619		$	484
Changes recognized in other comprehensive income:
Prior service cost amortization	$	(24	)	$	(24	)	$	(24	)	$	291		$	(137	)	$	(137	)
Recognized net actuarial loss	(12		)	—			—			(13		)	(32		)	—
Prior service credit	—			—			—			—			(2,463		)	—
Net actuarial loss (gain)	629			22			687			(197		)	(697		)	675
Prior service cost amortization - curtailment	(271		)	—			—			—			—			—
Net curtailment gain	(149		)	—			—			—			—			—
Pre-tax unrecognized net loss (gain) included in accumulated other comprehensive income at end of period	$	173		$	(2	)	$	663		$	81		$	(3,329	)	$	538

	Cash Balance Plan						Retiree Medical Plan
	As of December 31,
	2016		2015		2014		2016		2015		2014
Weighted average assumptions used to determine benefit obligations at December 31:
Discount rate	4.00	%	4.50	%	4.00	%	2.75	%	2.50	%	4.00	%
Rate of compensation increase	3.00		3.00		3.00		N/A		N/A		N/A
Weighted average assumptions used to determine net periodic benefit cost:
Discount rate (1)	4.50% / 3.75%		4.00		5.00		2.50		4.00		5.00
Expected long-term return on assets (1)	4.25% / 3.50%		3.75		4.75		N/A		N/A		N/A
Rate of compensation increase	3.00		3.00		4.00		N/A		N/A		N/A

(1) The rates for 2016 are disclosed pre-curtailment and post-curtailment, respectively.

The health care cost trend rate for the Retiree Medical Plan for 2016 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 $2.7 million, $2.2 million and $0.2 million were made during the period ended December 31, 2016, 2015 and 2014, 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. we expect funding requirements of approximately $2.3 million during the year ended December 31, 2017.

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

	Cash Balance Plan		Retiree Medical Plan
2017	$	1,150	$	31
2018	439		14
2019	493		15
2020	544		16
2021	528		17
2022 - 2026	2,849		46

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 4.37% and 4.43% at December 31, 2016 and 2015, respectively, to determine the benefit obligation, the components of the postretirement obligation were:

	As of December 31,
	2016			2015
	(In thousands)
Benefit obligation at beginning of year	$	5,893		$	6,735
Service cost	104			124
Interest cost	212			251
Benefits paid	(145		)	(182		)
Actuarial gain	(1,157		)	(1,035		)
Benefit obligation at end of year	$	4,907		$	5,893
Underfunded status	$	4,907		$	5,893
Current liabilities	$	150		$	202
Non-current liabilities	4,757			5,691
Underfunded status recognized in the consolidated balance sheets	$	4,907		$	5,893

	Year Ended December 31,
	2016			2015			2014
	(In thousands)
Net periodic benefit cost includes:
Service cost	$	104		$	124		$	92
Interest cost	212			251			264
Amortization of net actuarial loss (gain)	(11		)	23			20
Net periodic benefit cost	$	305		$	398		$	376
Pre-tax unrecognized net loss included in accumulated other comprehensive income at beginning of year	$	538		$	1,596		$	784
Net actuarial loss (gain)	(1,157		)	(1,035		)	792
Amortization of net actuarial loss (gain)	11			(23		)	20
Pre-tax unrecognized net loss (gain) included in accumulated other comprehensive income at end of year	$	(608	)	$	538		$	1,596

The weighted average discount rates used to determine net periodic benefit costs were 4.43%, 4.09% and 4.88% for 2016, 2015 and 2014, respectively. The following benefit payments (in thousands) are expected to be paid in the year indicated:

2017	$	153
2018	158
2019	164
2020	173
2021	181
2022 - 2026	1,092

The health care cost trend rate for the plan covering El Paso employees for 2016 and future years is capped at 4.00%. The health care cost trend rate for the plan covering Yorktown employees for 2016 is 4.50% and 4.50% in 2017. 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	$	(46	)
Effect on accumulated benefit obligation	13		(560		)

(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,
	2016			2015			2014
	(In thousands)
Beginning of period balance	$	651		$	(1,291	)	$	(350	)
Amortization of net prior service cost	(183		)	83			63
Net prior service credit	—			945			—
Reclassification of loss to income	—			50			21
Pension plan termination adjustment	420			—			—
Actuarial gain (loss)	724			1,267			(1,320		)
Income tax	(386		)	(403		)	295
End of period balance	$	1,226		$	651		$	(1,291	)

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 $10.2 million, $10.0 million and $9.1 million in connection with this plan for the years ended December 31, 2016, 2015 and 2014, respectively.

We sponsor a qualified defined contribution plan for eligible NTI employees. Eligibility is based upon a minimum age requirement and a minimum level of service. Participants may make contributions of a percentage of their annual compensation subject to Internal Revenue Service limits. In 2016, we provided a non-matching contribution of 3.0% of eligible compensation and a matching contribution at the rate of 100% of a participant's contribution up to 6.0%. Total contributions were $7.5 million, $7.4 million and $7.1 million for the years ended December 31, 2016, 2015 and 2014, respectively.

Northern Tier Energy LP [Member]

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Retirement Plans

15. EMPLOYEE BENEFIT PLANS

Defined Contribution Plans

The Company sponsors one qualified defined contribution plan for eligible employees. Eligibility is based upon a minimum age requirement and a minimum level of service. Participants may make contributions of a percentage of their annual compensation subject to Internal Revenue Service limits. In 2016, the Company provides a non-matching contribution of 3.0% of eligible compensation and a matching contribution at the rate of 100% of a participant's contribution up to 6.0%. Total Company contributions to the Retirement Savings Plans were $7.5 million, $7.4 million and $7.1 million for the years ended December 31, 2016, 2015 and 2014, respectively.

Cash Balance Plan

The Company sponsors a defined benefit cash balance pension plan (the "Cash Balance Plan") for eligible employees. In the fourth quarter 2016, the Company curtailed this benefit effective January 1, 2017 whereby the Company will no longer credit employees for service or interest related to service years after 2016. The Company will continue to sponsor the plan until all benefit obligations are exhausted. Prior to this change, Company contributions made to the cash account of the participants were equal to 5.0% of eligible compensation. Participants' cash accounts also received 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.

Funded Status and Net Period Benefit Costs

The changes to the benefit obligation, fair value of plan assets and funded status of the Cash Balance Plan for the years ended December 31, 2016, 2015 and 2014 were as follows:

			Cash Balance Plan
			Year Ended December 31,
(in millions)			2016			2015			2014
Change in benefit obligation:
	Benefit obligation at beginning of year		$	8.9		$	7.0		$	4.6
		Service cost	2.2			2.3			2.1
		Interest cost	0.5			0.4			0.3
		Actuarial loss (gain)	0.5			(0.2		)	0.6
		Curtailments	(0.1		)	—			—
		Benefits paid	(0.7		)	(0.6		)	(0.6		)
	Benefit obligation at end of year		11.3			8.9			7.0
Change in plan assets:
	Fair value of plan assets at beginning of year		5.9			4.3			4.6
		Employer contributions	2.8			2.2			0.2
		Return on plan assets	0.1			—			0.1
		Benefits paid	(0.7		)	(0.6		)	(0.6		)
	Fair value of plan assets at end of year		8.1			5.9			4.3
Reconciliation of funded status:
	Fair value of plan assets at end of year		8.1			5.9			4.3
	Benefit obligation at end of year		11.3			8.9			7.0
	Underfunded status at end of year		$	(3.2	)	$	(3.0	)	$	(2.7	)

At December 31, 2016 and 2015, the projected benefit obligations exceeded the fair value of the Cash Balance Plan assets by $3.2 million and $3.0 million, respectively. This underfunded obligation is classified in other liabilities on the consolidated balance sheets.

Our cash balance plan held investments in mutual funds of $8.1 million and $5.9 million at December 31, 2016 and 2015, respectively, that were valued using level 1 inputs from the fair value hierarchy (see Note 12).

The components of net periodic benefit cost and other amounts recognized in equity related to the Cash Balance Plan for the years ended December 31, 2016, 2015 and 2014 were as follows:

		Cash Balance Plan
		Year Ended December 31,
(in millions)		2016			2015			2014
Components of net periodic benefit cost:
	Service cost	$	2.2		$	2.3		$	2.1
	Interest cost	0.5			0.4			0.3
	Expected return on plan assets	(0.2		)	(0.1		)	(0.2		)
	Net periodic benefit cost	$	2.5		$	2.6		$	2.2
Changes recognized in other comprehensive (income) loss:
	Actuarial (gain) loss	—			—			0.7
	Net credit due to curtailment	(0.4		)	—			—
	Experience loss	0.6			—			—
	Total changes recognized in other comprehensive (income) loss	$	0.2		$	—		$	0.7

Assumptions

The weighted average assumptions used to determine the Company's benefit obligations are as follows:

	Cash Balance Plan
	Year Ended December 31,
	2016	2015	2014
Discount rate	4.00%	4.50%	4.00%
Rate of compensation increase	N/A	3.00%	3.00%

The weighted average assumptions used to determine the net periodic benefit cost are as follows:

	Cash Balance Plan
	Year Ended December 31,
	2016	2015	2014
Discount rate (1)	4.50% / 3.75%	4.00%	5.00%
Expected long-term rate of return on plan assets (1)	4.25% / 3.50%	3.75%	4.75%
Rate of compensation increase	3.00%	3.00%	4.00%

(1) 2016 rates are disclosed pre-curtailment and post-curtailment, respectively.

The assumptions used to determine of the Company's 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 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.

Contributions, Plan Assets and Estimated Future Benefit Payments

Employer contributions to the Cash Balance Plan of $2.8 million, $2.2 million and $0.2 million were made during the years ended December 31, 2016, 2015 and 2014, respectively. These contributions were invested into equity and bond mutual funds and money market funds which are deemed Level 1 assets as described in Note 12. The Company expects funding requirements of approximately $2.3 million during the year ending December 31, 2017.

At December 31, 2016, anticipated benefit payments to participants from the Cash Balance Plan in future years are as follows:

(in millions)	Cash Balance Plan
2017	$	1.1
2018	0.4
2019	0.5
2020	0.5
2021	0.5
2022-2026	2.9

XML

Crude Oil and Refined Product Risk Management

12 Months Ended

Dec. 31, 2016

Derivative [Line Items]

Crude Oil and Refined Product Risk Management

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 2016, 2015 and 2014, we entered into net forward, fixed-price contracts to physically receive and deliver crude oil that qualify as normal purchases and normal sales and are exempt from derivative reporting requirements.

We use crude oil and refined products futures, swap contracts or options to mitigate the change in value for a portion of our LIFO inventory volumes subject to market price fluctuations and swap contracts to fix the margin on a portion of our future gasoline and distillate production. The physical volumes are not exchanged; 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.

The following tables summarize our economic hedging activity recognized within cost of products sold for the three years ended December 31, 2016, and open commodity hedging positions as of December 31, 2016, and December 31, 2015:

	Year Ended December 31,
	2016			2015			2014
	(In thousands)
Economic hedging activities recognized within cost of products sold:
Realized hedging gain, net	$	58,773		$	93,699		$	95,331
Unrealized hedging gain (loss), net	(77,674		)	(50,233		)	194,423
Total hedging gain (loss), net	$	(18,901	)	$	43,466		$	289,754

	December 31, 2016			December 31, 2015
	(In thousands)
Open commodity hedging instruments (barrels):
Crude oil differential swaps, net long positions	2,124			5,155
Crude oil futures, net short positions	(1,703		)	(562		)
Refined product price and crack spread swaps, net short positions	(6,632		)	(5,645		)
Total open commodity hedging instruments, net short positions	(6,211		)	(1,052		)
Fair value of outstanding contracts, net:
Other current assets	$	13,649		$	78,125
Other assets	8			11,881
Accrued liabilities	(10,827		)	(10,273		)
Other long-term liabilities	(771		)	—
Fair value of outstanding contracts - unrealized gain, net	$	2,059		$	79,733

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.

The following table presents offsetting information regarding Western's commodity hedging contracts as of December 31, 2016 and 2015:

	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, 2016
	(In thousands)
Gross financial assets:
Other current assets	$	18,929		$	(5,280	)	$	13,649
Other assets	677			(669		)	8
Gross financial liabilities:
Accrued liabilities	(17,547		)	6,720			(10,827		)
Other long-term liabilities	—			(771		)	(771		)
	$	2,059		$	—		$	2,059

	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
	(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

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, 2016, we had the following outstanding crude oil and refined product hedging instruments that were entered into as economic hedges. Settlement prices for our distillate crack spread swaps range from $15.06 to $16.62 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
	2017		2018		2019
Inventory positions (futures and swaps):
Crude oil differential swaps, net long positions	2,124		—		—
Crude oil futures, net short positions	(1,703	)	—		—
Distillate - net short positions	(150	)	—		—
Refined products - net short positions	(1,403	)	—		—
Natural gas futures - net long positions	301		—		—
Refined product positions (crack spread swaps):
Distillate - net short positions	(2,730	)	(1,800	)	—
Unleaded gasoline - net short positions	(850	)	—		—

Northern Tier Energy LP [Member]

Derivative [Line Items]

Crude Oil and Refined Product Risk Management

9. DERIVATIVES

The Company is exposed to market risks related to the volatility in the price of crude oil, refined products (primarily gasoline and distillate), and natural gas used in its operations. To reduce the impact of price volatility on its results of operations and cash flows, the Company uses commodity derivative instruments, including forwards, futures, swaps, and options. The Company uses the futures markets for the available liquidity, which provides greater flexibility in transacting in these instruments. The Company uses swaps primarily to manage its price and margin exposure. The positions in commodity derivative instruments are monitored and managed on a daily basis by a risk control group to ensure compliance with the Company's stated commercial risk management policy. The Company considers these transactions economic hedges of market risk but has elected not to designate these instruments as hedges for financial reporting purposes.

The Company recognizes all derivative instruments, except for those that qualify for the normal purchase and normal sales exception, as either assets or liabilities at fair value on the consolidated balance sheets and any related net gain or loss is recorded as a gain or loss in the consolidated statements of operations and comprehensive income. Observable quoted prices for similar assets or liabilities in active markets (Level 2 as described in Note 12) are considered to determine the fair values for the purpose of marking to market the derivative instruments at each period end.

Risk Management Activities by Type of Risk

The Company periodically uses futures and swaps contracts to manage price risks associated with inventory quantities both above and below target levels. The Company also periodically uses crack spread and crude differential futures and swaps contracts to manage refining margins. Under the Company's risk mitigation strategy, it may buy or sell an amount equal to a fixed price times a certain number of barrels, and to buy or sell in return an amount equal to a specified variable price times the same amount of barrels. Physical volumes are not exchanged and these contracts are net settled with cash.

The objective of the Company's economic hedges pertaining to crude oil and refined products is to hedge price volatility in certain refining inventories and firm commitments to purchase crude oil inventories. The level of activity for the Company's economic hedges is based on the level of operating inventories, and generally represents the amount by which inventories differ from established target inventory levels. The objective of the Company's economic hedges pertaining to natural gas is to lock in the price for a portion of the Company's forecasted natural gas requirements at existing market prices that are deemed favorable.

At December 31, 2016 and 2015, the Company had open commodity derivative instruments as follows:

	December 31, 2016	December 31, 2015
Crude oil and refined products (thousands of barrels):
Futures - long	30	90
Futures - short	1,270	933
Swaps - long	1,073	5,155
Swaps - short	530	525
Forwards - long	4,382	4,445
Forwards - short	3,101	2,572
Natural gas (thousands of MMBTUs):
Swaps	1,169	1,554

The information below presents the notional volume of outstanding contracts by type of instrument and year of maturity at December 31, 2016:

	Notional Contract Volumes by Year of Maturity
	2017
Crude oil and refined products (thousands of barrels):
Futures - long	30
Futures - short	1,270
Swaps - long	1,073
Swaps - short	530
Forwards - long	4,382
Forwards - short	3,101
Natural gas (thousands of MMBTUs):
Swaps	1,169

Fair Value of Derivative Instruments

The following tables provide information about the fair values of the Company's derivative instruments as of December 31, 2016 and December 31, 2015 and the line items in the consolidated balance sheets in which the fair values are reflected. See Note 12 for additional information related to the fair values of derivative instruments.

The Company is required to post margin collateral with a counterparty in support of our hedging activities. Funds posted as collateral were $7.6 million and $6.0 million as of December 31, 2016 and December 31, 2015, respectively. The margin collateral posted is required by counterparties and cannot be offset against the fair value of open contracts except in the event of default. The Company nets fair value amounts recognized for multiple similar derivative contracts executed with the same counterparty under master netting arrangements, including cash collateral assets and obligations. The tables below, however, are presented on a gross asset and gross liability basis.

		December 31, 2016
(in millions)	Balance Sheet Location	Assets		Liabilities
Commodity instruments:
Swaps	Other current assets	$	1.1	$	—
Swaps	Accrued liabilities	0.1		0.4
Futures	Accrued liabilities	0.2		1.2
Forwards	Other current assets	5.2		—
Forwards	Accrued liabilities	—		4.7
Total		$	6.6	$	6.3
		December 31, 2015
(in millions)	Balance Sheet Location	Assets		Liabilities
Commodity instruments:
Swaps	Accrued liabilities	$	—	$	7.9
Futures	Other current assets	0.4		—
Forwards	Other current assets	1.5		—
Forwards	Accrued liabilities	—		1.5
Total		$	1.9	$	9.4

Effect of Derivative Instruments on Income

All derivative contracts are marked to market at period end and the resulting gains and losses are recognized in earnings. The following tables provide information about the gain or loss recognized in income on the Company's derivative instruments and the line items in the financial statements in which such gains and losses are reflected.

Recognized gains and losses on derivatives were as follows:

	Year Ended December 31,
(in millions)	2016			2015			2014
Gain (loss) on the change in fair value of outstanding derivatives	$	7.8		$	(4.7	)	$	(2.8	)
Settled derivative gains (losses)	(19.8		)	1.5			12.4
Total recognized gain (loss)	$	(12.0	)	$	(3.2	)	$	9.6
Gain (loss) recognized in cost of sales	$	(13.3	)	$	(0.5	)	$	9.6
Gain (loss) recognized in operating expenses	1.3			(2.7		)	—
Total recognized net gain (loss) on derivatives	$	(12.0	)	$	(3.2	)	$	9.6

Market and Counterparty Risk

The Company is exposed to credit risk in the event of nonperformance by counterparties on its risk mitigating arrangements. The counterparties are large financial institutions with long-term credit ratings of at least A by Standard and Poor's and A2 by Moody's. In the event of default, the Company may be subject to losses on a derivative instrument's mark-to-market gains. The Company does not expect nonperformance of the counterparties involved in its risk mitigation arrangements.

XML

Stock-Based Compensation

12 Months Ended

Dec. 31, 2016

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Disclosure of Compensation Related Costs, Share-based Payments [Text Block]

19. Stock-Based Compensation

Tesoro Merger

Effective upon the closing of the Tesoro Merger, each of the outstanding RSUs that were granted prior to December 31, 2016 will vest and be settled in cash. Each of the outstanding phantom stock awards under the NTI LTIP and 123,570 RSUs granted on January 18, 2017 will be automatically converted into the right to acquire or receive benefits measured by the value of the number of shares of Tesoro common stock, rounded down to the nearest whole number, equal to the number of shares of our common stock subject to such award immediately prior to the effective time of the First Tesoro Merger multiplied by the exchange ratio. See Note 31, Tesoro Merger, for additional information.

Western Incentive Plans

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 RSUs among other forms of awards. As of December 31, 2016, there were 19,856 and 2,391,711 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, 2016, there were 658,506 unvested RSUs outstanding. The final vesting for remaining restricted share awards occurred during the first quarter of 2014.

We incurred equity-based compensation expense related to RSUs of $6.3 million, $4.2 million and $4.3 million for the years ended December 31, 2016, 2015 and 2014, respectively.

As of December 31, 2016, the aggregate fair value at grant date of outstanding RSUs was $21.2 million. The aggregate intrinsic value of RSUs was $24.9 million. The unrecognized compensation cost of outstanding RSUs was $14.9 million. Unrecognized compensation cost for RSUs will be recognized over a weighted average period of approximately 2.41 years.

The excess tax deficiency related to the RSUs that vested during the year ended December 31, 2016 was $0.4 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, 2016 was $4.1 million. The related aggregate intrinsic value of these RSUs was $3.0 million at the vesting date.

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 following table summarizes our RSU and restricted share activity for the three years ended December 31, 2016:

	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, 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		—		—
Awards granted	375,774		28.52		—		—
Awards vested	(109,634	)	37.63		—		—
Awards forfeited	(6,848	)	43.81		—		—
Not vested at December 31, 2016	658,506		32.25		—		—

Amended and Restated Northern Tier Energy LP 2012 Long-Term Incentive Plan

Effective upon the closing of the NTI Merger, Western adopted and assumed NTI's equity compensation plan. Modifications to the NTI LTIP include, among other things, a change to the unit of equity from an NTI common unit to a share of Western common stock. The amendment changes the administrator of the NTI LTIP from the board of directors of NTI's general partner to Western's board of directors or its applicable committee. Consistent with the terms of the NTI Merger Agreement, all unvested equity awards at the time of the NTI Merger were exchanged for Western phantom stock awards and performance cash awards under the NTI LTIP.

We incurred equity-based compensation expense related to phantom stock awards of $13.6 million, $10.3 million and $14.0 million for the years ended December 31, 2016, 2015 and 2014, respectively.

The NTI LTIP provides, among other awards, for grants of stock options, restricted stock, phantom stock, dividend equivalent rights, stock appreciation rights and other awards that derive their value from the market price of Western's common stock. As of December 31, 2016, there was 330,018 common share equivalents reserved for future grants under the NTI LTIP.

We determined the fair value of the phantom stock based on the closing price of Western common stock on the grant date. We amortize the estimated fair value of the phantom stock on a straight-line basis over the scheduled vesting periods of individual awards.

The aggregate grant date fair value of non-vested phantom stock outstanding as of December 31, 2016, was $13.4 million. The aggregate intrinsic value of such phantom stock was $25.1 million. Total unrecognized compensation cost related to unvested phantom stock totaled $5.8 million as of December 31, 2016, that is expected to be recognized over a weighted-average period of 1.6 years.

The excess tax benefit related to the phantom stock that vested during the year ended December 31, 2016, was $1.0 million using a statutory blended rate of 38.1%. The aggregate grant date fair value of the phantom stock that vested during the year ended December 31, 2016, was $3.4 million. The related aggregate intrinsic value of the vested phantom stock was $6.0 million at the vesting date.

A summary of our phantom stock award activity under the NTI LTIP for the three years ended December 31, 2016, is set forth below:

	Number of Phantom Stock		Weighted Average Grant Date Fair Value
Not vested at December 31, 2015	—		—
Awards granted	848,267		20.25
Awards vested	(167,342	)	20.25
Awards forfeited	(18,553	)	20.25
Not vested at December 31, 2016	662,372		20.25

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, 2016, there were 4,098,368 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 $2.7 million, $2.0 million and $1.6 million for the years ended December 31, 2016, 2015 and 2014, respectively.

The fair value at grant date of non-vested phantom units outstanding as of December 31, 2016, was $7.5 million. The aggregate intrinsic value of phantom units was $6.1 million. Total unrecognized compensation cost related to our non-vested phantom units totaled $5.6 million as of December 31, 2016, that is expected to be recognized over a weighted-average period of approximately 2.36 years.

A summary of WNRL's unit award activity for the three years ended December 31, 2016, is set forth below:

	Number of Phantom Units		Weighted Average Grant Date Fair Value
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
Awards granted	101,955		22.69
Awards vested	(86,406	)	25.80
Awards forfeited	(10,181	)	31.87
Not vested at December 31, 2016	285,155		26.42

Northern Tier Energy LP [Member]

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Disclosure of Compensation Related Costs, Share-based Payments [Text Block]

14. EQUITY-BASED COMPENSATION

Prior to Northern Tier's merger with Western, the Company maintained the 2012 Long-Term Incentive Plan ("LTIP"). Effective upon the closing of the Merger, Western's board of directors adopted and assumed the LTIP and amended and renamed the LTIP to the Northern Tier Energy LP Amended and Restated 2012 Long-Term Incentive Plan ("Amended LTIP"). The Amended LTIP changed, among other things, the unit of equity from a unit of NTI common partnership interest to a share of Western common stock and the administrator of the plan was changed from the board of directors of the NTE GP to the board of directors of Western or its applicable committee. All unvested equity awards at the time of the Merger with Western were exchanged for new awards under the Amended LTIP consistent with the terms of the Merger Agreement.

The Company recognized equity-based compensation expense of $13.6 million, $10.3 million and $14.0 million for the years ended December 31, 2016, 2015 and 2014, respectively, related to these plans. This expense is included in selling, general and administrative expenses in the consolidated statements of operations and comprehensive income.

AMENDED LTIP

Approximately 0.3 million Western common share equivalents are reserved for issuance under the Amended LTIP as of December 31, 2016. The Amended LTIP permits the award of stock options, restricted stocks, phantom stocks, dividend equivalent rights, stock appreciation rights and other awards that derive their value from the market price of Western’s common stock. As of December 31, 2016, approximately 0.7 million shares of equity denominated awards and approximately $9.0 million in cash denominated awards were outstanding under the Amended LTIP. The Company recognized the expense on all LTIP awards ratably from the grant date until all units vested. Service-based awards generally vested ratably over a three-year period beginning on the award's first anniversary date and performance-based awards generally vested following the end of the measurement period which, for the performance-based phantom awards, had traditionally been three years after the commencement of the measurement period. Compensation expense related to service-based phantom awards was 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. Compensation expense related to performance-based phantom awards was based on the grant date fair value as determined by either the closing price on the grant date and management's estimates on the number of units that ultimately vested in the case of awards with company performance based criteria or by third-party valuation experts in the case of awards with market based criteria. For awards to employees, the Company estimates a forfeiture rate which is subject to revision depending on the actual forfeiture experience.

As of December 31, 2016 and 2015, the total unrecognized compensation cost for stock and cash awards under the Amended LTIP was $8.6 million and $16.1 million, respectively.

Restricted Common Units

Legacy NTI Service-based Restricted Common Unit Awards

As of December 31, 2016, the Company had no restricted common units outstanding as all restricted common units were exchanged upon the Merger with Western. As a replacement for these awards, for every one unvested outstanding restricted common unit, 1.0323 shares of Western phantom stock were issued to the participant with all vesting dates remaining unchanged.

A summary of the service-based restricted common unit activity is set forth below:

	Number of		Weighted		Weighted Average Term
	restricted common units		Average Grant		Until Maturity
	(in thousands)		Date Price		(years)
Nonvested at December 31, 2014	396.2		$	24.73	1.3
Awarded	1.0		24.90		2.0
Vested	(205.7	)	24.71		—
Nonvested at December 31, 2015	191.5		24.75		1.0
Forfeited	(12.3	)	25.57		—
Vested	(34.5	)	26.83		—
Exchanged due to merger	(144.7	)	24.18		0.5
Nonvested at December 31, 2016	—		—		—

Phantom Common Units

Legacy NTI Service-based Restricted Common Unit Awards

As of December 31, 2016, the Company had no service-based phantom common units outstanding as all service-based phantom common units were exchanged in accordance with the Merger. For every one unvested service-based phantom common units outstanding, 1.0323 shares of Western phantom stock were issued to the participant with all vesting dates remaining unchanged.

A summary of the service-based phantom common unit activity is set forth below:

	Number of phantom common units						Weighted		Weighted
	(in thousands)						Average Grant		Average Term
	Service-Based		Performance-Based		Total		Date Value		Until Maturity
Nonvested at December 31, 2014	337.7		—		337.7		$	26.99	2.0
Awarded	447.9		182.4		630.3		23.37		1.9
Incremental performance units	—		80.4		80.4		23.06		1.7
Forfeited	(91.3	)	(2.1	)	(93.4	)	26.22		—
Vested	(112.4	)	—		(112.4	)	27.02		—
Nonvested at December 31, 2015	581.9		260.7		842.6		24.00		1.5
Awarded	381.0		163.6		544.6		25.87		2.5
Incremental performance units	—		231.8		231.8		27.82		2.0
Forfeited	(16.5	)	(19.1	)	(35.6	)	25.36		—
Vested	(269.2	)	(1.8	)	(271.0	)	24.10		—
Exchanged due to merger	(677.2	)	(635.2	)	(1,312.4	)	25.45		2.0
Nonvested at December 31, 2016	—		—		—		—		—

Western Service-based Phantom Stock Awards

As a result of the Merger, both the previously outstanding service-based restricted and phantom common unit awards were exchanged with 0.8 million service based awards of Western phantom stock. Upon vesting, Western may settle these awards in common stock, cash or a combination of both, in the discretion of the board of directors of Western or its applicable committee. The new Western phantom stock awards participate in dividends on an equal basis with Western's common shareholders. However, dividends for phantom stock awards are paid in cash only upon vesting. In the event that unvested phantom stock awards are forfeited or canceled, any unpaid dividends on the underlying awards are also forfeited by the grantee. For phantom stock awards outstanding at December 31, 2016, the forfeiture rates ranged from zero to 30%, depending on the employee pay grade classification.

Legacy NTI Performance-based Phantom Common Awards

As of December 31, 2016, the Company had no performance-based phantom common units outstanding as all performance-based phantom common units were exchanged in accordance with the Merger. Western issued (a) fixed-value cash denominated awards for the pre-merger time period pertaining to the legacy NTI performance-based phantom common unit awards based upon the performance multiples achieved through March 31, 2016 (the most recently completed quarter prior to the Merger date) and (b) variable-value cash denominated awards for the post-merger time period pertaining to the legacy NTI performance-based phantom common unit awards. Both the fixed value and variable value awards were converted to cash denominated awards at a rate of $21.1049 in cash for every one unvested outstanding performance-based phantom common unit prior to the Merger.

Pre-Merger Period Service-Based Cash Denominated Awards

As of December 31, 2016, Western had $4.4 million in unvested fixed value, cash denominated awards applicable to the Company's pre-merger period ("Legacy Performance Awards"). The vesting dates of the Legacy Performance Awards remained unchanged and are now subject only to service conditions. These awards have a weighted average term until maturity of 1.0 years. The related expense is amortized over the remaining service period using the straight-line method and recognized in selling, general and administrative expenses. In the event that unvested Legacy Performance Awards are forfeited or canceled, all dividend rights associated with the grant are also forfeited by the grantee. The forfeiture rates on the Legacy Performance Awards range from 5% to 20%, depending on the employee's pay grade classification.

Post-Merger Period Performance-Based Cash Denominated Awards

As of December 31, 2016, the Western had $4.6 million in unvested variable value, cash denominated awards applicable to the Company's post-merger period (the "Performance Cash Award"). Assuming a threshold EBITDA is achieved and the participant meets the service conditions throughout the vesting term, participants are entitled to a payout under the Performance Cash Award based on the Company’s achievement of two criteria compared to the performance peer group selected by the compensation committee of Western's board of directors over the performance period: (a) return on capital employed, referred to as a performance condition, and (b) total shareholder return, referred to as a market condition. The average of these two conditions is then multiplied by a third condition relating to Western's average safety rate over the performance period relative to the comparable average safety rate of the refining industry as published by the Bureau of Labor Statistics, and can range between 85% for relatively poor safety performance to 115% for relatively superior safety performance.

The Company accounts for the performance and market conditions in each Performance Cash Award as separate liability awards and remeasures the expected liability each period.

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Equity

12 Months Ended

Dec. 31, 2016

Class of Stock [Line Items]

Stockholders' Equity

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.

Pursuant to the NTI Merger Agreement, we issued 17.1 million shares of Western common stock including 11.6 million treasury shares on June 23, 2016. See Note 30, NTI, for further discussion of the NTI Merger.

Effective upon the closing of the Tesoro Merger, each share of our common stock may be converted into and become exchangeable for, at the election of the holder of each share of our common stock, either (a) $37.30 in cash or (b) 0.4350 shares of Tesoro common stock, in each case without interest, subject to the terms and conditions. See Note 31, Tesoro Merger, for further discussion of the Tesoro Merger.

Between July 18, 2012 and December 31, 2016, 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. Our board of directors approved a share repurchase program in September of 2015 that expired on December 31, 2016. Through December 31, 2016, we purchased 23.0 million shares of our common stock under our share repurchase programs. On December 31, 2016, we had no active share repurchase program.

The following table summarizes our share repurchase activity for our share repurchase programs.

	January 2014 Program			November 2014 Program			September 2015 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)
Shares purchased at December 31, 2013	—	$	—	—	$	—	—	$	—
Shares purchased during 2014 (1)	4,976,039	200,000		1,492,874	59,222		—	—
Shares purchased at December 31, 2014	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	4,976,039	200,000		4,140,614	164,222		—	—
Shares purchased during 2016 (2)	—	—		—	—		2,462,350	75,000
Shares purchased at December 31, 2016	4,976,039	$	200,000	4,140,614	$	164,222	2,462,350	$	75,000

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

(2) The shares purchased during 2016 were issued on June 23, 2016 pursuant to the NTI Merger Agreement.

Dividends

Our ability to pay dividends to our shareholders is subject to certain restrictions in the Western 2019 Revolving Credit Facility, Western 2020 Term Loan Credit Facility, Western 2023 Term Loan Credit Facility and the Western 2021 Indenture governing the Western 2021 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.

Under the Tesoro Merger Agreement, we have agreed that, until the completion of the Tesoro Merger, we will not declare, set aside, make or pay any dividend or other distribution in respect of any of our capital stock, except for regular quarterly cash dividends to the holders of shares of our common stock in an amount not in excess of $0.38 per share.

The table below summarizes our 2016 cash dividend declarations, payments and scheduled payments:

	Declaration Date	Record Date	Payment Date	Dividend per common share		Total Payment(in thousands)
First quarter	January 6	January 20	February 4	$	0.38	$	35,601
Second quarter	April 8	April 18	May 2	0.38		34,685
Third quarter	July 15	July 25	August 9	0.38		41,202
Fourth quarter	October 13	October 24	November 8	0.38		41,202
Total						$	152,690

On January 4, 2017, our board of directors approved a cash dividend for the first quarter of 2017 of $0.38 per share of common stock in an aggregate payment of $41.3 million that was paid on February 2, 2017 to holders of record on January 18, 2017.

NTI Distributions

The table below summarizes NTI's 2016 quarterly distribution declarations, payments and scheduled payments:

Declaration Date	Record Date	Payment Date	Distribution per Unit
February 3	February 12	February 19	$	0.38
June 13	June 23	June 23	0.18
Total			$	0.56

WNRL Distributions

The table below summarizes WNRL's 2016 quarterly distribution declarations, payments and scheduled payments:

Declaration Date	Record Date	Payment Date	Distribution per Common and Subordinated Unit
January 30	February 13	February 23	$	0.3925
May 1	May 15	May 26	0.4025
July 31	August 14	August 24	0.4125
October 30	November 13	November 23	0.4225
			$	1.6300

In addition to its quarterly distributions, WNRL paid incentive distributions of $4.4 million and $1.1 million for the years ended December 31, 2016 and 2015, respectively, to Western as its General Partner and holder of its incentive distribution rights.

On January 31, 2017, WNRL declared a quarterly distribution of $0.4375 per unit to common unitholders of record on February 13, 2017, payable on March 1, 2017.

Northern Tier Energy LP [Member]

Class of Stock [Line Items]

Stockholders' Equity

11. EQUITY

Western indirectly owns 100% of Northern Tier Energy GP LLC and 100% of the limited partnership interest in NTE LP.

Merger with Western

On December 21, 2015, Western and NTE LP announced that they had entered into an Agreement and Plan of Merger dated as of December 21, 2015 ("the Merger Agreement"), with NTE GP and Western Acquisition Co, LLC, a Delaware limited liability company and wholly-owned subsidiary of Western ("MergerCo") whereby Western would acquire all of Northern Tier's outstanding common units not already owned by Western (the "Merger").

Based upon the consideration elections made by NTI common unitholders, this cash and Western common stock was allocated among NTI common unitholders as follows:

• NTI common unitholders who made a valid "Mixed Election" (as defined in the Merger Agreement), or who made no election, received $15.00 in cash and 0.2986 of a share of Western common stock for each such NTI common unit held.

• NTI common unitholders who made a valid "Cash Election" (as defined in the Merger Agreement) received $15.357 in cash and 0.28896 of a share of Western common stock as prorated in accordance with the Merger Agreement for each such NTI common unit held.

• NTI common unitholders who made a valid "Stock Election" (as defined in the Merger Agreement) received 0.7036 of a share of Western common stock for each such NTI common unit held.

On June 23, 2016, following the approval of the Merger by NTI common unitholders, all closing conditions to the Merger were satisfied, and the Merger was successfully completed. The transaction resulted in approximately 17.1 million additional shares of WNR common stock outstanding. Subsequent to this transaction, NTI continues to exist as a limited partnership and became an indirect wholly-owned subsidiary of Western (see Note 20).

Distribution Policy

Prior to our merger with Western, the Company generally made distributions, if any, within 60 days after the end of each quarter to unitholders of record as of the applicable record date. The board of directors of the Company's general partner adopted a policy pursuant to which distributions for each quarter, if any, would equal the amount of available cash the Company generates in such quarter. Distributions on the Company's units were in cash. Available cash for each quarter, if any, was determined by the board of directors of the Company's general partner following the end of such quarter. Distributions were expected to be based on the amount of available cash generated in such quarter. Available cash for each quarter was generally equal the Company's cash flow from operations for the quarter, excluding working capital changes, less cash required for maintenance and regulatory capital expenditures, reimbursement of expenses incurred by the Company's general partner and its affiliates, debt service and other contractual obligations and reserves for future operating or capital needs that the board of directors of our general partner deemed necessary or appropriate, including reserves for turnaround and related expenses, working capital, and organic growth projects. Pursuant to the terms of the Merger Agreement, the Company declared and paid a prorated quarterly distribution for the period April 1, 2016, to June 13, 2016, which was paid on June 23, 2016, to unitholders of record as of immediately prior to the Effective Time of the Merger (as defined in the Merger Agreement).

The following table details the quarterly distributions paid to common unitholders (in millions, except per unit amounts):

Date Declared	Date Paid	Common Units and equivalents at record date (in millions)	Distribution per common unit and equivalent		Total Distribution (in millions)
2014 Distributions:
February 7, 2014	February 28, 2014	92.7	$	0.41	$	38.0
May 6, 2014	May 30, 2014	93.0	$	0.77	71.6
August 5, 2014	August 29, 2014	93.0	$	0.53	49.3
November 4, 2014	November 25, 2014	93.1	$	1.00	92.9
Total distributions paid during 2014			$	2.71	$	251.8
2015 Distributions:
February 5, 2015	February 27, 2015	93.7	$	0.49	$	45.9
May 5, 2015	May 29, 2015	93.7	$	1.08	100.8
August 4, 2015	August 28, 2015	93.7	$	1.19	111.3
November 3, 2015	November 25, 2015	93.7	$	1.04	97.3
Total distributions paid during 2015			$	3.80	$	355.3
2016 Distributions:
February 3, 2016	February 19, 2016	94.2	$	0.38	$	36.0
June 13, 2016	June 23, 2016	93.0	$	0.18	$	16.7
Total distributions paid prior to our merger			$	0.56	$	52.7

Subsequent to our merger with Western, we declared a distribution for $110.0 million which was paid in the fourth quarter 2016.

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Earnings Per Share

12 Months Ended

Dec. 31, 2016

Earnings Per Share [Abstract]

Earnings Per Share

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 and phantom stock. 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 or phantom stock in the two-class method when calculating earnings per share.

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

	Year Ended December 31,
	2016			2015			2014
	(In thousands, except per share data)
Basic earnings per common share:
Allocation of earnings:
Net income attributable to Western Refining, Inc.	$	124,939		$	406,756		$	559,926
Distributed earnings	(153,691		)	(129,211		)	(293,746		)
Income allocated to participating securities	—			—			(3		)
Distributed earnings allocated to participating securities	—			—			3
Undistributed income (loss) available to Western Refining, Inc.	$	(28,752	)	$	277,545		$	266,180
Weighted average number of common shares outstanding (1)	100,473			94,899			90,708
Basic earnings per common share:
Distributed earnings per share	$	1.53		$	1.36		$	3.24
Undistributed earnings (loss) per share	(0.29		)	2.92			2.93
Basic earnings per common share	$	1.24		$	4.28		$	6.17

(1) Excludes the weighted average number of common shares outstanding associated with participating securities of 884 shares for the year ended December 31, 2014.

	Year Ended December 31,
	2016		2015		2014
	(In thousands, except per share data)
Diluted earnings per common share:
Net income attributable to Western Refining, Inc.	$	124,939	$	406,756	$	559,926
Tax effected interest related to convertible debt	—		—		8,010
Net income available to Western Refining, Inc., assuming dilution	$	124,939	$	406,756	$	567,936
Weighted average number of diluted shares outstanding	100,868		94,999		101,190
Diluted earnings per common share	$	1.24	$	4.28	$	5.61

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

	Year Ended December 31,
	2016	2015	2014
	(In thousands)
Weighted average number of common shares outstanding	100,473	94,899	90,708
Common equivalent shares from Convertible Senior Notes	—	—	10,349
Restricted shares, restricted share units and phantom stock	395	100	133
Weighted average number of diluted shares outstanding	100,868	94,999	101,190

A shareholder's interest in our common stock could become diluted as a result of vestings of RSUs, phantom stock 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 and phantom stock that have not vested and common equivalent shares related to the Western Convertible Notes. We include unvested RSUs and phantom stock 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 were generally included in our diluted earnings calculation when net income exceeds certain thresholds above which the effect of the shares became 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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Cash Flows

12 Months Ended

Dec. 31, 2016

Other Significant Noncash Transactions [Line Items]

Cash Flow, Supplemental Disclosures [Text Block]

22. Cash Flows

Supplemental disclosures of cash flow information were as follows:

	Year Ended December 31,
	2016		2015		2014
	(In thousands)
Non-cash operating activities were as follows:
Income taxes paid	$	38,227	$	283,330	$	227,953
Interest paid, excluding amounts capitalized	124,037		95,012		83,943
Non-cash investing activities were as follows:
Accrued capital expenditures	$	28,934	$	53,361	$	9,189
Assets acquired through capital lease obligations	4,644		29,082		—
PP&E derecognized from sale leaseback continuing involvement release	2,799		1,773		—
Transfer of capital spares	860		1,490		—
Non-cash financing activities were as follows:
Reduction of long-term debt proceeds for original issuance discount	$	10,250	$	—	$	—
Treasury stock issuance	438,168		—		—
Accrued financing costs	67		—		—
Issuance of common shares for redemption of Western Convertible Notes	—		—		357,608
Distributions accrued on unvested NTI equity awards	—		4,210		—

Northern Tier Energy LP [Member]

Other Significant Noncash Transactions [Line Items]

Cash Flow, Supplemental Disclosures [Text Block]

16. SUPPLEMENTAL CASH FLOW INFORMATION

Supplemental cash flow information is as follows:

	Year Ended December 31,
(in millions)	2016		2015		2014
Net cash from operating activities included:
Interest paid	$	28.6	$	29.0	$	22.5
Income taxes paid	0.1		6.1		5.0
Noncash investing activities included:
Capital expenditures included in accounts payable	$	11.4	$	13.8	$	2.9
PP&E derecognized in sale leaseback	2.8		1.8		—
Book value of tank and terminal related assets sold to WNRL	48.7		—		—
PP&E additions resulting from a capital lease	0.3		4.5		1.7
Noncash financing activities included:
Distributions accrued on unvested equity awards	$	—	$	4.2	$	—
Increase in equity due to proceeds received exceeding book value of assets sold to WNRL	146.3		—		—

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Contingencies

12 Months Ended

Dec. 31, 2016

Loss Contingencies [Line Items]

Contingencies

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, 2016, and 2015, we had consolidated environmental accruals of $13.8 million and $18.3 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 $6.5 million remained as of December 31, 2016. 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 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 incurred $0.1 million, $0.1 million and $1.9 million for the years ended December 31, 2016, 2015 and 2014, respectively, to complete an FCC emission offset project. We paid penalties between 2009 and 2012 totaling $2.7 million. For 2017, we have budgeted capital projects specifically designed to address our compliance with the 2005 NMED Amended Agreement regarding air emissions from waste handling at our Gallup refinery.

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 operations 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.

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.

Gallup 2017 EPA RCRA Order: In February 2017, we received from the EPA a draft administrative order with a proposed penalty of $0.1 million to settle alleged violations of the RCRA regulations noted during an EPA inspection of the Gallup refinery in August 2014. We are evaluating the draft order and expect to enter into a settlement with the EPA. The draft settlement does not contain requirements for groundwater clean-up or capital expenditure.

St. Paul Park Refinery

At December 31, 2016, and 2015, liabilities for remediation and closure obligations at the St. Paul Park refinery totaled $3.4 million and $8.6 million, respectively, of which $2.5 million and $2.6 million, respectively, are recorded on a discounted basis. These discounted liabilities are expected to be settled over at least the next 21 years. At December 31, 2016, the estimated future cash flows to settle these discounted liabilities totaled $3.1 million and are discounted at a rate of 2.82%. 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 at December 31, 2016, and 2015.

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 the review of the test results and additional discussions with MPCA, we plan to close the remaining lagoon. At December 31, 2016 and 2015, we estimated the remediation and closure costs to be approximately $0.9 million and $6.0 million, respectively. 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.

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 NTI Merger, Evercore Group, L.L.C. (“Evercore”), and MergerCo (collectively, “Defendants”) (the “NTI Merger Litigation”). The NTI Merger Litigation appears to challenge the adequacy of disclosures made in connection with the NTI Merger. Plaintiff seeks monetary damages and attorneys’ fees. The NTI Merger Litigation is in the earliest stages of litigation. Western believes the NTI Merger Litigation is without merit and intends to vigorously defend against it.

As of February 8, 2017, Western was named as defendants in five substantially similar purported stockholder class actions by Western stockholders (the “Tesoro Merger Litigation”). The suits challenge the adequacy of the disclosures made in connection with the Tesoro Merger. Among other remedies, the plaintiffs seek to enjoin the merger until additional information relating to the transaction is disclosed. The Tesoro Merger Litigation is in the earliest stages of litigation. Western believes the Tesoro Merger Litigation is without merit, intends to vigorously defend against it and on February 23, 2017, Western and the members of its board of directors filed a motion to dismiss the operative complaint in the consolidated proceedings.

Tax Matters

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

Union Matters

During 2016, we negotiated a new collective bargaining agreement covering employees in St. Paul Park, scheduled to expire in 2020. SuperMom's bakery has 26 employees associated with its operations that are covered by a collective bargaining agreement that expires in August 2017. During 2015, we negotiated a new collective bargaining agreement covering employees at the El Paso refinery that is scheduled to expire in April of 2021. During 2014, we negotiated a collective bargaining agreement covering employees at the Gallup refinery that expires in 2020.

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.

Other Matters

The EPA has issued Renewable Fuels Standards ("RFS") that require refiners to blend renewable fuels into the refined products produced at their refineries. Annually, the EPA is required to establish a volume of renewable fuels that refineries must blend into their refined petroleum fuels. To the extent we are unable to blend at the rate necessary to satisfy the EPA mandated volume, we purchase Renewable Identification Numbers ("RIN"). The purchase price for RINs is volatile and may vary significantly from period to period. The net cost of meeting our estimated renewable volume obligations was $65.4 million, $35.5 million and $28.2 million for the year ended December 31, 2016, 2015 and 2014, respectively. The supply and demand environment for RINs is uncertain and we cannot predict the impact of RIN purchases on our results of operations in any given period.

In addition, the EPA has investigated and brought enforcement actions against companies it believes produced invalid RINs. We have purchased RINs that the EPA determined were invalid. Previously, we have entered into settlements 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.

Northern Tier Energy LP [Member]

Loss Contingencies [Line Items]

Contingencies

. COMMITMENTS AND CONTINGENCIES

The Company is the subject of, or party to, contingencies and commitments involving a variety of matters. Certain of these matters are discussed below. While the results of these commitments and contingencies cannot be predicted with certainty, the Company believes that the final resolution of the foregoing would not, individually or in the aggregate, have a material adverse effect on the Company's consolidated financial statements as a whole.

Legal Matters

On February 20, 2015, a customer served a complaint in the United States District Court for the District of Minnesota alleging violations of the Telephone Consumer Protection Act. We denied and continue to deny all material allegations in the complaint. On December 29, 2016, we entered into a settlement which will require a payment to the plaintiff class of between $2.2 million and $3.5 million. The parties are awaiting court approval of the settlement terms.

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. The Company believes the Merger Litigation is without merit and intends to vigorously defend against it.

Environmental Matters

The Company is subject to federal, state, local and foreign laws and regulations relating to the environment. These laws generally provide for control of pollutants released into the environment and require responsible parties to undertake remediation of hazardous waste disposal sites. Penalties may be imposed for noncompliance. At December 31, 2016 and 2015, accruals for remediation and closure obligations totaled $3.4 million and $8.6 million, respectively. Of the $3.4 million and $8.6 million accrued, $2.5 million and $2.6 million are recorded on a discounted basis as of December 31, 2016 and 2015, respectively. These discounted liabilities are expected to be settled over at least the next 21 years. At December 31, 2016, the estimated future cash flows to settle these discounted liabilities totaled $3.1 million, and are discounted at a rate of 2.82%. 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 at both December 31, 2016 and 2015. Costs associated with environmental remediation are recorded in direct operating expenses in the statement of operations.

On June 3, 2014, SPPR was issued a National Pollutant Discharge Elimination Permit/State Disposal System Permit by the Minnesota Pollution Control Agency ("MPCA") relating to its upgraded wastewater treatment plant at its St. Paul Park refinery. This permit required the refinery to conduct additional testing of its remaining lagoon. The testing was completed in the fourth quarter of 2014 and following the Company's review of the test results and additional discussions with the MPCA, the Company plans to close the remaining lagoon. The MPCA accepted the Company's remediation plan in the fourth quarter of 2015. At December 31, 2016, and 2015, the Company estimates the remaining remediation costs to be approximately $0.9 million and $6.0 million, respectively. In connection with the Company's December 2010 acquisition of the St. Paul Park refinery, among other assets, from Marathon Petroleum Company LP ("Marathon"), the Company entered into an agreement with Marathon which required Marathon to share in the future remediation costs of this Lagoon, should they be required. During the three months ended September 30, 2015, the Company entered into a settlement and release agreement with Marathon and received $3.5 million pursuant to this settlement which was recorded as a reduction of direct operating expenses.

Future estimated cash outflows to remediate environmental matters are as follows:

(in millions)	Groundwater Contamination			Wastewater Lagoon		Total
2017	$	0.5		$	0.9	$	1.4
2018	0.3			—		0.3
2019	0.1			—		0.1
2020	0.1			—		0.1
2021	0.1			—		0.1
Thereafter	2.0			—		2.0
Total	3.1			0.9		4.0
Less: amount representing interest	(0.6		)	—		(0.6		)
Present value of estimated future cash flows	$	2.5		$	0.9	$	3.4

It is not presently possible to estimate the ultimate amount of all remediation costs that might be incurred by the Company or the penalties that may be imposed. Furthermore, environmental remediation costs may vary from estimates for which a liability has been recorded either in accrued liabilities or other liabilities in the balance sheet because of changes in laws, regulations and their interpretation; additional information on the extent and nature of site contamination; and improvements in technology.

Franchise Agreements

In the normal course of its business, SAF enters into ten-year license agreements with the operators of franchised SuperAmerica brand retail outlets. These agreements obligate SAF or its affiliates to provide certain services including information technology support, maintenance, credit card processing and signage for specified monthly fees.

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Concentration of Risk

12 Months Ended

Dec. 31, 2016

Risks and Uncertainties [Abstract]

Concentration of Risk

24. Concentration of Risk

We sell a variety of refined products to a diverse customer base. No single customer accounted for more than 10% of consolidated net sales for the years ended December 31, 2016, 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 6.0%, 6.3% and 5.5% of consolidated sales during the years ended December 31, 2016, 2015 and 2014, respectively.

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Leases and Other Commitments

12 Months Ended

Dec. 31, 2016

Other Commitments [Line Items]

Leases and Other Commitments

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 2040. 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 are 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 logistic 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 Veolia North America, Inc. (“Veolia”), Veolia owns and operates two sulfuric acid regeneration units on property we lease to Veolia 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. 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 38 capital leases, with initial terms of 20 years, expiring in 2017 through 2036. The current portion of our capital lease obligation of $1.3 million and $1.0 million is included in accrued liabilities and the non-current portion of $54.2 million and $53.2 million is included in lease financing obligations in the accompanying Consolidated Balance Sheets as of December 31, 2016 and 2015, respectively. The capital lease obligations include a deferred gain of $0.2 million. These capital leases were discounted using annual rates of 3.24% to 10.51%. Total remaining interest related to these leases was $40.0 million and $44.1 million at December 31, 2016, and 2015, respectively. Annual payments, including interest, for the next five years are approximately $5.6 million annually with the remaining $67.1 million due through 2036.

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, 2016:

	Operating		Capital
2017	$	55,675	$	5,419
2018	52,509		5,444
2019	47,269		5,553
2020	42,420		5,744
2021	43,284		5,891
2022 and thereafter	305,646		67,139
Total minimum lease payments	$	546,803	95,190
Less amount that represents interest			39,960
Present value of net minimum capital lease payments			$	55,230

Total rent expense was $71.6 million, $64.7 million and $53.7 million for the years ended December 31, 2016, 2015 and 2014, respectively. Contingent rentals and subleases were not significant in any year.

Northern Tier Energy LP [Member]

Other Commitments [Line Items]

Leases and Other Commitments

Concurrent with our formation in 2010, certain acquired assets (including real property interests and land related to 135 of the SuperAmerica convenience stores and the SuperMom's bakery) were sold to a third party equity real estate investment trust. In connection with the closing of the Marathon Acquisition, the Company assumed the leasing of these properties from the real estate investment trust on a long-term basis. All stores owned at the conclusion of these transactions were sold and leased back from the equity real estate investment trust. As of December 31, 2016, 133 of the SuperAmerica convenience stores and the SuperMom's Bakery remain under the lease with the equity real estate investment trust.

In accordance with ASC Topic 840 "Sale Leaseback Transactions," the Company determined that subsequent to this sale, it had a continuing involvement for a portion of these property interests due to potential environmental obligations or due to subleasing arrangements. For these respective properties, the fair value of the assets and the related lease obligation will remain on the Company's consolidated balance sheet until the end of the lease term or until the continuing involvement is resolved. The assets are included in property, plant and equipment and are being depreciated over their remaining useful lives. The lease payments relating to these property interests are recognized as interest expense. Subsequent to the initial transaction, the Company's continuing involvement ended for a subset of these stores and, as such, the related fair value of the assets and the lease obligation for these stores have been removed from the Company's consolidated balance sheet.

The remainder of properties sold to the third party real estate investment trust are treated as operating leases. The Company also leases a variety of facilities and equipment under other operating leases, including land and building space, office equipment, vehicles, rail tracks for storage of rail tank cars near the refinery and numerous rail tank cars. Many of our operating leases have renewal options at various future dates and some of our leases have escalation clauses which are indexed to CPI or other inflation related measures.

Future minimum commitments for operating lease obligations having an initial or remaining non-cancelable lease terms in excess of one year are as follows:

(in millions)	Capital Leases			Operating Leases		Total Leases
2017	$	1.1		$	27.8	$	28.9
2018	1.0			27.5		28.5
2019	1.1			26.2		27.3
2020	1.1			25.6		26.7
2021	1.1			27.2		28.3
Thereafter	12.2			139.2		151.4
Total	17.6			273.5		291.1
Less: amount representing interest	(8.4		)	—		(8.4		)
Present value of net minimum lease payments	$	9.2		$	273.5	$	282.7

Rental expense was $28.3 million, $25.1 million, $25.4 million for the years ended December 31, 2016, 2015 and 2014, respectively.

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Related Party Transactions

12 Months Ended

Dec. 31, 2016

Related Party Transaction [Line Items]

Related Party Transactions Disclosure [Text Block]

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. Under the terms of the lease, we make annual payments of $0.2 million. For the years ended December 31, 2016, 2015 and 2014, we made rental payments under this lease to the related party of $0.2 million. We have no amounts due as of December 31, 2016, related to this lease agreement. This lease agreement expired in January 2017.

Beginning on September 30, 2014, we began paying MPL for transportation services at published tariff rates. We incurred $52.2 million, $55.4 million and $12.6 million in crude transportation costs with MPL for the years ended December 31, 2016, 2015 and 2014, respectively. Prior to September 30, 2014, we had a crude oil supply and logistics agreement with a third-party and had no direct supply transactions with MPL prior to this date. Western's President and Chief Operating Officer is a member of MPL's board of managers.

Northern Tier Energy LP [Member]

Related Party Transaction [Line Items]

Related Party Transactions Disclosure [Text Block]

3. RELATED PARTY TRANSACTIONS

As of December 31, 2016, Western indirectly owns 100% of both Northern Tier Energy GP LLC ("NTE GP") and NTE LP. On December 21, 2015, Western and NTE LP announced that they had entered into the Merger Agreement with MergerCo and NTE GP whereby Western would acquire all of NTE LP's outstanding common units not already owned by Western (see Note 20). The transaction closed on June 23, 2016 (see Note 20).

On September 15, 2016, Western executed the Contribution Agreement by and among Western, SPPR, WNRL and Western Refining Logistics GP, LLC, the general partner of WNRL. Pursuant to the terms of the Contribution Agreement, SPPR has agreed to sell to WNRL approximately four million barrels of refined product and crude oil storage tanks, a light products terminal, a heavy products loading rack, certain rail and barge facilities, certain other related logistics assets, and two crude oil pipeline segments and one pipeline segment not currently in service, each of which is approximately 2.5 miles and extends from SPPR's refinery in St. Paul Park, Minnesota to SPPR's tank farm in Cottage Grove, Minnesota, in exchange for $195 million in cash and 628,224 of common units representing limited partner interests in WNRL. The Company's book value on the date of sale of the property, plant and equipment, certain assets under construction and additive inventory used in the terminal operations amounted to $48.7 million. The proceeds from this transaction, reduced by the book value of the assets sold was $146.3 million. The Company treated the transaction as a transfer of assets between entities under common control and, as such, accounted for the transfer at the historical book value of the assets as required by GAAP. We recognized the difference between the proceeds and the book value of the assets as an increase in equity.

In connection with the closing of the Contribution Agreement, SPPR entered into a terminalling, transportation and storage services agreement (the "Terminalling Agreement") with Western Refining Terminals, LLC ("WRT"), an indirect, wholly-owned subsidiary of WNRL. Pursuant to the Terminalling Agreement, WRT has agreed to provide product storage services, product throughput services and product additive and blending services at the terminal facilities located at or near SPPR's refinery in St. Paul Park, Minnesota. In exchange for such services, SPPR has agreed to certain minimum volume commitments and to pay certain fees. The Terminalling Agreement will have an initial term of ten years, which may be extended for up to two renewal terms of five years each upon the mutual agreement of the parties.

The Company has engaged in several types of transactions with Western and its subsidiaries including crude and feedstock purchases, asphalt purchases, finished product purchases, railcar leases and tank and terminal service fee. Additionally, the Company is party to a shared services agreement with Western and WNRL whereby the Company both receives and provides administrative support services. The shared services agreement was entered into with Western as of September 1, 2014, and was approved by the Conflicts Committee of the board of directors of NTE GP. On May 4, 2015, WNRL joined as a party to this agreement. The services covered by the shared services agreement include assistance with treasury, risk management and commercial operations, environmental compliance, information technology support, internal audit and legal.

MPL is also a related party of the Company. Prior to September 30, 2014, the Company had a crude oil supply and logistics agreement with a third party and therefore had no direct supply transactions with MPL prior to that date. Beginning on September 30, 2014, the Company began paying MPL for transportation services at published tariff rates. Additionally, the Company owns a 17% interest in MPL (see Note 6) and generally receives quarterly cash distributions related to this investment. The Company's Chief Executive Officer is a member of MPL's board of managers.

In addition to the Contribution Agreement, the Company engaged in the following related party transactions with unconsolidated affiliates for the years ended December 31, 2016, 2015 and 2014:

		For the year ended December 31,
(in millions)	Location in Statement of Operations and Comprehensive Income	2016		2015		2014
Western Refining:
Asphalt sales	Revenue	$	32.0	$	46.6	$	19.0
Feedstock sales	Revenue	—		0.6		—
Railcar rental	Revenue	0.2		0.2		0.1
Crude and feedstock purchases	Cost of sales	—		—		6.3
Refined product purchases	Cost of sales	—		1.5		—
Shared services purchases	Selling, general and administrative expenses	0.6		3.6		1.1
Western Refining Logistics:
Tank and terminal service fees	Cost of sales	13.6		—		—
Shared services purchases	Selling, general and administrative expenses	0.4		—		—
Minnesota Pipe Line Company:
Pipeline transportation purchases	Cost of sales	52.2		55.4		12.6

The Company had the following outstanding receivables and payables with non-consolidated related parties at December 31, 2016 and December 31, 2015:

(in millions)	Balance Sheet Location	December 31, 2016			December 31, 2015
Net receivable (payable) with related party:
Western Refining, Inc.	Accounts receivable, net	$	3.7		$	2.8
Western Refining Logistics, LP	Accounts payable	(2.0		)	—
Minnesota Pipe Line Company	Accounts payable	(1.5		)	(2.7		)

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Condensed Consolidating Financial Information

12 Months Ended

Dec. 31, 2016

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Condensed Financial Statements [Text Block]

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, 2016, the Parent and certain 100% owned 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 St. Paul Park Logistics 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.

As of December 31, 2016, we owned a 100% limited partnership interest in NTI and a 52.6% 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 WNRL through our 100% ownership of its general partner. Accordingly, NTI and WNRL are consolidated with the other accounts of Western.

NTI's long-term debt is comprised of the 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, NTI's general partner. We have 100% ownership of the general partner of NTI. 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; for transporting crude oil and asphalt through its 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.

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.

CONDENSED CONSOLIDATING BALANCE SHEETS

As of December 31, 2016

(In thousands)

	Parent		Guarantor Subsidiaries		Non-Guarantors		Eliminations			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	21	$	224,431	$	44,129	$	—		$	268,581
Accounts receivable, trade, net of a reserve for doubtful accounts	—		117,007		306,164		—			423,171
Accounts receivable, affiliate	16,832		72,760		3,736		(93,328		)	—
Inventories	—		448,012		323,977		—			771,989
Prepaid expenses	—		80,199		15,156		—			95,355
Other current assets	—		74,832		38,589		—			113,421
Total current assets	16,853		1,017,241		731,751		(93,328		)	1,672,517
Equity method investment	—		—		102,685		—			102,685
Property, plant and equipment, net	—		1,117,958		1,246,524		—			2,364,482
Goodwill	—		—		1,289,443		—			1,289,443
Intangible assets, net	—		31,516		52,296		—			83,812
Investment in subsidiaries	5,348,171		—		—		(5,348,171		)	—
Due from affiliate	—		2,443,306		—		(2,443,306		)	—
Other assets	—		27,425		20,033		—			47,458
Total assets	$	5,365,024	$	4,637,446	$	3,442,732	$	(7,884,805	)	$	5,560,397
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable, trade	$	—	$	372,570	$	381,363	$	—		$	753,933
Accounts payable, affiliate	—		—		93,328		(93,328		)	—
Accrued liabilities	5,655		124,628		89,324		—			219,607
Current portion of long-term debt	10,500		—		—		—			10,500
Total current liabilities	16,155		497,198		564,015		(93,328		)	984,040
Long-term liabilities:
Long-term debt, less current portion	1,208,703		—		663,102		—			1,871,805
Due to affiliate	2,443,306		—		—		(2,443,306		)	—
Lease financing obligation	—		45,007		9,156		—			54,163
Deferred income tax liability, net	—		222,372		37,921		—			260,293
Deficit in subsidiaries	—		501,776		—		(501,776		)	—
Other liabilities	—		79,501		13,635		—			93,136
Total long-term liabilities	3,652,009		848,656		723,814		(2,945,082		)	2,279,397
Equity:
Equity - Western	1,696,860		3,291,592		1,554,803		(4,846,395		)	1,696,860
Equity - Non-controlling interest	—		—		600,100		—			600,100
Total equity	1,696,860		3,291,592		2,154,903		(4,846,395		)	2,296,960
Total liabilities and equity	$	5,365,024	$	4,637,446	$	3,442,732	$	(7,884,805	)	$	5,560,397

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	3,790,958		—		—		(3,790,958		)	—
Due from affiliate	—		1,623,427		—		(1,623,427		)	—
Other assets	—		42,166		22,831		—			64,997
Total assets	$	3,790,979	$	4,203,423	$	3,312,431	$	(5,473,440	)	$	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	1,623,427		—		—		(1,623,427		)	—
Lease financing obligation	—		42,168		11,064		—			53,232
Deferred income tax liability, net	—		275,634		37,280		—			312,914
Deficit in subsidiaries	—		287,761		—		(287,761		)	—
Other liabilities	—		63,674		4,921		—			68,595
Total long-term liabilities	2,479,754		669,237		841,832		(1,911,188		)	2,079,635
Equity:
Equity - Western	1,299,297		3,129,379		373,818		(3,503,197		)	1,299,297
Equity - Non-controlling interest	—		—		1,646,609		—			1,646,609
Total equity	1,299,297		3,129,379		2,020,427		(3,503,197		)	2,945,906
Total liabilities and equity	$	3,790,979	$	4,203,423	$	3,312,431	$	(5,473,440	)	$	5,833,393

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS AND COMPREHENSIVE INCOME

For the Year Ended December 31, 2016

(In thousands)

	Parent			Guarantor Subsidiaries			Non-Guarantors			Eliminations			Consolidated
Net sales	$	—		$	6,178,382		$	5,270,300		$	(3,705,469	)	$	7,743,213
Operating costs and expenses:
Cost of products sold (exclusive of depreciation and amortization)	—			5,298,962			4,385,318			(3,705,469		)	5,978,811
Direct operating expenses (exclusive of depreciation and amortization)	—			453,750			474,273			—			928,023
Selling, general and administrative expenses	185			111,268			106,408			—			217,861
Merger and reorganization costs	—			7,759			4,681			—			12,440
Loss (gain) and impairments on disposal of assets, net	—			(207		)	(1,064		)	—			(1,271		)
Maintenance turnaround expense	—			1,372			45,765			—			47,137
Depreciation and amortization	—			106,753			110,034			—			216,787
Total operating costs and expenses	185			5,979,657			5,125,415			(3,705,469		)	7,399,788
Operating income (loss)	(185		)	198,725			144,885			—			343,425
Other income (expense):
Equity in earnings of subsidiaries	201,150			16,603			—			(217,753		)	—
Interest income	—			426			266			—			692
Interest and debt expense	(72,110		)	(3,087		)	(48,094		)	—			(123,291		)
Loss on extinguishment of debt	(3,916		)	—			—			—			(3,916		)
Other, net	—			1,799			23,165			—			24,964
Income before income taxes	124,939			214,466			120,222			(217,753		)	241,874
Provision for income taxes	—			(52,253		)	(2,615		)	—			(54,868		)
Net income	124,939			162,213			117,607			(217,753		)	187,006
Less net income attributed to non-controlling interests	—			—			62,067			—			62,067
Net income attributable to Western Refining, Inc.	$	124,939		$	162,213		$	55,540		$	(217,753	)	$	124,939
Comprehensive income attributable to Western Refining, Inc.	$	124,939		$	162,973		$	55,355		$	(217,753	)	$	125,514

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 of subsidiaries	461,049			11,551			—			(472,600		)	—
Interest income	—			389			314			—			703
Interest and debt expense	(54,104		)	(2,717		)	(48,782		)	—			(105,603		)
Other, net	—			492			12,669			—			13,161
Income before income taxes	406,756			530,934			373,296			(472,600		)	838,386
Provision for income taxes	—			(223,908		)	(47		)	—			(223,955		)
Net income	406,756			307,026			373,249			(472,600		)	614,431
Less net income attributed to non-controlling interests	—			—			207,675			—			207,675
Net income attributable to Western Refining, Inc.	$	406,756		$	307,026		$	165,574		$	(472,600	)	$	406,756
Comprehensive income attributable to Western Refining, Inc.	$	406,756		$	307,681		$	166,861		$	(472,600	)	$	408,698

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
Merger and reorganization 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 of subsidiaries	630,407			17,059			—			(647,466		)	—
Interest income	—			795			393			—			1,188
Interest and debt expense	(70,286		)	(1,044		)	(25,732		)	—			(97,062		)
Loss on extinguishment of debt	(9		)	—			—			—			(9		)
Other, net	—			(604		)	2,650			—			2,046
Income before income taxes	559,926			799,025			291,191			(647,466		)	1,002,676
Provision for income taxes	—			(292,145		)	(459		)	—			(292,604		)
Net income	559,926			506,880			290,732			(647,466		)	710,072
Less net income attributed to non-controlling interests	—			—			150,146			—			150,146
Net income attributable to Western Refining, Inc.	$	559,926		$	506,880		$	140,586		$	(647,466	)	$	559,926
Comprehensive income attributable to Western Refining, Inc.	$	559,926		$	506,403		$	140,122		$	(647,466	)	$	558,985

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

For the Year Ended December 31, 2016

(In thousands)

	Parent			Guarantor Subsidiaries			Non-Guarantors			Eliminations			Consolidated
Cash flows from operating activities:
Net cash provided by operating activities	$	(41,614	)	$	331,819		$	182,302		$	(88,760	)	$	383,747
Cash flows from investing activities:
Capital expenditures	—			(145,760		)	(156,356		)	1,147			(300,969		)
Return of capital from equity method investment	97,379			—			—			(97,379		)	—
Contributions to affiliate	—			(689,063		)	(20,092		)	709,155			—
Proceeds from the sale of assets	—			1,365			5,303			(1,147		)	5,521
Increase in restricted cash	—			—			(195,000		)	—			(195,000		)
Use of restricted cash	—			69,106			195,000			—			264,106
Net cash provided by (used in) investing activities	97,379			(764,352		)	(171,145		)	611,776			(226,342		)
Cash flows from financing activities:
Additions to long-term debt	500,000			—			—			—			500,000
Payments on long-term debt and capital lease obligations	(133,000		)	(1,035		)	(1,357		)	—			(135,392		)
Borrowings on revolving credit facility	—			—			466,900			—			466,900
Repayments of revolving credit facility	—			—			(591,600		)	—			(591,600		)
Payments for NTI units related to merger	(859,893		)	—			—			—			(859,893		)
Transaction costs for NTI merger	(11,741		)	—			—			—			(11,741		)
Contributions from affiliate	689,063			—			20,092			(709,155		)	—
Distribution to non-controlling interest holders	—			—			(66,311		)	—			(66,311		)
Deferred financing costs	(11,503		)	—			(1,224		)	—			(12,727		)
Distribution to affiliate	—			—			(186,139		)	186,139			—
Purchases of common stock for treasury	(75,000		)	—			—			—			(75,000		)
Dividends paid	(153,691		)	—			—			—			(153,691		)
Proceeds from issuance of WNRL common units	—			—			277,751			—			277,751
Offering costs for issuance of WNRL common units	—			—			(655		)	—			(655		)
Excess tax benefit from stock-based compensation	—			1,033			—			—			1,033
Net cash provided by (used in) financing activities	(55,765		)	(2		)	(82,543		)	(523,016		)	(661,326		)
Net increase (decrease) in cash and cash equivalents	—			(432,535		)	(71,386		)	—			(503,921		)
Cash and cash equivalents at beginning of year	21			656,966			115,515			—			772,502
Cash and cash equivalents at end of year	$	21		$	224,431		$	44,129		$	—		$	268,581

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 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		)
Proceeds from the sale of assets	—			2,028			643			(1,557		)	1,114
Contributions to affiliate	—			(178,243		)	(27,888		)	206,131			—
Increase in restricted cash	—			(170,000		)	—			—			(170,000		)
Use of restricted cash	—			267,903			—			—			267,903
Net cash used in investing activities	—			(235,912		)	(162,065		)	206,131			(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			—			53,784			(206,131		)	—
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		)
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			(367,248		)	(25,311		)	(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

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		)	(119,147		)	797,775			—
Increase in restricted cash	—			(320,000		)	—			—			(320,000		)
Use of restricted cash	—			152,991			—			—			152,991
Net cash used in investing activities	—			(943,581		)	(235,058		)	797,775			(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
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			—
Contributions from affiliate	618,564			93,546			85,665			(797,775		)	—
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			(197,021		)	(666,195		)	(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

Due to the change in the guarantor structure resulting from the St. Paul Park Logistics 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, 2015

(In thousands)

	As Previously Reported			Adjustment			Revised
Parent	$	3,964,578		$	(173,620	)	$	3,790,958
Guarantor subsidiaries	(395,774		)	108,013			(287,761		)
Non-guarantor subsidiaries	—			—			—
Eliminations	(3,568,804		)	65,607			(3,503,197		)
Investment (deficit) in subsidiaries	$	—		$	—		$	—
Parent	$	3,964,599		$	(173,620	)	$	3,790,979
Guarantor subsidiaries	4,377,043			(173,620		)	4,203,423
Non-guarantor subsidiaries	3,312,431			—			3,312,431
Eliminations	(5,820,680		)	347,240			(5,473,440		)
Total assets	$	5,833,393		$	—		$	5,833,393
Parent	$	2,665,302		$	(173,620	)	$	2,491,682
Guarantor subsidiaries	1,182,057			(108,013		)	1,074,044
Non-guarantor subsidiaries	1,292,004			—			1,292,004
Eliminations	(2,251,876		)	281,633			(1,970,243		)
Total liabilities	$	2,887,487		$	—		$	2,887,487
Parent	$	1,299,297		$	—		$	1,299,297
Guarantor subsidiaries	3,194,986			(65,607		)	3,129,379
Non-guarantor subsidiaries	2,020,427			—			2,020,427
Eliminations	(3,568,804		)	65,607			(3,503,197		)
Total equity	$	2,945,906		$	—		$	2,945,906

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS AND COMPREHENSIVE INCOME

For the Year Ended December 31, 2015

(In thousands)

	As Previously Reported			Adjustment			Revised
Parent	$	461,049		$	—		$	461,049
Guarantor subsidiaries	42,470			(30,919		)	11,551
Non-guarantor subsidiaries	—			—			—
Eliminations	(503,519		)	30,919			(472,600		)
Equity in earnings (loss) of subsidiaries	$	—		$	—		$	—
Parent	406,756			—			406,756
Guarantor subsidiaries	337,945			(30,919		)	307,026
Non-guarantor subsidiaries	165,574			—			165,574
Eliminations	(503,519		)	30,919			(472,600		)
Net income (loss) attributable to Western Refining, Inc.	$	406,756		$	—		$	406,756
Parent	$	406,756		$	—		$	406,756
Guarantor subsidiaries	338,600			(30,919		)	307,681
Non-guarantor subsidiaries	166,861			—			166,861
Eliminations	(503,519		)	30,919			(472,600		)
Comprehensive income attributable to Western Refining, Inc.	$	408,698		$	—		$	408,698

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	51,747			(34,688		)	17,059
Non-guarantor subsidiaries	—			—			—
Eliminations	(682,154		)	34,688			(647,466		)
Equity in earnings (loss) of subsidiaries	$	—		$	—		$	—
Parent	559,926			—			559,926
Guarantor subsidiaries	541,568			(34,688		)	506,880
Non-guarantor subsidiaries	140,586			—			140,586
Eliminations	(682,154		)	34,688			(647,466		)
Net income (loss) attributable to Western Refining, Inc.	$	559,926		$	—		$	559,926
Parent	$	559,926		$	—		$	559,926
Guarantor subsidiaries	541,091			(34,688		)	506,403
Non-guarantor subsidiaries	140,122			—			140,122
Eliminations	(682,154		)	34,688			(647,466		)
Comprehensive income attributable to Western Refining, Inc.	$	558,985		$	—		$	558,985

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

For the Year Ended December 31, 2015

(In thousands)

	As Previously Reported			Adjustment			Revised
Parent	$	87,364		$	—		$	87,364
Guarantor subsidiaries	433,863			—			433,863
Non-guarantor subsidiaries	502,676			—			502,676
Eliminations	(180,820		)	—			(180,820		)
Net cash provided by (used in) operating activities	$	843,083		$	—		$	843,083
Parent	—			—			—
Guarantor subsidiaries	(235,912		)	—			(235,912		)
Non-guarantor subsidiaries	(134,177		)	(27,888		)	(162,065		)
Eliminations	178,243			27,888			206,131
Net cash provided by (used in) investing activities	$	(191,846	)	$	—		$	(191,846	)
Parent	$	(87,364	)	$	—		$	(87,364	)
Guarantor subsidiaries	170,029			—			170,029
Non-guarantor subsidiaries	(395,136		)	27,888			(367,248		)
Eliminations	2,577			(27,888		)	(25,311		)
Net cash provided by (used in) financing activities	$	(309,894	)	$	—		$	(309,894	)

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	520,972			—			520,972
Non-guarantor subsidiaries	403,087			—			403,087
Eliminations	(131,580		)	—			(131,580		)
Net cash provided by (used in) operating activities	$	737,633		$	—		$	737,633
Parent	—			—			—
Guarantor subsidiaries	(943,581		)	—			(943,581		)
Non-guarantor subsidiaries	(209,457		)	(25,601		)	(235,058		)
Eliminations	772,174			25,601			797,775
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	(222,622		)	25,601			(197,021		)
Eliminations	(640,594		)	(25,601		)	(666,195		)
Net cash provided by (used in) financing activities	$	(393,680	)	$	—		$	(393,680	)

XML

Quarterly Financial Information (Unaudited)

12 Months Ended

Dec. 31, 2016

Quarterly Financial Information (Unaudited)

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 2016 and 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 quarterly financial data for the years ended December 31, 2016, and 2015 is presented below.

	Year Ended December 31, 2016
	Quarter
	First			Second			Third			Fourth
	(Unaudited) (In thousands, except for per share data)
Net sales	$	1,455,504		$	2,107,308		$	2,065,076		$	2,115,325
Operating costs and expenses:
Cost of products sold (exclusive of depreciation and amortization)	1,047,361			1,602,628			1,607,010			1,721,812
Direct operating expenses (exclusive of depreciation and amortization)	223,585			231,169			232,553			240,716
Selling, general and administrative expenses	53,285			56,052			57,320			51,204
Merger and reorganization costs	408			735			2,844			8,453
Gain and impairments on disposal of assets, net	(130		)	(772		)	(279		)	(90		)
Maintenance turnaround expense	125			400			27,208			19,404
Depreciation and amortization	52,651			54,359			54,321			55,456
Total operating costs and expenses	1,377,285			1,944,571			1,980,977			2,096,955
Operating income	78,219			162,737			84,099			18,370
Other income (expense):
Interest income	164			131			141			256
Interest and debt expense	(26,681		)	(26,928		)	(34,456		)	(35,226		)
Loss on extinguishment of debt	—			—			—			(3,916		)
Other, net	6,512			5,076			6,224			7,152
Income (loss) before income taxes	58,214			141,016			56,008			(13,364		)
Provision for income taxes	(18,629		)	(38,152		)	(11,700		)	13,613
Net income	39,585			102,864			44,308			249
Less net income attributable to non-controlling interests	9,047			37,449			5,733			9,838
Net income (loss) attributable to Western Refining, Inc.	$	30,538		$	65,415		$	38,575		$	(9,589	)
Basic earnings (loss) per common share	$	0.34		$	0.70		$	0.36		$	(0.09	)
Diluted earnings (loss) per common share	$	0.33		$	0.70		$	0.35		$	(0.09	)

	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 and debt expense	(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) attributable 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

Northern Tier Energy LP [Member]

Quarterly Financial Information (Unaudited)

21. SUPPLEMENTARY 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 2016 and 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.

(in millions, except per unit data)		First Quarter		Second Quarter		Third Quarter		Fourth Quarter			Total
2016
	Revenue	$	604.4	$	812.3	$	732.3	$	739.6		$	2,888.6
	Operating income	21.8		77.7		11.6		(5.5		)	105.6
	Net income	14.7		70.6		3.6		(12.4		)	76.5
	Earnings per common unit - basic	$	0.16	N/A		N/A		N/A			N/A
	Earnings per common unit - diluted	$	0.16	N/A		N/A		N/A			N/A
2015
	Revenue	$	793.8	$	959.8	$	891.6	$	759.8		$	3,405.0
	Operating income	119.5		139.3		114.6		(5.3		)	368.1
	Net income	111.2		128.9		103.5		(12.6		)	331.0
	Earnings per common unit - basic	$	1.20	$	1.39	$	1.11	$	(0.14	)	$	3.58
	Earnings per common unit - diluted	$	1.20	$	1.39	$	1.11	$	(0.14	)	$	3.56

XML

Western Refining Logistics, L.P.

12 Months Ended

Dec. 31, 2016

Business Combinations [Abstract]

Western Refining Logistics, L.P. [Text Block]

29. Western Refining Logistics, LP

WNRL is a publicly held master limited partnership that owns and operates logistic assets consisting of pipeline and gathering, terminalling, storage and transportation assets, providing related services to our refining segment, including 705 miles of pipelines and approximately 12.4 million barrels of active storage capacity. The majority of WNRL's logistics assets are integral to the operations of the El Paso, Gallup and St. Paul Park 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, asphalt, refined product and lubricant delivery trucks. WNRL distributes commercial wholesale petroleum products primarily in Arizona, Colorado, Nevada, New Mexico and Texas. WNRL purchases petroleum fuels and lubricants from our refining segment and from third-party suppliers.

During the fourth quarter of 2016, WNRL completed an evaluation of its lubricant operations. After careful consideration, having concluded that lubricants are not strategic to its core operations, WNRL has taken steps to divest the remaining assets associated with this business. WNRL anticipates a completed sale within the first half of 2017. Assets related to our lubricant operations include $10.1 million in inventories and $7.3 million in property, plant and equipment in our Consolidated Balance Sheet at December 31, 2016. WNRL expects proceeds from this divestiture to result in a gain on disposal of assets; however, no amounts related to this anticipated transaction have been recorded in the Consolidated Statements of Operations for the year ended December 31, 2016.

At December 31, 2016, we held a 52.6% limited partner interest in WNRL including a non-economic general partner interest. This interest included 9,207,847 common partnership units and 22,811,000 subordinated partnership units. As the general partner of WNRL, we have the sole ability to direct the activities that most significantly impact WNRL's financial performance, and therefore we consolidate WNRL. All intercompany transactions with WNRL are eliminated upon consolidation.

We are WNRL’s primary logistics customer and a significant wholesale customer through our retail business. WNRL generates revenues by charging tariffs and fees for transporting petroleum products and crude oil though its pipelines, by charging fees for terminalling refined products and other hydrocarbons, and storing and providing other services at its storage tanks and terminals. Additionally, WNRL sells various finished petroleum products to us and other third-party customers. Under our long-term agreements with WNRL (discussed below), we accounted for 31.6%, 30.2% and 28.9% of WNRL’s total revenues for the years ended December 31, 2016, 2015 and 2014, respectively. We do not provide financial or equity support through any liquidity arrangements and/or debt guarantees to WNRL.

WNRL has outstanding debt under a senior secured revolving credit facility and its senior notes. Excluding assets held by Western Refining Logistic GP, LLC, WNRL’s creditors have no recourse to our assets. Any recourse to WNRL’s general partner would be limited to the extent of Western Refining Logistics GP LLC’s assets that other than its investment in WNRL, are not significant.Our creditors have no recourse to the assets of WNRL and its consolidated subsidiaries.

WNRL provides us with various pipeline transportation, terminal distribution and storage services under long-term, fee-based commercial agreements. 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 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 has risk associated with its operations. If a major customer of WNRL were to terminate its contracts or fail to meet desired shipping or throughput levels for an extended period of time, revenue would be reduced and WNRL could suffer substantial losses to the extent that a new customer is not found. In the event that WNRL incurs a loss, our operating results will reflect WNRL’s loss, net of intercompany eliminations, to the extent of our ownership interest in WNRL at that point in time.

St. Paul Park Logistics Transaction

On September 15, 2016, we sold the St. Paul Park Logistics Assets to WNRL in exchange for $195 million in cash and 628,224 common units representing limited partner interests in WNRL.

The St. Paul Park Logistics Assets included approximately 4.0 million barrels of refined product and crude oil storage tanks, a light products terminal, a heavy products loading rack, certain rail and barge facilities, certain other related logistics assets and two crude oil pipeline segments and one pipeline segment not currently in service, each of which is approximately 2.5 miles and extends from Western's refinery in St. Paul Park, Minnesota to Western's tank farm in Cottage Grove, Minnesota.

In connection with the St. Paul Park Logistics Transaction, we entered into a terminalling, transportation and storage services agreement with Western (the "St. Paul Park Terminalling Agreement"). Pursuant to the St. Paul Park Terminalling Agreement, we agreed to provide product storage services, product throughput services and product additive and blending services at the terminal facilities located at or near Western's refinery in St. Paul Park, Minnesota. In exchange for such services, Western has agreed to certain minimum volume commitments and to pay certain fees. The St. Paul Park Terminalling Agreement has an initial term of ten years, which may be extended for up to two renewal terms of five years each upon the mutual agreement of the parties.

TexNew Mex Pipeline System Acquisition

On October 30, 2015, we sold the TexNew Mex Pipeline System to WNRL. We sold these assets to WNRL in exchange for $170 million in cash and 421,031 common units representing limited partner interests in WNRL and 80,000TexNew 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.

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

• Asphalt Trucking Transportation Services Agreement – Western has agreed to utilize WNRL's asphalt trucks and pay a flat rate per mile per ton (with market adjustments) based on the distance between the applicable pick-up and delivery points, plus monthly fuel adjustments and customary applicable surcharges. Volumes of asphalt transported pursuant to this agreement will be credited, on a barrel per barrel basis, towards Western’s contract minimum under the Crude Oil Trucking Transportation Services Agreement.

XML

NTI

12 Months Ended

Dec. 31, 2016

Business Acquisition [Line Items]

Mergers, Acquisitions and Dispositions Disclosures [Text Block]

30. NTI

NTI Merger Agreement

On December 21, 2015, Western entered into the NTI Merger Agreement, by and among Western, MergerCo, NTI and Northern Tier Energy GP LLC, the general partner of NTI and a wholly-owned subsidiary of Western (“NTI GP”). On June 23, 2016, following the approval of the NTI Merger by NTI common unitholders, all closing conditions to the NTI Merger were satisfied, and the NTI Merger was successfully completed. Upon the terms and subject to the conditions set forth in the NTI Merger Agreement, MergerCo merged with and into NTI, the separate limited liability company existence of MergerCo ceased and NTI continued to exist as a limited partnership under Delaware law and as an indirect wholly-owned subsidiary of Western and as the surviving entity in the NTI Merger.

Prior to the NTI Merger, NT InterHoldCo LLC, a Delaware limited liability company and wholly-owned subsidiary of Western ("NT InterHoldCo"), owned 100% of the membership interests in NTI GP and 38.3% of NTI’s outstanding common units representing limited partner interests in NTI (“NTI Common Units”). NT InterHoldCo also owned 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 NTI Merger, NTI GP remained the sole general partner of NTI, the NTI Common Units held by Western and its subsidiaries were unchanged and remained issued and outstanding, and, by virtue of the NTI Merger, all of the membership interests in MergerCo automatically 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 NTI Merger. Consequently, NT InterHoldCo and its wholly-owned subsidiary, MergerCo HoldCo, became the sole limited partners of NTI.

Pursuant to the NTI Merger Agreement, we paid $859.9 million in cash and issued 17.1 million shares of Western common stock adjusted slightly for cash paid in lieu of fractional shares. We incurred transaction costs related to the NTI Merger of $11.7 million.

The NTI Merger involved a change in WNR’s ownership interest in its subsidiary, NTI, due to the purchase of the remaining ownership interests not already owned by WNR and was accounted for under Accounting Standards Codification 810-10-45-23, Consolidation, which indicates that increases in a parent’s ownership interest while the parent retains its controlling financial interest in its subsidiary shall be accounted for as an equity transaction. Therefore, no gain or loss was realized as a result of the NTI Merger. Any difference between the consideration paid and the amount by which the non-controlling interest is adjusted was recognized in Western shareholders' equity.

NTI common unitholders made consideration elections that resulted in the following allocation of cash and Western common stock among NTI common unitholders.

• NTI common unitholders who made a valid “Mixed Election” (as defined in the NTI Merger Agreement), or who made no election, received $15.00 in cash and 0.2986 of a share of Western common stock for each such NTI common unit held.

• NTI common unitholders who made a valid “Cash Election” (as defined in the NTI Merger Agreement) received $15.357 in cash and 0.28896 of a share of Western common stock as prorated in accordance with the Merger Agreement for each such NTI common unit held.

• NTI common unitholders who made a valid “Stock Election” (as defined in the NTI Merger Agreement) received 0.7036 of a share of Western common stock for each such NTI common unit held.

The consolidated statements of operations include the results of the NTI Merger beginning on June 23, 2016. NTI's net sales and net loss since June 23, 2016 was $1,905.3 million and $20.1 million, respectively. The following unaudited pro forma information assumes that (i) the Merger occurred on January 1, 2015; (ii) $500.0 million was borrowed to fund the NTI Merger consideration on January 1, 2015, resulting in increased interest and debt expense of $16.8 million and $36.1 million for the years ended December 31, 2016 and 2015, respectively; and (iii) income tax expense increased as a result of the increased net income attributable to Western Refining, Inc. offset by increased interest and debt expense of $7.0 million and $57.3 million for the years ended December 31, 2016 and 2015, respectively.

	Year Ended
	December 31,
	2016		2015
	(In thousands, except per share data)
Net sales	$	7,743,213	$	9,787,036
Operating income	343,425		930,125
Net income	163,129		521,014
Net income attributable to Western Refining, Inc.	136,385		499,859
Basic earnings per share	$	1.26	$	4.46
Diluted earnings per share	1.25		4.46

NTI Merger and Reorganization Expenses

We incurred professional service fees in connection with the NTI Merger transaction. Additionally, we incurred costs associated with initiating a plan of reorganization for various positions during the second half of 2016. In relation to this reorganization plan, it was determined that certain employees would be terminated during 2016 and 2017. We recognized $6.3 million of expense during the year ended December 31, 2016 which included compensation related to the severance of employment and retention bonuses for selected employees. These costs have been included in Merger and reorganization costs in the accompanying Consolidated Statements of Operations and are included in the "Other" category within our segment presentation. We recognize these costs ratably from September 1, 2016, the effective date of the agreements, through the remaining service period, which varies for each employee, but in no case is later than September 1, 2017. As of December 31, 2016, we anticipate that these costs will continue to be recognized through the third quarter of 2017 and for the expenses to be completely paid out by December 31, 2017.

The following table summarizes the expense activity related to the NTI Merger and reorganization for the years ended December 31, 2016, 2015 and 2014:

	Year Ended
	December 31,
	2016			2015			2014
	(In thousands)
Beginning liability for merger and reorganization costs	$	189		$	808		$	—
Third-party professional service fees	1,662			—			—
Reorganization and related personnel costs incurred during period	4,650			—			12,878
Non-cash equity-based awards with accelerated vesting	—			—			(4,789		)
Cash payments to third-party professional service providers	(1,459		)	—			—
Cash payments made to severed employees	(2,468		)	(619		)	(7,281		)
Ending liability for merger and reorganization costs	$	2,574		$	189		$	808

31. Tesoro Merger

Agreement and Plan of Merger

On November 16, 2016, we entered into the Tesoro Merger Agreement with Tesoro, Merger Sub 1 and Merger Sub 2. Subject to the terms and conditions set forth in the Tesoro Merger Agreement, upon consummation of the First Tesoro Merger, each share of our common stock, par value $0.01 per share issued and outstanding immediately prior to the effective time of the First Tesoro Merger (excluding 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 our common stock, either (a) $37.30 in cash or (b) 0.4350 shares of common stock, par value $0.16⅔ per share, of Tesoro (“Tesoro Shares”), in each case without interest.

We recognized $6.1 million of expense related to the Tesoro Merger during the year ended December 31, 2016 which included transaction and consulting costs. These costs have been included in Merger and reorganization costs in the accompanying Consolidated Statements of Operations.

Cash elections will be subject to proration if cash elections are made in respect of more than approximately 10.8 million shares of our common stock. Stock elections are not subject to proration. Western common stock in respect of which no cash election or stock election is validly made will be deemed to be Western common stock in respect of which stock elections have been made.

The Tesoro Merger Agreement permits either the Company or Tesoro to require that the surviving corporation of the First Tesoro Merger be merged with and into Merger Sub 2 immediately following the effective time of the First Tesoro Merger, with Merger Sub 2 being the surviving company from the second merger (the “Second Tesoro Merger” and, if the second merger election is made, collectively with the First Tesoro Merger, the “Tesoro Merger”) if the requiring party reasonably believes, based on legal advice, that the Second Tesoro Merger is necessary to enable the Tesoro Merger to qualify as a “reorganization” within the meaning of Section 368(a) of the Internal Revenue Code.

The completion of the Tesoro Merger is subject to certain customary mutual conditions, including (i) the receipt of the required approvals from Tesoro’s and the Company’s stockholders, (ii) Tesoro’s registration statement on Form S-4 having become effective under the Securities Act of 1933, (iii) the Tesoro Shares issuable in connection with the First Tesoro Merger having been approved for listing on the New York Stock Exchange, subject to official notice of issuance, (iv) the expiration or termination of the waiting period under the Hart-Scott-Rodino Act, (v) the absence of any governmental order or law prohibiting the consummation of the Tesoro Merger or the other transactions contemplated by the Tesoro Merger Agreement and (vi) there not having been imposed a burdensome condition in connection with the expiration or termination of the waiting period applicable under the Hart-Scott-Rodino Act. The obligation of each party to consummate the Tesoro Merger is also conditioned upon (i) compliance by the other party in all material respects with its pre-closing obligations under the Tesoro Merger Agreement and (ii) the accuracy of the representations and warranties of the other party as of the date of the Tesoro Merger Agreement and as of the closing (subject to customary materiality qualifiers). Our obligation to complete the Tesoro Merger is additionally subject to Tesoro's receipt of a tax opinion to the effect that the Tesoro Merger qualifies as a “reorganization” within the meaning of Section 368(a) of the Internal Revenue Code.

The Company and Tesoro have made customary representations, warranties and covenants in the Tesoro Merger Agreement. Subject to certain exceptions, the Company and Tesoro have agreed, among other things, to covenants relating to (i) the conduct of their respective businesses during the interim period between the execution of the Tesoro Merger Agreement and the consummation of the First Tesoro Merger, (ii) the use of their respective reasonable best efforts, subject to certain exceptions, to obtain governmental and regulatory approvals, (iii) obligations to facilitate the Company’s stockholders’ consideration of, and voting upon, the adoption of the Tesoro Merger Agreement and certain related matters as applicable and Tesoro’s stockholders’ consideration of, and voting upon, the issuance of Tesoro Shares in the First Tesoro Merger and certain related matters as applicable, (iv) the recommendation by the board of directors of the Company in favor of the adoption by its stockholders of the Tesoro Merger Agreement, subject to certain exceptions, (v) the recommendation by the board of directors of Tesoro in favor of the issuance of Tesoro Shares in the First Tesoro Merger, subject to certain exceptions, (vi) non-solicitation obligations of Tesoro and the Company relating to alternative acquisition proposals and (vii) the use of reasonable best efforts by Tesoro to take certain steps to obtain debt financing at the closing of the Tesoro Merger to the extent the proceeds thereof are needed to pay the cash consideration and all other cash amounts required to be paid in connection with the closing of the Tesoro Merger.

The Tesoro Merger Agreement permits the Company to continue paying a regular quarterly dividend of up to $0.38 per Company Share and permits Tesoro to continue paying a regular quarterly dividend of up to $0.55 per share.

On December 14, 2016, Tesoro filed a preliminary registration statement on Form S-4 (the “Preliminary S-4”) to register the shares of Tesoro Common Stock to be issued and delivered (or, to the extent held in treasury by Tesoro, delivered but not issued) in the Tesoro Merger. The Preliminary S-4 is subject to future amendments depending on review and comments by the Securities and Exchange Commission (the “SEC”). During January and February of 2017, amended Form S-4s were filed with the SEC. On February 16, 2017, Tesoro filed with the SEC, and the SEC declared effective, a registration statement on Form S-4 (Reg. No. 333-215080), containing a joint proxy statement/prospectus of Tesoro and Western, which proxy statement/prospectus was first mailed to Tesoro and Western stockholders on February 17, 2017.

Voting Agreements

On November 16, 2016, concurrently with the execution of the Tesoro Merger Agreement, the Company, Merger Sub 1, Merger Sub 2 and Tesoro entered into three separate voting agreements (each, a “Voting Agreement”) with (i) Paul L. Foster and Franklin Mountain Investments, LP, (ii) Jeff A. Stevens, and (iii) Scott D. Weaver (each, a “Stockholder” and collectively, the “Stockholders”) pursuant to each of which, among other things and subject to the terms and conditions therein, the Stockholder(s) party thereto have agreed to vote all Western common stock beneficially owned by them (the “Covered Shares”) in favor of the adoption of the Tesoro Merger Agreement and the approval of the transactions contemplated by the Tesoro Merger Agreement, including the Tesoro Merger, and to not vote in favor of any alternative acquisition proposal or other action or agreement that would reasonably be expected to adversely affect the Tesoro Merger.

The Voting Agreements also generally prohibit the Stockholders from transferring the Covered Shares. The Voting Agreements terminate upon the earlier of the termination of the Tesoro Merger Agreement and the time the Tesoro Merger becomes effective.

Northern Tier Energy LP [Member]

Business Acquisition [Line Items]

Mergers, Acquisitions and Dispositions Disclosures [Text Block]

20. MERGER TRANSACTION

Description of the Transaction

On December 21, 2015, Western entered into the Merger Agreement, by and among Western, MergerCo, NTI and Northern Tier Energy GP LLC, the general partner of NTI and a wholly-owned subsidiary of Western ("NTI GP"). On June 23, 2016, following the approval of the Merger by NTI common unitholders, all closing conditions to the Merger were satisfied, and the Merger was successfully completed. Upon the terms and subject to the conditions set forth in the Merger Agreement, MergerCo merged with and into NTI, the separate limited liability company existence of MergerCo ceased and NTI continued 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.

Prior to the Merger, NT InterHoldCo LLC, a Delaware limited liability company and wholly-owned subsidiary of Western ("NT InterHoldCo"), owned 100% of the membership interests in NTI GP and 38.3% of NTI’s outstanding common units representing limited partner interests in NTI ("NTI Common Units"). NT InterHoldCo also owned 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 remained the sole general partner of NTI, the NTI Common Units held by Western and its subsidiaries were unchanged and remained issued and outstanding, and, by virtue of the Merger, all of the membership interests in MergerCo automatically 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. Consequently, NT InterHoldCo and its wholly-owned subsidiary, MergerCo HoldCo, became the sole limited partners of NTI.

Pursuant to the Merger Agreement, Western paid $859.9 million in cash and issued 17.1 million shares of Western Common Stock adjusted slightly for cash paid in lieu of fractional shares. NTI common unitholders made consideration elections that resulted in the following allocation of cash and Western common stock among NTI common unitholders.

• NTI common unitholders who made a valid "Mixed Election" (as defined in the Merger Agreement), or who made no election, received $15.00 in cash and 0.2986 of a share of Western common stock for each such NTI common unit held.

• NTI common unitholders who made a valid "Cash Election" (as defined in the Merger Agreement) received $15.357 in cash and 0.28896 of a share of Western common stock as prorated in accordance with the Merger Agreement for each such NTI common unit held.

• NTI common unitholders who made a valid "Stock Election" (as defined in the Merger Agreement) received 0.7036 of a share of Western common stock for each such NTI common unit held.

Merger and Reorganization expenses

The Company incurred professional service fees in connection with the Merger transaction. Additionally, the Company incurred costs associated with initiating a plan of reorganization for various positions in the third quarter of 2016. In relation to this reorganization plan, it was determined that certain employees would be terminated during 2016 and 2017. The Company recognized $4.7 million and $2.5 million of expense during the years ended December 31, 2016 and 2015, respectively, which included compensation related to the severance of employment and retention bonuses for selected employees. These costs are recognized in the merger-related expenses line within the consolidated statements of operations and comprehensive income. All reorganization and related costs are recognized in the Other segment. The Company recognizes these costs ratably from September 1, 2016, the effective date of the agreements, through the remaining service period, which varies for each employee, but in no case is later than September 1, 2017. As of December 31, 2016, the Company anticipates that these costs will continue to be recognized through the third quarter of 2017 and for the expenses to be completely paid out by December 31, 2017.

The following table summarizes the merger-related and reorganization expense activity for the years ended December 31, 2016, 2015 and 2014:

	Year Ended December 31,
(in millions)	2016			2015			2014
Beginning liability for merger and reorganization costs	$	0.2		$	0.8		$	—
Third-party professional service fees	1.7			—			—
Reorganization and related personnel costs incurred during period	3.0			—			12.9
Less: non-cash equity-based awards with accelerated vesting	—			—			(4.8		)
Cash payments to third-party professional service providers	(1.4		)	—			—
Cash payments made to severed employees	(1.0		)	(0.6		)	(7.3		)
Ending liability for merger and reorganization costs	$	2.5		$	0.2		$	0.8

XML

Tesoro Merger (Notes)

12 Months Ended

Dec. 31, 2016

Business Combinations [Abstract]

Mergers, Acquisitions and Dispositions Disclosures [Text Block]

30. NTI

NTI Merger Agreement

On December 21, 2015, Western entered into the NTI Merger Agreement, by and among Western, MergerCo, NTI and Northern Tier Energy GP LLC, the general partner of NTI and a wholly-owned subsidiary of Western (“NTI GP”). On June 23, 2016, following the approval of the NTI Merger by NTI common unitholders, all closing conditions to the NTI Merger were satisfied, and the NTI Merger was successfully completed. Upon the terms and subject to the conditions set forth in the NTI Merger Agreement, MergerCo merged with and into NTI, the separate limited liability company existence of MergerCo ceased and NTI continued to exist as a limited partnership under Delaware law and as an indirect wholly-owned subsidiary of Western and as the surviving entity in the NTI Merger.

Prior to the NTI Merger, NT InterHoldCo LLC, a Delaware limited liability company and wholly-owned subsidiary of Western ("NT InterHoldCo"), owned 100% of the membership interests in NTI GP and 38.3% of NTI’s outstanding common units representing limited partner interests in NTI (“NTI Common Units”). NT InterHoldCo also owned 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 NTI Merger, NTI GP remained the sole general partner of NTI, the NTI Common Units held by Western and its subsidiaries were unchanged and remained issued and outstanding, and, by virtue of the NTI Merger, all of the membership interests in MergerCo automatically 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 NTI Merger. Consequently, NT InterHoldCo and its wholly-owned subsidiary, MergerCo HoldCo, became the sole limited partners of NTI.

Pursuant to the NTI Merger Agreement, we paid $859.9 million in cash and issued 17.1 million shares of Western common stock adjusted slightly for cash paid in lieu of fractional shares. We incurred transaction costs related to the NTI Merger of $11.7 million.

The NTI Merger involved a change in WNR’s ownership interest in its subsidiary, NTI, due to the purchase of the remaining ownership interests not already owned by WNR and was accounted for under Accounting Standards Codification 810-10-45-23, Consolidation, which indicates that increases in a parent’s ownership interest while the parent retains its controlling financial interest in its subsidiary shall be accounted for as an equity transaction. Therefore, no gain or loss was realized as a result of the NTI Merger. Any difference between the consideration paid and the amount by which the non-controlling interest is adjusted was recognized in Western shareholders' equity.

NTI common unitholders made consideration elections that resulted in the following allocation of cash and Western common stock among NTI common unitholders.

• NTI common unitholders who made a valid “Mixed Election” (as defined in the NTI Merger Agreement), or who made no election, received $15.00 in cash and 0.2986 of a share of Western common stock for each such NTI common unit held.

• NTI common unitholders who made a valid “Cash Election” (as defined in the NTI Merger Agreement) received $15.357 in cash and 0.28896 of a share of Western common stock as prorated in accordance with the Merger Agreement for each such NTI common unit held.

• NTI common unitholders who made a valid “Stock Election” (as defined in the NTI Merger Agreement) received 0.7036 of a share of Western common stock for each such NTI common unit held.

The consolidated statements of operations include the results of the NTI Merger beginning on June 23, 2016. NTI's net sales and net loss since June 23, 2016 was $1,905.3 million and $20.1 million, respectively. The following unaudited pro forma information assumes that (i) the Merger occurred on January 1, 2015; (ii) $500.0 million was borrowed to fund the NTI Merger consideration on January 1, 2015, resulting in increased interest and debt expense of $16.8 million and $36.1 million for the years ended December 31, 2016 and 2015, respectively; and (iii) income tax expense increased as a result of the increased net income attributable to Western Refining, Inc. offset by increased interest and debt expense of $7.0 million and $57.3 million for the years ended December 31, 2016 and 2015, respectively.

	Year Ended
	December 31,
	2016		2015
	(In thousands, except per share data)
Net sales	$	7,743,213	$	9,787,036
Operating income	343,425		930,125
Net income	163,129		521,014
Net income attributable to Western Refining, Inc.	136,385		499,859
Basic earnings per share	$	1.26	$	4.46
Diluted earnings per share	1.25		4.46

NTI Merger and Reorganization Expenses

We incurred professional service fees in connection with the NTI Merger transaction. Additionally, we incurred costs associated with initiating a plan of reorganization for various positions during the second half of 2016. In relation to this reorganization plan, it was determined that certain employees would be terminated during 2016 and 2017. We recognized $6.3 million of expense during the year ended December 31, 2016 which included compensation related to the severance of employment and retention bonuses for selected employees. These costs have been included in Merger and reorganization costs in the accompanying Consolidated Statements of Operations and are included in the "Other" category within our segment presentation. We recognize these costs ratably from September 1, 2016, the effective date of the agreements, through the remaining service period, which varies for each employee, but in no case is later than September 1, 2017. As of December 31, 2016, we anticipate that these costs will continue to be recognized through the third quarter of 2017 and for the expenses to be completely paid out by December 31, 2017.

The following table summarizes the expense activity related to the NTI Merger and reorganization for the years ended December 31, 2016, 2015 and 2014:

	Year Ended
	December 31,
	2016			2015			2014
	(In thousands)
Beginning liability for merger and reorganization costs	$	189		$	808		$	—
Third-party professional service fees	1,662			—			—
Reorganization and related personnel costs incurred during period	4,650			—			12,878
Non-cash equity-based awards with accelerated vesting	—			—			(4,789		)
Cash payments to third-party professional service providers	(1,459		)	—			—
Cash payments made to severed employees	(2,468		)	(619		)	(7,281		)
Ending liability for merger and reorganization costs	$	2,574		$	189		$	808

31. Tesoro Merger

Agreement and Plan of Merger

On November 16, 2016, we entered into the Tesoro Merger Agreement with Tesoro, Merger Sub 1 and Merger Sub 2. Subject to the terms and conditions set forth in the Tesoro Merger Agreement, upon consummation of the First Tesoro Merger, each share of our common stock, par value $0.01 per share issued and outstanding immediately prior to the effective time of the First Tesoro Merger (excluding 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 our common stock, either (a) $37.30 in cash or (b) 0.4350 shares of common stock, par value $0.16⅔ per share, of Tesoro (“Tesoro Shares”), in each case without interest.

We recognized $6.1 million of expense related to the Tesoro Merger during the year ended December 31, 2016 which included transaction and consulting costs. These costs have been included in Merger and reorganization costs in the accompanying Consolidated Statements of Operations.

Cash elections will be subject to proration if cash elections are made in respect of more than approximately 10.8 million shares of our common stock. Stock elections are not subject to proration. Western common stock in respect of which no cash election or stock election is validly made will be deemed to be Western common stock in respect of which stock elections have been made.

The Tesoro Merger Agreement permits either the Company or Tesoro to require that the surviving corporation of the First Tesoro Merger be merged with and into Merger Sub 2 immediately following the effective time of the First Tesoro Merger, with Merger Sub 2 being the surviving company from the second merger (the “Second Tesoro Merger” and, if the second merger election is made, collectively with the First Tesoro Merger, the “Tesoro Merger”) if the requiring party reasonably believes, based on legal advice, that the Second Tesoro Merger is necessary to enable the Tesoro Merger to qualify as a “reorganization” within the meaning of Section 368(a) of the Internal Revenue Code.

The completion of the Tesoro Merger is subject to certain customary mutual conditions, including (i) the receipt of the required approvals from Tesoro’s and the Company’s stockholders, (ii) Tesoro’s registration statement on Form S-4 having become effective under the Securities Act of 1933, (iii) the Tesoro Shares issuable in connection with the First Tesoro Merger having been approved for listing on the New York Stock Exchange, subject to official notice of issuance, (iv) the expiration or termination of the waiting period under the Hart-Scott-Rodino Act, (v) the absence of any governmental order or law prohibiting the consummation of the Tesoro Merger or the other transactions contemplated by the Tesoro Merger Agreement and (vi) there not having been imposed a burdensome condition in connection with the expiration or termination of the waiting period applicable under the Hart-Scott-Rodino Act. The obligation of each party to consummate the Tesoro Merger is also conditioned upon (i) compliance by the other party in all material respects with its pre-closing obligations under the Tesoro Merger Agreement and (ii) the accuracy of the representations and warranties of the other party as of the date of the Tesoro Merger Agreement and as of the closing (subject to customary materiality qualifiers). Our obligation to complete the Tesoro Merger is additionally subject to Tesoro's receipt of a tax opinion to the effect that the Tesoro Merger qualifies as a “reorganization” within the meaning of Section 368(a) of the Internal Revenue Code.

The Company and Tesoro have made customary representations, warranties and covenants in the Tesoro Merger Agreement. Subject to certain exceptions, the Company and Tesoro have agreed, among other things, to covenants relating to (i) the conduct of their respective businesses during the interim period between the execution of the Tesoro Merger Agreement and the consummation of the First Tesoro Merger, (ii) the use of their respective reasonable best efforts, subject to certain exceptions, to obtain governmental and regulatory approvals, (iii) obligations to facilitate the Company’s stockholders’ consideration of, and voting upon, the adoption of the Tesoro Merger Agreement and certain related matters as applicable and Tesoro’s stockholders’ consideration of, and voting upon, the issuance of Tesoro Shares in the First Tesoro Merger and certain related matters as applicable, (iv) the recommendation by the board of directors of the Company in favor of the adoption by its stockholders of the Tesoro Merger Agreement, subject to certain exceptions, (v) the recommendation by the board of directors of Tesoro in favor of the issuance of Tesoro Shares in the First Tesoro Merger, subject to certain exceptions, (vi) non-solicitation obligations of Tesoro and the Company relating to alternative acquisition proposals and (vii) the use of reasonable best efforts by Tesoro to take certain steps to obtain debt financing at the closing of the Tesoro Merger to the extent the proceeds thereof are needed to pay the cash consideration and all other cash amounts required to be paid in connection with the closing of the Tesoro Merger.

The Tesoro Merger Agreement permits the Company to continue paying a regular quarterly dividend of up to $0.38 per Company Share and permits Tesoro to continue paying a regular quarterly dividend of up to $0.55 per share.

On December 14, 2016, Tesoro filed a preliminary registration statement on Form S-4 (the “Preliminary S-4”) to register the shares of Tesoro Common Stock to be issued and delivered (or, to the extent held in treasury by Tesoro, delivered but not issued) in the Tesoro Merger. The Preliminary S-4 is subject to future amendments depending on review and comments by the Securities and Exchange Commission (the “SEC”). During January and February of 2017, amended Form S-4s were filed with the SEC. On February 16, 2017, Tesoro filed with the SEC, and the SEC declared effective, a registration statement on Form S-4 (Reg. No. 333-215080), containing a joint proxy statement/prospectus of Tesoro and Western, which proxy statement/prospectus was first mailed to Tesoro and Western stockholders on February 17, 2017.

Voting Agreements

On November 16, 2016, concurrently with the execution of the Tesoro Merger Agreement, the Company, Merger Sub 1, Merger Sub 2 and Tesoro entered into three separate voting agreements (each, a “Voting Agreement”) with (i) Paul L. Foster and Franklin Mountain Investments, LP, (ii) Jeff A. Stevens, and (iii) Scott D. Weaver (each, a “Stockholder” and collectively, the “Stockholders”) pursuant to each of which, among other things and subject to the terms and conditions therein, the Stockholder(s) party thereto have agreed to vote all Western common stock beneficially owned by them (the “Covered Shares”) in favor of the adoption of the Tesoro Merger Agreement and the approval of the transactions contemplated by the Tesoro Merger Agreement, including the Tesoro Merger, and to not vote in favor of any alternative acquisition proposal or other action or agreement that would reasonably be expected to adversely affect the Tesoro Merger.

The Voting Agreements also generally prohibit the Stockholders from transferring the Covered Shares. The Voting Agreements terminate upon the earlier of the termination of the Tesoro Merger Agreement and the time the Tesoro Merger becomes effective.

XML

Summary of Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2016

Segment Reporting Information [Line Items]

Principles of Consolidation

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.

We own 100% of NTI's general partner and, subsequent to the NTI Merger, we own 100% of the limited partner interest in NTI. We own a 52.6% limited partner interest in WNRL and 100% of WNRL's general partner. As the general partner of WNRL, we have the ability to direct the activities of WNRL that most significantly impact its respective economic performance. We have reported a non-controlling interest for WNRL as of December 31, 2016, of $600.1 million and non-controlling interests for NTI and WNRL of $1,646.6 million as of December 31, 2015, in our Consolidated Balance Sheets. Investments in significant non-controlled entities over which we have the ability to exercise significant influence are accounted for using the equity method.

Cash Equivalents

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.

Cash and Cash Equivalents, Restricted Cash and Cash Equivalents, Policy [Policy Text Block]

Restricted Cash

Restricted cash at December 31, 2015 reported in our Consolidated Balance Sheets relates to net proceeds from the sale of Western's TexNew Mex Pipeline System to WNRL. This cash was used to invest in capital assets.

Accounts Receivable

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, $0.2 million and $0.5 million for the years ended December 31, 2016, 2015 and 2014, respectively. Additions, deductions and balances for the reserve for doubtful accounts for the three years ended December 31, 2016, are presented below:

	Year Ended December 31,
	2016			2015			2014
	(In thousands)
Balance at January 1	$	169		$	484		$	906
Additions	803			367			3,095
Reductions	(737		)	(682		)	(3,517		)
Balance at December 31	$	235		$	169		$	484

Inventories

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.

Equity Method Investments, Policy [Policy Text Block]

Equity Method Investment

We own a 17% common equity interest in Minnesota Pipe Line Company, LLC ("MPL"). 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, 2016 and 2015 and is included in other non-current assets in our Consolidated Balance Sheets.

Property, Plant and Equipment

Property, Plant and Equipment

Property, plant and equipment are stated at cost. We capitalize interest on expenditures for capital projects in process greater than six months and greater than $1 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.

Intangible Assets

Goodwill

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

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

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.

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

Other assets consist primarily of commodity hedging activities receivable and various other assets that are related to our general operation and are stated at cost.

Impairment of Long-Lived Assets

Impairment of Long-Lived Assets

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

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

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

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

Revenue Recognition

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

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 and service parts and labor. Retail cost of products sold includes costs for motor fuels and for merchandise. Motor fuel cost of products sold represents net cost for purchased fuel. Net cost of purchased fuel excludes transportation and motor fuel taxes. Merchandise cost of products sold includes merchandise purchases, net of merchandise rebates and inventory shrinkage.

Refining direct operating expenses include direct costs of labor, maintenance materials and services, chemicals and catalysts, natural gas, utilities and other direct operating expenses. 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.

Maintenance Turnaround Expense

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

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 ("RSU"). The fair value of each restricted share or RSU 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 RSUs 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.

Financial Instruments and Fair Value

Financial Instruments and Fair Value

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

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

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

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

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

Pension and Other Postretirement Obligations

Pension and Other Postretirement 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

Asset Retirement Obligations

We are required to recognize certain obligations for the retirement of our tangible long-lived assets that result from acquisition, construction, development and normal operation. A retirement obligation exists if a party is required to settle an obligation as a result of an existing or enacted law, statute, ordinance or written or oral contract or by legal construction of a contract under the doctrine of promissory estoppel. We record the fair value of a liability for an asset retirement obligation (“ARO”) in the period in which it is incurred if a reasonable estimate of fair value can be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. The increase in the ARO due to the passage of time is recorded as an operating expense (accretion expense). See Note 14, Asset Retirement Obligations.

Environmental and Other Loss Contingencies

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

Income Taxes

Income Taxes

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 WNRL due to our ownership of the general partner. WNRL is a publicly held master limited partnership, which is not taxable for federal income tax. We record income taxes on the portion of income or loss attributable to our respective ownership of WNRL.

Use of Estimates

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.

Northern Tier Energy LP [Member]

Segment Reporting Information [Line Items]

Concentration Risk, Credit Risk, Policy [Policy Text Block]

Concentrations of Risk

The Company is exposed to credit risk in the event of nonpayment by customers. The creditworthiness of customers is subject to continuing review. No single non-related party customer accounts for more than 10% of annual revenues.

Crude oil is the principal raw material for the Company and the majority of the crude oil processed is delivered to the refinery through a pipeline that is owned by MPL, a related party. A prolonged disruption of that pipeline's operations would materially impact the Company's ability to economically obtain raw materials.

The Company is exposed to concentrated geographical risk as most of its operations are conducted in the Upper Great Plains of the United States.

Principles of Consolidation

Principles of Consolidation

NTE LP is a Delaware limited partnership which consolidates all accounts of NTE LLC and its subsidiaries, including SPPR, NTRH and NTOT. All intercompany accounts have been eliminated in these consolidated financial statements.

The Company’s common equity interests in MPL and WNRL are accounted for using the equity method of accounting. Although SPPR owns only 1.0% of WNRL's common equity, its indirect parent company, Western, owns 52.6%. Because of Western’s controlling influence over WNRL, the investment provides the Company significant influence over WNRL and the Company accounts for its ownership interest in WNRL under the equity method. Equity income from MPL and WNRL represent the Company’s proportionate share of net income available to common equity owners generated by MPL and WNRL. See Note 3for further discussion of the Company's ownership interests in MPL and WNRL.

The equity method investments are 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 operating income. See Note 6 for further information on the Company’s equity method investment.

MPLI owns all of the preferred membership units of MPL. This investment in MPLI, which provides the Company no significant influence over MPLI, is accounted for as a cost method investment. The investment in MPLI is carried at a value of $6.8 million at both December 31, 2016 and 2015, and is included in other noncurrent assets within the consolidated balance sheets.

Cash Equivalents

Cash and Cash Equivalents

The Company considers all highly liquid investments with maturities of three months or less from the date of purchase to be cash equivalents.

Accounts Receivable

Receivables and Allowance for Doubtful Accounts

Receivables of the Company primarily consist of customer accounts receivable. The accounts receivable are due from a diverse base including companies in the petroleum industry, airlines and governmental entities. The allowance for doubtful accounts is reviewed regularly for collectability. All customer receivables are recorded at the invoiced amounts and generally do not bear interest. When it becomes probable the receivable will not be collected, the balances for customer receivables are charged directly to bad debt expense. The allowance for doubtful accounts was zero at both December 31, 2016 and 2015.

Inventories

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. Ending inventory costs in excess of market value are written down to net realizable market values and charged to cost of sales in the period recorded. In subsequent periods, a new LCM determination is made based upon current circumstances relative to, and not to exceed, the original LCM reserve that was established in fourth quarter 2014. However, in no case would the LCM reserve be reversed beyond zero. The Company has LIFO pools for crude oil and other feedstocks and for refined products in its Refining segment and a LIFO pool for refined products inventory held by the retail stores in its Retail segment. Retail merchandise inventory is valued using the average cost method.

Property, Plant and Equipment

Property, Plant and Equipment

Property, plant and equipment is recorded at cost and depreciated on a straight-line basis over the estimated useful lives of the assets. Such assets or asset groups are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If the sum of the expected undiscounted future cash flows from the use of the asset and its eventual disposition is less than the carrying amount of the asset, an impairment loss is recognized based on the fair value of the asset. The amortization of capital lease assets is presented in depreciation and amortization.

When property, plant and equipment depreciated on an individual basis is sold or otherwise disposed of, any gains or losses are reported in the consolidated statements of operations and comprehensive income. Gains on the disposal of property, plant and equipment are recognized when earned, which is generally at the time of sale. If a loss on disposal is expected, such losses are generally recognized when the assets are classified as held for sale.

Expenditures for routine maintenance and repair costs are expensed when incurred. Refinery process units require periodic major maintenance and repairs that are commonly referred to as "turnarounds." Turnaround cycles vary from unit to unit but can be as short as one year for catalyst changes to as long as six years. Turnaround costs are expensed as incurred.

Intangible Assets

Intangible Assets

Intangible assets primarily include a retail marketing trade name and franchise agreements. These assets have an indefinite life and therefore are not amortized, but rather are tested for impairment annually or when events or changes in circumstances indicate that the fair value of the intangible asset has been reduced below carrying value. If the estimated fair value is less than the carrying amount of the asset, an impairment loss is recognized based on the estimated fair value of the asset. Significant assumptions in determining the estimated fair value of the indefinite lived intangibles include projected store growth, estimated market royalty rates, market growth rates and the estimated discount rate.

Other Assets

Financing Costs

Financing origination fees on the Company's senior secured notes and ABL Facility are deferred and classified within long-term debt on the consolidated balance sheets. Additionally, financing origination fees on the Company's sales-leaseback transaction covering a majority of its retail stores were also deferred and are classified within other assets on the consolidated balance sheets. Amortization on these deferred costs are provided on a straight-line basis over the term of the agreement, which approximates the effective interest method.

Revenue Recognition

Revenue Recognition

Revenues are recognized when products are shipped or services are provided to customers, title is transferred, the sales price is fixed or determinable and collectability is reasonably assured. Revenues are recorded net of discounts granted to customers. Shipping and other transportation costs billed to customers are presented on a gross basis in revenues and cost of sales.

Prior to October 1, 2014, the Company maintained a crude oil supply and logistics agreement with J.P. Morgan Commodities Canada Corporation ("JPM CCC") pursuant to which JPM CCC assisted the Company in the purchase of substantially all of its crude oil needs for the refinery. As discussed in Note 5, JPM CCC and the Company mutually agreed to terminate this agreement. In the fourth quarter of 2014, subsequent to the termination of this agreement, the Company significantly increased its crude procurement activities and related exchange and buy/sell activity to manage the volumes, grade, timing, and locations of such crude. Such activities are similar to the buy/sell crude oil transactions noted above and are recorded net in cost of sales.

Nonmonetary product exchanges and certain buy/sell crude oil transactions, which are entered into in contemplation one with another, are included on a net cost basis in cost of sales. The Company also enters into agreements to purchase and sell crude oil to third parties and certain of these activities are recorded on a gross basis.

Cost Classifications

Product Exchanges

The Company enters into exchange contracts whereby it agrees to deliver a particular quantity and quality of crude oil or refined products at a specified location and date to a particular counterparty and to receive from the same counterparty a particular quantity and quality of crude oil or refined products at a specified location on the same or another specified date. The exchange receipts and deliveries are nonmonetary transactions, with the exception of associated grade or location differentials that are settled in cash. These transactions are recorded net in cost of sales because they involve the exchange of inventories held in the ordinary course of business to facilitate sales to customers or delivery of feedstocks to our refinery. The exchange transactions are recognized at the carrying amount of the inventory transferred plus or minus any cash settlement due to grade or location differentials.

Cost of Sales

Cost of sales in the consolidated statements of operations and comprehensive income excludes depreciation and amortization of refinery assets and the direct labor and overhead costs related to the operation of the refinery. These costs are included in the consolidated statements of operations and comprehensive income in the depreciation and amortization and direct operating expenses line items, respectively.

Excise Taxes

The Company is required by various governmental authorities, including federal and state, to collect and remit taxes on certain products. Such taxes are presented on a gross basis in revenue and cost of sales in the consolidated statements of operations and comprehensive income. These taxes totaled $432.2 million, $402.9 million and $396.4 million for the years ended December 31, 2016, 2015 and 2014, respectively.

Advertising

The Company expenses the costs of advertising as incurred. Advertising expense was $2.9 million, $2.9 million and $2.3 million for the years ended December 31, 2016, 2015 and 2014, respectively.

Stock-Based Compensation

Equity-Based Compensation

The Company recognizes compensation expense for equity-based awards issued over the requisite service period. Equity-based compensation costs are measured at the date of grant, based on the fair value of the award. Prior to our Merger, the Company granted equity awards indexed to Northern Tier Energy, LP common units. Concurrent with the Merger, all unvested equity-based awards were converted to new awards indexed to Western Refining, Inc. common stock. Both prior to and subsequent to the Merger, the Company has awarded equity-based phantom awards which, at the discretion of the board of directors of our general partner, may be settled in either cash or common equity. All equity-based phantom awards that vested through December 31, 2016 have been settled in common equity. We anticipate that the remaining unvested phantom awards will also be satisfied with common equity and have therefore classified the accrual of the service cost as equity. However, if our general partner's board elects to settle the phantom awards with cash, it could cause us to remeasure the fair value of those awards resulting in an adjustment to earnings for the cumulative difference between the fair value at the date of grant and date of the remeasurement.

Financial Instruments and Fair Value

Derivative Financial Instruments

The Company is exposed to earnings and cash flow volatility due to fluctuations in crude oil, refined products, and natural gas prices. The timing of certain commodity purchases and sales also subject the Company to earnings and cash flow volatility. To manage these risks, the Company may use derivative instruments associated with the purchase or sale of crude oil, refined products, and natural gas to hedge volatility in our refining and operating margins. The Company may use futures, options, and swaps contracts to manage price risks associated with inventory quantities above or below target levels. Crack spread and crude differential futures and swaps contracts may also be used to hedge the volatility of refining margins.

All derivative instruments, except for those that meet the normal purchases and normal sales exception, are recorded in the consolidated balance sheets at fair value and are classified depending on the maturity date of the underlying contracts. Changes in the fair value of the Company's contracts are accounted for by marking them to market and recognizing any resulting gains or losses in the consolidated statements of operations and comprehensive income. Gains and losses from derivative activity specific to managing price risk on inventory quantities both above and below target levels are included within cost of sales. Derivative gains and losses are reported as operating activities within the consolidated statements of cash flows.

The Company enters into crude oil forward contracts to facilitate the supply of crude oil to the refinery. These contracts may qualify for the normal purchases and normal sales exception because the Company physically receives and delivers the crude oil under the contracts and when the Company enters into these contracts, the quantities are expected to be used or sold over a reasonable period of time in the normal course of business. These transactions are reflected in the period that delivery of the crude oil takes place. When forward contracts do not qualify for the normal purchases and sales exception, the contracts are marked to market each period through the settlement date, which is generally no longer than one to three months.

Pension and Other Postretirement Obligations

Defined Benefit Plans

The Company has a cash balance plan and a retiree medical plan that are considered defined benefit plans. Expenses and liabilities related to defined benefit plans 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.

Cash balance and retiree medical 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 could have a significant effect on our pension and retiree medical liabilities and costs. See further information on our plans in Note 15.

Asset Retirement Obligations

Asset Retirement Obligations

The fair value of asset retirement obligations is recognized in the period in which the obligations are incurred if a reasonable estimate of fair value can be made. Conditional asset retirement obligations for removal and disposal of fire-retardant material from certain refining assets have been recognized. The amounts recorded for such obligations are based on the most probable current cost projections. Asset retirement obligations have not been recognized for the removal of materials and equipment from or the closure of certain refinery, pipeline, terminal and retail marketing assets because the fair value cannot be reasonably estimated since the settlement dates of the obligations are indeterminable. Current inflation rates and credit-adjusted-risk-free interest rates are used to estimate the fair value of asset retirement obligations. Depreciation of capitalized asset retirement costs and accretion of asset retirement obligations are recorded over time. Depreciation is determined on a straight-line basis, while accretion escalates over the lives of the assets. See further information on our asset retirement obligations in Note 13.

Environmental and Other Loss Contingencies

Environmental Costs

Environmental expenditures are capitalized if the costs mitigate or prevent future contamination or if the costs improve environmental safety or efficiency of the existing assets. The Company provides for remediation costs and penalties when the responsibility to remediate is probable and the amount of associated costs can be reasonably estimated. The timing of remediation accruals coincides with completion of feasibility studies, investigations or the commitment to a formal plan of action. 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. Remediation liabilities are accrued based on estimates of known environmental exposure and are discounted when the estimated amounts are reasonably fixed and determinable. If recoveries of remediation costs from third parties are probable, a receivable is recorded and is discounted to net present value when the estimated amount is reasonably fixed and determinable.

Use of Estimates

Use of Estimates

The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities as of the date of the consolidated financial statements and the reported amounts of revenues and expenses during the respective reporting periods. Actual results could differ from those estimates.

Segment Reporting, Policy [Policy Text Block]

Operating Segments

The Company has two reportable operating segments; Refining and Retail (see Note19 for further information on the Company’s operating segments). The Refining and Retail operating segments consist of the following:

• Refining – operates the St. Paul Park, Minnesota refinery, NTOT and includes the Company's interest in MPL and MPLI, and

• Retail – comprised 170 Company-operated convenience stores and 115 franchisee operated convenience stores as of December 31, 2016, primarily in Minnesota and Wisconsin. The retail segment also includes the operation of NTB.

Comprehensive Income, Policy [Policy Text Block]

Comprehensive Income

The Company has unrecognized prior service cost related to both its defined benefit cash balance plan as of December 31, 2016, 2015 and 2014 and unrecognized actuarial losses and prior service cost related to its retiree medical plan as of December 31, 2016 and 2015 (see Note 15). The accumulated unrecognized income (loss) related to these plans amounted to $(0.1) million and $0.2 million as of December 31, 2016 and 2015, respectively. These gains/(losses) of $(0.3) million, $3.4 million and $(1.2) million were recognized directly to equity as an element of other comprehensive income (loss) in the years ended December 31, 2016, 2015 and 2014, respectively.

Renewable Identification Numbers [Policy Text Block]

Renewable Identification Numbers

The Company is subject to obligations to generate or purchase Renewable Identification Numbers ("RINs") required to comply with the Renewable Fuels Standard. The Company's overall RINs obligation is based on a percentage of domestic shipments of on-road fuels as established by the Environmental Protection Agency ("EPA"). To the degree the Company is unable to blend the required amount of biofuels to satisfy its RINs obligation, RINs must be purchased on the open market to avoid penalties and fines. The Company records its RINs obligation on a net basis in accrued liabilities when its RINs liability is greater than the amount of RINs earned and purchased in a given period and in other current assets when the amount of RINs earned and purchased is greater than the RINs liability.

Future changes to existing laws and regulations could increase the minimum volumes of renewable fuels that must be blended with refined petroleum fuels. Because the Company does not produce renewable fuels, increasing the volume of renewable fuels that must be blended into its products could displace an increasing volume of the Company's refineries' product pool, potentially resulting in lower earnings and materially adversely affecting our ability to issue dividends to the Company's unitholders. 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 upon the Company's operating results.

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Summary of Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2016

Accounting Policies [Abstract]

Schedule of Allowance for Doubtful Accounts

Additions, deductions and balances for the reserve for doubtful accounts for the three years ended December 31, 2016, are presented below:

	Year Ended December 31,
	2016			2015			2014
	(In thousands)
Balance at January 1	$	169		$	484		$	906
Additions	803			367			3,095
Reductions	(737		)	(682		)	(3,517		)
Balance at December 31	$	235		$	169		$	484

Property, Plant, and Equipment Schedule of Estimated Useful Lives

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

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Segment Information (Tables)

12 Months Ended

Dec. 31, 2016

Segment Reporting Information [Line Items]

Schedule of Segment Reporting Information, by Segment

.

Disclosures regarding our reportable segments with reconciliations to consolidated totals for the three years ended December 31, 2016, are presented below:

	Year Ended
	December 31, 2016			December 31, 2015			December 31, 2014
	(In thousands)
Operating Results:
Refining
Net sales	$	6,918,931		$	8,777,196		$	14,196,564
Intersegment eliminations	2,819,844			3,072,806			4,291,617
Net refining sales to external customers	4,099,087			5,704,390			9,904,947
WNRL
Net sales	2,222,718			2,599,867			3,501,888
Intersegment eliminations	702,157			786,324			1,011,575
Net WNRL sales to external customers	1,520,561			1,813,543			2,490,313
Retail
Net sales	2,159,946			2,279,737			2,776,782
Intersegment eliminations	36,381			10,634			19,575
Net retail sales to external customers	2,123,565			2,269,103			2,757,207
Other
Other revenue, net	—			—			1,106
Intersegment eliminations	—			—			—
Net other sales to external customers	—			—			1,106
Consolidated net sales to external customers	$	7,743,213		$	9,787,036		$	15,153,573
Operating income (loss)
Refining (1) (2)	$	357,610		$	930,531		$	1,140,580
WNRL (2)	70,095			55,794			35,607
Retail (1)	25,146			41,279			42,087
Other	(109,426		)	(97,479		)	(121,761		)
Operating income	343,425			930,125			1,096,513
Other income (expense), net	(101,551		)	(91,739		)	(93,837		)
Consolidated income before income taxes	$	241,874		$	838,386		$	1,002,676
Depreciation and amortization
Refining (2)	$	150,989		$	142,108		$	137,715
WNRL (2)	39,242			35,384			28,934
Retail	23,193			23,197			19,869
Other	3,363			4,602			4,048
Consolidated depreciation and amortization	$	216,787		$	205,291		$	190,566

	Year Ended
	December 31, 2016		December 31, 2015		December 31, 2014
	(In thousands)
Capital expenditures
Refining (2)	$	248,863	$	201,249	$	119,416
WNRL (2)	29,161		65,635		79,338
Retail	20,308		20,895		22,056
Other	2,637		3,084		2,461
Consolidated capital expenditures	$	300,969	$	290,863	$	223,271
Total assets
Refining (2) (including $1,267,455 of goodwill)	$	4,312,212	$	4,024,131	$	4,126,005
WNRL (2)	533,952		566,209		552,253
Retail (including $21,988 of goodwill)	435,030		444,382		417,269
Other	279,203		798,671		546,659
Consolidated total assets	$	5,560,397	$	5,833,393	$	5,642,186

(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 $18.9 million in net realized and unrealized economic hedging losses for the year ended December 31, 2016 and $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. Cost of products sold included net non-cash LCM recoveries in our refining segment of $132.0 million for the year ended December 31, 2016 and charges of $95.8 million and $77.1 million for the years ended December 31, 2015 and 2014, respectively, and recoveries in our retail segment of $1.4 million for the year ended December 31, 2016 and charges of $0.7 million and $1.4 million for the years ended December 31, 2015 and 2014, respectively.

(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, 2016. The information contained herein for WNRL has been retrospectively adjusted, to include the historical results of the St. Paul Park Logistics Assets.

Northern Tier Energy LP [Member]

Segment Reporting Information [Line Items]

Schedule of Segment Reporting Information, by Segment

Operating results for the Company's operating segments are as follows:

	Year ended December 31, 2016
(in millions)	Refining		Retail		Other			Total
Revenues
Customer	$	1,857.8	$	1,030.8	$	—		$	2,888.6
Intersegment	563.6		—		—			563.6
Segment revenues	2,421.4		1,030.8		—			3,452.2
Elimination of intersegment revenues	—		—		(563.6		)	(563.6		)
Total revenues	$	2,421.4	$	1,030.8	$	(563.6	)	$	2,888.6
Income (loss) from operations	$	121.5	$	10.7	$	(26.6	)	$	105.6
Income from equity method investment	$	21.9	$	—	$	—		$	21.9
Depreciation and amortization	$	37.4	$	8.3	$	0.8		$	46.5
Capital expenditures	$	120.4	$	7.3	$	0.2		$	127.9

	Year ended December 31, 2015
(in millions)	Refining		Retail		Other			Total
Revenues
Customer	$	2,289.1	$	1,115.9	$	—		$	3,405.0
Intersegment	647.7		—		—			647.7
Segment revenues	2,936.8		1,115.9		—			4,052.7
Elimination of intersegment revenues	—		—		(647.7		)	(647.7		)
Total revenues	$	2,936.8	$	1,115.9	$	(647.7	)	$	3,405.0
Income (loss) from operations	$	374.8	$	19.2	$	(25.9	)	$	368.1
Income from equity method investment	$	14.8	$	—	$	—		$	14.8
Depreciation and amortization	$	35.4	$	7.7	$	0.9		$	44.0
Capital expenditures	$	63.8	$	7.7	$	0.3		$	71.8

	Year ended December 31, 2014 (1)
(in millions)	Refining		Retail		Other			Total
Revenues
Customer	$	4,165.6	$	1,390.4	$	—		$	5,556.0
Intersegment	932.1		—		—			932.1
Segment revenues	5,097.7		1,390.4		—			6,488.1
Elimination of intersegment revenues	—		—		(932.1		)	(932.1		)
Total revenues	$	5,097.7	$	1,390.4	$	(932.1	)	$	5,556.0
Income (loss) from operations	$	303.5	$	22.9	$	(51.1	)	$	275.3
Income from equity method investment	$	2.2	$	—	$	—		$	2.2
Depreciation and amortization	$	33.7	$	7.3	$	0.9		$	41.9
Capital expenditures	$	35.4	$	8.8	$	0.6		$	44.8

(1) In 2015, the Company modified the methodology whereby corporate costs are allocated to the Refining and Retail segments. This modification resulted in additional costs being allocated to the Refining and Retail segments from the Other segment. The table below presents the increase or (decrease) in Income (loss) from operations the year ended December 31, 2014 that would have occurred as a result of this modification if the adjustments had been applied retroactively:

	Year ended December 31, 2014
(in millions)	Refining		Retail		Other	Total
Increase (decrease)	(7.7	)	(4.4	)	12.1	—

Intersegment sales from the refining segment to the retail segment consist primarily of sales of refined products which are recorded based on contractual prices that are market-based. Revenues from external customers are nearly all in the United States.

Total assets by segment were as follows:

(in millions)	Refining		Retail		Corporate/Other		Total
At December 31, 2016	$	1,113.8	$	137.5	$	40.0	$	1,291.3
At December 31, 2015	$	917.4	$	138.7	$	81.2	$	1,137.3

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Fair Value Measurement (Tables)

12 Months Ended

Dec. 31, 2016

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Fair Value, by Balance Sheet Grouping [Table Text Block]

As of December 31, 2016 and 2015, the carrying amount and estimated fair value of our debt was as follows:

	December 31,
	2016		2015
	(In thousands)
Western obligations:
Carrying amount	$	1,256,000	$	889,000
Fair value	1,277,956		867,178
NTI obligations:
Carrying amount	$	349,980	$	350,000
Fair value	363,542		360,500
WNRL obligations:
Carrying amount	$	320,300	$	445,000
Fair value	345,050		439,000

Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Table Text Block]

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, 2016 and 2015.

	December 31,
	2016			2015
	(In thousands)
Asset (liability) balance at beginning of period	$	(5,756	)	$	330
Change in fair value of Level 3 trades open at the beginning of the period	—			—
Fair value of trades entered into during the period	—			(5,756		)
Fair value reclassification from Level 3 to Level 2	5,756			(330		)
Asset (liability) balance at end of period	$	—		$	(5,756	)

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis, Valuation Techniques [Table Text Block]

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, 2016 and 2015, and the basis for that measurement:

	Carrying Value at December 31, 2016			Fair Value Measurement at December 31, 2016 Using							Netting Adjustments			Recorded Value at December 31, 2016
				Level 1		Level 2			Level 3
	(In thousands)
Gross financial assets:
Other current assets	$	18,929		$	—	$	18,929		$	—	$	(5,280	)	$	13,649
Other assets	677			—		677			—		(669		)	8
Gross financial liabilities:
Accrued liabilities	(17,547		)	—		(17,547		)	—		6,720			(10,827		)
Other long-term liabilities	—			—		—			—		(771		)	(771		)
	$	2,059		$	—	$	2,059		$	—	$	—		$	2,059

	Carrying Value at December 31, 2015			Fair Value Measurement at December 31, 2015 Using								Netting Adjustments			Recorded Value at December 31, 2015
				Level 1		Level 2			Level 3
	(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

Northern Tier Energy LP [Member]

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Fair Value, by Balance Sheet Grouping [Table Text Block]

The following table provides the assets and liabilities carried at fair value measured on a recurring basis at December 31, 2016 and 2015:

	Balance at		Quoted prices in active markets		Significant other observable inputs		Unobservable inputs
(in millions)	December 31, 2016		(Level 1)		(Level 2)		(Level 3)
ASSETS
Cash and cash equivalents	$	29.5	$	29.5	$	—	$	—
Other current assets
Derivative asset - current	6.3		—		6.3		—
	$	35.8	$	29.5	$	6.3	$	—
LIABILITIES
Accrued liabilities
Derivative liability - current	$	6.0	$	—	$	6.0	$	—
	$	6.0	$	—	$	6.0	$	—

	Balance at		Quoted prices in active markets		Significant other observable inputs		Unobservable inputs
(in millions)	December 31, 2015		(Level 1)		(Level 2)		(Level 3)
ASSETS
Cash and cash equivalents	$	70.9	$	70.9	$	—	$	—
Other current assets
Derivative asset - current	1.9		—		1.9		—
	$	72.8	$	70.9	$	1.9	$	—
LIABILITIES
Accrued liabilities
Derivative liability - current	$	9.4	$	—	$	9.4	$	—
	$	9.4	$	—	$	9.4	$	—

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis, Valuation Techniques [Table Text Block]

The carrying value of debt, which is reported on the Company's consolidated balance sheets, reflects the cash proceeds received upon issuance, net of subsequent repayments. The fair value of the 2020 Secured Notes disclosed below was determined based on quoted prices in active markets (Level 1).

	December 31, 2016				December 31, 2015
(in millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
2020 Secured Notes	$	350.0	$	363.5	$	350.0	$	360.5

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Inventories (Tables)

12 Months Ended

Dec. 31, 2016

Inventory [Line Items]

Schedule of Inventory, Current [Table Text Block]

Inventories were as follows:

	December 31,
	2016		2015
	(In thousands)
Refined products (1)	$	325,889	$	201,928
Crude oil and other raw materials	395,131		288,403
Lubricants	10,121		14,996
Retail store merchandise	40,848		42,211
Inventories	$	771,989	$	547,538

(1) Includes $50.5 million and $14.5 million of inventory valued using the FIFO valuation method at December 31, 2016 and 2015, respectively.

Summary of Lower Cost of Market and Applicable LIFO Liquidation [Table Text Block]

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,
	2016			2015			2014
	(In thousands, except per share amount)
Increase (decrease) in operating income	$	(2,868	)	$	(16,111	)	$	1,097
Increase (decrease) in net income	(2,218		)	(11,808		)	777
Increase (decrease) in earnings per diluted share	$	(0.02	)	$	(0.12	)	$	0.01

Schedule of LIFO Costs Included in Inventory [Table Text Block]

LIFO cost per barrel of our refined products and crude oil and other raw materials inventories as of December 31, 2016 and 2015, was as follows:

	December 31,
	2016					2015
	Barrels	LIFO Cost		Average LIFO Cost Per Barrel		Barrels	LIFO Cost		Average LIFO Cost Per Barrel
	(In thousands, except cost per barrel)
Refined products	4,259	$	303,968	$	71.37	3,536	$	259,722	$	73.45
Crude oil and other	6,641	394,798		59.45		6,490	391,237		60.28
	10,900	$	698,766	64.11		10,026	$	650,959	64.93

Northern Tier Energy LP [Member]

Inventory [Line Items]

Schedule of Inventory, Current [Table Text Block]

	December 31,
(in millions)	2016			2015
Crude oil and refinery feedstocks	$	174.3		$	171.8
Refined products	160.2			162.0
Merchandise	22.1			22.8
Supplies and sundry items	18.8			19.0
	375.4			375.6
Lower of cost or market inventory reserve	(41.7		)	(134.4		)
Total	$	333.7		$	241.2

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Prepaid Expenses (Tables)

12 Months Ended

Dec. 31, 2016

Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]

Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Table Text Block]

Prepaid expenses were as follows:

	December 31,
	2016		2015
	(In thousands)
Prepaid crude oil and other raw materials inventories	$	49,405	$	23,793
Prepaid insurance	12,726		5,904
RINs	12,722		21,174
Prepaid income taxes	456		3,099
Other	20,046		19,243
Prepaid expenses	$	95,355	$	73,213

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Other Current Assets (Tables)

12 Months Ended

Dec. 31, 2016

Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]

Schedule of Other Current Assets [Table Text Block]

Other current assets were as follows:

	December 31,
	2016		2015
	(In thousands)
Material and chemical inventories	$	49,915	$	54,053
Excise and other taxes receivable	19,644		21,801
Margin account deposits	14,852		—
Fair value of open commodity hedging positions, net	13,649		78,125
Exchange and other receivables	15,361		15,749
Other current assets	$	113,421	$	169,728

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Equity Method Investment (Tables)

12 Months Ended

Dec. 31, 2016

Schedule of Equity Method Investments [Line Items]

Equity Method Investments [Table Text Block]

Summarized financial information for MPL for the years ended December 31, 2016, 2015 and 2014 and as of December 31, 2016 and 2015, was as follows:

	Year Ended December 31,
	2016		2015		2014
	(In thousands)
Revenues	$	215,564	$	206,195	$	184,712
Operating costs and expenses	57,444		88,909		141,250
Income from operations	158,120		117,286		43,462
Net income	137,476		96,485		22,821
Net income attributable to MPL unitholders	127,823		86,832		13,168

	December 31, 2016		December 31, 2015
	(In thousands)
Current assets	$	14,882	$	24,020
Noncurrent assets	491,955		441,825
Total assets	$	506,837	$	465,845
Current liabilities	$	26,827	$	17,658
Noncurrent liabilities	—		—
Total liabilities	$	26,827	$	17,658
Equity	$	480,010	$	448,187

Northern Tier Energy LP [Member]

Schedule of Equity Method Investments [Line Items]

Equity Method Investments [Table Text Block]

Summarized financial information for MPL is as follows:

	Year Ended December 31,
(in millions)	2016		2015		2014
Revenues	$	215.6	$	206.2	$	184.7
Operating costs and expenses	57.5		88.9		141.3
Income from operations	158.1		117.3		43.4
Net income	137.5		96.5		22.8
Net income available to MPL common members	127.8		86.8		13.1

			December 31,
(in millions)			2016		2015
Balance sheet data:
	Current assets		$	14.8	$	24.0
	Noncurrent assets		492.0		441.8
		Total assets	$	506.8	$	465.8
	Current liabilities		$	26.8	$	17.7
	Noncurrent liabilities		—		—
		Total liabilities	26.8		17.7
	Members capital		$	480.0	$	448.1

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Property, Plant and Equipment, Net (Tables)

12 Months Ended

Dec. 31, 2016

Property, Plant and Equipment [Line Items]

Property, Plant and Equipment [Table Text Block]

Property, plant and equipment, net was as follows:

	December 31,
	2016			2015
	(In thousands)
Refinery facilities and related equipment	$	2,260,351		$	2,113,650
Pipelines, terminals and transportation equipment	560,478			427,854
Retail facilities and related equipment	333,187			324,686
Wholesale facilities and related equipment	52,284			59,875
Corporate	53,566			50,607
	3,259,866			2,976,672
Accumulated depreciation	(1,118,477		)	(923,415		)
	2,141,389			2,053,257
Construction in progress	223,093			251,914
Property, plant and equipment, net	$	2,364,482		$	2,305,171

Northern Tier Energy LP [Member]

Property, Plant and Equipment [Line Items]

Property, Plant and Equipment [Table Text Block]

Major classes of property, plant and equipment ("PP&E") consisted of the following:

	Estimated	December 31,
(in millions)	Useful Lives	2016			2015
Land		$	7.7		$	9.0
Retail stores and equipment	2 - 22 years	80.5			72.3
Refinery and equipment	5 - 24 years	487.0			457.2
Buildings and building improvements	25 years	18.7			11.7
Software	5 years	18.9			18.9
Vehicles	5 years	3.2			5.6
Other equipment	2 - 7 years	10.8			10.4
Precious metals		10.4			10.2
Assets under construction		78.6			73.3
		715.8			668.6
Less: Accumulated depreciation		(198.0		)	(180.8		)
Property, plant and equipment, net		$	517.8		$	487.8

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Intangible Assets, Net (Tables)

12 Months Ended

Dec. 31, 2016

Goodwill and Intangible Assets Disclosure [Abstract]

Schedule of Intangible Assets and Goodwill [Table Text Block]

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

	December 31, 2016							December 31, 2015							Weighted Average Amortization Period (Years)
	Gross Carrying Value		Accumulated Amortization			Net Carrying Value		Gross Carrying Value		Accumulated Amortization			Net Carrying Value
	(In thousands)
Amortizable assets:
Licenses and permits	$	20,427	$	(15,307	)	$	5,120	$	20,427	$	(13,729	)	$	6,698	3.3
Customer relationships	7,172		(4,234		)	2,938		7,551		(3,921		)	3,630		5.5
Rights-of-way and other	8,538		(3,242		)	5,296		6,839		(1,797		)	5,042		5.0
	36,137		(22,783		)	13,354		34,817		(19,447		)	15,370
Unamortizable assets:
Franchise rights and trademarks	50,500		—			50,500		50,500		—			50,500
Liquor licenses	19,958		—			19,958		19,075		—			19,075
Intangible assets, net	$	106,595	$	(22,783	)	$	83,812	$	104,392	$	(19,447	)	$	84,945

Schedule of Expected Amortization Expense [Table Text Block]

Estimated amortization expense for the next five fiscal years is as follows (in thousands):

2017	$	2,880
2018	2,880
2019	2,212
2020	1,268
2021	980

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Other Assets (Tables)

12 Months Ended

Dec. 31, 2016

Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]

Schedule of Other Assets, Noncurrent [Table Text Block]

Other assets were as follows:

	December 31,
	2016		2015
	(In thousands)
Capital spare parts	$	12,717	$	8,112
Purchase agreement	9,762		16,067
Cost method investment	7,864		7,872
Notes receivable	4,366		4,586
Deposits	3,582		3,747
Fair value of open commodity hedging positions, net	8		11,881
Other	9,159		12,732
Other assets	$	47,458	$	64,997

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Accrued and Other Long-Term Liabilities (Tables)

12 Months Ended

Dec. 31, 2016

Accrued Liabilities and Other Liabilities [Abstract]

Schedule of Accrued Liabilities [Table Text Block]

Accrued liabilities were as follows:

	December 31,
	2016		2015
	(In thousands)
Excise and other taxes	$	68,116	$	67,932
Payroll and related costs	66,021		77,482
Professional and other	24,146		28,093
Property taxes	23,387		20,175
Interest	17,248		17,093
Fair value of open commodity hedging positions, net	10,827		10,273
Environmental reserves	6,945		10,099
Banking fees and other financing	2,718		189
Income taxes	199		—
Margin and other customer deposits	—		17,059
Accrued liabilities	$	219,607	$	248,395

Other Noncurrent Liabilities [Table Text Block]

Other long-term liabilities were as follows:

	December 31,
	2016		2015
	(In thousands)
Unrecognized tax benefits	$	58,317	$	42,049
Retiree plan obligations and other	18,725		10,529
Asset retirement obligations	8,484		7,822
Environmental reserves	6,839		8,195
Fair value of open commodity hedging positions, net	771		—
Other long-term liabilities	$	93,136	$	68,595

Environmental Exit Costs by Cost [Table Text Block]

The table below summarizes changes in our environmental liability accruals:

	December 31, 2015		Increase (Decrease)		Payments			December 31, 2016
	(In thousands)
Discounted liabilities	$	3,633	$	300	$	(433	)	$	3,500
Undiscounted liabilities	14,661		626		(5,003		)	10,284
Total environmental liabilities	$	18,294	$	926	$	(5,436	)	$	13,784

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Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2016

Guarantor Obligations [Line Items]

Schedule of Change in Asset Retirement Obligation [Table Text Block]

The following table reconciles the beginning and ending aggregate carrying amount of our AROs for the three years ended December 31, 2016:

	December 31,
	2016			2015			2014
	(In thousands)
Liability, beginning of period	$	7,822		$	7,539		$	7,327
Liabilities incurred	566			58			17
Liabilities acquired	—			—			—
Liabilities settled	(479		)	(187		)	(313		)
Accretion expense	575			412			508
Liability, end of period	$	8,484		$	7,822		$	7,539

Northern Tier Energy LP [Member]

Guarantor Obligations [Line Items]

Schedule of Change in Asset Retirement Obligation [Table Text Block]

The following table summarizes the changes in asset retirement obligations:

	Year Ended December 31,
(in millions)	2016			2015			2014
Asset retirement obligation balance at beginning of period	$	2.4		$	2.4		$	2.2
Costs incurred to remediate	(0.2		)	(0.3		)	—
Accretion expense	0.2			0.3			0.2
Asset retirement obligation balance at end of period	$	2.4		$	2.4		$	2.4

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Long-Term Debt (Tables)

12 Months Ended

Dec. 31, 2016

Debt Disclosure [Abstract]

Schedule of Debt [Table Text Block]

Long-term debt was as follows:

	December 31,
	2016			2015
	(In thousands)
Western obligations:
Revolving Credit Facility due 2019	$	—		$	—
Term Loan - 5.25% Credit Facility due 2020	533,500			539,000
6.25% Senior Unsecured Notes due 2021	350,000			350,000
Term Loan - 5.50% Credit Facility due 2023	372,500			—
Total Western obligations	1,256,000			889,000
NTI obligations:
Revolving Credit Facility due 2019	—			—
7.125% Senior Secured Notes, due November 2020	349,980			350,000
Total NTI obligations	349,980			350,000
WNRL obligations:
Revolving Credit Facility due 2018	20,300			145,000
7.5% Senior Notes due 2023	300,000			300,000
Total WNRL obligations	320,300			445,000
Less unamortized discount, premium and debt issuance costs	43,975			33,606
Long-term debt	1,882,305			1,650,394
Current portion of long-term debt	(10,500		)	(5,500		)
Long-term debt, net of current portion	$	1,871,805		$	1,644,894

Schedule of Interest Expense and Other Financing Costs [Table Text Block]

Interest and debt expense were as follows:

	Year Ended December 31,
	2016			2015			2014
	(In thousands)
Contractual interest:
Western obligations	$	62,893		$	45,248		$	51,114
NTI obligations	24,462			24,474			20,342
WNRL obligations	24,325			21,079			1,096
	111,680			90,801			72,552
Amortization of loan fees	9,125			7,561			7,786
Amortization of original issuance discount	790			—			7,352
Other interest expense	12,377			9,059			11,717
Capitalized interest	(10,681		)	(1,818		)	(2,345		)
Interest and debt expense	$	123,291		$	105,603		$	97,062

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Income Taxes (Tables)

12 Months Ended

Dec. 31, 2016

Operating Loss Carryforwards [Line Items]

Schedule of Components of Income Tax Expense (Benefit) [Table Text Block]

The following is an analysis of our consolidated income tax expense for the three years ended December 31, 2016:

	Year Ended December 31,
	2016			2015			2014
	(In thousands)
Current:
Federal	$	63,421		$	228,457		$	187,320
State	7,231			30,222			32,581
Total current	70,652			258,679			219,901
Deferred:
Federal	(7,262		)	(27,876		)	63,182
State	(8,522		)	(6,848		)	9,521
Total deferred	(15,784		)	(34,724		)	72,703
Provision for income taxes	$	54,868		$	223,955		$	292,604

Schedule of Effective Income Tax Rate Reconciliation [Table Text Block]

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, 2016:

	Year Ended December 31,
	2016			2015			2014
	(In thousands)
Taxes at the federal statutory rate	$	84,656		$	293,435		$	350,937
State income taxes, net of federal tax benefit (1)	3,601			13,637			31,477
Valuation allowance for state net operating losses	(3,848		)	—			(2,887		)
Domestic Activity Production deduction	(2,843		)	(14,000		)	(11,900		)
Non-controlling interests	(21,723		)	(70,214		)	(50,044		)
Federal tax credit for production of ultra low sulfur diesel	—			—			(15,486		)
UTP releases	(10,823		)	(1,138		)	(2,266		)
Federal tax credit for increasing research activities	(3,780		)	1,176			(2,256		)
Impact of allocating deferred taxes associated with investment in NTI	8,132			—			—
Other, net	1,496			1,059			(4,971		)
Total income tax expense	$	54,868		$	223,955		$	292,604

(1) State income taxes, net of federal tax benefit, include $0.2 million, $5.0 million and $0.8 million in unrecognized tax benefits for the years ended December 31, 2016, 2015 and 2014, respectively.

Schedule of Unrecognized Tax Benefits Roll Forward [Table Text Block]

The following is a reconciliation of unrecognized tax benefits for the three years ended December 31, 2016:

	December 31,
	2016			2015			2014
	(In thousands)
Unrecognized tax benefits at beginning of year	$	40,174		$	13,762		$	10,571
Increases related to current year tax positions	36,281			1,100			1,500
Increases related to prior year tax positions	2,651			26,329			3,845
Decreases related to prior year tax positions	(19,180		)	(1,017		)	(2,154		)
Decreases resulting from the expiration of the statute of limitations	(4,142		)	—			—
Unrecognized tax benefits at end of year	$	55,784		$	40,174		$	13,762

Schedule of Deferred Tax Assets and Liabilities [Table Text Block]

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

	December 31,
	2016									2015
	Assets			Liabilities			Net			Assets			Liabilities			Net
	(In thousands)
Inventories	$	—		$	(61,850	)	$	(61,850	)	$	—		$	(28,411	)	$	(28,411	)
Stock-based compensation	3,388			—			3,388			1,614			—			1,614
Property, plant and equipment	—			(357,044		)	(357,044		)	—			(261,476		)	(261,476		)
Investment in WNRL	147,625			—			147,625			77,824			—			77,824
Investment in NTI (1)	—			—			—			—			(81,789		)	(81,789		)
Postretirement obligations	2,117			—			2,117			2,595			—			2,595
Commodity hedging activities	—			(671		)	(671		)	—			(33,260		)	(33,260		)
Environmental and retirement obligations	3,975			—			3,975			3,742			—			3,742
Other, net	—			(1,750		)	(1,750		)	6,247			—			6,247
Net operating loss and tax credit carryforwards	20,897			—			20,897			20,828			—			20,828
Valuation allowance	(16,980		)	—			(16,980		)	(20,828		)	—			(20,828		)
Net deferred taxes	$	161,022		$	(421,315	)	$	(260,293	)	$	92,022		$	(404,936	)	$	(312,914	)

Summary of Operating Loss Carryforwards [Table Text Block]

At December 31, 2016, 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	$	(4,833	)	$	(243	)	2023
Virginia and Maryland	(17,200		)	(737		)	2024
Virginia and Maryland	(503		)	(22		)	2026
Virginia and Maryland	(31,219		)	(1,337		)	2028
Virginia and Maryland	(56,838		)	(2,435		)	2029
Virginia and Maryland	(98,316		)	(4,212		)	2030
Virginia and Maryland	(132,582		)	(5,680		)	2031
Virginia and Maryland	(129,268		)	(5,503		)	2032
Other	(1,070		)	(221		)	2027
Texas	(507		)	(507		)	2035
Total state NOL carryforwards	(472,336		)	(20,897		)
Less valuation allowance for operating loss carryforwards	395,130			16,980
Total credits and NOL carryforwards	$	(77,206	)	$	(3,917	)

Northern Tier Energy LP [Member]

Operating Loss Carryforwards [Line Items]

Schedule of Components of Income Tax Expense (Benefit) [Table Text Block]

On July 31, 2012, NTRH was established as the parent company of NTR and NTB. NTRH elected to be taxed as a corporation for federal and state income tax purposes effective August 1, 2012. Prior to that, no provision for income tax was calculated on earnings of the Company or its subsidiaries as all entities were non-taxable.

	Year Ended December 31,
(in millions)	2016		2015		2014
Current tax expense	$	2.5	$	5.6	$	4.5
Deferred tax expense	$	1.8	$	2.8	$	2.6
Income tax provision	$	4.3	$	8.4	$	7.1

Schedule of Effective Income Tax Rate Reconciliation [Table Text Block]

The following is a reconciliation of income tax expense to income taxes computed by applying the applicable statutory federal income tax rate of 34% for 2016 and 35% for 2015 and 2014 to income before income taxes for the applicable periods:

	Year Ended December 31,
(in millions)	2016			2015			2014
Federal statutory rate applied to income before taxes	$	27.5		$	118.8		$	87.0
Taxes on earnings attributable to flow-through entities	(24.2		)	(112.4		)	(81.0		)
State and local income taxes, net of federal income tax effects	0.6			1.2			1.0
Work opportunity tax credit	(0.2		)	(0.4		)	(0.3		)
Other, net	0.6			1.2			0.4
Income tax provision	$	4.3		$	8.4		$	7.1

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Retirement Plans (Tables)

12 Months Ended

Dec. 31, 2016

Defined Benefit Plan Disclosure [Line Items]

Schedule of Allocation of Plan Assets [Table Text Block]

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.

Schedule of Amounts Recognized in Other Comprehensive Income (Loss) [Table Text Block]

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,
	2016			2015			2014
	(In thousands)
Beginning of period balance	$	651		$	(1,291	)	$	(350	)
Amortization of net prior service cost	(183		)	83			63
Net prior service credit	—			945			—
Reclassification of loss to income	—			50			21
Pension plan termination adjustment	420			—			—
Actuarial gain (loss)	724			1,267			(1,320		)
Income tax	(386		)	(403		)	295
End of period balance	$	1,226		$	651		$	(1,291	)

Western Refining, Inc. [Member]

Defined Benefit Plan Disclosure [Line Items]

Schedule of Expected Benefit Payments [Table Text Block]

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

2017	$	153
2018	158
2019	164
2020	173
2021	181
2022 - 2026	1,092

Schedule of Effect of One-Percentage-Point Change in Assumed Health Care Cost Trend Rates [Table Text Block]

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	$	(46	)
Effect on accumulated benefit obligation	13		(560		)

(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.

Northern Tier Energy LP [Member]

Defined Benefit Plan Disclosure [Line Items]

Schedule of Net Funded Status [Table Text Block]

The following tables set forth significant information about the Cash Balance Plan and the Retiree Medical Plan. The reconciliation of the benefit obligation, plan assets, funded status and significant assumptions are based upon an annual measurement date of December 31, 2016:

	Cash Balance Plan						Retiree Medical Plan
	As of December 31,
	2016			2015			2016			2015
	(In thousands)
Benefit obligation at beginning of period	$	8,927		$	6,965		$	345		$	3,098
Service cost	2,196			2,326			—			315
Interest cost	488			366			8			135
Actuarial (gain) loss	490			(151		)	(197		)	(697		)
Plan amendments	—			—			—			(2,463		)
Plan participants' contributions	—			—			12			26
Benefits paid	(675		)	(579		)	(42		)	(69		)
Curtailments	(149		)	—			—			—
Benefit obligation at end of period	$	11,277		$	8,927		$	126		$	345
Fair value of plan assets at beginning of period	$	5,932		$	4,319		$	—		$	—
Employer contribution	2,748			2,200			30			43
Actual return on plan assets	134			(8		)	—			—
Benefits paid	(675		)	(579		)	(42		)	(69		)
Plan participants' contributions	—			—			12			26
Fair value of plan assets at end of period	$	8,139		$	5,932		$	—		$	—
Current liabilities	—			—			31			61
Non-current liabilities	3,138			2,995			95			284
Underfunded status recognized in the consolidated balance sheets	$	3,138		$	2,995		$	126		$	345
Accumulated benefit obligation	$	11,277		$	8,927		$	126		$	345

The changes to the benefit obligation, fair value of plan assets and funded status of the Cash Balance Plan for the years ended December 31, 2016, 2015 and 2014 were as follows:

			Cash Balance Plan
			Year Ended December 31,
(in millions)			2016			2015			2014
Change in benefit obligation:
	Benefit obligation at beginning of year		$	8.9		$	7.0		$	4.6
		Service cost	2.2			2.3			2.1
		Interest cost	0.5			0.4			0.3
		Actuarial loss (gain)	0.5			(0.2		)	0.6
		Curtailments	(0.1		)	—			—
		Benefits paid	(0.7		)	(0.6		)	(0.6		)
	Benefit obligation at end of year		11.3			8.9			7.0
Change in plan assets:
	Fair value of plan assets at beginning of year		5.9			4.3			4.6
		Employer contributions	2.8			2.2			0.2
		Return on plan assets	0.1			—			0.1
		Benefits paid	(0.7		)	(0.6		)	(0.6		)
	Fair value of plan assets at end of year		8.1			5.9			4.3
Reconciliation of funded status:
	Fair value of plan assets at end of year		8.1			5.9			4.3
	Benefit obligation at end of year		11.3			8.9			7.0
	Underfunded status at end of year		$	(3.2	)	$	(3.0	)	$	(2.7	)

Schedule of Net Benefit Costs [Table Text Block]

	Cash Balance Plan									Retiree Medical Plan
	As of December 31,
	2016			2015			2014			2016			2015			2014
	(In thousands)
Net periodic benefit cost includes:
Service cost	$	2,196		$	2,326		$	2,054		$	—		$	315		$	231
Interest cost	488			366			327			8			135			116
Expected return on assets	(273		)	(165		)	(218		)	—			—			—
Recognized net actuarial loss	12			22			—			13			32			—
Amortization of prior service cost	25			24			25			(291		)	137			137
Curtailments	270			—			—			—			—			—
Net periodic benefit cost	$	2,718		$	2,573		$	2,188		$	(270	)	$	619		$	484
Changes recognized in other comprehensive income:
Prior service cost amortization	$	(24	)	$	(24	)	$	(24	)	$	291		$	(137	)	$	(137	)
Recognized net actuarial loss	(12		)	—			—			(13		)	(32		)	—
Prior service credit	—			—			—			—			(2,463		)	—
Net actuarial loss (gain)	629			22			687			(197		)	(697		)	675
Prior service cost amortization - curtailment	(271		)	—			—			—			—			—
Net curtailment gain	(149		)	—			—			—			—			—
Pre-tax unrecognized net loss (gain) included in accumulated other comprehensive income at end of period	$	173		$	(2	)	$	663		$	81		$	(3,329	)	$	538

The components of net periodic benefit cost and other amounts recognized in equity related to the Cash Balance Plan for the years ended December 31, 2016, 2015 and 2014 were as follows:

		Cash Balance Plan
		Year Ended December 31,
(in millions)		2016			2015			2014
Components of net periodic benefit cost:
	Service cost	$	2.2		$	2.3		$	2.1
	Interest cost	0.5			0.4			0.3
	Expected return on plan assets	(0.2		)	(0.1		)	(0.2		)
	Net periodic benefit cost	$	2.5		$	2.6		$	2.2
Changes recognized in other comprehensive (income) loss:
	Actuarial (gain) loss	—			—			0.7
	Net credit due to curtailment	(0.4		)	—			—
	Experience loss	0.6			—			—
	Total changes recognized in other comprehensive (income) loss	$	0.2		$	—		$	0.7

Schedule of Assumptions Used [Table Text Block]

	Cash Balance Plan						Retiree Medical Plan
	As of December 31,
	2016		2015		2014		2016		2015		2014
Weighted average assumptions used to determine benefit obligations at December 31:
Discount rate	4.00	%	4.50	%	4.00	%	2.75	%	2.50	%	4.00	%
Rate of compensation increase	3.00		3.00		3.00		N/A		N/A		N/A
Weighted average assumptions used to determine net periodic benefit cost:
Discount rate (1)	4.50% / 3.75%		4.00		5.00		2.50		4.00		5.00
Expected long-term return on assets (1)	4.25% / 3.50%		3.75		4.75		N/A		N/A		N/A
Rate of compensation increase	3.00		3.00		4.00		N/A		N/A		N/A

The weighted average assumptions used to determine the Company's benefit obligations are as follows:

	Cash Balance Plan
	Year Ended December 31,
	2016	2015	2014
Discount rate	4.00%	4.50%	4.00%
Rate of compensation increase	N/A	3.00%	3.00%

The weighted average assumptions used to determine the net periodic benefit cost are as follows:

	Cash Balance Plan
	Year Ended December 31,
	2016	2015	2014
Discount rate (1)	4.50% / 3.75%	4.00%	5.00%
Expected long-term rate of return on plan assets (1)	4.25% / 3.50%	3.75%	4.75%
Rate of compensation increase	3.00%	3.00%	4.00%

Schedule of Expected Benefit Payments [Table Text Block]

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

	Cash Balance Plan		Retiree Medical Plan
2017	$	1,150	$	31
2018	439		14
2019	493		15
2020	544		16
2021	528		17
2022 - 2026	2,849		46

At December 31, 2016, anticipated benefit payments to participants from the Cash Balance Plan in future years are as follows:

(in millions)	Cash Balance Plan
2017	$	1.1
2018	0.4
2019	0.5
2020	0.5
2021	0.5
2022-2026	2.9

Other Postretirement Benefit Plan [Member] | Western Refining, Inc. [Member]

Defined Benefit Plan Disclosure [Line Items]

Schedule of Net Funded Status [Table Text Block]

Based on an annual measurement date of December 31, and discount rates of 4.37% and 4.43% at December 31, 2016 and 2015, respectively, to determine the benefit obligation, the components of the postretirement obligation were:

	As of December 31,
	2016			2015
	(In thousands)
Benefit obligation at beginning of year	$	5,893		$	6,735
Service cost	104			124
Interest cost	212			251
Benefits paid	(145		)	(182		)
Actuarial gain	(1,157		)	(1,035		)
Benefit obligation at end of year	$	4,907		$	5,893
Underfunded status	$	4,907		$	5,893
Current liabilities	$	150		$	202
Non-current liabilities	4,757			5,691
Underfunded status recognized in the consolidated balance sheets	$	4,907		$	5,893

Schedule of Net Benefit Costs [Table Text Block]

	Year Ended December 31,
	2016			2015			2014
	(In thousands)
Net periodic benefit cost includes:
Service cost	$	104		$	124		$	92
Interest cost	212			251			264
Amortization of net actuarial loss (gain)	(11		)	23			20
Net periodic benefit cost	$	305		$	398		$	376
Pre-tax unrecognized net loss included in accumulated other comprehensive income at beginning of year	$	538		$	1,596		$	784
Net actuarial loss (gain)	(1,157		)	(1,035		)	792
Amortization of net actuarial loss (gain)	11			(23		)	20
Pre-tax unrecognized net loss (gain) included in accumulated other comprehensive income at end of year	$	(608	)	$	538		$	1,596

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Crude Oil and Refined Product Risk Management (Tables)

12 Months Ended

Dec. 31, 2016

Derivative [Line Items]

Derivative Instruments, Gain (Loss) [Table Text Block]

	Year Ended December 31,
	2016			2015			2014
	(In thousands)
Economic hedging activities recognized within cost of products sold:
Realized hedging gain, net	$	58,773		$	93,699		$	95,331
Unrealized hedging gain (loss), net	(77,674		)	(50,233		)	194,423
Total hedging gain (loss), net	$	(18,901	)	$	43,466		$	289,754

	December 31, 2016			December 31, 2015
	(In thousands)
Open commodity hedging instruments (barrels):
Crude oil differential swaps, net long positions	2,124			5,155
Crude oil futures, net short positions	(1,703		)	(562		)
Refined product price and crack spread swaps, net short positions	(6,632		)	(5,645		)
Total open commodity hedging instruments, net short positions	(6,211		)	(1,052		)
Fair value of outstanding contracts, net:
Other current assets	$	13,649		$	78,125
Other assets	8			11,881
Accrued liabilities	(10,827		)	(10,273		)
Other long-term liabilities	(771		)	—
Fair value of outstanding contracts - unrealized gain, net	$	2,059		$	79,733

Schedule of Derivative Instruments in Statement of Financial Position, Fair Value [Table Text Block]

The following table presents offsetting information regarding Western's commodity hedging contracts as of December 31, 2016 and 2015:

	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, 2016
	(In thousands)
Gross financial assets:
Other current assets	$	18,929		$	(5,280	)	$	13,649
Other assets	677			(669		)	8
Gross financial liabilities:
Accrued liabilities	(17,547		)	6,720			(10,827		)
Other long-term liabilities	—			(771		)	(771		)
	$	2,059		$	—		$	2,059

	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
	(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

Schedule of Notional Amounts of Outstanding Derivative Positions [Table Text Block]

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
	2017		2018		2019
Inventory positions (futures and swaps):
Crude oil differential swaps, net long positions	2,124		—		—
Crude oil futures, net short positions	(1,703	)	—		—
Distillate - net short positions	(150	)	—		—
Refined products - net short positions	(1,403	)	—		—
Natural gas futures - net long positions	301		—		—
Refined product positions (crack spread swaps):
Distillate - net short positions	(2,730	)	(1,800	)	—
Unleaded gasoline - net short positions	(850	)	—		—

Northern Tier Energy LP [Member]

Derivative [Line Items]

Derivative Instruments, Gain (Loss) [Table Text Block]

Recognized gains and losses on derivatives were as follows:

	Year Ended December 31,
(in millions)	2016			2015			2014
Gain (loss) on the change in fair value of outstanding derivatives	$	7.8		$	(4.7	)	$	(2.8	)
Settled derivative gains (losses)	(19.8		)	1.5			12.4
Total recognized gain (loss)	$	(12.0	)	$	(3.2	)	$	9.6
Gain (loss) recognized in cost of sales	$	(13.3	)	$	(0.5	)	$	9.6
Gain (loss) recognized in operating expenses	1.3			(2.7		)	—
Total recognized net gain (loss) on derivatives	$	(12.0	)	$	(3.2	)	$	9.6

Schedule of Derivative Instruments in Statement of Financial Position, Fair Value [Table Text Block]

The Company is required to post margin collateral with a counterparty in support of our hedging activities. Funds posted as collateral were $7.6 million and $6.0 million as of December 31, 2016 and December 31, 2015, respectively. The margin collateral posted is required by counterparties and cannot be offset against the fair value of open contracts except in the event of default. The Company nets fair value amounts recognized for multiple similar derivative contracts executed with the same counterparty under master netting arrangements, including cash collateral assets and obligations. The tables below, however, are presented on a gross asset and gross liability basis.

		December 31, 2016
(in millions)	Balance Sheet Location	Assets		Liabilities
Commodity instruments:
Swaps	Other current assets	$	1.1	$	—
Swaps	Accrued liabilities	0.1		0.4
Futures	Accrued liabilities	0.2		1.2
Forwards	Other current assets	5.2		—
Forwards	Accrued liabilities	—		4.7
Total		$	6.6	$	6.3
		December 31, 2015
(in millions)	Balance Sheet Location	Assets		Liabilities
Commodity instruments:
Swaps	Accrued liabilities	$	—	$	7.9
Futures	Other current assets	0.4		—
Forwards	Other current assets	1.5		—
Forwards	Accrued liabilities	—		1.5
Total		$	1.9	$	9.4

Schedule of Notional Amounts of Outstanding Derivative Positions [Table Text Block]

At December 31, 2016 and 2015, the Company had open commodity derivative instruments as follows:

	December 31, 2016	December 31, 2015
Crude oil and refined products (thousands of barrels):
Futures - long	30	90
Futures - short	1,270	933
Swaps - long	1,073	5,155
Swaps - short	530	525
Forwards - long	4,382	4,445
Forwards - short	3,101	2,572
Natural gas (thousands of MMBTUs):
Swaps	1,169	1,554

The information below presents the notional volume of outstanding contracts by type of instrument and year of maturity at December 31, 2016:

	Notional Contract Volumes by Year of Maturity
	2017
Crude oil and refined products (thousands of barrels):
Futures - long	30
Futures - short	1,270
Swaps - long	1,073
Swaps - short	530
Forwards - long	4,382
Forwards - short	3,101
Natural gas (thousands of MMBTUs):
Swaps	1,169

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Stock-Based Compensation (Tables)

12 Months Ended

Dec. 31, 2016

Incentive Plans of Western Refining, Inc. [Member]

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Schedule of Share-based Compensation, Activity [Table Text Block]

The following table summarizes our RSU and restricted share activity for the three years ended December 31, 2016:

	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, 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		—		—
Awards granted	375,774		28.52		—		—
Awards vested	(109,634	)	37.63		—		—
Awards forfeited	(6,848	)	43.81		—		—
Not vested at December 31, 2016	658,506		32.25		—		—

NTI 2016 LTIP [Member]

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Schedule of Share-based Compensation, Activity [Table Text Block]

A summary of our phantom stock award activity under the NTI LTIP for the three years ended December 31, 2016, is set forth below:

	Number of Phantom Stock		Weighted Average Grant Date Fair Value
Not vested at December 31, 2015	—		—
Awards granted	848,267		20.25
Awards vested	(167,342	)	20.25
Awards forfeited	(18,553	)	20.25
Not vested at December 31, 2016	662,372		20.25

WNRL 2013 LTIP [Member]

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Schedule of Share-based Compensation, Activity [Table Text Block]

A summary of WNRL's unit award activity for the three years ended December 31, 2016, is set forth below:

	Number of Phantom Units		Weighted Average Grant Date Fair Value
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
Awards granted	101,955		22.69
Awards vested	(86,406	)	25.80
Awards forfeited	(10,181	)	31.87
Not vested at December 31, 2016	285,155		26.42

Phantom Share Units (PSUs) [Member] | Northern Tier Energy LP [Member]

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Schedule of Share-based Compensation, Activity [Table Text Block]

A summary of the service-based phantom common unit activity is set forth below:

	Number of phantom common units						Weighted		Weighted
	(in thousands)						Average Grant		Average Term
	Service-Based		Performance-Based		Total		Date Value		Until Maturity
Nonvested at December 31, 2014	337.7		—		337.7		$	26.99	2.0
Awarded	447.9		182.4		630.3		23.37		1.9
Incremental performance units	—		80.4		80.4		23.06		1.7
Forfeited	(91.3	)	(2.1	)	(93.4	)	26.22		—
Vested	(112.4	)	—		(112.4	)	27.02		—
Nonvested at December 31, 2015	581.9		260.7		842.6		24.00		1.5
Awarded	381.0		163.6		544.6		25.87		2.5
Incremental performance units	—		231.8		231.8		27.82		2.0
Forfeited	(16.5	)	(19.1	)	(35.6	)	25.36		—
Vested	(269.2	)	(1.8	)	(271.0	)	24.10		—
Exchanged due to merger	(677.2	)	(635.2	)	(1,312.4	)	25.45		2.0
Nonvested at December 31, 2016	—		—		—		—		—

Restricted Stock [Member]

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Schedule of Share-based Compensation, Activity [Table Text Block]

A summary of the service-based restricted common unit activity is set forth below:

	Number of		Weighted		Weighted Average Term
	restricted common units		Average Grant		Until Maturity
	(in thousands)		Date Price		(years)
Nonvested at December 31, 2014	396.2		$	24.73	1.3
Awarded	1.0		24.90		2.0
Vested	(205.7	)	24.71		—
Nonvested at December 31, 2015	191.5		24.75		1.0
Forfeited	(12.3	)	25.57		—
Vested	(34.5	)	26.83		—
Exchanged due to merger	(144.7	)	24.18		0.5
Nonvested at December 31, 2016	—		—		—

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Equity (Tables)

12 Months Ended

Dec. 31, 2016

Class of Stock [Line Items]

Accelerated Share Repurchases [Table Text Block]

The following table summarizes our share repurchase activity for our share repurchase programs.

	January 2014 Program			November 2014 Program			September 2015 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)
Shares purchased at December 31, 2013	—	$	—	—	$	—	—	$	—
Shares purchased during 2014 (1)	4,976,039	200,000		1,492,874	59,222		—	—
Shares purchased at December 31, 2014	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	4,976,039	200,000		4,140,614	164,222		—	—
Shares purchased during 2016 (2)	—	—		—	—		2,462,350	75,000
Shares purchased at December 31, 2016	4,976,039	$	200,000	4,140,614	$	164,222	2,462,350	$	75,000

Dividends Declared [Table Text Block]

The table below summarizes our 2016 cash dividend declarations, payments and scheduled payments:

	Declaration Date	Record Date	Payment Date	Dividend per common share		Total Payment(in thousands)
First quarter	January 6	January 20	February 4	$	0.38	$	35,601
Second quarter	April 8	April 18	May 2	0.38		34,685
Third quarter	July 15	July 25	August 9	0.38		41,202
Fourth quarter	October 13	October 24	November 8	0.38		41,202
Total						$	152,690

Distributions Made to Limited Partner, by Distribution [Table Text Block]

NTI Distributions

The table below summarizes NTI's 2016 quarterly distribution declarations, payments and scheduled payments:

Declaration Date	Record Date	Payment Date	Distribution per Unit
February 3	February 12	February 19	$	0.38
June 13	June 23	June 23	0.18
Total			$	0.56

WNRL Distributions

The table below summarizes WNRL's 2016 quarterly distribution declarations, payments and scheduled payments:

Declaration Date	Record Date	Payment Date	Distribution per Common and Subordinated Unit
January 30	February 13	February 23	$	0.3925
May 1	May 15	May 26	0.4025
July 31	August 14	August 24	0.4125
October 30	November 13	November 23	0.4225
			$	1.6300

Northern Tier Energy LP [Member]

Class of Stock [Line Items]

Distributions Made to Limited Partner, by Distribution [Table Text Block]

The following table details the quarterly distributions paid to common unitholders (in millions, except per unit amounts):

Date Declared	Date Paid	Common Units and equivalents at record date (in millions)	Distribution per common unit and equivalent		Total Distribution (in millions)
2014 Distributions:
February 7, 2014	February 28, 2014	92.7	$	0.41	$	38.0
May 6, 2014	May 30, 2014	93.0	$	0.77	71.6
August 5, 2014	August 29, 2014	93.0	$	0.53	49.3
November 4, 2014	November 25, 2014	93.1	$	1.00	92.9
Total distributions paid during 2014			$	2.71	$	251.8
2015 Distributions:
February 5, 2015	February 27, 2015	93.7	$	0.49	$	45.9
May 5, 2015	May 29, 2015	93.7	$	1.08	100.8
August 4, 2015	August 28, 2015	93.7	$	1.19	111.3
November 3, 2015	November 25, 2015	93.7	$	1.04	97.3
Total distributions paid during 2015			$	3.80	$	355.3
2016 Distributions:
February 3, 2016	February 19, 2016	94.2	$	0.38	$	36.0
June 13, 2016	June 23, 2016	93.0	$	0.18	$	16.7
Total distributions paid prior to our merger			$	0.56	$	52.7

Subsequent to our merger with Western, we declared a distribution for $110.0 million which was paid in the fourth quarter 2016.

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Earnings Per Share (Tables)

12 Months Ended

Dec. 31, 2016

Earnings Per Share [Abstract]

Schedule of Earnings Per Share, Basic and Diluted [Table Text Block]

	Year Ended December 31,
	2016			2015			2014
	(In thousands, except per share data)
Basic earnings per common share:
Allocation of earnings:
Net income attributable to Western Refining, Inc.	$	124,939		$	406,756		$	559,926
Distributed earnings	(153,691		)	(129,211		)	(293,746		)
Income allocated to participating securities	—			—			(3		)
Distributed earnings allocated to participating securities	—			—			3
Undistributed income (loss) available to Western Refining, Inc.	$	(28,752	)	$	277,545		$	266,180
Weighted average number of common shares outstanding (1)	100,473			94,899			90,708
Basic earnings per common share:
Distributed earnings per share	$	1.53		$	1.36		$	3.24
Undistributed earnings (loss) per share	(0.29		)	2.92			2.93
Basic earnings per common share	$	1.24		$	4.28		$	6.17

(1) Excludes the weighted average number of common shares outstanding associated with participating securities of 884 shares for the year ended December 31, 2014.

	Year Ended December 31,
	2016		2015		2014
	(In thousands, except per share data)
Diluted earnings per common share:
Net income attributable to Western Refining, Inc.	$	124,939	$	406,756	$	559,926
Tax effected interest related to convertible debt	—		—		8,010
Net income available to Western Refining, Inc., assuming dilution	$	124,939	$	406,756	$	567,936
Weighted average number of diluted shares outstanding	100,868		94,999		101,190
Diluted earnings per common share	$	1.24	$	4.28	$	5.61

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

	Year Ended December 31,
	2016	2015	2014
	(In thousands)
Weighted average number of common shares outstanding	100,473	94,899	90,708
Common equivalent shares from Convertible Senior Notes	—	—	10,349
Restricted shares, restricted share units and phantom stock	395	100	133
Weighted average number of diluted shares outstanding	100,868	94,999	101,190

A

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Cash Flows (Tables)

12 Months Ended

Dec. 31, 2016

Other Significant Noncash Transactions [Line Items]

Schedule of Cash Flow, Supplemental Disclosures [Table Text Block]

Supplemental disclosures of cash flow information were as follows:

	Year Ended December 31,
	2016		2015		2014
	(In thousands)
Non-cash operating activities were as follows:
Income taxes paid	$	38,227	$	283,330	$	227,953
Interest paid, excluding amounts capitalized	124,037		95,012		83,943
Non-cash investing activities were as follows:
Accrued capital expenditures	$	28,934	$	53,361	$	9,189
Assets acquired through capital lease obligations	4,644		29,082		—
PP&E derecognized from sale leaseback continuing involvement release	2,799		1,773		—
Transfer of capital spares	860		1,490		—
Non-cash financing activities were as follows:
Reduction of long-term debt proceeds for original issuance discount	$	10,250	$	—	$	—
Treasury stock issuance	438,168		—		—
Accrued financing costs	67		—		—
Issuance of common shares for redemption of Western Convertible Notes	—		—		357,608
Distributions accrued on unvested NTI equity awards	—		4,210		—

Northern Tier Energy LP [Member]

Other Significant Noncash Transactions [Line Items]

Schedule of Cash Flow, Supplemental Disclosures [Table Text Block]

Supplemental cash flow information is as follows:

	Year Ended December 31,
(in millions)	2016		2015		2014
Net cash from operating activities included:
Interest paid	$	28.6	$	29.0	$	22.5
Income taxes paid	0.1		6.1		5.0
Noncash investing activities included:
Capital expenditures included in accounts payable	$	11.4	$	13.8	$	2.9
PP&E derecognized in sale leaseback	2.8		1.8		—
Book value of tank and terminal related assets sold to WNRL	48.7		—		—
PP&E additions resulting from a capital lease	0.3		4.5		1.7
Noncash financing activities included:
Distributions accrued on unvested equity awards	$	—	$	4.2	$	—
Increase in equity due to proceeds received exceeding book value of assets sold to WNRL	146.3		—		—

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Contingencies (Tables)

12 Months Ended

Dec. 31, 2016

Northern Tier Energy LP [Member]

Loss Contingencies [Line Items]

Schedule of Environmental Loss Contingencies by Site [Table Text Block]

Future estimated cash outflows to remediate environmental matters are as follows:

(in millions)	Groundwater Contamination			Wastewater Lagoon		Total
2017	$	0.5		$	0.9	$	1.4
2018	0.3			—		0.3
2019	0.1			—		0.1
2020	0.1			—		0.1
2021	0.1			—		0.1
Thereafter	2.0			—		2.0
Total	3.1			0.9		4.0
Less: amount representing interest	(0.6		)	—		(0.6		)
Present value of estimated future cash flows	$	2.5		$	0.9	$	3.4

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Leases and Other Commitments (Tables)

12 Months Ended

Dec. 31, 2016

Other Commitments [Line Items]

Schedule of Future Minimum Rental Payments for Operating Leases [Table Text Block]

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, 2016:

	Operating		Capital
2017	$	55,675	$	5,419
2018	52,509		5,444
2019	47,269		5,553
2020	42,420		5,744
2021	43,284		5,891
2022 and thereafter	305,646		67,139
Total minimum lease payments	$	546,803	95,190
Less amount that represents interest			39,960
Present value of net minimum capital lease payments			$	55,230

Northern Tier Energy LP [Member]

Other Commitments [Line Items]

Schedule of Future Minimum Rental Payments for Operating Leases [Table Text Block]

Future minimum commitments for operating lease obligations having an initial or remaining non-cancelable lease terms in excess of one year are as follows:

(in millions)	Capital Leases			Operating Leases		Total Leases
2017	$	1.1		$	27.8	$	28.9
2018	1.0			27.5		28.5
2019	1.1			26.2		27.3
2020	1.1			25.6		26.7
2021	1.1			27.2		28.3
Thereafter	12.2			139.2		151.4
Total	17.6			273.5		291.1
Less: amount representing interest	(8.4		)	—		(8.4		)
Present value of net minimum lease payments	$	9.2		$	273.5	$	282.7

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Related Party Transactions (Tables)

12 Months Ended

Dec. 31, 2016

Northern Tier Energy LP [Member]

Related Party Transaction [Line Items]

Schedule of Related Party Transactions [Table Text Block]

In addition to the Contribution Agreement, the Company engaged in the following related party transactions with unconsolidated affiliates for the years ended December 31, 2016, 2015 and 2014:

		For the year ended December 31,
(in millions)	Location in Statement of Operations and Comprehensive Income	2016		2015		2014
Western Refining:
Asphalt sales	Revenue	$	32.0	$	46.6	$	19.0
Feedstock sales	Revenue	—		0.6		—
Railcar rental	Revenue	0.2		0.2		0.1
Crude and feedstock purchases	Cost of sales	—		—		6.3
Refined product purchases	Cost of sales	—		1.5		—
Shared services purchases	Selling, general and administrative expenses	0.6		3.6		1.1
Western Refining Logistics:
Tank and terminal service fees	Cost of sales	13.6		—		—
Shared services purchases	Selling, general and administrative expenses	0.4		—		—
Minnesota Pipe Line Company:
Pipeline transportation purchases	Cost of sales	52.2		55.4		12.6

The Company had the following outstanding receivables and payables with non-consolidated related parties at December 31, 2016 and December 31, 2015:

(in millions)	Balance Sheet Location	December 31, 2016			December 31, 2015
Net receivable (payable) with related party:
Western Refining, Inc.	Accounts receivable, net	$	3.7		$	2.8
Western Refining Logistics, LP	Accounts payable	(2.0		)	—
Minnesota Pipe Line Company	Accounts payable	(1.5		)	(2.7		)

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Condensed Consolidating Financial Information (Tables)

12 Months Ended

Dec. 31, 2016

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Condensed Balance Sheet [Table Text Block]

CONDENSED CONSOLIDATING BALANCE SHEETS

As of December 31, 2016

(In thousands)

	Parent		Guarantor Subsidiaries		Non-Guarantors		Eliminations			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	21	$	224,431	$	44,129	$	—		$	268,581
Accounts receivable, trade, net of a reserve for doubtful accounts	—		117,007		306,164		—			423,171
Accounts receivable, affiliate	16,832		72,760		3,736		(93,328		)	—
Inventories	—		448,012		323,977		—			771,989
Prepaid expenses	—		80,199		15,156		—			95,355
Other current assets	—		74,832		38,589		—			113,421
Total current assets	16,853		1,017,241		731,751		(93,328		)	1,672,517
Equity method investment	—		—		102,685		—			102,685
Property, plant and equipment, net	—		1,117,958		1,246,524		—			2,364,482
Goodwill	—		—		1,289,443		—			1,289,443
Intangible assets, net	—		31,516		52,296		—			83,812
Investment in subsidiaries	5,348,171		—		—		(5,348,171		)	—
Due from affiliate	—		2,443,306		—		(2,443,306		)	—
Other assets	—		27,425		20,033		—			47,458
Total assets	$	5,365,024	$	4,637,446	$	3,442,732	$	(7,884,805	)	$	5,560,397
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable, trade	$	—	$	372,570	$	381,363	$	—		$	753,933
Accounts payable, affiliate	—		—		93,328		(93,328		)	—
Accrued liabilities	5,655		124,628		89,324		—			219,607
Current portion of long-term debt	10,500		—		—		—			10,500
Total current liabilities	16,155		497,198		564,015		(93,328		)	984,040
Long-term liabilities:
Long-term debt, less current portion	1,208,703		—		663,102		—			1,871,805
Due to affiliate	2,443,306		—		—		(2,443,306		)	—
Lease financing obligation	—		45,007		9,156		—			54,163
Deferred income tax liability, net	—		222,372		37,921		—			260,293
Deficit in subsidiaries	—		501,776		—		(501,776		)	—
Other liabilities	—		79,501		13,635		—			93,136
Total long-term liabilities	3,652,009		848,656		723,814		(2,945,082		)	2,279,397
Equity:
Equity - Western	1,696,860		3,291,592		1,554,803		(4,846,395		)	1,696,860
Equity - Non-controlling interest	—		—		600,100		—			600,100
Total equity	1,696,860		3,291,592		2,154,903		(4,846,395		)	2,296,960
Total liabilities and equity	$	5,365,024	$	4,637,446	$	3,442,732	$	(7,884,805	)	$	5,560,397

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	3,790,958		—		—		(3,790,958		)	—
Due from affiliate	—		1,623,427		—		(1,623,427		)	—
Other assets	—		42,166		22,831		—			64,997
Total assets	$	3,790,979	$	4,203,423	$	3,312,431	$	(5,473,440	)	$	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	1,623,427		—		—		(1,623,427		)	—
Lease financing obligation	—		42,168		11,064		—			53,232
Deferred income tax liability, net	—		275,634		37,280		—			312,914
Deficit in subsidiaries	—		287,761		—		(287,761		)	—
Other liabilities	—		63,674		4,921		—			68,595
Total long-term liabilities	2,479,754		669,237		841,832		(1,911,188		)	2,079,635
Equity:
Equity - Western	1,299,297		3,129,379		373,818		(3,503,197		)	1,299,297
Equity - Non-controlling interest	—		—		1,646,609		—			1,646,609
Total equity	1,299,297		3,129,379		2,020,427		(3,503,197		)	2,945,906
Total liabilities and equity	$	3,790,979	$	4,203,423	$	3,312,431	$	(5,473,440	)	$	5,833,393

Condensed Income Statement [Table Text Block]

For the Year Ended December 31, 2016

(In thousands)

	Parent			Guarantor Subsidiaries			Non-Guarantors			Eliminations			Consolidated
Net sales	$	—		$	6,178,382		$	5,270,300		$	(3,705,469	)	$	7,743,213
Operating costs and expenses:
Cost of products sold (exclusive of depreciation and amortization)	—			5,298,962			4,385,318			(3,705,469		)	5,978,811
Direct operating expenses (exclusive of depreciation and amortization)	—			453,750			474,273			—			928,023
Selling, general and administrative expenses	185			111,268			106,408			—			217,861
Merger and reorganization costs	—			7,759			4,681			—			12,440
Loss (gain) and impairments on disposal of assets, net	—			(207		)	(1,064		)	—			(1,271		)
Maintenance turnaround expense	—			1,372			45,765			—			47,137
Depreciation and amortization	—			106,753			110,034			—			216,787
Total operating costs and expenses	185			5,979,657			5,125,415			(3,705,469		)	7,399,788
Operating income (loss)	(185		)	198,725			144,885			—			343,425
Other income (expense):
Equity in earnings of subsidiaries	201,150			16,603			—			(217,753		)	—
Interest income	—			426			266			—			692
Interest and debt expense	(72,110		)	(3,087		)	(48,094		)	—			(123,291		)
Loss on extinguishment of debt	(3,916		)	—			—			—			(3,916		)
Other, net	—			1,799			23,165			—			24,964
Income before income taxes	124,939			214,466			120,222			(217,753		)	241,874
Provision for income taxes	—			(52,253		)	(2,615		)	—			(54,868		)
Net income	124,939			162,213			117,607			(217,753		)	187,006
Less net income attributed to non-controlling interests	—			—			62,067			—			62,067
Net income attributable to Western Refining, Inc.	$	124,939		$	162,213		$	55,540		$	(217,753	)	$	124,939
Comprehensive income attributable to Western Refining, Inc.	$	124,939		$	162,973		$	55,355		$	(217,753	)	$	125,514

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 of subsidiaries	461,049			11,551			—			(472,600		)	—
Interest income	—			389			314			—			703
Interest and debt expense	(54,104		)	(2,717		)	(48,782		)	—			(105,603		)
Other, net	—			492			12,669			—			13,161
Income before income taxes	406,756			530,934			373,296			(472,600		)	838,386
Provision for income taxes	—			(223,908		)	(47		)	—			(223,955		)
Net income	406,756			307,026			373,249			(472,600		)	614,431
Less net income attributed to non-controlling interests	—			—			207,675			—			207,675
Net income attributable to Western Refining, Inc.	$	406,756		$	307,026		$	165,574		$	(472,600	)	$	406,756
Comprehensive income attributable to Western Refining, Inc.	$	406,756		$	307,681		$	166,861		$	(472,600	)	$	408,698

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
Merger and reorganization 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 of subsidiaries	630,407			17,059			—			(647,466		)	—
Interest income	—			795			393			—			1,188
Interest and debt expense	(70,286		)	(1,044		)	(25,732		)	—			(97,062		)
Loss on extinguishment of debt	(9		)	—			—			—			(9		)
Other, net	—			(604		)	2,650			—			2,046
Income before income taxes	559,926			799,025			291,191			(647,466		)	1,002,676
Provision for income taxes	—			(292,145		)	(459		)	—			(292,604		)
Net income	559,926			506,880			290,732			(647,466		)	710,072
Less net income attributed to non-controlling interests	—			—			150,146			—			150,146
Net income attributable to Western Refining, Inc.	$	559,926		$	506,880		$	140,586		$	(647,466	)	$	559,926
Comprehensive income attributable to Western Refining, Inc.	$	559,926		$	506,403		$	140,122		$	(647,466	)	$	558,985

Condensed Cash Flow Statement [Table Text Block]

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

For the Year Ended December 31, 2016

(In thousands)

	Parent			Guarantor Subsidiaries			Non-Guarantors			Eliminations			Consolidated
Cash flows from operating activities:
Net cash provided by operating activities	$	(41,614	)	$	331,819		$	182,302		$	(88,760	)	$	383,747
Cash flows from investing activities:
Capital expenditures	—			(145,760		)	(156,356		)	1,147			(300,969		)
Return of capital from equity method investment	97,379			—			—			(97,379		)	—
Contributions to affiliate	—			(689,063		)	(20,092		)	709,155			—
Proceeds from the sale of assets	—			1,365			5,303			(1,147		)	5,521
Increase in restricted cash	—			—			(195,000		)	—			(195,000		)
Use of restricted cash	—			69,106			195,000			—			264,106
Net cash provided by (used in) investing activities	97,379			(764,352		)	(171,145		)	611,776			(226,342		)
Cash flows from financing activities:
Additions to long-term debt	500,000			—			—			—			500,000
Payments on long-term debt and capital lease obligations	(133,000		)	(1,035		)	(1,357		)	—			(135,392		)
Borrowings on revolving credit facility	—			—			466,900			—			466,900
Repayments of revolving credit facility	—			—			(591,600		)	—			(591,600		)
Payments for NTI units related to merger	(859,893		)	—			—			—			(859,893		)
Transaction costs for NTI merger	(11,741		)	—			—			—			(11,741		)
Contributions from affiliate	689,063			—			20,092			(709,155		)	—
Distribution to non-controlling interest holders	—			—			(66,311		)	—			(66,311		)
Deferred financing costs	(11,503		)	—			(1,224		)	—			(12,727		)
Distribution to affiliate	—			—			(186,139		)	186,139			—
Purchases of common stock for treasury	(75,000		)	—			—			—			(75,000		)
Dividends paid	(153,691		)	—			—			—			(153,691		)
Proceeds from issuance of WNRL common units	—			—			277,751			—			277,751
Offering costs for issuance of WNRL common units	—			—			(655		)	—			(655		)
Excess tax benefit from stock-based compensation	—			1,033			—			—			1,033
Net cash provided by (used in) financing activities	(55,765		)	(2		)	(82,543		)	(523,016		)	(661,326		)
Net increase (decrease) in cash and cash equivalents	—			(432,535		)	(71,386		)	—			(503,921		)
Cash and cash equivalents at beginning of year	21			656,966			115,515			—			772,502
Cash and cash equivalents at end of year	$	21		$	224,431		$	44,129		$	—		$	268,581

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 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		)
Proceeds from the sale of assets	—			2,028			643			(1,557		)	1,114
Contributions to affiliate	—			(178,243		)	(27,888		)	206,131			—
Increase in restricted cash	—			(170,000		)	—			—			(170,000		)
Use of restricted cash	—			267,903			—			—			267,903
Net cash used in investing activities	—			(235,912		)	(162,065		)	206,131			(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			—			53,784			(206,131		)	—
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		)
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			(367,248		)	(25,311		)	(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

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		)	(119,147		)	797,775			—
Increase in restricted cash	—			(320,000		)	—			—			(320,000		)
Use of restricted cash	—			152,991			—			—			152,991
Net cash used in investing activities	—			(943,581		)	(235,058		)	797,775			(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
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			—
Contributions from affiliate	618,564			93,546			85,665			(797,775		)	—
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			(197,021		)	(666,195		)	(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

Condensed Financial Statements [Table Text Block]

Due to the change in the guarantor structure resulting from the St. Paul Park Logistics 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, 2015

(In thousands)

	As Previously Reported			Adjustment			Revised
Parent	$	3,964,578		$	(173,620	)	$	3,790,958
Guarantor subsidiaries	(395,774		)	108,013			(287,761		)
Non-guarantor subsidiaries	—			—			—
Eliminations	(3,568,804		)	65,607			(3,503,197		)
Investment (deficit) in subsidiaries	$	—		$	—		$	—
Parent	$	3,964,599		$	(173,620	)	$	3,790,979
Guarantor subsidiaries	4,377,043			(173,620		)	4,203,423
Non-guarantor subsidiaries	3,312,431			—			3,312,431
Eliminations	(5,820,680		)	347,240			(5,473,440		)
Total assets	$	5,833,393		$	—		$	5,833,393
Parent	$	2,665,302		$	(173,620	)	$	2,491,682
Guarantor subsidiaries	1,182,057			(108,013		)	1,074,044
Non-guarantor subsidiaries	1,292,004			—			1,292,004
Eliminations	(2,251,876		)	281,633			(1,970,243		)
Total liabilities	$	2,887,487		$	—		$	2,887,487
Parent	$	1,299,297		$	—		$	1,299,297
Guarantor subsidiaries	3,194,986			(65,607		)	3,129,379
Non-guarantor subsidiaries	2,020,427			—			2,020,427
Eliminations	(3,568,804		)	65,607			(3,503,197		)
Total equity	$	2,945,906		$	—		$	2,945,906

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS AND COMPREHENSIVE INCOME

For the Year Ended December 31, 2015

(In thousands)

	As Previously Reported			Adjustment			Revised
Parent	$	461,049		$	—		$	461,049
Guarantor subsidiaries	42,470			(30,919		)	11,551
Non-guarantor subsidiaries	—			—			—
Eliminations	(503,519		)	30,919			(472,600		)
Equity in earnings (loss) of subsidiaries	$	—		$	—		$	—
Parent	406,756			—			406,756
Guarantor subsidiaries	337,945			(30,919		)	307,026
Non-guarantor subsidiaries	165,574			—			165,574
Eliminations	(503,519		)	30,919			(472,600		)
Net income (loss) attributable to Western Refining, Inc.	$	406,756		$	—		$	406,756
Parent	$	406,756		$	—		$	406,756
Guarantor subsidiaries	338,600			(30,919		)	307,681
Non-guarantor subsidiaries	166,861			—			166,861
Eliminations	(503,519		)	30,919			(472,600		)
Comprehensive income attributable to Western Refining, Inc.	$	408,698		$	—		$	408,698

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	51,747			(34,688		)	17,059
Non-guarantor subsidiaries	—			—			—
Eliminations	(682,154		)	34,688			(647,466		)
Equity in earnings (loss) of subsidiaries	$	—		$	—		$	—
Parent	559,926			—			559,926
Guarantor subsidiaries	541,568			(34,688		)	506,880
Non-guarantor subsidiaries	140,586			—			140,586
Eliminations	(682,154		)	34,688			(647,466		)
Net income (loss) attributable to Western Refining, Inc.	$	559,926		$	—		$	559,926
Parent	$	559,926		$	—		$	559,926
Guarantor subsidiaries	541,091			(34,688		)	506,403
Non-guarantor subsidiaries	140,122			—			140,122
Eliminations	(682,154		)	34,688			(647,466		)
Comprehensive income attributable to Western Refining, Inc.	$	558,985		$	—		$	558,985

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

For the Year Ended December 31, 2015

(In thousands)

	As Previously Reported			Adjustment			Revised
Parent	$	87,364		$	—		$	87,364
Guarantor subsidiaries	433,863			—			433,863
Non-guarantor subsidiaries	502,676			—			502,676
Eliminations	(180,820		)	—			(180,820		)
Net cash provided by (used in) operating activities	$	843,083		$	—		$	843,083
Parent	—			—			—
Guarantor subsidiaries	(235,912		)	—			(235,912		)
Non-guarantor subsidiaries	(134,177		)	(27,888		)	(162,065		)
Eliminations	178,243			27,888			206,131
Net cash provided by (used in) investing activities	$	(191,846	)	$	—		$	(191,846	)
Parent	$	(87,364	)	$	—		$	(87,364	)
Guarantor subsidiaries	170,029			—			170,029
Non-guarantor subsidiaries	(395,136		)	27,888			(367,248		)
Eliminations	2,577			(27,888		)	(25,311		)
Net cash provided by (used in) financing activities	$	(309,894	)	$	—		$	(309,894	)

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	520,972			—			520,972
Non-guarantor subsidiaries	403,087			—			403,087
Eliminations	(131,580		)	—			(131,580		)
Net cash provided by (used in) operating activities	$	737,633		$	—		$	737,633
Parent	—			—			—
Guarantor subsidiaries	(943,581		)	—			(943,581		)
Non-guarantor subsidiaries	(209,457		)	(25,601		)	(235,058		)
Eliminations	772,174			25,601			797,775
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	(222,622		)	25,601			(197,021		)
Eliminations	(640,594		)	(25,601		)	(666,195		)
Net cash provided by (used in) financing activities	$	(393,680	)	$	—		$	(393,680	)

XML

Quarterly Financial Information (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2016

Schedule of Quarterly Financial Information [Table Text Block]

	Year Ended December 31, 2016
	Quarter
	First			Second			Third			Fourth
	(Unaudited) (In thousands, except for per share data)
Net sales	$	1,455,504		$	2,107,308		$	2,065,076		$	2,115,325
Operating costs and expenses:
Cost of products sold (exclusive of depreciation and amortization)	1,047,361			1,602,628			1,607,010			1,721,812
Direct operating expenses (exclusive of depreciation and amortization)	223,585			231,169			232,553			240,716
Selling, general and administrative expenses	53,285			56,052			57,320			51,204
Merger and reorganization costs	408			735			2,844			8,453
Gain and impairments on disposal of assets, net	(130		)	(772		)	(279		)	(90		)
Maintenance turnaround expense	125			400			27,208			19,404
Depreciation and amortization	52,651			54,359			54,321			55,456
Total operating costs and expenses	1,377,285			1,944,571			1,980,977			2,096,955
Operating income	78,219			162,737			84,099			18,370
Other income (expense):
Interest income	164			131			141			256
Interest and debt expense	(26,681		)	(26,928		)	(34,456		)	(35,226		)
Loss on extinguishment of debt	—			—			—			(3,916		)
Other, net	6,512			5,076			6,224			7,152
Income (loss) before income taxes	58,214			141,016			56,008			(13,364		)
Provision for income taxes	(18,629		)	(38,152		)	(11,700		)	13,613
Net income	39,585			102,864			44,308			249
Less net income attributable to non-controlling interests	9,047			37,449			5,733			9,838
Net income (loss) attributable to Western Refining, Inc.	$	30,538		$	65,415		$	38,575		$	(9,589	)
Basic earnings (loss) per common share	$	0.34		$	0.70		$	0.36		$	(0.09	)
Diluted earnings (loss) per common share	$	0.33		$	0.70		$	0.35		$	(0.09	)

	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 and debt expense	(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) attributable 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

Northern Tier Energy LP [Member]

Schedule of Quarterly Financial Information [Table Text Block]

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 2016 and 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.

(in millions, except per unit data)		First Quarter		Second Quarter		Third Quarter		Fourth Quarter			Total
2016
	Revenue	$	604.4	$	812.3	$	732.3	$	739.6		$	2,888.6
	Operating income	21.8		77.7		11.6		(5.5		)	105.6
	Net income	14.7		70.6		3.6		(12.4		)	76.5
	Earnings per common unit - basic	$	0.16	N/A		N/A		N/A			N/A
	Earnings per common unit - diluted	$	0.16	N/A		N/A		N/A			N/A
2015
	Revenue	$	793.8	$	959.8	$	891.6	$	759.8		$	3,405.0
	Operating income	119.5		139.3		114.6		(5.3		)	368.1
	Net income	111.2		128.9		103.5		(12.6		)	331.0
	Earnings per common unit - basic	$	1.20	$	1.39	$	1.11	$	(0.14	)	$	3.58
	Earnings per common unit - diluted	$	1.20	$	1.39	$	1.11	$	(0.14	)	$	3.56

XML

NTI (Tables)

12 Months Ended

Dec. 31, 2016

Business Combinations [Abstract]

Business Acquisition, Pro Forma Information [Table Text Block]

The consolidated statements of operations include the results of the NTI Merger beginning on June 23, 2016. NTI's net sales and net loss since June 23, 2016 was $1,905.3 million and $20.1 million, respectively. The following unaudited pro forma information assumes that (i) the Merger occurred on January 1, 2015; (ii) $500.0 million was borrowed to fund the NTI Merger consideration on January 1, 2015, resulting in increased interest and debt expense of $16.8 million and $36.1 million for the years ended December 31, 2016 and 2015, respectively; and (iii) income tax expense increased as a result of the increased net income attributable to Western Refining, Inc. offset by increased interest and debt expense of $7.0 million and $57.3 million for the years ended December 31, 2016 and 2015, respectively.

	Year Ended
	December 31,
	2016		2015
	(In thousands, except per share data)
Net sales	$	7,743,213	$	9,787,036
Operating income	343,425		930,125
Net income	163,129		521,014
Net income attributable to Western Refining, Inc.	136,385		499,859
Basic earnings per share	$	1.26	$	4.46
Diluted earnings per share	1.25		4.46

Restructuring and Related Costs [Table Text Block]

The following table summarizes the expense activity related to the NTI Merger and reorganization for the years ended December 31, 2016, 2015 and 2014:

	Year Ended
	December 31,
	2016			2015			2014
	(In thousands)
Beginning liability for merger and reorganization costs	$	189		$	808		$	—
Third-party professional service fees	1,662			—			—
Reorganization and related personnel costs incurred during period	4,650			—			12,878
Non-cash equity-based awards with accelerated vesting	—			—			(4,789		)
Cash payments to third-party professional service providers	(1,459		)	—			—
Cash payments made to severed employees	(2,468		)	(619		)	(7,281		)
Ending liability for merger and reorganization costs	$	2,574		$	189		$	808

XML

Organization and Basis of Presentation (Details)		1 Months Ended				3 Months Ended			12 Months Ended
	Sep. 14, 2016 USD ($) shares	Sep. 30, 2016 mi shares	Jun. 30, 2016 shares	May 31, 2016 shares	Oct. 31, 2014 USD ($)	Sep. 30, 2016 USD ($) mi	Mar. 31, 2016	Dec. 31, 2015 USD ($) mi $ / shares bbl	Dec. 31, 2016 operating_segments stores_stations refineries Segment mi $ / shares	Jun. 23, 2016 USD ($) $ / shares	Dec. 31, 2014 $ / shares	Jun. 10, 2009 $ / shares
Segment Reporting Information [Line Items]
Number of Stores | stores_stations									544
Common Stock, Par or Stated Value Per Share | $ / shares								$ 0.01	$ 0.01		$ 0.01	$ 0.01
Number of Reportable Segments | operating_segments									3
Proceeds from Divestiture of Businesses					$ 320,000,000
Retail network [Member]
Segment Reporting Information [Line Items]
Property, Plant and Equipment, Operated, Number of Significant Assets | refineries									2
Pipelines [Member] | TexNew Mex 16 inch pipeline [Member]
Segment Reporting Information [Line Items]
Pipeline, Miles | mi								375
Western Refining Logistics, LP [Member]
Segment Reporting Information [Line Items]
Limited Liability Company (LLC) or Limited Partnership (LP), Members or Limited Partners, Ownership Interest									52.60%
Limited Liability Company (LLC) or Limited Partnership (LP), Managing Member or General Partner, Ownership Interest									100.00%
Partners' Capital Account, Units, Sold in Public Offering | shares			562,500	3,750,000
Northern Tier Energy LP [Member]
Segment Reporting Information [Line Items]
Limited Liability Company (LLC) or Limited Partnership (LP), Members or Limited Partners, Ownership Interest							38.30%		100.00%
Limited Liability Company (LLC) or Limited Partnership (LP), Managing Member or General Partner, Ownership Interest									100.00%
Debt Instrument, Face Amount								$ 350,000,000
Number of Reportable Segments | Segment									2
Public [Member] | Western Refining Logistics, LP [Member]
Segment Reporting Information [Line Items]
Limited Liability Company (LLC) or Limited Partnership (LP), Members or Limited Partners, Ownership Interest									47.40%
Public [Member] | Northern Tier Energy LP [Member]
Segment Reporting Information [Line Items]
Limited Liability Company (LLC) or Limited Partnership (LP), Managing Member or General Partner, Ownership Interest									100.00%
Tesoro Merger [Member]
Segment Reporting Information [Line Items]
Business Acquisition, Share Price | $ / shares									$ 37.30
St. Paul Park Logistics Assets [Member]
Segment Reporting Information [Line Items]
Pipeline, Miles | mi		2.5				2.5
St. Paul Park Logistics Assets [Member] | Western Refining Logistics, LP [Member]
Segment Reporting Information [Line Items]
Proceeds from Divestiture of Businesses						$ 195,000,000
St. Paul Park Logistics Assets [Member] | Northern Tier Energy LP [Member]
Segment Reporting Information [Line Items]
Pipeline, Miles | mi									2.5
TexNew Mex 16 inch pipeline [Member]
Segment Reporting Information [Line Items]
Proceeds from Divestiture of Businesses								$ 170,000,000
TexNew Mex 16 inch pipeline [Member] | Western Refining Logistics, LP [Member] | Gas Gathering and Processing Equipment [Member] | Crude Oil Storage Tanks [Member]
Segment Reporting Information [Line Items]
Long-term Purchase Commitment, Minimum Volume Required | bbl								80,000
TexNew Mex Units [Member] | TexNew Mex 16 inch pipeline [Member] | Western Refining Logistics, LP [Member]
Segment Reporting Information [Line Items]
Business Combination, Consideration Transferred, Equity Interests Issued and Issuable								$ 80,000
Common Units [Member] | St. Paul Park Logistics Assets [Member] | Western Refining Logistics, LP [Member]
Segment Reporting Information [Line Items]
Business Combination, Consideration Transferred, Equity Interests Issued and Issuable	$ 628,224
Common Units [Member] | TexNew Mex 16 inch pipeline [Member] | Western Refining Logistics, LP [Member]
Segment Reporting Information [Line Items]
Business Combination, Consideration Transferred, Equity Interests Issued and Issuable								$ 421,031
Term Loan, due 2023 [Member] | Line of Credit [Member]
Segment Reporting Information [Line Items]
Debt Instrument, Face Amount										$ 500,000,000
Common Units [Member]
Segment Reporting Information [Line Items]
Partners' Capital Account, Units, Sold in Public Offering | shares		1,125,000
Common Units [Member] | Western Refining Logistics, LP [Member]
Segment Reporting Information [Line Items]
Partners' Capital Account, Units, Sold in Public Offering | shares	7,500,000
Common Stock [Member]
Segment Reporting Information [Line Items]
Common Stock, Par or Stated Value Per Share | $ / shares									$ 0.01
Common Stock [Member] | Tesoro Merger [Member]
Segment Reporting Information [Line Items]
Payment of shares to acquire business, per unit | $ / shares									$ 0.4350
Common Stock [Member] | Northern Tier Energy LP [Member] | Northern Tier Energy LP [Member]
Segment Reporting Information [Line Items]
Payment of shares to acquire business, per unit | $ / shares										$ 0.2986

XML

Organization and Basis of Presentation (NTI) (Details) $ / shares in Units, shares in Millions		1 Months Ended	6 Months Ended	12 Months Ended
	Sep. 14, 2016 USD ($)	Jun. 30, 2016 shares	Jun. 30, 2016 shares	Dec. 31, 2016 USD ($) stores_stations Store bbl	Dec. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)	Jun. 23, 2016 $ / shares
Segment Reporting Information [Line Items]
Active Storage Capacity | bbl				12,400,000
Increase in Restricted Cash | $				$ 195,000,000	$ 170,000,000	$ 320,000,000
Number of Stores | stores_stations				544
Minnesota Pipe Line Company [Member]
Segment Reporting Information [Line Items]
Equity Method Investment, Ownership Percentage				17.00%
Western Refining Logistics, LP [Member]
Segment Reporting Information [Line Items]
Limited Liability Company (LLC) or Limited Partnership (LP), Managing Member or General Partner, Ownership Interest				100.00%
Minnesota Pipe Line Company [Member]
Segment Reporting Information [Line Items]
Preferred Interest By Parent				100.00%
Crude Oil Pipeline Capacity | bbl				465,000
Northern Tier Energy LP [Member]
Segment Reporting Information [Line Items]
Limited Liability Company (LLC) or Limited Partnership (LP), Managing Member or General Partner, Ownership Interest				100.00%
Increase in Restricted Cash | $					$ 0	$ 0
Northern Tier Energy LP [Member] | Subsidiaries [Member]
Segment Reporting Information [Line Items]
Equity Method Investment, Ownership Percentage				100.00%
Northern Tier Energy LP [Member] | Western Refining Logistics, LP [Member]
Segment Reporting Information [Line Items]
Equity Method Investment, Ownership Percentage				1.00%
Northern Tier Energy LP [Member] | Minnesota Pipe Line Company, LLC [Member]
Segment Reporting Information [Line Items]
Equity Method Investment, Ownership Percentage				0.00%
Northern Tier Energy LP [Member] | Minnesota Pipe Line Company [Member]
Segment Reporting Information [Line Items]
Equity Method Investment, Ownership Percentage				17.00%
Public [Member] | Northern Tier Energy LP [Member]
Segment Reporting Information [Line Items]
Limited Liability Company (LLC) or Limited Partnership (LP), Managing Member or General Partner, Ownership Interest				100.00%
Public [Member] | Northern Tier Energy GP LLC [Member]
Segment Reporting Information [Line Items]
Limited Liability Company (LLC) or Limited Partnership (LP), Managing Member or General Partner, Ownership Interest				100.00%
Maximum [Member] | Northern Tier Energy LP [Member] | Northern Tier Energy LP [Member]
Segment Reporting Information [Line Items]
Cash payments to acquire business, per unit | $ / shares							$ 15.357
Minimum [Member] | Northern Tier Energy LP [Member] | Northern Tier Energy LP [Member]
Segment Reporting Information [Line Items]
Cash payments to acquire business, per unit | $ / shares							15.00
Common Stock [Member] | Northern Tier Energy LP [Member]
Segment Reporting Information [Line Items]
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares | shares		17.1
Common Stock [Member] | Northern Tier Energy LP [Member] | Northern Tier Energy LP [Member]
Segment Reporting Information [Line Items]
Payment of shares to acquire business, per unit | $ / shares							0.2986
Common Stock [Member] | Maximum [Member] | Northern Tier Energy LP [Member] | Northern Tier Energy LP [Member]
Segment Reporting Information [Line Items]
Payment of shares to acquire business, per unit | $ / shares							0.7036
Common Stock [Member] | Minimum [Member] | Northern Tier Energy LP [Member] | Northern Tier Energy LP [Member]
Segment Reporting Information [Line Items]
Payment of shares to acquire business, per unit | $ / shares							$ 0.28896
Western Refining, Inc. [Member] | Common Stock [Member] | Northern Tier Energy LP [Member] | Merger Agreement Dated December Two Thousand Fifteen [Member]
Segment Reporting Information [Line Items]
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares | shares			17.1
Retail [Member] | Northern Tier Energy LP [Member]
Segment Reporting Information [Line Items]
Number of Stores | Store				285
Refining Equipment [Member] | St. Paul Park, Minnesota [Member] | Refining Group [Member] | Northern Tier Energy LP [Member]
Segment Reporting Information [Line Items]
Active Storage Capacity | bbl				102,000
Restricted cash [Member] | Western Refining Logistics, LP [Member] | St. Paul Park Logistics Assets [Member]
Segment Reporting Information [Line Items]
Increase in Restricted Cash | $				$ 195,000,000
Other Significant Noncash Transaction, Value of Consideration Received | $				$ 195,000,000
Common Units [Member] | Western Refining Logistics, LP [Member] | St. Paul Park Logistics Assets [Member]
Segment Reporting Information [Line Items]
Business Combination, Consideration Transferred, Equity Interests Issued and Issuable | $	$ 628,224
Franchised Units [Member] | Retail [Member] | Super America Franchising Company [Member]
Segment Reporting Information [Line Items]
Number of Stores | Store				115
Entity Operated Units [Member] | Retail [Member] | Northern Tier Energy LP [Member]
Segment Reporting Information [Line Items]
Number of Stores | Store				170

XML

Summary of Accounting Policies - Business Acquisitions and Other Non-Cash Activity (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended	12 Months Ended
	Mar. 31, 2016	Dec. 31, 2016	Dec. 31, 2015
Business Acquisition [Line Items]
Non-controlling interest		$ 600,100	$ 1,646,609
Cost method investment		$ 7,864	7,872
Maximum [Member]
Business Acquisition [Line Items]
Cash and Cash Equivalents, Short-term Investments, Maturity Period		3 months
Minnesota Pipe Line Company [Member]
Business Acquisition [Line Items]
Equity Method Investment, Ownership Percentage		17.00%
Northern Tier Energy LP [Member]
Business Acquisition [Line Items]
Limited Liability Company (LLC) or Limited Partnership (LP), Members or Limited Partners, Ownership Interest	38.30%	100.00%
Limited Liability Company (LLC) or Limited Partnership (LP), Managing Member or General Partner, Ownership Interest		100.00%
Cost method investment		$ 6,800	$ 6,800
Northern Tier Energy LP [Member] | Minnesota Pipe Line Company [Member]
Business Acquisition [Line Items]
Equity Method Investment, Ownership Percentage		17.00%
Western Refining Logistics, LP [Member]
Business Acquisition [Line Items]
Limited Liability Company (LLC) or Limited Partnership (LP), Members or Limited Partners, Ownership Interest		52.60%
Limited Liability Company (LLC) or Limited Partnership (LP), Managing Member or General Partner, Ownership Interest		100.00%
Tesoro Merger [Member] | Common Stock [Member]
Business Acquisition [Line Items]
Payment of shares to acquire business, per unit		$ 0.4350

XML

Summary of Accounting Policies - Schedule of Allowance for Doubtful Accounts Receivable (Details) - Trade receivables [Member] - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Movement in Valuation Allowances and Reserves [Roll Forward]
Balance, beginning of year	$ 169	$ 484	$ 906
Additions	803	367	3,095
Reductions	(737)	(682)	(3,517)
Balance, end of year	$ 235	$ 169	$ 484

XML

Summary of Accounting Policies - Property, Plant and Equipment (Details) $ in Millions	12 Months Ended
	Dec. 31, 2016 USD ($)
Property, Plant and Equipment [Line Items]
Interest Costs, Capitalization Benchmark, Minimum Capital Expenditure	$ 1
Minimum [Member]
Property, Plant and Equipment [Line Items]
Maintenance Turnaround, Frequency Period, Duration	2 years
Minimum [Member] | Refining facilities and related equipment [Member]
Property, Plant and Equipment [Line Items]
Estimated Useful Life	3 years
Minimum [Member] | Pipelines, terminals, and transportation equipment [Member]
Property, Plant and Equipment [Line Items]
Estimated Useful Life	5 years
Minimum [Member] | Gas Transmission Equipment [Member]
Property, Plant and Equipment [Line Items]
Estimated Useful Life	3 years
Minimum [Member] | Retail Site [Member]
Property, Plant and Equipment [Line Items]
Estimated Useful Life	3 years
Minimum [Member] | Other Capitalized Property Plant and Equipment [Member]
Property, Plant and Equipment [Line Items]
Estimated Useful Life	3 years
Maximum [Member]
Property, Plant and Equipment [Line Items]
Maintenance Turnaround, Frequency Period, Duration	6 years
Maximum [Member] | Refining facilities and related equipment [Member]
Property, Plant and Equipment [Line Items]
Estimated Useful Life	25 years
Maximum [Member] | Pipelines, terminals, and transportation equipment [Member]
Property, Plant and Equipment [Line Items]
Estimated Useful Life	20 years
Maximum [Member] | Gas Transmission Equipment [Member]
Property, Plant and Equipment [Line Items]
Estimated Useful Life	20 years
Maximum [Member] | Retail Site [Member]
Property, Plant and Equipment [Line Items]
Estimated Useful Life	30 years
Maximum [Member] | Other Capitalized Property Plant and Equipment [Member]
Property, Plant and Equipment [Line Items]
Estimated Useful Life	10 years

XML

Summary of Accounting Policies - NTI (Details) $ in Thousands	3 Months Ended	12 Months Ended
	Mar. 31, 2016	Dec. 31, 2016 USD ($) operating_segments stores_stations Store customer Segment	Dec. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)
Segment Reporting Information [Line Items]
Cost method investment		$ 7,864	$ 7,872
Number of Reportable Segments | operating_segments		3
Number of Stores | stores_stations		544
Allowance for Doubtful Accounts Receivable			235	$ 169
Accumulated Other Comprehensive Income (Loss), Net of Tax		$ 1,226	651
Sales Revenue, Net [Member] | Customer Concentration Risk [Member]
Segment Reporting Information [Line Items]
Number of Major Customers | customer		0
Northern Tier Energy LP [Member]
Segment Reporting Information [Line Items]
Limited Liability Company (LLC) or Limited Partnership (LP), Members or Limited Partners, Ownership Interest	38.30%	100.00%
Cost method investment		$ 6,800	6,800
Number of Reportable Segments | Segment		2
Allowance for Doubtful Accounts Receivable		$ 0	0
Required Frequency Of Maintenance Minimum		1 year
Required Frequency Of Maintenance Maximum		6 years
Excise and Sales Taxes		$ 432,200	402,900	396,400
Advertising Expense		2,900	2,900	2,300
Accumulated Other Comprehensive Income (Loss), Net of Tax		(100)	200
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Net Prior Service Cost (Credit) Arising During Period, Net of Tax		$ 300	$ (3,400)	$ 1,200
Western Refining Logistics, LP [Member]
Segment Reporting Information [Line Items]
Limited Liability Company (LLC) or Limited Partnership (LP), Members or Limited Partners, Ownership Interest		52.60%
Maximum [Member] | Northern Tier Energy LP [Member]
Segment Reporting Information [Line Items]
Cash Equivalents Maturity Period		3 months
Retail [Member] | Northern Tier Energy LP [Member]
Segment Reporting Information [Line Items]
Number of Stores | Store		285
Franchised Units [Member] | Retail [Member] | Super America Franchising Company [Member]
Segment Reporting Information [Line Items]
Number of Stores | Store		115
Entity Operated Units [Member] | Retail [Member] | Northern Tier Energy LP [Member]
Segment Reporting Information [Line Items]
Number of Stores | Store		170
St Paul Park Refining Company [Member] | Northern Tier Energy LP [Member]
Segment Reporting Information [Line Items]
Limited Liability Company (LLC) or Limited Partnership (LP), Members or Limited Partners, Ownership Interest		1.00%

XML

Segment Information (Details) $ in Thousands		3 Months Ended								12 Months Ended
		Dec. 31, 2016 USD ($) stores_stations refineries mi bbl	Sep. 30, 2016 USD ($)	Jun. 30, 2016 USD ($)	Mar. 31, 2016 USD ($)	Dec. 31, 2015 USD ($) stores_stations	Sep. 30, 2015 USD ($)	Jun. 30, 2015 USD ($)	Mar. 31, 2015 USD ($)	Dec. 31, 2016 USD ($) operating_segments stores_stations refineries mi bbl	Dec. 31, 2015 USD ($) stores_stations	Dec. 31, 2014 USD ($) stores_stations
Segment Reporting Information [Line Items]
Number of Reportable Segments | operating_segments										3
Active Storage Capacity | bbl		12,400,000								12,400,000
Number of Stores | stores_stations		544								544
Derivative, Gain (Loss) on Derivative, Net										$ (18,901)	$ 43,466	$ 289,754
FIFO Inventory Amount		$ 50,500				$ 14,500				50,500	14,500
Inventory, Change in Lower of Cost or Market Reserve										(133,400)	96,500	78,600
Net sales		2,115,325	$ 2,065,076	$ 2,107,308	$ 1,455,504	2,070,324	$ 2,569,090	$ 2,828,892	$ 2,318,730	7,743,213	9,787,036	15,153,573
Operating income		18,370	84,099	162,737	78,219	26,141	332,598	315,393	255,993	343,425	930,125	1,096,513
Nonoperating Income (Expense)										(101,551)	(91,739)	(93,837)
Income before income taxes		(13,364)	56,008	141,016	58,214	1,464	310,215	292,302	234,405	241,874	838,386	1,002,676
Depreciation and amortization		55,456	$ 54,321	$ 54,359	$ 52,651	52,845	$ 51,377	$ 51,143	$ 49,926	216,787	205,291	190,566
Payments to Acquire Productive Assets										300,969	290,863	223,271
Goodwill		1,289,443				1,289,443				1,289,443	1,289,443
Total assets		5,560,397				5,833,393				5,560,397	5,833,393	5,642,186
Refining Group [Member]
Segment Reporting Information [Line Items]
Insurance Recoveries												5,800
Derivative, Gain (Loss) on Derivative, Net										(18,900)	43,500	289,800
Inventory, Change in Lower of Cost or Market Reserve										(132,000)	95,800	77,100
Revenues	[1]									4,099,087	5,704,390	9,904,947
Goodwill		$ 1,267,455				$ 1,267,455				$ 1,267,455	1,267,455	1,267,455
Western Refining Logistics, LP [Member]
Segment Reporting Information [Line Items]
Active Storage Capacity | bbl		12,400,000								12,400,000
Pipeline, Miles | mi		705								705
Revenues	[1]									$ 1,520,561	$ 1,813,543	$ 2,490,313
Retail Group [Member]
Segment Reporting Information [Line Items]
Number of Stores | stores_stations		259				258				259	258	230
Inventory, Change in Lower of Cost or Market Reserve										$ (1,400)	$ 700	$ 1,400
Revenues										2,123,565	2,269,103	2,757,207
Goodwill		$ 21,988				$ 21,988				21,988	21,988	21,988
Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Revenues										0	0	0
Intersegment Eliminations [Member] | Refining Group [Member]
Segment Reporting Information [Line Items]
Revenues	[1]									2,819,844	3,072,806	4,291,617
Intersegment Eliminations [Member] | Western Refining Logistics, LP [Member]
Segment Reporting Information [Line Items]
Revenues	[1]									702,157	786,324	1,011,575
Intersegment Eliminations [Member] | Retail Group [Member]
Segment Reporting Information [Line Items]
Revenues										36,381	10,634	19,575
Operating Segments [Member] | Refining Group [Member]
Segment Reporting Information [Line Items]
Revenues	[1]									6,918,931	8,777,196	14,196,564
Operating income	[1],[2]									357,610	930,531	1,140,580
Depreciation and amortization	[1]									150,989	142,108	137,715
Payments to Acquire Productive Assets	[1]									248,863	201,249	119,416
Total assets	[1]	4,312,212				4,024,131				4,312,212	4,024,131	4,126,005
Operating Segments [Member] | Western Refining Logistics, LP [Member]
Segment Reporting Information [Line Items]
Revenues	[1]									2,222,718	2,599,867	3,501,888
Operating income	[1]									70,095	55,794	35,607
Depreciation and amortization	[1]									39,242	35,384	28,934
Payments to Acquire Productive Assets	[1]									29,161	65,635	79,338
Total assets	[1]	533,952				566,209				533,952	566,209	552,253
Operating Segments [Member] | Retail Group [Member]
Segment Reporting Information [Line Items]
Revenues										2,159,946	2,279,737	2,776,782
Operating income	[2]									25,146	41,279	42,087
Depreciation and amortization										23,193	23,197	19,869
Payments to Acquire Productive Assets										20,308	20,895	22,056
Total assets		435,030				444,382				435,030	444,382	417,269
Corporate, Non-Segment [Member]
Segment Reporting Information [Line Items]
Revenues										0	0	1,106
Operating income										(109,426)	(97,479)	(121,761)
Depreciation and amortization										3,363	4,602	4,048
Payments to Acquire Productive Assets										2,637	3,084	2,461
Total assets		$ 279,203				$ 798,671				$ 279,203	$ 798,671	$ 546,659
Refining Equipment [Member] | Refining Group [Member]
Segment Reporting Information [Line Items]
Property, Plant and Equipment, Operated, Number of Significant Assets | refineries		3								3
El Paso Facility [Member] | Refining Equipment [Member] | Refining Group [Member]
Segment Reporting Information [Line Items]
Active Storage Capacity | bbl		135,000								135,000
Gallup Facility [Member] | Refining Equipment [Member] | Refining Group [Member]
Segment Reporting Information [Line Items]
Active Storage Capacity | bbl		25,000								25,000
Non-Staffed Fueling Locations [Member] | Retail Group [Member]
Segment Reporting Information [Line Items]
Number of Stores | stores_stations		51				52				51	52	50
Glencore Supply Agreement [Member] | Refining Group [Member]
Segment Reporting Information [Line Items]
Net Assets		$ 4,100				$ 1,800				$ 4,100	$ 1,800
Derivative, Gain (Loss) on Derivative, Net										8,700	$ 48,700	$ 34,600
FIFO Inventory Amount		$ 46,000								$ 46,000
RetailGroup_UpperGreatPlains [Member] | Wholly Owned Properties [Member] | Retail Group [Member]
Segment Reporting Information [Line Items]
Number of Stores | stores_stations		170				168				170	168	165
RetailGroup_UpperGreatPlains [Member] | Franchised Units [Member] | Retail Group [Member]
Segment Reporting Information [Line Items]
Number of Stores | stores_stations		115				109				115	109	89

[1] )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, 2016. The information contained herein for WNRL has been retrospectively adjusted, to include the historical results of the St. Paul Park Logistics Assets.

[2] )The effect of our economic hedging activity is included within operating income of our refining segment as a component of cost of products sold. The cost of products sold within our refining segment included $18.9 million in net realized and unrealized economic hedging losses for the year ended December 31, 2016 and $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

XML

Segment Information (NTI) (Details) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2016 USD ($) stores_stations Store	Sep. 30, 2016 USD ($)	Jun. 30, 2016 USD ($)	Mar. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)	Sep. 30, 2015 USD ($)	Jun. 30, 2015 USD ($)	Mar. 31, 2015 USD ($)	Dec. 31, 2016 USD ($) operating_segments stores_stations Store Segment	Dec. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)
Segment Reporting Information [Line Items]
Equity method investment	$ 102,685				$ 97,513				$ 102,685	$ 97,513
Total assets	$ 5,560,397				5,833,393				$ 5,560,397	5,833,393	$ 5,642,186
Number of Reportable Segments | operating_segments									3
Number of Stores | stores_stations	544								544
Operating income	$ 18,370	$ 84,099	$ 162,737	$ 78,219	26,141	$ 332,598	$ 315,393	$ 255,993	$ 343,425	930,125	1,096,513
Depreciation and amortization	55,456	54,321	54,359	52,651	52,845	51,377	51,143	49,926	216,787	205,291	190,566
Payments to Acquire Productive Assets									300,969	290,863	223,271
Northern Tier Energy LP [Member]
Segment Reporting Information [Line Items]
Equity method investment	87,300				82,100				87,300	82,100
Total assets	1,291,300				1,137,300				1,291,300	1,137,300
Revenues	(739,600)	(732,300)	(812,300)	(604,400)	(759,800)	(891,600)	(959,800)	(793,800)	$ (2,888,600)	(3,405,000)	(5,556,000)
Number of Reportable Segments | Segment									2
Operating income	(5,500)	$ 11,600	$ 77,700	$ 21,800	(5,300)	$ 114,600	$ 139,300	$ 119,500	$ 105,600	368,100	275,300
Income from equity method investment									21,900	14,800	2,200
Depreciation and amortization									46,500	44,000	41,900
Payments to Acquire Productive Assets									127,900	71,800	44,800
Refining [Member] | Northern Tier Energy LP [Member]
Segment Reporting Information [Line Items]
Total assets	1,113,800				917,400				1,113,800	917,400
Revenues									(1,857,800)	(2,289,100)	(4,165,600)
Operating income									121,500	374,800	303,500
Income from equity method investment									21,900	14,800	2,200
Depreciation and amortization									37,400	35,400	33,700
Payments to Acquire Productive Assets									120,400	63,800	35,400
Retail [Member] | Northern Tier Energy LP [Member]
Segment Reporting Information [Line Items]
Total assets	$ 137,500				138,700				137,500	138,700
Revenues									$ (1,030,800)	(1,115,900)	(1,390,400)
Number of Stores | Store	285								285
Operating income									$ 10,700	19,200	22,900
Income from equity method investment									0	0	0
Depreciation and amortization									8,300	7,700	7,300
Payments to Acquire Productive Assets									$ 7,300	7,700	8,800
Retail [Member] | Entity Operated Units [Member] | Northern Tier Energy LP [Member]
Segment Reporting Information [Line Items]
Number of Stores | Store	170								170
Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Revenues									$ 0	0	0
Intersegment Eliminations [Member] | Northern Tier Energy LP [Member]
Segment Reporting Information [Line Items]
Revenues									(563,600)	(647,700)	(932,100)
Intersegment Eliminations [Member] | Refining [Member] | Northern Tier Energy LP [Member]
Segment Reporting Information [Line Items]
Revenues									(563,600)	(647,700)	(932,100)
Operating Segments [Member] | Northern Tier Energy LP [Member]
Segment Reporting Information [Line Items]
Revenues									(3,452,200)	(4,052,700)	(6,488,100)
Operating Segments [Member] | Refining [Member] | Northern Tier Energy LP [Member]
Segment Reporting Information [Line Items]
Revenues									(2,421,400)	(2,936,800)	(5,097,700)
Operating Segments [Member] | Retail [Member] | Northern Tier Energy LP [Member]
Segment Reporting Information [Line Items]
Revenues									(1,030,800)	(1,115,900)	(1,390,400)
Corporate, Non-Segment [Member]
Segment Reporting Information [Line Items]
Total assets	$ 279,203				798,671				279,203	798,671	546,659
Revenues									0	0	(1,106)
Operating income									(109,426)	(97,479)	(121,761)
Depreciation and amortization									3,363	4,602	4,048
Payments to Acquire Productive Assets									2,637	3,084	2,461
Corporate, Non-Segment [Member] | Northern Tier Energy LP [Member]
Segment Reporting Information [Line Items]
Total assets	$ 40,000				$ 81,200				40,000	81,200
Operating income									(26,600)	(25,900)	(51,100)
Income from equity method investment									0	0	0
Depreciation and amortization									800	900	900
Payments to Acquire Productive Assets									$ 200	$ 300	600
Operating Income (Loss) [Member] | Northern Tier Energy LP [Member]
Segment Reporting Information [Line Items]
Prior Period Reclassification Adjustment											0
Operating Income (Loss) [Member] | Operating Segments [Member] | Refining [Member] | Northern Tier Energy LP [Member]
Segment Reporting Information [Line Items]
Prior Period Reclassification Adjustment											(7,700)
Operating Income (Loss) [Member] | Operating Segments [Member] | Retail [Member] | Northern Tier Energy LP [Member]
Segment Reporting Information [Line Items]
Prior Period Reclassification Adjustment											(4,400)
Operating Income (Loss) [Member] | Corporate, Non-Segment [Member] | Northern Tier Energy LP [Member]
Segment Reporting Information [Line Items]
Prior Period Reclassification Adjustment											$ 12,100

XML

Fair Value Measurement - Fair Value - Information (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Fair Value Disclosures [Abstract]
Fair Value, Assets, Level 1 to Level 2 Transfers, Amount	$ 0
Cash Equivalents, at Carrying Value	$ 60,000	$ 70,100

XML

Fair Value Measurement - Fair Value - Assets & Liabilities - Recurring Basis (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative Asset	$ 2,059	$ 79,733
Commodity Contract [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative Asset, Fair Value, Gross Asset	2,059	79,733
Commodity Contract [Member] | Fair Value, Measurements, Recurring [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative Asset	2,059	79,733
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset	0	0
Commodity Contract [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative Liability, Fair Value, Gross Liability	0	0
Commodity Contract [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative Asset, Fair Value, Gross Asset	2,059	85,489
Commodity Contract [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative Liability, Fair Value, Gross Liability	0	(5,756)
Commodity Contract [Member] | Other Current Assets [Member] | Fair Value, Measurements, Recurring [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative Asset, Fair Value, Gross Asset	18,929	95,062
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset	5,280	16,937
Derivative Asset	13,649	78,125
Commodity Contract [Member] | Other Current Assets [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative Asset, Fair Value, Gross Asset	0	0
Commodity Contract [Member] | Other Current Assets [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative Asset, Fair Value, Gross Asset	18,929	95,062
Commodity Contract [Member] | Other Current Assets [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative Asset, Fair Value, Gross Asset	0	0
Commodity Contract [Member] | Other Noncurrent Assets [Member] | Fair Value, Measurements, Recurring [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative Asset, Fair Value, Gross Asset	677	11,881
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset	669	0
Derivative Asset	8	11,881
Commodity Contract [Member] | Other Noncurrent Assets [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative Asset, Fair Value, Gross Asset	0	0
Commodity Contract [Member] | Other Noncurrent Assets [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative Asset, Fair Value, Gross Asset	677	11,881
Commodity Contract [Member] | Other Noncurrent Assets [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative Asset, Fair Value, Gross Asset	0	0
Commodity Contract [Member] | Accrued Liabilities [Member] | Fair Value, Measurements, Recurring [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative Liability	(10,827)	(10,273)
Derivative Liability, Fair Value, Gross Liability	(17,547)	(21,454)
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset	6,720	11,181
Commodity Contract [Member] | Accrued Liabilities [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative Liability, Fair Value, Gross Liability	0	0
Commodity Contract [Member] | Accrued Liabilities [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative Liability, Fair Value, Gross Liability	(17,547)	(15,698)
Commodity Contract [Member] | Accrued Liabilities [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative Liability, Fair Value, Gross Liability	0	(5,756)
Commodity Contract [Member] | Other Noncurrent Liabilities [Member] | Fair Value, Measurements, Recurring [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative Liability	(771)	0
Derivative Liability, Fair Value, Gross Liability	0	(5,756)
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset	771	5,756
Commodity Contract [Member] | Other Noncurrent Liabilities [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative Liability, Fair Value, Gross Liability	0	0
Commodity Contract [Member] | Other Noncurrent Liabilities [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative Liability, Fair Value, Gross Liability	0	(5,756)
Commodity Contract [Member] | Other Noncurrent Liabilities [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative Liability, Fair Value, Gross Liability	$ 0	$ 0

XML

Fair Value Measurement - Fair Value - Level 3 Rollforward (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Fair Value, Assets, Level 1 to Level 2 Transfers, Amount	$ 0
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Derivative Asset	79,733
Fair Value, Inputs, Level 3 [Member] | Commodity Contract [Member] | Fair Value, Measurements, Recurring [Member]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Derivative Asset		$ 330
Derivative Liability	(5,756)
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Liability, Gain (Loss) Included in Earnings	0	0
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Liability, Purchases	0	(5,756)
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Transfers, Net	5,756	(330)
Derivative Liability	$ 0	$ (5,756)

XML

Fair Value Measurement - Fair Value - Debt (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt	$ 1,882,305	$ 1,650,394
Western Refining, Inc. [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt	1,256,000	889,000
Northern Tier Energy LP [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt	349,980	350,000
Western Refining Logistics, LP [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt	320,300	445,000
Fair Value, Inputs, Level 2 [Member] | Western Refining, Inc. [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt, Fair Value	1,277,956	867,178
Fair Value, Inputs, Level 2 [Member] | Northern Tier Energy LP [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt, Fair Value	363,542	360,500
Fair Value, Inputs, Level 2 [Member] | Western Refining Logistics, LP [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt, Fair Value	$ 345,050	$ 439,000

XML

Fair Value Measurement - NTI - Fair Value - Assets & Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value of open commodity hedging positions, net	$ 13,649	$ 78,125
Fair value of open commodity hedging positions, net	8	11,881
Northern Tier Energy LP [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash and Cash Equivalents, Fair Value Disclosure	29,500	70,900
Fair value of open commodity hedging positions, net	6,300	1,900
Assets, Fair Value Disclosure, Recurring	35,800	72,800
Derivative Liability, Current	6,000	9,400
Liabilities, Fair Value Disclosure, Recurring	6,000	9,400
Fair Value, Inputs, Level 1 [Member] | Northern Tier Energy LP [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash and Cash Equivalents, Fair Value Disclosure	29,500	70,900
Fair value of open commodity hedging positions, net	0	0
Assets, Fair Value Disclosure, Recurring	29,500	70,900
Derivative Liability, Current	0	0
Liabilities, Fair Value Disclosure, Recurring	0	0
Fair Value, Inputs, Level 2 [Member] | Northern Tier Energy LP [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash and Cash Equivalents, Fair Value Disclosure	0	0
Fair value of open commodity hedging positions, net	6,300	1,900
Assets, Fair Value Disclosure, Recurring	6,300	1,900
Derivative Liability, Current	6,000	9,400
Liabilities, Fair Value Disclosure, Recurring	6,000	9,400
Fair Value, Inputs, Level 3 [Member] | Northern Tier Energy LP [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash and Cash Equivalents, Fair Value Disclosure	0	0
Fair value of open commodity hedging positions, net	0	0
Assets, Fair Value Disclosure, Recurring	0	0
Derivative Liability, Current	0	0
Liabilities, Fair Value Disclosure, Recurring	$ 0	$ 0

XML

Fair Value Measurement - NTI - Fair Value - Information (Details) - Northern Tier Energy LP [Member] - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, Fair Value Adjustment	$ 0	$ 0	$ 0
Fair Value, Measurement with Unobservable Inputs Reconciliation, Liability, Transfers Into Level 3	0	$ 0	$ 0
Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Financial and Nonfinancial Liabilities, Fair Value Disclosure	$ 0

XML

Fair Value Measurement - NTI - Fair Value - Debt (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt, less current portion	$ 1,871,805	$ 1,644,894
Northern Tier Energy LP [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt, less current portion	344,000	342,000
Long-term Line of Credit	0
Senior Secured Notes Due Two Thousand Twenty [Member] | Northern Tier Energy LP [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt, less current portion	350,000	350,000
Notes Payable, Fair Value Disclosure	$ 363,500	$ 360,500

XML

Inventories - Schedule of Inventories (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Inventory Disclosure [Abstract]
Refined products	$ 325,889	$ 201,928
Crude oil and other raw materials	395,131	288,403
Lubricants	10,121	14,996
Convenience store merchandise	40,848	42,211
Inventories	771,989	547,538
FIFO Inventory Amount	$ 50,500	$ 14,500

XML

Inventories - Lower Cost or Market Effect on Income (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Inventory Disclosure [Abstract]
Inventory, Change in Lower of Cost or Market Reserve	$ (133,400)	$ 96,500	$ 78,600
Liquidation of LIFO layers:
Operating income	(2,868)	(16,111)	1,097
Net income	$ (2,218)	$ (11,808)	$ 777
Earnings per diluted share	$ (0.02)	$ (0.12)	$ 0.01

XML

Inventories - LIFO Costs Per Barrel (Details) bbl in Thousands, $ in Thousands	Dec. 31, 2016 USD ($) $ / Barrel bbl	Dec. 31, 2015 USD ($) $ / Barrel bbl
Inventory Disclosure [Abstract]
Refined products, Barrels | bbl	4,259	3,536
Refined products, LIFO Cost | $	$ 303,968	$ 259,722
Refined products, Average LIFO Cost Per Barrel | $ / Barrel	71.37	73.45
Crude Oil and other, Barrels | bbl	6,641	6,490
Crude Oil and other, LIFO Cost | $	$ 394,798	$ 391,237
Crude Oil and other, Average LIFO Cost Per Barrel | $ / Barrel	59.45	60.28
Energy Related Inventory, Barrels | bbl	10,900	10,026
Energy Related Inventory, LIFO Cost | $	$ 698,766	$ 650,959
Energy Related Inventory, Average LIFO Cost Per Barrel | $ / Barrel	64.11	64.93

XML

Inventories - Inventories Information (Details) bbl in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2016 USD ($) bbl	Dec. 31, 2015 USD ($) bbl	Dec. 31, 2014 USD ($)
Inventory Disclosure [Abstract]
Inventory Valued Using LIFO | bbl	10.9	10.0
Excess of Replacement or Current Costs over Stated LIFO Value	$ 140.1	$ 198.4
Inventory, LIFO Reserve, Period Charge	58.3	170.0	$ 222.0
Inventory Adjustments	$ 41.7	$ 175.1

XML

Inventories - NTI Inventories (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Inventory [Line Items]
Inventory, LIFO Reserve, Period Charge	$ (58,300)	$ (170,000)	$ (222,000)
Inventory, Net [Abstract]
Crude oil and other raw materials	395,131	288,403
Convenience store merchandise	40,848	42,211
Inventories	$ 771,989	$ 547,538
Northern Tier Energy LP [Member]
Inventory [Line Items]
Percentage of LIFO Inventory	89.00%	89.00%
Inventory, Net [Abstract]
Crude oil and other raw materials	$ 174,300	$ 171,800
Energy Related Inventory, Crude Oil, Products and Merchandise	160,200	162,000
Convenience store merchandise	22,100	22,800
Inventory, Supplies, Net of Reserves	18,800	19,000
Inventory, Net Before Adjustments	375,400	375,600
Inventory Valuation Reserves	41,700	134,400
Inventories	$ 333,700	$ 241,200

XML

Prepaid Expenses (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]
Prepaid crude oil and other raw materials inventories	$ 49,405	$ 23,793
Prepaid insurance	12,726	5,904
RINs	12,722	21,174
Prepaid income taxes	456	3,099
Other	20,046	19,243
Prepaid expenses	$ 95,355	$ 73,213

XML

Other Current Assets (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]
Material and chemical inventories	$ 49,915	$ 54,053
Excise and other taxes receivable	19,644	21,801
Margin account deposits	14,852	0
Fair value of open commodity hedging positions, net	13,649	78,125
Exchange and other receivables	15,361	15,749
Other current assets	$ 113,421	$ 169,728

XML

Equity Method Investment - Equity Method Investment Information (Details) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Quoted Market Value	$ 13,400,000
Equity method investment	102,685,000	$ 97,513,000
Income (Loss) from Equity Method Investments	$ 0	0	$ 0
Minnesota Pipe Line Company [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	17.00%
Equity Method Investment, Difference Between Carrying Amount and Underlying Equity	$ 21,100,000	21,300,000
Equity Method Investment, Quoted Market Value	0
Equity method investment	102,700,000	97,500,000
Proceeds from Equity Method Investment, Dividends or Distributions	16,300,000	13,100,000	7,500,000
Income (Loss) from Equity Method Investments	$ 21,700,000	$ 14,800,000	$ 2,200,000

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Equity Method Investment - Summarized Financial Information (Details) - Minnesota Pipe Line Company [Member] - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Income Statement [Abstract]
Equity Method Investment, Summarized Financial Information, Revenue	$ 215,564	$ 206,195	$ 184,712
Equity Method Investment, Summarized Financial Information, Cost of Sales	57,444	88,909	141,250
Equity Method Investment, Summarized Financial Information, Gross Profit (Loss)	158,120	117,286	43,462
Equity Method Investment, Summarized Financial Information, Net Income (Loss)	137,476	96,485	22,821
Equity Method Investment, Summarized Financial Information, Net Income (Loss) Available to Common Shareholders	127,823	86,832	$ 13,168
Balance Sheet Related Disclosures [Abstract]
Equity Method Investment, Summarized Financial Information, Current Assets	14,882	24,020
Equity Method Investment, Summarized Financial Information, Noncurrent Assets	491,955	441,825
Equity Method Investment, Summarized Financial Information, Assets	506,837	465,845
Equity Method Investment, Summarized Financial Information, Current Liabilities	26,827	17,658
Equity Method Investment, Summarized Financial Information, Noncurrent Liabilities	0	0
Equity Method Investment, Summarized Financial Information, Liabilities	26,827	17,658
Equity Method Investment Summarized Financial Information, Equity	$ 480,010	$ 448,187

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Equity Method Investment - NTI Equity Method Investment Information (Details) - USD ($)	3 Months Ended	12 Months Ended
	Mar. 31, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Schedule of Equity Method Investments [Line Items]
Equity method investment		$ 102,685,000	$ 97,513,000
Income (Loss) from Equity Method Investments		0	0	$ 0
Equity Method Investment, Quoted Market Value		$ 13,400,000
Minnesota Pipe Line Company [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage		17.00%
Equity Method Investment, Difference Between Carrying Amount and Underlying Equity		$ 21,100,000	21,300,000
Equity method investment		102,700,000	97,500,000
Proceeds from Equity Method Investment, Dividends or Distributions		16,300,000	13,100,000	7,500,000
Income (Loss) from Equity Method Investments		21,700,000	14,800,000	2,200,000
Equity Method Investment, Quoted Market Value		$ 0
Northern Tier Energy LP [Member]
Schedule of Equity Method Investments [Line Items]
Limited Liability Company (LLC) or Limited Partnership (LP), Members or Limited Partners, Ownership Interest	38.30%	100.00%
Equity method investment		$ 87,300,000	82,100,000
Proceeds from Equity Method Investment, Dividends or Distributions		16,600,000	13,100,000
Income (Loss) from Equity Method Investments		$ 21,900,000	14,800,000	2,200,000
Northern Tier Energy LP [Member] | Minnesota Pipe Line Company [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage		17.00%
Equity Method Investment, Difference Between Carrying Amount and Underlying Equity		$ 5,700,000	5,900,000
Proceeds from Equity Method Investment, Dividends or Distributions				7,500,000
Income (Loss) from Equity Method Investments		$ 127,800,000	$ 86,800,000	$ 13,100,000
Northern Tier Energy LP [Member] | St Paul Park Refining Company [Member]
Schedule of Equity Method Investments [Line Items]
Limited Liability Company (LLC) or Limited Partnership (LP), Members or Limited Partners, Ownership Interest		1.00%

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Equity Method Investment - NTI Summarized Financial Information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Schedule of Equity Method Investments [Line Items]
Income (Loss) from Equity Method Investments	$ 0	$ 0	$ 0
Minnesota Pipe Line Company [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Summarized Financial Information, Revenue	215,564	206,195	184,712
Equity Method Investment, Summarized Financial Information, Net Income (Loss)	137,476	96,485	22,821
Income (Loss) from Equity Method Investments	21,700	14,800	2,200
Equity Method Investment, Summarized Financial Information, Current Assets	14,882	24,020
Equity Method Investment, Summarized Financial Information, Noncurrent Assets	491,955	441,825
Equity Method Investment, Summarized Financial Information, Assets	506,837	465,845
Equity Method Investment, Summarized Financial Information, Current Liabilities	26,827	17,658
Equity Method Investment, Summarized Financial Information, Noncurrent Liabilities	0	0
Equity Method Investment, Summarized Financial Information, Liabilities	26,827	17,658
Equity Method Investment Summarized Financial Information, Equity	480,010	448,187
Northern Tier Energy LP [Member]
Schedule of Equity Method Investments [Line Items]
Income (Loss) from Equity Method Investments	21,900	14,800	2,200
Northern Tier Energy LP [Member] | Minnesota Pipe Line Company [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Summarized Financial Information, Revenue	215,600	206,200	184,700
Equity Method Investment Summarized Financial Information Costs And Expenses	57,500	88,900	141,300
Equity Method Investment Summarized Financial Information Operating Income Loss	158,100	117,300	43,400
Equity Method Investment, Summarized Financial Information, Net Income (Loss)	137,500	96,500	22,800
Income (Loss) from Equity Method Investments	127,800	86,800	$ 13,100
Equity Method Investment, Summarized Financial Information, Current Assets	14,800	24,000
Equity Method Investment, Summarized Financial Information, Noncurrent Assets	492,000	441,800
Equity Method Investment, Summarized Financial Information, Assets	506,800	465,800
Equity Method Investment, Summarized Financial Information, Current Liabilities	26,800	17,700
Equity Method Investment, Summarized Financial Information, Noncurrent Liabilities	0	0
Equity Method Investment, Summarized Financial Information, Liabilities	26,800	17,700
Equity Method Investment Summarized Financial Information, Equity	$ 480,000	$ 448,100

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Property, Plant and Equipment, Net (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross, Excluding Construction in Progress	$ 3,259,866	$ 2,976,672
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment	(1,118,477)	(923,415)
Property, plant and equipment, net, excluding construction in progress	2,141,389	2,053,257
Property, plant and equipment, net	2,364,482	2,305,171
Depreciation	213,500	201,200	$ 187,100
Refining Equipment [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	2,260,351	2,113,650
Pipelines [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	560,478	427,854
Retail Site [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	333,187	324,686
Gas, Transmission and Distribution Equipment [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	52,284	59,875
Corporate and Other [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	53,566	50,607
Construction in Progress [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	$ 223,093	$ 251,914

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Property, Plant and Equipment, Net (NTI) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Property, Plant and Equipment [Line Items]
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment	$ 1,118,477	$ 923,415
Property, plant and equipment, net	2,364,482	2,305,171
Northern Tier Energy LP [Member]
Property, Plant and Equipment [Line Items]
Capital Leased Assets, Gross	10,800	13,300
Property, Plant and Equipment, Gross	715,800	668,600
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment	198,000	180,800
Property, plant and equipment, net	517,800	487,800
Capital Leases, Lessee Balance Sheet, Assets by Major Class, Accumulated Depreciation	2,300	2,000
Interest Costs Capitalized	6,400	1,400	$ 0
Capitalized Software [Member] | Northern Tier Energy LP [Member]
Property, Plant and Equipment [Line Items]
Other Depreciation and Amortization	2,900	3,700	$ 3,700
Land [Member] | Northern Tier Energy LP [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	7,700	9,000
Retail Site [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	333,187	324,686
Retail Site [Member] | Northern Tier Energy LP [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	80,500	72,300
Refining Equipment [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	2,260,351	2,113,650
Refining Equipment [Member] | Northern Tier Energy LP [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	$ 487,000	457,200
Building and Building Improvements [Member] | Northern Tier Energy LP [Member]
Property, Plant and Equipment [Line Items]
Estimated Useful Life	25 years
Property, Plant and Equipment, Gross	$ 18,700	11,700
Computer Software, Intangible Asset [Member] | Northern Tier Energy LP [Member]
Property, Plant and Equipment [Line Items]
Estimated Useful Life	5 years
Property, Plant and Equipment, Gross	$ 18,900	18,900
Vehicles [Member] | Northern Tier Energy LP [Member]
Property, Plant and Equipment [Line Items]
Estimated Useful Life	5 years
Property, Plant and Equipment, Gross	$ 3,200	5,600
Other Capitalized Property Plant and Equipment [Member] | Northern Tier Energy LP [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	10,800	10,400
Precious Metals [Member] | Northern Tier Energy LP [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	10,400	10,200
Asset under Construction [Member] | Northern Tier Energy LP [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	$ 78,600	$ 73,300
Minimum [Member] | Retail Site [Member]
Property, Plant and Equipment [Line Items]
Estimated Useful Life	3 years
Minimum [Member] | Retail Site [Member] | Northern Tier Energy LP [Member]
Property, Plant and Equipment [Line Items]
Estimated Useful Life	2 years
Minimum [Member] | Refining Equipment [Member]
Property, Plant and Equipment [Line Items]
Estimated Useful Life	3 years
Minimum [Member] | Refining Equipment [Member] | Northern Tier Energy LP [Member]
Property, Plant and Equipment [Line Items]
Estimated Useful Life	5 years
Minimum [Member] | Other Capitalized Property Plant and Equipment [Member]
Property, Plant and Equipment [Line Items]
Estimated Useful Life	3 years
Minimum [Member] | Other Capitalized Property Plant and Equipment [Member] | Northern Tier Energy LP [Member]
Property, Plant and Equipment [Line Items]
Estimated Useful Life	2 years
Maximum [Member] | Retail Site [Member]
Property, Plant and Equipment [Line Items]
Estimated Useful Life	30 years
Maximum [Member] | Retail Site [Member] | Northern Tier Energy LP [Member]
Property, Plant and Equipment [Line Items]
Estimated Useful Life	22 years
Maximum [Member] | Refining Equipment [Member]
Property, Plant and Equipment [Line Items]
Estimated Useful Life	25 years
Maximum [Member] | Refining Equipment [Member] | Northern Tier Energy LP [Member]
Property, Plant and Equipment [Line Items]
Estimated Useful Life	24 years
Maximum [Member] | Other Capitalized Property Plant and Equipment [Member]
Property, Plant and Equipment [Line Items]
Estimated Useful Life	10 years
Maximum [Member] | Other Capitalized Property Plant and Equipment [Member] | Northern Tier Energy LP [Member]
Property, Plant and Equipment [Line Items]
Estimated Useful Life	7 years

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Goodwill (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Goodwill and Intangible Assets Disclosure [Abstract]
Goodwill	$ 1,289,443	$ 1,289,443

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Intangible Assets, Net - Intangible Assets, Net (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Finite-Lived Intangible Assets [Line Items]
Gross Carrying Value	$ 36,137	$ 34,817
Accumulated Amortization	(22,783)	(19,447)
Net Carrying Value	13,354	15,370
Intangible Assets, Gross (Excluding Goodwill)	106,595	104,392
Intangible assets, net	83,812	84,945
Licensing and permits [Member]
Finite-Lived Intangible Assets [Line Items]
Gross Carrying Value	20,427	20,427
Accumulated Amortization	(15,307)	(13,729)
Net Carrying Value	$ 5,120	6,698
Weighted Average Amortization Period (Years)	3 years 3 months 4 days
Customer relationships [Member]
Finite-Lived Intangible Assets [Line Items]
Gross Carrying Value	$ 7,172	7,551
Accumulated Amortization	(4,234)	(3,921)
Net Carrying Value	$ 2,938	3,630
Weighted Average Amortization Period (Years)	5 years 6 months 11 days
Other Intangible Assets [Member]
Finite-Lived Intangible Assets [Line Items]
Gross Carrying Value	$ 8,538	6,839
Accumulated Amortization	(3,242)	(1,797)
Net Carrying Value	$ 5,296	$ 5,042
Weighted Average Amortization Period (Years)	4 years 11 months 20 days

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Intangible Assets, Net - Indefinite-Lived Intangible Assets (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Franchise Rights and Trademarks [Member]
Indefinite-lived Intangible Assets [Line Items]
Indefinite-Lived Intangible Assets (Excluding Goodwill)	$ 50,500	$ 50,500
Liquor Licenses [Member]
Indefinite-lived Intangible Assets [Line Items]
Indefinite-Lived Intangible Assets (Excluding Goodwill)	$ 19,958	$ 19,075

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Intangible Assets, Net - Amortization Expense (Details) $ in Thousands	Dec. 31, 2016 USD ($)
Finite-Lived Intangible Assets, Future Amortization Expense [Abstract]
2016	$ 2,880
2017	2,880
2018	2,212
2019	1,268
2020	$ 980

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Intangible Assets, Net - Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Finite-Lived Intangible Assets [Line Items]
Amortization of Intangible Assets	$ 3.0	$ 2.9	$ 2.8
Minimum [Member]
Finite-Lived Intangible Assets [Line Items]
Weighted Average Amortization Period (Years)	1 year
Maximum [Member]
Finite-Lived Intangible Assets [Line Items]
Weighted Average Amortization Period (Years)	35 years

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Intangible Assets, Net - NTI Intangibles (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Indefinite-lived Intangible Assets [Line Items]
Intangible assets, net	$ 83,812	$ 84,945
Indefinite-Lived Franchise Rights	12,400
Northern Tier Energy LP [Member]
Indefinite-lived Intangible Assets [Line Items]
Intangible assets, net	33,800	33,800
Indefinite-Lived Franchise Rights		12,400
Indefinite-Lived Trademarks	$ 21,400	$ 21,400

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Other Assets (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]
Capital spare parts	$ 12,717	$ 8,112
Purchase agreement	9,762	16,067
Cost method investment	7,864	7,872
Notes receivable	4,366	4,586
Deposits	3,582	3,747
Fair value of open commodity hedging positions, net	8	11,881
Other	9,159	12,732
Other assets	$ 47,458	$ 64,997

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Accrued and Other Long-Term Liabilities (Accrued Liabilities) (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Payables and Accruals [Abstract]
Excise and other taxes	$ 68,116	$ 67,932
Payroll and related costs	66,021	77,482
Professional and other	24,146	28,093
Property taxes	23,387	20,175
Interest	17,248	17,093
Fair value of open commodity hedging positions, net	10,827	10,273
Environmental reserves	6,945	10,099
Banking fees and other financing	2,718	189
Income taxes	199	0
Margin and other customer deposits	0	17,059
Accrued liabilities	$ 219,607	$ 248,395

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Accrued and Other Long-Term Liabilities (Other Long-Term Liabilities) (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Payables and Accruals [Abstract]
Unrecognized tax benefits	$ 58,317	$ 42,049
Defined Benefit Pension Plan, Liabilities, Noncurrent	18,725	10,529
Accrued Environmental Loss Contingencies, Noncurrent	6,839	8,195
Asset Retirement Obligations, Noncurrent	8,484	7,822
Hedging Liabilities, Noncurrent	771	0
Other Accrued Liabilities, Noncurrent	$ 93,136	$ 68,595

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Accrued and Other Long-Term Liabilities (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2016 USD ($)
Loss Contingencies [Line Items]
Accrual for Environmental Loss Contingencies	$ 18,294
Other Increase (Decrease) in Environmental Liabilities	926
Accrual for Environmental Loss Contingencies, Payments	(5,436)
Accrual for Environmental Loss Contingencies	13,784
Discounted [Member]
Loss Contingencies [Line Items]
Accrual for Environmental Loss Contingencies	3,633
Other Increase (Decrease) in Environmental Liabilities	300
Accrual for Environmental Loss Contingencies, Payments	(433)
Accrual for Environmental Loss Contingencies	3,500
Undiscounted [Member]
Loss Contingencies [Line Items]
Accrual for Environmental Loss Contingencies	14,661
Other Increase (Decrease) in Environmental Liabilities	626
Accrual for Environmental Loss Contingencies, Payments	(5,003)
Accrual for Environmental Loss Contingencies	$ 10,284

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Asset Retirement Obligations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Liability, beginning of period	$ 7,822	$ 7,539	$ 7,327
Liabilities incurred	566	58	17
Liabilities acquired	0	0	0
Liabilities settled	(479)	(187)	(313)
Accretion expense	575	412	508
Liability, end of period	8,484	7,822	$ 7,539
Asset Retirement Obligation, Current	$ 200	$ 200

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Asset Retirement Obligations (NTI) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Liability, beginning of period	$ 7,822	$ 7,539	$ 7,327
Accretion expense	575	412	508
Liability, end of period	8,484	7,822	7,539
Northern Tier Energy LP [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Liability, beginning of period	2,400	2,400	2,200
Costs Incurred, Asset Retirement Obligation Incurred	(200)	(300)	0
Accretion expense	200	300	200
Liability, end of period	$ 2,400	$ 2,400	$ 2,400

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Long-Term Debt - Long-Term Debt Summary (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Jun. 30, 2016	Dec. 31, 2015
Debt Instrument [Line Items]
Long-term Debt, Maturities, Repayments of Principal in Next Twelve Months	$ 10,500
Long-term Debt, Maturities, Repayments of Principal in Next Twelve Months	355,000
Long-term Debt	1,882,305		$ 1,650,394
Debt Instrument, Unamortized Discount (Premium), Net	43,975		33,606
Long-term Debt, Maturities, Repayments of Principal in Year Four	872,000
Current portion of long-term debt	10,500		5,500
Long-term debt, less current portion	1,871,805		1,644,894
Long-term Debt, Maturities, Repayments of Principal after Year Five	647,500
Western Refining, Inc. [Member]
Debt Instrument [Line Items]
Long-term Debt	1,256,000		889,000
Western Refining Logistics, LP [Member]
Debt Instrument [Line Items]
Long-term Debt	320,300		445,000
Northern Tier Energy LP [Member]
Debt Instrument [Line Items]
Long-term Debt	349,980		350,000
Long-term debt, less current portion	344,000		342,000
Revolving Credit Facility [Member] | NTI Senior Secured Asset-Based Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Long-term Debt	0		0
Revolving Credit Facility [Member] | Western Refining, Inc. [Member] | Revolving Credit Agreement [Member]
Debt Instrument [Line Items]
Long-term Debt	0		0
Revolving Credit Facility [Member] | Western Refining Logistics, LP [Member] | Revolving Credit Agreement - WNRL [Member]
Debt Instrument [Line Items]
Long-term Debt	20,300		145,000
Line of Credit [Member] | Term Loan, due 2020 [Member]
Debt Instrument [Line Items]
Debt Instrument, Unused Borrowing Capacity, Amount		$ 500,000
Line of Credit [Member] | Western Refining, Inc. [Member] | Term Loan, due 2020 [Member]
Debt Instrument [Line Items]
Long-term Debt	533,500		539,000
Line of Credit [Member] | Western Refining, Inc. [Member] | Term Loan, due 2023 [Member]
Debt Instrument [Line Items]
Long-term Debt	372,500		0
Senior Notes [Member] | Western Refining, Inc. [Member] | 6.25% Senior Notes due 2021 [Member]
Debt Instrument [Line Items]
Long-term Debt	350,000		350,000
Senior Notes [Member] | Western Refining Logistics, LP [Member] | 7.5% WNRL Secured Notes, due 2023 [Member]
Debt Instrument [Line Items]
Long-term Debt	300,000		300,000
Senior Notes [Member] | Northern Tier Energy LP [Member] | 7.125% NTI Secured Notes, due 2020 [Member]
Debt Instrument [Line Items]
Long-term Debt	$ 349,980		$ 350,000

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Long-Term Debt - Interest Expense and Other Financing Costs (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Debt Instrument [Line Items]
Interest Expense, Debt, Excluding Amortization									$ 111,680	$ 90,801	$ 72,552
Amortization of Financing Costs									9,125	7,561	7,786
Amortization of Debt Discount (Premium)									790	0	7,352
Interest Income (Expense), Net									12,377	9,059	11,717
Interest Expense, Construction in Progress, Contra									10,681	1,818	2,345
Interest Expense	$ 35,226	$ 34,456	$ 26,928	$ 26,681	$ 26,434	$ 26,896	$ 27,316	$ 24,957	123,291	105,603	97,062
Western Refining, Inc. [Member]
Debt Instrument [Line Items]
Interest Expense, Debt, Excluding Amortization									62,893	45,248	51,114
Northern Tier Energy LP [Member]
Debt Instrument [Line Items]
Interest Expense, Debt, Excluding Amortization									24,462	24,474	20,342
Interest Expense									24,800	28,700	26,600
Western Refining Logistics, LP [Member]
Debt Instrument [Line Items]
Interest Expense, Debt, Excluding Amortization									$ 24,325	$ 21,079	$ 1,096

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Long-Term Debt - Debt Instruments (Details)				2 Months Ended	3 Months Ended						6 Months Ended	9 Months Ended	12 Months Ended
	Sep. 29, 2014 USD ($)	Jun. 17, 2014 USD ($) shares	Oct. 15, 2013	Jun. 02, 2014 USD ($) shares	Dec. 31, 2016 USD ($)	Sep. 30, 2016 USD ($)	Jun. 30, 2016 USD ($)	Dec. 31, 2015 USD ($)	Dec. 31, 2014	Dec. 31, 2013 USD ($)	Jun. 30, 2014 shares	Sep. 30, 2014 USD ($)	Dec. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)	Sep. 15, 2016 USD ($)	Jun. 23, 2016 USD ($)	May 27, 2016 USD ($)	Oct. 30, 2015 USD ($)	Feb. 11, 2015 USD ($)	Oct. 15, 2014 USD ($)	Oct. 02, 2014 USD ($)	Sep. 25, 2014 USD ($)	Nov. 13, 2013 USD ($)	Oct. 16, 2013 USD ($)	Mar. 25, 2013 USD ($)	Nov. 08, 2012 USD ($)	Jul. 17, 2012 USD ($)	Jul. 31, 2009 USD ($)	Jun. 12, 2009
Debt Instrument [Line Items]
Long-term Debt					$ 1,882,305,000			$ 1,650,394,000					$ 1,882,305,000	$ 1,650,394,000
Long-term Debt, Maturities, Repayments of Principal in Year Two					30,800,000								30,800,000
Long-term Debt, Maturities, Repayments of Principal in Year Three					10,500,000								10,500,000
Long-term Debt, Maturities, Repayments of Principal in Next Twelve Months					10,500,000								10,500,000
Long-term Debt, Maturities, Repayments of Principal in Next Twelve Months					355,000,000								355,000,000
Repayments of Long-term Debt													135,392,000	7,368,000	$ 6,072,000
Payments of Financing Costs													12,727,000	6,820,000	9,649,000
Borrowings on revolving credit facility													466,900,000	145,000,000	269,000,000
Additions to long-term debt													500,000,000	300,000,000	79,311,000
Long-term Debt, Maturities, Repayments of Principal in Year Four					872,000,000								872,000,000
Long-term Debt, Maturities, Repayments of Principal after Year Five					647,500,000								647,500,000
Senior Convertible Notes [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount																													$ 215,500,000
Revolving Credit Facility [Member] | Revolving Credit Agreement [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Current Borrowing Capacity																						$ 900,000,000
Line of Credit Facility, Maximum Borrowing Capacity																						$ 1,400,000,000
Long-term Line of Credit					0								0
Line of Credit Facility, Remaining Borrowing Capacity					266,600,000								266,600,000
Revolving Credit Facility [Member] | Revolving Credit Agreement [Member] | London Interbank Offered Rate (LIBOR) [Member]
Debt Instrument [Line Items]
Debt Instrument, Description of Variable Rate Basis									LIBOR
Revolving Credit Facility [Member] | NTI Senior Secured Asset-Based Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Long-term Debt					0			0					0	0
Letters of Credit Outstanding, Amount					70,600,000								70,600,000
Line of Credit Facility, Current Borrowing Capacity	$ 500,000,000																											$ 300,000,000
Long-term Line of Credit								$ 0						0
Line of Credit Facility, Remaining Borrowing Capacity					$ 214,900,000								$ 214,900,000
Revolving Credit Facility [Member] | Revolving Credit Agreement - WNRL [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage					4.75%								4.75%
Debt Instrument, Interest Rate, Effective Percentage					3.77%								3.77%
Line of Credit Facility, Current Borrowing Capacity																$ 500,000,000									$ 300,000,000
Line of Credit Facility, Difference Between Current Borrowing Capacity and Maximum Borrowing Capacity																150,000,000
Line of Credit Facility, Maximum Borrowing Capacity																$ 650,000,000
Long-term Line of Credit																			$ 145,000,000		$ 269,000,000
Repayments of Long-term Lines of Credit													$ 179,100,000
Borrowings on revolving credit facility						$ 20,300,000
Letter of Credit [Member] | Revolving Credit Agreement [Member]
Debt Instrument [Line Items]
Letters of Credit Outstanding, Amount					$ 92,900,000								$ 92,900,000
Letter of Credit [Member] | NTI Senior Secured Asset-Based Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	500,000,000
Loans [Member] | NTI Senior Secured Asset-Based Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	45,000,000
Line of Credit [Member] | Term Loan, due 2020 [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount																								$ 550,000,000
Debt Instrument, Periodic Payment, Principal										$ 1,400,000
Debt Instrument, Interest Rate, Stated Percentage																								5.25%
Debt Instrument, Interest Rate, Effective Percentage					5.80%								5.80%
Line of Credit Facility, Maximum Borrowing Capacity																		$ 700,000,000						$ 200,000,000
Line of Credit [Member] | Term Loan, due 2020 [Member] | Base Rate [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate										2.25%
Line of Credit [Member] | Term Loan, due 2020 [Member] | London Interbank Offered Rate (LIBOR) [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate										4.25%
Line of Credit [Member] | Term Loan, due 2023 [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount																	$ 500,000,000
Debt Instrument, Unamortized Discount (Premium) and Debt Issuance Costs, Net																	$ 17,000,000
Debt Instrument, Periodic Payment, Principal							$ 1,300,000
Debt Instrument, Interest Rate, Stated Percentage																	5.50%
Repayments of Long-term Debt					$ 125,000,000
Debt Instrument, Interest Rate, Effective Percentage					6.30%								6.30%
Line of Credit [Member] | Term Loan, due 2023 [Member] | Base Rate [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate							3.50%
Line of Credit [Member] | Term Loan, due 2023 [Member] | London Interbank Offered Rate (LIBOR) [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate							4.50%
Senior Notes [Member] | 7.5% WNRL Secured Notes, due 2023 [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount																				$ 300,000,000
Debt Instrument, Interest Rate, Stated Percentage																				7.50%
Debt Instrument, Interest Rate, Effective Percentage					7.78%								7.78%
Senior Notes [Member] | 6.25% Senior Notes due 2021 [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount																										$ 350,000,000
Debt Instrument, Interest Rate, Stated Percentage																										6.25%				6.25%
Debt Instrument, Interest Rate, Effective Percentage					6.52%								6.52%
Debt Instrument, Collateral Amount																										$ 150,000,000
Senior Notes [Member] | 7.125% NTI Secured Notes, due 2020 [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount																											$ 275,000,000
Debt Instrument, Interest Rate, Stated Percentage																											7.125%
Debt Instrument, Unamortized Premium																							$ 4,200,000
Additions to long-term debt												$ 79,200,000
Convertible Debt Securities [Member] | Senior Convertible Notes [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage																													5.75%
Stock Issued During Period, Shares, Treasury Stock Reissued | shares		22,750,088		0							22,759,243
Convertible debt redemption		$ 214,881,000		$ 87,000
Debt Instrument, Convertible, Conversion Ratio		105.8731
Minimum [Member] | Revolving Credit Facility [Member] | Revolving Credit Agreement [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage								0.25%
Line of Credit Facility, Commitment Fee Percentage								1.50%
Minimum [Member] | Revolving Credit Facility [Member] | Revolving Credit Agreement [Member] | Base Rate [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage																						0.50%
Minimum [Member] | Revolving Credit Facility [Member] | Revolving Credit Agreement [Member] | London Interbank Offered Rate (LIBOR) [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate								1.50%
Minimum [Member] | Revolving Credit Facility [Member] | Revolving Credit Agreement - WNRL [Member]
Debt Instrument [Line Items]
Ratio of Indebtedness to Net Capital																4.50
Minimum [Member] | Revolving Credit Facility [Member] | Revolving Credit Agreement - WNRL [Member] | Base Rate [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate			0.75%
Minimum [Member] | Revolving Credit Facility [Member] | Revolving Credit Agreement - WNRL [Member] | London Interbank Offered Rate (LIBOR) [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate			1.75%
Minimum [Member] | Line of Credit [Member] | Term Loan, due 2023 [Member] | London Interbank Offered Rate (LIBOR) [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage																	1.00%
Minimum [Member] | Convertible Debt Securities [Member] | Senior Convertible Notes [Member]
Debt Instrument [Line Items]
Debt Instrument, Convertible, Conversion Ratio				105.2394
Maximum [Member] | Revolving Credit Facility [Member] | Revolving Credit Agreement [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage								0.375%
Line of Credit Facility, Commitment Fee Percentage								2.00%
Maximum [Member] | Revolving Credit Facility [Member] | Revolving Credit Agreement [Member] | Base Rate [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage																						1.00%
Maximum [Member] | Revolving Credit Facility [Member] | Revolving Credit Agreement [Member] | London Interbank Offered Rate (LIBOR) [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate								2.00%
Maximum [Member] | Revolving Credit Facility [Member] | Revolving Credit Agreement - WNRL [Member]
Debt Instrument [Line Items]
Ratio of Indebtedness to Net Capital																5.00
Maximum [Member] | Revolving Credit Facility [Member] | Revolving Credit Agreement - WNRL [Member] | Base Rate [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate			1.75%
Maximum [Member] | Revolving Credit Facility [Member] | Revolving Credit Agreement - WNRL [Member] | London Interbank Offered Rate (LIBOR) [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate			2.75%
Maximum [Member] | Convertible Debt Securities [Member] | Senior Convertible Notes [Member]
Debt Instrument [Line Items]
Debt Instrument, Convertible, Conversion Ratio				105.8731
Revolving Credit Agreement - WNRL [Member] | Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Letters of Credit Outstanding, Amount					$ 700,000								$ 700,000
Long-term Line of Credit					20,300,000								20,300,000
Line of Credit Facility, Remaining Borrowing Capacity					479,000,000								479,000,000
Loans [Member] | Revolving Credit Facility [Member] | Revolving Credit Agreement - WNRL [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity																									10,000,000
Standby Letters of Credit [Member] | Revolving Credit Facility [Member] | Revolving Credit Agreement - WNRL [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity																									$ 25,000,000
Western Refining, Inc. [Member]
Debt Instrument [Line Items]
Long-term Debt					1,256,000,000			$ 889,000,000					1,256,000,000	889,000,000
Western Refining, Inc. [Member] | Revolving Credit Facility [Member] | Revolving Credit Agreement [Member]
Debt Instrument [Line Items]
Long-term Debt					0			0					0	0
Western Refining, Inc. [Member] | Line of Credit [Member] | Term Loan, due 2020 [Member]
Debt Instrument [Line Items]
Long-term Debt					533,500,000			539,000,000					533,500,000	539,000,000
Western Refining, Inc. [Member] | Line of Credit [Member] | Term Loan, due 2023 [Member]
Debt Instrument [Line Items]
Long-term Debt					372,500,000			0					372,500,000	0
Western Refining, Inc. [Member] | Senior Notes [Member] | 6.25% Senior Notes due 2021 [Member]
Debt Instrument [Line Items]
Long-term Debt					350,000,000			350,000,000					350,000,000	350,000,000
Northern Tier Energy LP [Member]
Debt Instrument [Line Items]
Long-term Debt					349,980,000			350,000,000					349,980,000	350,000,000
Letters of Credit Outstanding, Amount					70,600,000								70,600,000
Debt Instrument, Face Amount								350,000,000						350,000,000
Line of Credit Facility, Maximum Borrowing Capacity					285,500,000								285,500,000
Payments of Financing Costs													0	0	5,400,000
Long-term Line of Credit					0								0
Borrowings on revolving credit facility													412,500,000	0	$ 30,000,000
Line of Credit Facility, Remaining Borrowing Capacity					214,900,000								214,900,000
Northern Tier Energy LP [Member] | Revolving Credit Facility [Member] | NTI Senior Secured Asset-Based Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	$ 750,000,000
Northern Tier Energy LP [Member] | Revolving Credit Facility [Member] | NTI Senior Secured Asset-Based Revolving Credit Facility [Member] | London Interbank Offered Rate (LIBOR) [Member]
Debt Instrument [Line Items]
Debt Instrument, Description of Variable Rate Basis	LIBOR
Northern Tier Energy LP [Member] | Senior Notes [Member] | 7.125% NTI Secured Notes, due 2020 [Member]
Debt Instrument [Line Items]
Long-term Debt					$ 349,980,000			350,000,000					349,980,000	350,000,000
Debt Instrument, Face Amount																							75,000,000
Debt Instrument, Interest Rate, Stated Percentage																											7.125%			7.125%
Repayments of Long-term Debt													$ 20,000
Debt Instrument, Interest Rate, Effective Percentage					6.91%								6.91%
Payments of Financing Costs												$ 2,500,000
Debt Instrument, Unamortized Premium																							$ 4,200,000
Northern Tier Energy LP [Member] | Minimum [Member] | Revolving Credit Facility [Member] | NTI Senior Secured Asset-Based Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage	1.50%
Line of Credit Facility, Commitment Fee Percentage	0.25%
Northern Tier Energy LP [Member] | Minimum [Member] | Revolving Credit Facility [Member] | NTI Senior Secured Asset-Based Revolving Credit Facility [Member] | Base Rate [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate	0.50%
Northern Tier Energy LP [Member] | Minimum [Member] | Revolving Credit Facility [Member] | NTI Senior Secured Asset-Based Revolving Credit Facility [Member] | London Interbank Offered Rate (LIBOR) [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate	1.50%
Northern Tier Energy LP [Member] | Maximum [Member] | Revolving Credit Facility [Member] | NTI Senior Secured Asset-Based Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage	2.00%
Line of Credit Facility, Commitment Fee Percentage	0.375%
Northern Tier Energy LP [Member] | Maximum [Member] | Revolving Credit Facility [Member] | NTI Senior Secured Asset-Based Revolving Credit Facility [Member] | Base Rate [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate	1.00%
Northern Tier Energy LP [Member] | Maximum [Member] | Revolving Credit Facility [Member] | NTI Senior Secured Asset-Based Revolving Credit Facility [Member] | London Interbank Offered Rate (LIBOR) [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate	2.00%
Western Refining Logistics, LP [Member]
Debt Instrument [Line Items]
Long-term Debt					$ 320,300,000			445,000,000					$ 320,300,000	445,000,000
Western Refining Logistics, LP [Member] | Revolving Credit Facility [Member] | Revolving Credit Agreement - WNRL [Member]
Debt Instrument [Line Items]
Long-term Debt					20,300,000			145,000,000					20,300,000	145,000,000
Western Refining Logistics, LP [Member] | Senior Notes [Member] | 7.5% WNRL Secured Notes, due 2023 [Member]
Debt Instrument [Line Items]
Long-term Debt					300,000,000			300,000,000					300,000,000	300,000,000
Fair Value, Inputs, Level 2 [Member] | Western Refining, Inc. [Member]
Debt Instrument [Line Items]
Long-term Debt, Fair Value					1,277,956,000			867,178,000					1,277,956,000	867,178,000
Fair Value, Inputs, Level 2 [Member] | Northern Tier Energy LP [Member]
Debt Instrument [Line Items]
Long-term Debt, Fair Value					363,542,000			360,500,000					363,542,000	360,500,000
Fair Value, Inputs, Level 2 [Member] | Western Refining Logistics, LP [Member]
Debt Instrument [Line Items]
Long-term Debt, Fair Value					$ 345,050,000			$ 439,000,000					$ 345,050,000	$ 439,000,000

XML

Long-Term Debt - NTI (Details) - USD ($) $ in Thousands			9 Months Ended	12 Months Ended
	Sep. 29, 2014	Sep. 27, 2014	Sep. 30, 2014	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Sep. 25, 2014	Nov. 08, 2012	Jun. 12, 2009
Debt Instrument [Line Items]
Long-term Debt				$ 1,882,305	$ 1,650,394
Payments of Financing Costs				12,727	6,820	$ 9,649
Repayments of Long-term Debt				135,392	7,368	6,072
Senior Notes [Member] | 7.125% NTI Secured Notes, due 2020 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage								7.125%
Debt Instrument, Face Amount								$ 275,000
Debt Instrument, Unamortized Premium							$ 4,200
Revolving Credit Facility [Member] | NTI Senior Secured Asset-Based Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Remaining Borrowing Capacity				214,900
Long-term Line of Credit					0
Letters of Credit Outstanding, Amount				70,600
Long-term Debt				0	0
Northern Tier Energy LP [Member]
Debt Instrument [Line Items]
Revolving Credit Facility Commitment Amount	$ 500,000	$ 500,000
Line of Credit Facility, Maximum Borrowing Capacity				285,500
Line of Credit Facility, Remaining Borrowing Capacity				214,900
Long-term Line of Credit				0
Letters of Credit Outstanding, Amount				70,600
Long-term Debt				349,980	350,000
Debt Instrument, Face Amount					350,000
premium percentage	105.75%
Proceeds from Issuance of Senior Long-term Debt				0	0	79,200
Payments of Financing Costs				0	0	$ 5,400
Northern Tier Energy LP [Member] | Senior Secured Notes Due Two Thousand Twenty [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage								7.125%
Northern Tier Energy LP [Member] | Senior Notes [Member] | 7.125% NTI Secured Notes, due 2020 [Member]
Debt Instrument [Line Items]
Long-term Debt				349,980	$ 350,000
Debt Instrument, Interest Rate, Stated Percentage								7.125%	7.125%
Debt Instrument, Face Amount							75,000
Debt Instrument, Unamortized Premium							$ 4,200
Payments of Financing Costs			$ 2,500
Repayments of Long-term Debt				$ 20
Northern Tier Energy LP [Member] | Asset-based credit facility [Member]
Debt Instrument [Line Items]
Payments of Debt Issuance Costs	$ 3,000
Northern Tier Energy LP [Member] | Revolving Credit Facility [Member] | NTI Senior Secured Asset-Based Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	$ 750,000
Northern Tier Energy LP [Member] | Revolving Credit Facility [Member] | NTI Senior Secured Asset-Based Revolving Credit Facility [Member] | Minimum [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Commitment Fee Percentage	0.25%
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage	1.50%
Northern Tier Energy LP [Member] | Revolving Credit Facility [Member] | NTI Senior Secured Asset-Based Revolving Credit Facility [Member] | Maximum [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Commitment Fee Percentage	0.375%
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage	2.00%
Northern Tier Energy LP [Member] | Revolving Credit Facility [Member] | NTI Senior Secured Asset-Based Revolving Credit Facility [Member] | Base Rate [Member] | Minimum [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate	0.50%
Northern Tier Energy LP [Member] | Revolving Credit Facility [Member] | NTI Senior Secured Asset-Based Revolving Credit Facility [Member] | Base Rate [Member] | Maximum [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate	1.00%
Northern Tier Energy LP [Member] | Revolving Credit Facility [Member] | NTI Senior Secured Asset-Based Revolving Credit Facility [Member] | London Interbank Offered Rate (LIBOR) [Member]
Debt Instrument [Line Items]
Debt Instrument, Description of Variable Rate Basis	LIBOR
Northern Tier Energy LP [Member] | Revolving Credit Facility [Member] | NTI Senior Secured Asset-Based Revolving Credit Facility [Member] | London Interbank Offered Rate (LIBOR) [Member] | Minimum [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate	1.50%
Northern Tier Energy LP [Member] | Revolving Credit Facility [Member] | NTI Senior Secured Asset-Based Revolving Credit Facility [Member] | London Interbank Offered Rate (LIBOR) [Member] | Maximum [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate	2.00%
Revolving Credit Facility [Member] | Northern Tier Energy LP [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Expiration Date				Sep. 29, 2019

XML

Income Taxes - Income Tax Expense (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Federal									$ 63,421	$ 228,457	$ 187,320
State									7,231	30,222	32,581
Total current									70,652	258,679	219,901
Federal									(7,262)	(27,876)	63,182
State									(8,522)	(6,848)	9,521
Total deferred									(15,784)	(34,724)	72,703
Provision for income taxes	$ 13,613	$ (11,700)	$ (38,152)	$ (18,629)	$ 6,034	$ (92,117)	$ (78,435)	$ (59,437)	$ (54,868)	$ (223,955)	$ (292,604)

XML

Income Taxes - Tax Rate Reconciliation (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Taxes at the federal statutory rate									$ 84,656	$ 293,435	$ 350,937
State income taxes, net of federal tax benefit (1)									3,601	13,637	31,477
Valuation allowance for state net operating losses									(3,848)	0	(2,887)
Domestic Activity Production deduction									(2,843)	(14,000)	(11,900)
Non-controlling interests									(21,723)	(70,214)	(50,044)
Federal tax credit for production of ultra low sulfur diesel									0	0	(15,486)
UTP releases									(10,823)	(1,138)	(2,266)
Federal tax credit for increasing research activities									(3,780)	1,176	(2,256)
Impact of allocating deferred taxes associated with investment in NTI									8,132	0	0
Other, net									1,496	1,059	(4,971)
Income Tax Expense (Benefit)	$ (13,613)	$ 11,700	$ 38,152	$ 18,629	$ (6,034)	$ 92,117	$ 78,435	$ 59,437	$ 54,868	$ 223,955	$ 292,604

XML

Income Taxes - Reconciliation of Unrecognized Tax Benefits (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Unrecognized Tax Benefits	$ 40,174	$ 13,762	$ 10,571
Increases (decreases) related to current year tax positions	36,281	1,100	1,500
Increases (decreases) related to prior year tax positions	2,651	26,329	3,845
Decreases related to settlements with taxing authorities	(19,180)	(1,017)	(2,154)
Decreases resulting from the expiration of the statute of limitations	(4,142)	0	0
Unrecognized Tax Benefits	$ 55,784	$ 40,174	$ 13,762

XML

Income Taxes - Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Inventories	$ (61,850)	$ (28,411)
Stock-based compensation	3,388	1,614
Property, plant and equipment	(357,044)	(261,476)
Investment in WNRL	147,625	77,824
Investment in NTI (1)	(1,750)	(81,789)
Postretirement obligations	2,117	2,595
Commodity hedging activities	(671)	(33,260)
Environmental and retirement obligations	3,975	3,742
Other, net		6,247
Deferred Tax Assets, Operating Loss Carryforwards	20,897	20,828
Deferred Tax Assets, Valuation Allowance	(16,980)	(20,828)
Deferred Tax Assets, Gross	161,022	92,022
Deferred Tax Liabilities, Gross	421,315	404,936
Deferred tax liabilities, net	$ (260,293)	$ (312,914)

XML

Income Taxes - Net Operating Loss Carryforward (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
NOL Carryforwards
State NOL carryforwards - Tax effected amount	$ (20,897)	$ (20,828)
Less valuation allowance for operating loss carryforwards - Gross Amount	395,130
Deferred Tax Assets, Valuation Allowance	16,980	$ 20,828
Total credits and NOL carryforwards - Gross amount	(77,206)
Total credits and NOL carryforwards - Tax effected amount	(3,917)
Valuation Allowance, Deferred Tax Asset, Increase (Decrease), Amount	(3,800)
Virginia and Maryland [Member]
NOL Carryforwards
State NOL carryforwards - Gross amount	(472,336)
State NOL carryforwards - Tax effected amount	(20,897)
Expires 2023 [Member] | Virginia and Maryland [Member]
NOL Carryforwards
State NOL carryforwards - Gross amount	(4,833)
State NOL carryforwards - Tax effected amount	$ (243)
NOL - Expiration	Dec. 31, 2023
Expires 2024 [Member] | Virginia and Maryland [Member]
NOL Carryforwards
State NOL carryforwards - Gross amount	$ (17,200)
State NOL carryforwards - Tax effected amount	$ (737)
NOL - Expiration	Dec. 31, 2024
Expires 2026 [Member] | Virginia and Maryland [Member]
NOL Carryforwards
State NOL carryforwards - Gross amount	$ (503)
State NOL carryforwards - Tax effected amount	$ (22)
NOL - Expiration	Dec. 31, 2026
Expires 2027 [Member] | Virginia and Maryland [Member]
NOL Carryforwards
State NOL carryforwards - Gross amount	$ (1,070)
State NOL carryforwards - Tax effected amount	$ (221)
NOL - Expiration	Dec. 31, 2027
Expires 2028 [Member] | Virginia and Maryland [Member]
NOL Carryforwards
State NOL carryforwards - Gross amount	$ (31,219)
State NOL carryforwards - Tax effected amount	$ (1,337)
NOL - Expiration	Dec. 31, 2028
Expires 2029 [Member] | Virginia and Maryland [Member]
NOL Carryforwards
State NOL carryforwards - Gross amount	$ (56,838)
State NOL carryforwards - Tax effected amount	$ (2,435)
NOL - Expiration	Dec. 31, 2029
Expires 2030 [Member] | Virginia and Maryland [Member]
NOL Carryforwards
State NOL carryforwards - Gross amount	$ (98,316)
State NOL carryforwards - Tax effected amount	$ (4,212)
NOL - Expiration	Dec. 31, 2030
Expires 2031 [Member] | Virginia and Maryland [Member]
NOL Carryforwards
State NOL carryforwards - Gross amount	$ (132,582)
State NOL carryforwards - Tax effected amount	$ (5,680)
NOL - Expiration	Dec. 31, 2031
Expires 2032 [Member] | Virginia and Maryland [Member]
NOL Carryforwards
State NOL carryforwards - Gross amount	$ (129,268)
State NOL carryforwards - Tax effected amount	$ (5,503)
NOL - Expiration	Dec. 31, 2032
Expires 2035 [Member] | Virginia and Maryland [Member]
NOL Carryforwards
State NOL carryforwards - Gross amount	$ (507)
State NOL carryforwards - Tax effected amount	$ (507)
NOL - Expiration	Dec. 31, 2035

XML

Income Taxes - Tax Information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Tax Contingency [Line Items]
Unrecognized Tax Benefits, Excluding Interest & Penalties	$ 55,784	$ 40,174	$ 13,762	$ 10,571
Deferred Tax Assets, Valuation Allowance	$ 16,980	$ 20,828
Effective Income Tax Rate Reconciliation, Percent	22.70%	(26.70%)	(29.20%)
Unrecognized Tax Benefits that Would Impact Effective Tax Rate	$ 13,400
Decrease in Unrecognized Tax Benefits is Reasonably Possible	$ 2,100
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent	35.00%
Unrecognized tax benefits	$ 58,317	$ 42,049
Income taxes paid	38,227	283,330	$ 227,953
Unrecognized Tax Benefits, Income Tax Penalties and Interest Accrued	700
Valuation Allowance, Deferred Tax Asset, Increase (Decrease), Amount	(3,800)
State Income Taxes, Net of Federal Tax Benefit [Member]
Income Tax Contingency [Line Items]
Unrecognized tax benefits	$ 200	$ 5,000	$ 800

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Income Taxes - NTI - Income Tax Expense (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Operating Loss Carryforwards [Line Items]
Current Income Tax Expense (Benefit)									$ 70,652	$ 258,679	$ 219,901
Deferred Income Tax Expense (Benefit)									(15,784)	(34,724)	72,703
Income Tax Expense (Benefit)	$ (13,613)	$ 11,700	$ 38,152	$ 18,629	$ (6,034)	$ 92,117	$ 78,435	$ 59,437	$ 54,868	$ 223,955	$ 292,604
Effective Income Tax Rate Reconciliation, Percent									(22.70%)	26.70%	29.20%
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent									35.00%
Northern Tier Energy LP [Member]
Operating Loss Carryforwards [Line Items]
Current Income Tax Expense (Benefit)									$ 2,500	$ 5,600	$ 4,500
Deferred Income Tax Expense (Benefit)									1,800	2,800	2,600
Income Tax Expense (Benefit)									$ 4,300	$ 8,400	$ 7,100
Effective Income Tax Rate Reconciliation, Percent									5.30%	2.50%	2.90%
Statutory federal and state (net of federal benefit) tax rate									40.40%	41.40%	40.40%
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent									34.00%	35.00%	35.00%

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Income Taxes - NTI - Tax Rate Reconciliation (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Operating Loss Carryforwards [Line Items]
Taxes at the federal statutory rate									$ 84,656	$ 293,435	$ 350,937
State income taxes, net of federal tax benefit (1)									3,601	13,637	31,477
Other, net									1,496	1,059	(4,971)
Income Tax Expense (Benefit)	$ (13,613)	$ 11,700	$ 38,152	$ 18,629	$ (6,034)	$ 92,117	$ 78,435	$ 59,437	54,868	223,955	292,604
Northern Tier Energy LP [Member]
Operating Loss Carryforwards [Line Items]
Taxes at the federal statutory rate									27,500	118,800	87,000
Taxes On Earnings Attributable To Flow Through Entities									24,200	112,400	81,000
State income taxes, net of federal tax benefit (1)									600	1,200	1,000
Effective Income Tax Rate Reconciliation, Tax Credit, Amount									200	400	300
Other, net									600	1,200	400
Income Tax Expense (Benefit)									$ 4,300	$ 8,400	$ 7,100

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Income Taxes - NTI - Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Operating Loss Carryforwards [Line Items]
Other, net		$ 6,247
Deferred Tax Assets, Gross	$ 161,022	92,022
Deferred Tax Liabilities, Property, Plant and Equipment	357,044	261,476
Deferred Tax Liabilities, Inventory	61,850	28,411
Investment in NTI	1,750	81,789
Deferred Tax Liabilities, Gross	(421,315)	(404,936)
Deferred Tax Liabilities, Net	(260,293)	(312,914)
Deferred Tax Assets, Operating Loss Carryforwards	20,897	20,828
Northern Tier Energy LP [Member]
Operating Loss Carryforwards [Line Items]
Deferred Tax Assets, Tax Deferred Expense, Reserves and Accruals, Accrued Liabilities	2,300	2,200
Deferred Tax Assets Loyalty Program	600	400
Deferred Tax Assets, Tax Deferred Expense, Compensation and Benefits, Employee Compensation	400	500
Deferred tax assets - UNICAP	600	200
Other, net	100	300
Deferred Tax Assets, Gross	4,000	3,600
Deferred Tax Liabilities, Property, Plant and Equipment	5,200	6,300
Deferred Tax Liabilities, Intangible Assets	12,100	12,000
Deferred Tax Liabilities, Inventory	700	1,100
Investment in NTI	300	300
Deferred Tax Liabilities, Gross	(18,300)	(19,700)
Deferred Tax Liabilities, Net	(14,300)	(16,100)
Deferred Tax Assets, Operating Loss Carryforwards	$ 0	$ 0

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Retirement Plans - Pension - NTI (Details) - USD ($) $ in Thousands	3 Months Ended	9 Months Ended	12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Defined Benefit Plan, Amounts Recognized in Other Comprehensive Income (Loss) [Abstract]
Amortization of net prior service cost			$ 253	$ (215)	$ (161)
Net prior service credit			0	2,463	0
Other Comprehensive Income (Loss), Finalization of Pension and Other Postretirement Benefit Plan Valuation, before Tax			420	0	0
Pension Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Settlements, Plan Assets			149	0
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Benefit obligation at beginning of year		$ 8,927	8,927	6,965
Defined Benefit Plan, Service Cost			2,196	2,326	2,054
Defined Benefit Plan, Interest Cost			488	366	327
Defined Benefit Plan, Actuarial Gain (Loss)			490	(151)
Defined Benefit Plan, Plan Amendments			0	0
Defined Benefit Plan, Contributions by Plan Participants			0	0
Defined Benefit Plan, Benefits Paid			(675)	(579)
Benefit obligation at end of year	$ 11,277		11,277	8,927	6,965
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets at beginning of year		$ 5,932	5,932	4,319
Defined Benefit Plan, Contributions by Employer			2,748	2,200	200
Defined Benefit Plan, Actual Return on Plan Assets			134	(8)
Defined Benefit Plan, Benefits Paid			(675)	(579)
Defined Benefit Plan, Contributions by Plan Participants			0	0
Fair value of plan assets at end of year	8,139		8,139	5,932	4,319
Pension and Other Postretirement Defined Benefit Plans, Current Liabilities	0		0	0
Pension and Other Postretirement Defined Benefit Plans, Liabilities, Noncurrent	3,138		3,138	2,995
Defined Benefit Plan, Funded Status of Plan	3,138		3,138	2,995
Defined Benefit Plan, Accumulated Benefit Obligation	11,277		11,277	8,927
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Defined Benefit Plan, Service Cost			2,196	2,326	2,054
Defined Benefit Plan, Interest Cost			488	366	327
Defined Benefit Plan, Expected Return on Plan Assets			(273)	(165)	(218)
Defined Benefit Plan, Amortization of Gains (Losses)			(12)	(22)	0
Defined Benefit Plan, Amortization of Prior Service Cost (Credit)			25	24	25
Defined Benefit Plan, Recognized Net Gain (Loss) Due to Curtailments			270	0	0
Defined Benefit Plan, Net Periodic Benefit Cost			2,718	2,573	2,188
Defined Benefit Plan, Amounts Recognized in Other Comprehensive Income (Loss) [Abstract]
Amortization of net prior service cost			(24)	(24)	(24)
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Adjustment, before Reclassification Adjustments, Net of Tax			(12)	0	0
Net prior service credit			0	0	0
Net actuarial loss			629	22	687
Other Comprehensive Income (Loss), Finalization of Pension and Other Postretirement Benefit Plan Valuation, before Tax			(271)	0	0
Defined Benefit Plan, Recognized Net Gain (Loss) Due to Settlements and Curtailments			(149)	0	0
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), before Tax	$ 173		$ 173	$ (2)	$ 663
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate	4.00%		4.00%	4.50%	4.00%
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Rate of Compensation Increase	3.00%		3.00%	3.00%	3.00%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate	4.25%	4.50%		4.00%	5.00%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Return on Assets	3.50%	3.75%		3.75%	4.75%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase			3.00%	3.00%	4.00%
Expected Funding Requirements, Defined Benefit Plan			$ 2,300
Defined Benefit Plan, Expected Future Benefit Payments, Fiscal Year Maturity [Abstract]
Defined Benefit Plan, Expected Future Benefit Payments, Next Twelve Months	$ 1,150		1,150
Defined Benefit Plan, Expected Future Benefit Payments, Year Two	439		439
Defined Benefit Plan, Expected Future Benefit Payments, Year Three	493		493
Defined Benefit Plan, Expected Future Benefit Payments, Year Four	544		544
Defined Benefit Plan, Expected Future Benefit Payments, Year Five	528		528
Defined Benefit Plan, Expected Future Benefit Payments, Five Fiscal Years Thereafter	2,849		2,849
Other Pension Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Settlements, Plan Assets			0	$ 0
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Benefit obligation at beginning of year		$ 345	345	3,098
Defined Benefit Plan, Service Cost			0	315	$ 231
Defined Benefit Plan, Interest Cost			8	135	116
Defined Benefit Plan, Actuarial Gain (Loss)			(197)	(697)
Defined Benefit Plan, Plan Amendments			0	2,463
Defined Benefit Plan, Contributions by Plan Participants			12	26
Defined Benefit Plan, Benefits Paid			(42)	(69)
Benefit obligation at end of year	126		126	345	3,098
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets at beginning of year		$ 0	0	0
Defined Benefit Plan, Contributions by Employer			30	43
Defined Benefit Plan, Actual Return on Plan Assets			0	0
Defined Benefit Plan, Benefits Paid			(42)	(69)
Defined Benefit Plan, Contributions by Plan Participants			12	26
Fair value of plan assets at end of year	0		0	0	0
Pension and Other Postretirement Defined Benefit Plans, Current Liabilities	31		31	61
Pension and Other Postretirement Defined Benefit Plans, Liabilities, Noncurrent	95		95	284
Defined Benefit Plan, Funded Status of Plan	126		126	345
Defined Benefit Plan, Accumulated Benefit Obligation	126		126	345
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Defined Benefit Plan, Service Cost			0	315	231
Defined Benefit Plan, Interest Cost			8	135	116
Defined Benefit Plan, Expected Return on Plan Assets			0	0	0
Defined Benefit Plan, Amortization of Gains (Losses)			(13)	(32)	0
Defined Benefit Plan, Amortization of Prior Service Cost (Credit)			(291)	137	137
Defined Benefit Plan, Recognized Net Gain (Loss) Due to Curtailments			0	0	0
Defined Benefit Plan, Net Periodic Benefit Cost			(270)	619	484
Defined Benefit Plan, Amounts Recognized in Other Comprehensive Income (Loss) [Abstract]
Amortization of net prior service cost			291	(137)	(137)
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Adjustment, before Reclassification Adjustments, Net of Tax			(13)	(32)	0
Net prior service credit			0	(2,463)	0
Net actuarial loss			(197)	(697)	675
Other Comprehensive Income (Loss), Finalization of Pension and Other Postretirement Benefit Plan Valuation, before Tax			0	0	0
Defined Benefit Plan, Recognized Net Gain (Loss) Due to Settlements and Curtailments			0	0	0
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), before Tax	$ 81		$ 81	$ (3,329)	$ 538
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate	2.75%		2.75%	2.50%	4.00%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate			2.50%	4.00%	5.00%
Defined Benefit Plan, Ultimate Health Care Cost Trend Rate			5.00%
Defined Benefit Plan, Expected Future Benefit Payments, Fiscal Year Maturity [Abstract]
Defined Benefit Plan, Expected Future Benefit Payments, Next Twelve Months	$ 31		$ 31
Defined Benefit Plan, Expected Future Benefit Payments, Year Two	14		14
Defined Benefit Plan, Expected Future Benefit Payments, Year Three	15		15
Defined Benefit Plan, Expected Future Benefit Payments, Year Four	16		16
Defined Benefit Plan, Expected Future Benefit Payments, Year Five	17		17
Defined Benefit Plan, Expected Future Benefit Payments, Five Fiscal Years Thereafter	$ 46		$ 46
Maximum [Member] | Other Pension Plan [Member]
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Defined Benefit Plan, Health Care Cost Trend Rate Assumed for Next Fiscal Year			0.00%

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Retirement Plans - Postretirement Obligations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Accumulated Other Comprehensive Income (Loss), before Tax [Roll Forward]
Actuarial gain (loss)	$ 0	$ (50)	$ (21)
Other Postretirement Benefit Plan [Member]
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Benefit obligation at beginning of year	5,893	6,735
Defined Benefit Plan, Service Cost	104	124	92
Defined Benefit Plan, Interest Cost	212	251	264
Defined Benefit Plan, Benefits Paid	(145)	(182)
Defined Benefit Plan, Actuarial Gain (Loss)	(1,157)	(1,035)
Benefit obligation at end of year	4,907	5,893	6,735
Defined Benefit Plan, Funded Status of Plan	4,907	5,893
Pension and Other Postretirement Defined Benefit Plans, Current Liabilities	150	202
Pension and Other Postretirement Defined Benefit Plans, Liabilities, Noncurrent	4,757	5,691
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Defined Benefit Plan, Service Cost	104	124	92
Defined Benefit Plan, Interest Cost	212	251	264
Defined Benefit Plan, Amortization of Gains (Losses)	11	(23)	(20)
Defined Benefit Plan, Net Periodic Benefit Cost	305	398	376
Accumulated Other Comprehensive Income (Loss), before Tax [Roll Forward]
Pre-tax unrecognized net loss included in accumulated other comprehensive loss at beginning of year	538	1,596	784
Net actuarial loss	(1,157)	(1,035)	792
Actuarial gain (loss)	11	23	(20)
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), before Tax	(608)	$ 538	$ 1,596
Defined Benefit Plan, Expected Future Benefit Payments, Fiscal Year Maturity [Abstract]
Defined Benefit Plan, Expected Future Benefit Payments, Next Twelve Months	153
Defined Benefit Plan, Expected Future Benefit Payments, Year Two	158
Defined Benefit Plan, Expected Future Benefit Payments, Year Three	164
Defined Benefit Plan, Expected Future Benefit Payments, Year Four	173
Defined Benefit Plan, Expected Future Benefit Payments, Year Five	181
Defined Benefit Plan, Expected Future Benefit Payments, Five Fiscal Years Thereafter	1,092
Defined Benefit Plan, Effect of One-Percentage Point Change in Assumed Health Care Cost Trend Rates [Abstract]
Defined Benefit Plan, Effect of One Percentage Point Increase on Service and Interest Cost Components	1
Defined Benefit Plan, Effect of One Percentage Point Decrease on Service and Interest Cost Components	(46)
Defined Benefit Plan, Effect of One Percentage Point Increase on Accumulated Postretirement Benefit Obligation	13
Defined Benefit Plan, Effect of One Percentage Point Decrease on Accumulated Postretirement Benefit Obligation	$ (560)
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate	4.37%	4.43%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate	4.43%	4.09%	4.88%
Maximum [Member] | El Paso Facility [Member] | Other Postretirement Benefit Plan [Member]
Defined Benefit Plan, Effect of One-Percentage Point Change in Assumed Health Care Cost Trend Rates [Abstract]
Defined Benefit Plan, Health Care Cost Trend Rate Assumed for Next Fiscal Year	0.00%
Maximum [Member] | Yorktown Facility [Member] | Other Postretirement Benefit Plan [Member]
Defined Benefit Plan, Effect of One-Percentage Point Change in Assumed Health Care Cost Trend Rates [Abstract]
Defined Benefit Plan, Health Care Cost Trend Rate Assumed for Next Fiscal Year	4.50%
Defined Benefit Plan, Ultimate Health Care Cost Trend Rate	4.50%

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Retirement Plans - OCI (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Amortization of net prior service cost	$ (253)	$ 215	$ 161
Net prior service credit	0	2,463	0
Other Comprehensive Income (Loss), Finalization of Pension and Other Postretirement Benefit Plan Valuation, before Tax	420	0	0
Operating Expense [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Accumulated Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net of Tax	651	(1,291)	(350)
Amortization of net prior service cost	(183)	83	63
Net prior service credit	0	945	0
Reclassification from Accumulated Other Comprehensive Income, Current Period, before Tax	0	50	21
Actuarial gain (loss)	724	1,267	(1,320)
Income tax	(386)	(403)	295
Accumulated Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net of Tax	$ 1,226	$ 651	$ (1,291)

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Retirement Plans - Defined Contribution (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Northern Tier Energy LP [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Contribution Plan, Cost Recognized	$ 7.5	$ 7.4	$ 7.1
Western Refining, Inc. [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Contribution Plan, Cost Recognized	$ 10.2	$ 10.0	$ 9.1

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Retirement Plans - NTI (Details) $ in Thousands	3 Months Ended	9 Months Ended	12 Months Ended
	Dec. 31, 2016 USD ($) plan	Sep. 30, 2016 USD ($)	Dec. 31, 2016 USD ($) plan	Dec. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Net prior service credit			$ 0	$ (2,463)	$ 0
Northern Tier Energy LP [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Contribution Plan, Cost Recognized			$ 7,500	$ 7,400	$ 7,100
Defined Contribution Plan, Number Of Plans | plan	1		1
Pension Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Expected Future Benefit Payments, Next Twelve Months	$ 1,150		$ 1,150
Defined Benefit Plan, Expected Future Benefit Payments, Fiscal Year Maturity [Abstract]
Expected Funding Requirements, Defined Benefit Plan			2,300
Defined Benefit Plan, Expected Future Benefit Payments, Year Two	439		439
Defined Benefit Plan, Expected Future Benefit Payments, Year Three	493		493
Defined Benefit Plan, Expected Future Benefit Payments, Year Four	544		544
Defined Benefit Plan, Expected Future Benefit Payments, Year Five	528		528
Defined Benefit Plan, Expected Future Benefit Payments, Five Fiscal Years Thereafter	$ 2,849		$ 2,849
Defined Benefit Plan, Assumptions Used in Calculations [Abstract]
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate	4.00%		4.00%	4.50%	4.00%
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Rate of Compensation Increase	3.00%		3.00%	3.00%	3.00%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate	4.25%	4.50%		4.00%	5.00%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Return on Assets	3.50%	3.75%		3.75%	4.75%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase			3.00%	3.00%	4.00%
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Defined Benefit Plan, Service Cost			$ 2,196	$ 2,326	$ 2,054
Defined Benefit Plan, Amortization of Prior Service Cost (Credit)			25	24	25
Defined Benefit Plan, Interest Cost			488	366	327
Defined Benefit Plan, Expected Return on Plan Assets			273	165	218
Defined Benefit Plan, Net Periodic Benefit Cost			2,718	2,573	2,188
Net prior service credit			0	0	0
Defined Benefit Plan, Recognized Net Gain (Loss) Due to Settlements and Curtailments			(149)	0	0
Net actuarial loss			629	22	687
Defined Benefit Plan, Funded Status of Plan [Abstract]
Benefit obligation at beginning of year		$ 8,927	8,927	6,965
Defined Benefit Plan, Actuarial Gain (Loss)			490	(151)
Defined Benefit Plan, Plan Amendments			0	0
Defined Benefit Plan, Benefits Paid			675	579
Benefit obligation at end of year	$ 11,277		11,277	8,927	6,965
Defined Benefit Plan, Funded Status of Plan	(3,138)		(3,138)	(2,995)
Fair value of plan assets at beginning of year		$ 5,932	5,932	4,319
Defined Benefit Plan, Contributions by Employer			2,748	2,200	200
Defined Benefit Plan, Actual Return on Plan Assets			134	(8)
Fair value of plan assets at end of year	8,139		8,139	$ 5,932	$ 4,319
Pension Plan [Member] | Northern Tier Energy LP [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Expected Future Benefit Payments, Next Twelve Months	1,100		$ 1,100
Us Treasury Bond Maturity Term Used To Determine Employer Contributions			30 years
Deferred Compensation Arrangement with Individual, Requisite Service Period			3 years
Defined Benefit Plan Contributions By Employer Percentage Of Annual Compensation			5.00%
Defined Benefit Plan, Expected Future Benefit Payments, Fiscal Year Maturity [Abstract]
Expected Funding Requirements, Defined Benefit Plan			$ 2,300
Defined Benefit Plan, Expected Future Benefit Payments, Year Two	400		400
Defined Benefit Plan, Expected Future Benefit Payments, Year Three	500		500
Defined Benefit Plan, Expected Future Benefit Payments, Year Four	500		500
Defined Benefit Plan, Expected Future Benefit Payments, Year Five	500		500
Defined Benefit Plan, Expected Future Benefit Payments, Five Fiscal Years Thereafter	$ 2,900		$ 2,900
Defined Benefit Plan, Assumptions Used in Calculations [Abstract]
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate	4.00%		4.00%	4.50%	4.00%
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Rate of Compensation Increase				3.00%	3.00%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate	3.75%	4.50%		4.00%	5.00%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Return on Assets	3.50%	4.25%		3.75%	4.75%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase			3.00%	3.00%	4.00%
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Defined Benefit Plan, Service Cost			$ 2,200	$ 2,300	$ 2,100
Defined Benefit Plan, Interest Cost			500	400	300
Defined Benefit Plan, Expected Return on Plan Assets			200	100	200
Defined Benefit Plan, Net Periodic Benefit Cost			2,500	2,600	2,200
Defined Benefit Plan, Amounts Recognized in Other Comprehensive Income (Loss), Net Actuarial Gain (Loss), before Tax			0	0	700
Defined Benefit Plan, Recognized Net Gain (Loss) Due to Settlements and Curtailments			400	0	0
Net actuarial loss			(600)	0	0
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Adjustment, before Tax			200	0	700
Defined Benefit Plan, Funded Status of Plan [Abstract]
Benefit obligation at beginning of year		$ 8,900	8,900	7,000	4,600
Defined Benefit Plan, Actuarial Gain (Loss)			500	(200)	600
Defined Benefit Plan, Curtailments			100	0	0
Defined Benefit Plan, Benefits Paid			700	600	600
Benefit obligation at end of year	$ 11,300		11,300	8,900	7,000
Defined Benefit Plan, Funded Status of Plan	(3,200)		(3,200)	(3,000)	(2,700)
Fair value of plan assets at beginning of year		$ 5,900	5,900	4,300	4,600
Defined Benefit Plan, Contributions by Employer			2,800	2,200	200
Defined Benefit Plan, Actual Return on Plan Assets			100	0	100
Fair value of plan assets at end of year	$ 8,100		8,100	5,900	4,300
Defined Contribution Plans Participant Group One [Member] | Other Postretirement Benefit Plan [Member] | Northern Tier Energy LP [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Contribution Plan, Cost Recognized			$ 7,500	$ 7,400	$ 7,100
Defined Contribution Plan, Employer Matching Contribution, Percent of Employees' Gross Pay			100.00%
Defined Contribution Plan, Maximum Annual Contributions Per Employee, Percent			6.00%
Defined Contribution Plan, Employer Non-matching Contribution, Percentage			3.00%

XML

Crude Oil and Refined Product Risk Management (Details) bbl in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2016 USD ($) $ / Incident bbl	Dec. 31, 2015 USD ($) bbl	Dec. 31, 2014 USD ($)
Derivative [Line Items]
Realized Investment Gains (Losses) | $	$ 58,773	$ 93,699	$ 95,331
Derivative, Gain (Loss) on Derivative, Net | $	(18,901)	43,466	289,754
Unrealized Gain (Loss) on Derivatives and Commodity Contracts | $	(77,674)	(50,233)	$ 194,423
Derivative Asset | $	$ 2,059	79,733
Distillate Crack Spread Swaps [Member] | Minimum [Member]
Derivative [Line Items]
Underlying, Derivative Volume | $ / Incident	15.06
Distillate Crack Spread Swaps [Member] | Maximum [Member]
Derivative [Line Items]
Underlying, Derivative Volume | $ / Incident	16.62
Commodity Contract [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset | $	$ 2,059	$ 79,733
Not Designated as Hedging Instrument [Member] | Short [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume	(6,211)	(1,052)
Not Designated as Hedging Instrument [Member] | Short [Member] | Inventory Positions - Crude Oil - Futures - Current Fiscal Year [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume	(1,703)
Not Designated as Hedging Instrument [Member] | Short [Member] | Inventory Positions - Crude Oil - Futures - Year Three [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume	0
Not Designated as Hedging Instrument [Member] | Short [Member] | Inventory Positions - Crude Oil - Futures - Year Two [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume	0
Not Designated as Hedging Instrument [Member] | Short [Member] | Inventory Positions - Distillate - Crack Spread Swaps - Current Fiscal Year [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume	(150)
Not Designated as Hedging Instrument [Member] | Short [Member] | Inventory Positions - Distillate - Crack Spread Swaps - Year Three [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume	0
Not Designated as Hedging Instrument [Member] | Short [Member] | Inventory Positions - Distillate - Crack Spread Swaps - Year Two [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume	0
Not Designated as Hedging Instrument [Member] | Short [Member] | Inventory Positions - Refined Products - Futures & Swaps - Current Fiscal Year [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume	(1,403)
Not Designated as Hedging Instrument [Member] | Short [Member] | Inventory Positions - Refined Products - Futures & Swaps - Year Three [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume	0
Not Designated as Hedging Instrument [Member] | Short [Member] | Inventory Positions - Refined Products - Futures & Swaps - Year Two [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume	0
Not Designated as Hedging Instrument [Member] | Short [Member] | Refined Product Positions - Distillate - Crack Spread Swaps - Current Fiscal Year [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume	(2,730)
Not Designated as Hedging Instrument [Member] | Short [Member] | Refined Product Positions - Distillate - Crack Spread Swaps - Year Three [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume	0
Not Designated as Hedging Instrument [Member] | Short [Member] | Refined Product Positions - Distillate - Crack Spread Swaps - Year Two [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume	(1,800)
Not Designated as Hedging Instrument [Member] | Short [Member] | Refined Product Positions - Unleaded Gasoline - Crack Spread Swaps - Current Fiscal Year [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume	(850)
Not Designated as Hedging Instrument [Member] | Short [Member] | Refined Product Positions - Unleaded Gasoline - Crack Spread Swaps - Year Two [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume	0
Not Designated as Hedging Instrument [Member] | Short [Member] | Refined Product Positions - Unleaded Gasoline - Crack Spread Swaps - Year Three [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume	0
Not Designated as Hedging Instrument [Member] | Long [Member] | Inventory Positions - Crude Oil - Differential Swaps - Current Fiscal Year [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume	(2,124)
Not Designated as Hedging Instrument [Member] | Long [Member] | Inventory Positions - Crude Oil - Differential Swaps - Year Three [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume	0
Not Designated as Hedging Instrument [Member] | Long [Member] | Inventory Positions - Crude Oil - Differential Swaps - Year Two [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume	0
Not Designated as Hedging Instrument [Member] | Long [Member] | Inventory Positions - Natural Gas - Futures & Swaps - Current Fiscal Year [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume	(301)
Not Designated as Hedging Instrument [Member] | Long [Member] | Inventory Positions - Natural Gas - Futures & Swaps - Year Three [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume	0
Not Designated as Hedging Instrument [Member] | Long [Member] | Inventory Positions - Natural Gas - Futures & Swaps - Year Two [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume	0
Fair Value, Measurements, Recurring [Member] | Commodity Contract [Member]
Derivative [Line Items]
Derivative Asset | $	$ 2,059	$ 79,733
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset | $	0	0
Other Current Assets [Member] | Fair Value, Measurements, Recurring [Member] | Commodity Contract [Member]
Derivative [Line Items]
Derivative Asset | $	13,649	78,125
Derivative Asset, Fair Value, Gross Asset | $	18,929	95,062
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset | $	5,280	16,937
Other Noncurrent Assets [Member] | Fair Value, Measurements, Recurring [Member] | Commodity Contract [Member]
Derivative [Line Items]
Derivative Asset | $	8	11,881
Derivative Asset, Fair Value, Gross Asset | $	677	11,881
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset | $	669	0
Accrued Liabilities [Member] | Fair Value, Measurements, Recurring [Member] | Commodity Contract [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability | $	17,547	21,454
Derivative Liability | $	(10,827)	(10,273)
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset | $	(6,720)	(11,181)
Other Noncurrent Liabilities [Member] | Fair Value, Measurements, Recurring [Member] | Commodity Contract [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability | $	0	5,756
Derivative Liability | $	(771)	0
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset | $	$ (771)	$ (5,756)
Crude Oil [Member] | Not Designated as Hedging Instrument [Member] | Short [Member] | Future [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume	(1,703)	(562)
Crude Oil [Member] | Not Designated as Hedging Instrument [Member] | Long [Member] | Swap [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume	(2,124)	(5,155)
Fuel [Member] | Not Designated as Hedging Instrument [Member] | Short [Member] | Swap [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume	(6,632)	(5,645)

XML

Crude Oil and Refined Product Risk Management NTI (Details) bbl in Thousands, MMBTU in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2016 USD ($) MMBTU bbl	Dec. 31, 2015 USD ($) MMBTU bbl	Dec. 31, 2014 USD ($)
Derivative [Line Items]
Derivative Asset	$ 2,059	$ 79,733
Derivative, Gain (Loss) on Derivative, Net	(18,901)	43,466	$ 289,754
Northern Tier Energy LP [Member]
Derivative [Line Items]
Derivative, Collateral, Right to Reclaim Cash	7,600	6,000
Unrealized Gain (Loss) on Derivatives	7,800	(4,700)	(2,800)
Gain (Loss) on Sale of Derivatives	(19,800)	1,500	12,400
Derivative, Gain (Loss) on Derivative, Net	(12,000)	(3,200)	9,600
Northern Tier Energy LP [Member] | Cost of Sales [Member]
Derivative [Line Items]
Derivative, Gain (Loss) on Derivative, Net	(13,300)	(500)	9,600
Northern Tier Energy LP [Member] | Operating Expense [Member]
Derivative [Line Items]
Derivative, Gain (Loss) on Derivative, Net	1,300	(2,700)	$ 0
Northern Tier Energy LP [Member] | Assets [Member]
Derivative [Line Items]
Derivative Asset	6,600	1,900
Northern Tier Energy LP [Member] | Liability [Member]
Derivative [Line Items]
Derivative Liability	6,300	9,400
Northern Tier Energy LP [Member] | Swap [Member] | Accrued Liabilities [Member]
Derivative [Line Items]
Derivative Asset	100	0
Derivative Liability	400	7,900
Northern Tier Energy LP [Member] | Swap [Member] | Other Current Assets [Member]
Derivative [Line Items]
Derivative Asset	1,100
Derivative Liability	0
Northern Tier Energy LP [Member] | Future [Member] | Accrued Liabilities [Member]
Derivative [Line Items]
Derivative Asset	200
Derivative Liability	1,200
Northern Tier Energy LP [Member] | Future [Member] | Other Current Assets [Member]
Derivative [Line Items]
Derivative Asset		400
Derivative Liability		0
Northern Tier Energy LP [Member] | Forward Contracts [Member] | Accrued Liabilities [Member]
Derivative [Line Items]
Derivative Asset	0	0
Derivative Liability	4,700	1,500
Northern Tier Energy LP [Member] | Forward Contracts [Member] | Other Current Assets [Member]
Derivative [Line Items]
Derivative Asset	5,200	1,500
Derivative Liability	$ 0	$ 0
Long [Member] | Crude Oil And Refined Products [Member] | Northern Tier Energy LP [Member] | Swap [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume | bbl	1,073	5,155
Long [Member] | Crude Oil And Refined Products [Member] | Northern Tier Energy LP [Member] | Future [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume | bbl	30	90
Long [Member] | Crude Oil And Refined Products [Member] | Northern Tier Energy LP [Member] | Forward Contracts [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume | bbl	4,382	4,445
Long [Member] | Natural Gas [Member] | Northern Tier Energy LP [Member] | Swap [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU	1,169	1,554
Short [Member] | Crude Oil And Refined Products [Member] | Northern Tier Energy LP [Member] | Swap [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume | bbl	530	525
Short [Member] | Crude Oil And Refined Products [Member] | Northern Tier Energy LP [Member] | Future [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume | bbl	1,270	933
Short [Member] | Crude Oil And Refined Products [Member] | Northern Tier Energy LP [Member] | Forward Contracts [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume | bbl	3,101	2,572

XML

Stock-Based Compensation - Western Stock-Based Compensation Information (Details) - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Mar. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number		144,700
Excess Tax Benefit from Share-based Compensation, Operating Activities		$ 1,033	$ 871	$ 1,144
Statutory Blended Tax Rate, Excess Tax Benefit		38.10%	38.10%	38.30%
Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number		144,700
Long Term Incentive Plan, 2006 [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Common Stock, Capital Shares Reserved for Future Issuance		19,856
Incentive Plan of Western Refining, 2010 [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Common Stock, Capital Shares Reserved for Future Issuance		2,391,711
Incentive Plans of Western Refining, Inc. [Member] | Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number		0	0	0	3,842
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period		0	0	0
Excess Tax Benefit from Share-based Compensation, Operating Activities				$ 0
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Fair Value				100
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Aggregate Intrinsic Value, Vested				$ 100
Incentive Plans of Western Refining, Inc. [Member] | Restricted Stock Units (RSUs) [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Total Weighted Average Grant Date Fair Value		$ 21,200
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Aggregate Intrinsic Value, Nonvested		$ 24,900
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Term		3 years
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number		658,506	399,214	380,695	442,887
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period		375,774	155,828	124,276
Allocated Share-based Compensation Expense		$ 6,300	$ 4,200	$ 4,300
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized		$ 14,900
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized, Period for Recognition		2 years 4 months 28 days
Adjustments to Additional Paid in Capital, Income Tax Deficiency from Share-based Compensation		$ (400)
Excess Tax Benefit from Share-based Compensation, Operating Activities			900	1,100
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Fair Value		4,100	3,800	4,200
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Aggregate Intrinsic Value, Vested		3,000	$ 6,100	$ 7,100
WNRL 2013 LTIP [Member] | Phantom Share Units (PSUs) [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Total Weighted Average Grant Date Fair Value		7,500
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Aggregate Intrinsic Value, Nonvested		$ 6,100
Common Stock, Capital Shares Reserved for Future Issuance		4,098,368
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number		285,155	279,787	280,251	10,908
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period		101,955	72,005	293,810
Allocated Share-based Compensation Expense		$ 2,700	$ 2,000	$ 1,600
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized		$ 5,600
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized, Period for Recognition		2 years 4 months 10 days
Minimum [Member] | Incentive Plans of Western Refining, Inc. [Member] | Restricted Stock Units (RSUs) [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Term		1 year
Maximum [Member] | Incentive Plans of Western Refining, Inc. [Member] | Restricted Stock Units (RSUs) [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Term		5 years
Subsequent Event [Member] | Incentive Plans of Western Refining, Inc. [Member] | Restricted Stock Units (RSUs) [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period	123,570

XML

Stock-Based Compensation - Western Share Activity (Details) - $ / shares	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number	144,700
Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number	144,700
Incentive Plans of Western Refining, Inc. [Member] | Restricted Stock Units (RSUs) [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number	399,214	380,695	442,887
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period	375,774	155,828	124,276
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period	(109,634)	(131,165)	(180,923)
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeited in Period	(6,848)	(6,144)	(5,545)
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number	658,506	399,214	380,695
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value	$ 37.43	$ 30.14	$ 24.79
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value	28.52	48.26	39.08
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Weighted Average Grant Date Fair Value	37.63	29.19	23.29
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeitures, Weighted Average Grant Date Fair Value	43.81	36.76	26.69
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value	$ 32.25	$ 37.43	$ 30.14
Incentive Plans of Western Refining, Inc. [Member] | Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number	0	0	3,842
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period	0	0	0
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period	0	0	(3,842)
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeited in Period	0	0	0
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number	0	0	0
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value	$ 0.00	$ 0	$ 16.78
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value	0.00	0	0
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Weighted Average Grant Date Fair Value	0.00	0	16.78
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeitures, Weighted Average Grant Date Fair Value	0.00	0.00	0.00
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value	$ 0.00	$ 0.00	$ 0

XML

Stock-Based Compensation - NTI Stock-Based Compensation (Details) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Outstanding [Roll Forward]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number	144,700
NTI 2016 LTIP [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense	$ 13.6	$ 10.3	$ 14.0
Common Stock, Capital Shares Reserved for Future Issuance	330,018
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized	$ 5.8
NTI 2016 LTIP [Member] | Phantom Share Units (PSUs) [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Fair Value	3.4
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Total Weighted Average Grant Date Fair Value	13.4
Adjustments to Additional Paid in Capital, Income Tax Benefit from Share-based Compensation	$ 1.0
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized, Period for Recognition	1 year 7 months 22 days
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Aggregate Intrinsic Value, Nonvested	$ 25.1
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Outstanding [Roll Forward]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number	0
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period	848,267
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period	(18,553)
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeited in Period	(167,342)
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number	662,372	0
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value	$ 0.00
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value	20.25
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Weighted Average Grant Date Fair Value	20.25
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeitures, Weighted Average Grant Date Fair Value	20.25
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value	$ 20.25	$ 0.00
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Aggregate Intrinsic Value, Vested	$ 6.0

XML

Stock-Based Compensation - WNRL Stock-Based Compensation (Details) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number	144,700
WNRL 2013 LTIP [Member] | Phantom Share Units (PSUs) [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Common Stock, Capital Shares Reserved for Future Issuance	4,098,368
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number	279,787	280,251	10,908
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period	101,955	72,005	293,810
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period	(86,406)	(60,556)	(10,908)
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeited in Period	(10,181)	(11,913)	(13,559)
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number	285,155	279,787	280,251
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value	$ 28.06	$ 28.30	$ 22.00
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value	22.69	28.33	28.52
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Weighted Average Grant Date Fair Value	25.80	28.95	22.00
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeitures, Weighted Average Grant Date Fair Value	31.87	30.78	33.02
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value	$ 26.42	$ 28.06	$ 28.30
Allocated Share-based Compensation Expense	$ 2.7	$ 2.0	$ 1.6
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Total Weighted Average Grant Date Fair Value	7.5
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized	$ 5.6
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized, Period for Recognition	2 years 4 months 10 days

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Stock-Based Compensation - NTI Stock-Based Compensation Information (Details) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2016 USD ($) criteria $ / shares shares	Dec. 31, 2015 USD ($) shares	Dec. 31, 2014 USD ($) shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation expense | $	$ 22,523	$ 16,505	$ 19,903
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number	144,700
Other liabilities | $	$ 93,136	68,595
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Outstanding, Weighted Average Remaining Contractual Terms	0 months
Northern Tier Energy LP [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation expense | $	$ 13,600	10,300	$ 14,000
Other liabilities | $	$ 28,600	$ 27,900
Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number	144,700
Restricted Stock [Member] | Northern Tier Energy LP [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number	0	191,500	396,200
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Outstanding, Weighted Average Remaining Contractual Terms		1 year	1 year 3 months 18 days
Western Phantom Unit Award with Service-only Conditions [Member] | Northern Tier Energy LP [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number	800,000
Long Term Incentive Plan [Member] | Northern Tier Energy LP [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Deferred Compensation Arrangement with Individual, Common Stock Reserved for Future Issuance	300,000
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number	700,000
Deferred Compensation Cash-based Arrangements, Liability, Current and Noncurrent | $	$ 9,000
Employee Service Share-based Compensation, Nonvested Awards, Compensation Not yet Recognized, Share-based Awards Other than Options | $	$ 8,600	$ 16,100
Phantom Unit Award with Service-only Conditions [Member] | Northern Tier Energy LP [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number	0	581,900	337,700
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period	3 years
Phantom Awards with Performance or Market Conditions [Member] | Northern Tier Energy LP [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number	0	260,700	0
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Cash Denominated Award Rate | $ / shares	$ 21.1049
Pre-Merger Period, Service Based Cash Denominated Awards [Member] | Northern Tier Energy LP [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Other liabilities | $	$ 4,400
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Outstanding, Weighted Average Remaining Contractual Terms	1 year 15 days
Western Phantom Awards with Performance or Market Conditions [Member] | Northern Tier Energy LP [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number	4,600,000
Number of criteria in a performance-based equity award | criteria	2
Phantom Share Units (PSUs) [Member] | Northern Tier Energy LP [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number	0	842,600	337,700
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Outstanding, Weighted Average Remaining Contractual Terms	0 months	1 year 6 months	2 years
Maximum [Member] | Western Phantom Unit Award with Service-only Conditions [Member] | Northern Tier Energy LP [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Forfeiture Rate	30.00%
Maximum [Member] | Pre-Merger Period, Service Based Cash Denominated Awards [Member] | Northern Tier Energy LP [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Forfeiture Rate	20.00%
Maximum [Member] | Western Phantom Awards with Performance or Market Conditions [Member] | Northern Tier Energy LP [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Safety Multiple on Performance Awards	115.00%
Minimum [Member] | Pre-Merger Period, Service Based Cash Denominated Awards [Member] | Northern Tier Energy LP [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Forfeiture Rate	5.00%
Minimum [Member] | Western Phantom Awards with Performance or Market Conditions [Member] | Northern Tier Energy LP [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Safety Multiple on Performance Awards	85.00%

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Stock-Based Compensation - NTI - Restricted Common Units (Details)	12 Months Ended
	Dec. 31, 2016 $ / shares shares	Dec. 31, 2015 $ / shares shares	Dec. 31, 2014 $ / shares shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Outstanding, Weighted Average Remaining Contractual Terms	0 months
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number	144,700
Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number	144,700
Northern Tier Energy LP [Member] | Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Outstanding, Weighted Average Remaining Contractual Terms		1 year	1 year 3 months 18 days
Share Based Compensation Arrangement By Share Based Payment Award Equity Instruments Other Than Options Converted Weighted Average Remaining Contractual Terms	6 months
Share Based Compensation Arrangement By Share Based Payment Award Equity Instruments Other Than Options Grants In Period Weighted Average Remaining Contractual Terms		2 years
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number	191,500	396,200
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period		1,000
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeited in Period	12,300
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period	34,500	205,700
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number	0	191,500	396,200
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value | $ / shares	$ 24.75	$ 24.73
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value | $ / shares		24.90
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeitures, Weighted Average Grant Date Fair Value | $ / shares	25.57
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Weighted Average Grant Date Fair Value | $ / shares	26.83	24.71
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value | $ / shares	$ 0.00	$ 24.75	$ 24.73
Equity Awards Canceled Due to Business Combination	(144,700)
Share Based Compensation Cancellation Due to Business Combination Weighted Average Grant Date Fair Value | $ / shares	$ 24.18
Northern Tier Energy LP [Member] | Western Refining Phantom Stock Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Conversion Ratio	1.0323

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Stock-Based Compensation - NTI - Phantom Common Units (Details) - $ / shares	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Outstanding, Weighted Average Remaining Contractual Terms	0 months
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number	144,700
Phantom Unit Award with Service-only Conditions [Member] | Northern Tier Energy LP [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number	581,900	337,700
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period	381,000	447,900
Share-based Compensation Arrangement by Share-based Payment Award, Other Share Increase (Decrease)	0	0
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeited in Period	(16,500)	(91,300)
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period	(269,200)	(112,400)
Equity Awards Canceled Due to Business Combination	(677,200)
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number	0	581,900	337,700
Phantom Awards with Performance or Market Conditions [Member] | Northern Tier Energy LP [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number	260,700	0
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period	163,600	182,400
Share-based Compensation Arrangement by Share-based Payment Award, Other Share Increase (Decrease)	231,800	80,400
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeited in Period	(19,100)	(2,100)
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period	(1,800)	0
Equity Awards Canceled Due to Business Combination	(635,200)
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number	0	260,700	0
Phantom Share Units (PSUs) [Member] | Northern Tier Energy LP [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share Based Compensation Arrangement By Share Based Payment Award Equity Instruments Other Than Options Grants In Period Weighted Average Remaining Contractual Terms	2 years 6 months	1 year 10 months 24 days
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Incremental Performance Units, Weighted Average Remaining Contractual Terms	2 years	1 year 8 months 12 days
Share Based Compensation Arrangement By Share Based Payment Award Equity Instruments Other Than Options Converted Weighted Average Remaining Contractual Terms	2 years
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Outstanding, Weighted Average Remaining Contractual Terms	0 months	1 year 6 months	2 years
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number	842,600	337,700
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period	544,600	630,300
Share-based Compensation Arrangement by Share-based Payment Award, Other Share Increase (Decrease)	231,800	80,400
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeited in Period	(35,600)	(93,400)
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period	(271,000)	(112,400)
Equity Awards Canceled Due to Business Combination	(1,312,400)
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number	0	842,600	337,700
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value	$ 24.00	$ 26.99
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value	25.87	23.37
Share-based Compensation Arrangements by Share-based Payment Award, Options, Other Share Increase (Decrease) in Period, Weighted Average Exercise Price	27.82	23.06
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeitures, Weighted Average Grant Date Fair Value	25.36	26.22
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Weighted Average Grant Date Fair Value	24.10	27.02
Share Based Compensation Cancellation Due to Business Combination Weighted Average Grant Date Fair Value	25.45
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value	$ 0.00	$ 24.00	$ 26.99

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Equity - Equity Narrative (Details) - USD ($) $ / shares in Units, $ in Thousands				1 Months Ended	2 Months Ended		6 Months Ended	12 Months Ended
	Jun. 17, 2014	Jun. 10, 2009	Jan. 24, 2006	Jun. 30, 2016	Jun. 02, 2014	Jul. 31, 2009	Jun. 30, 2014	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Class of Stock [Line Items]
Stock Repurchase Program, Authorized Amount									$ 200,000
Stock Issued During Period, Shares, New Issues		20,000,000	18,750,000
Stock Issued During Period, Value, New Issues		$ 180,000	$ 318,800
Proceeds from Issuance Initial Public Offering			$ 297,200
Common Stock, Par or Stated Value Per Share		$ 0.01						$ 0.01	$ 0.01	$ 0.01
Underwriting Discounts Relating to Issuance of Shares		$ 9,000
Payments of Stock Issuance Costs		600						$ 655	$ 0	$ 0
Adjustments to Additional Paid in Capital, Equity Component of Convertible Debt										214,157
Common Stock [Member]
Class of Stock [Line Items]
Proceeds from Issuance of Common Stock		$ 170,400
Adjustments to Additional Paid in Capital, Equity Component of Convertible Debt										106
Additional Paid-in Capital [Member]
Class of Stock [Line Items]
Adjustments to Additional Paid in Capital, Equity Component of Convertible Debt										$ (143,557)
Senior Convertible Notes [Member]
Class of Stock [Line Items]
Payments of Debt Extinguishment Costs						$ 2,000
Debt Instrument, Face Amount						215,500
Deferred Income Taxes and Other Assets, Current						22,600
Senior Convertible Notes [Member] | Additional Paid-in Capital [Member]
Class of Stock [Line Items]
Adjustments to Additional Paid in Capital, Equity Component of Convertible Debt						$ 36,300
Convertible Debt Securities [Member] | Senior Convertible Notes [Member]
Class of Stock [Line Items]
Stock Issued During Period, Shares, Treasury Stock Reissued	22,750,088				0		22,759,243
Common Stock [Member]
Class of Stock [Line Items]
Common Stock, Par or Stated Value Per Share								$ 0.01
Northern Tier Energy LP [Member] | Common Stock [Member]
Class of Stock [Line Items]
Stock Issued During Period, Shares, Treasury Stock Reissued				11,600,000
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares				17,100,000

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Equity - Stock Repurchase Program (Details) $ in Thousands	12 Months Ended			42 Months Ended	48 Months Ended
	Dec. 31, 2016 USD ($) shares	Dec. 31, 2015 USD ($) shares	Dec. 31, 2014 USD ($) shares	Dec. 31, 2015 USD ($) shares	Dec. 31, 2009 USD ($) shares	Dec. 31, 2013 USD ($) shares
Equity, Class of Treasury Stock [Line Items]
Treasury Stock, Shares | shares		0	9,089,623	0
Treasury Stock, Value | $	$ 0	$ 363,168		$ 363,168
Treasury Stock, Shares, Acquired | shares				23,000,000	698,006
Treasury Stock, Value, Acquired, Cost Method | $	$ 75,000	$ 105,000	$ 259,222		$ 21,400
Share Repurchase Program, Number of Repurchase Programs		5		5
Stock Repurchase Program, Authorized Amount | $		$ 200,000		$ 200,000
Share Repurchase Program - Authorized January 2014 [Member]
Equity, Class of Treasury Stock [Line Items]
Debt Conversion, Converted Instrument, Shares Issued | shares			27,030
Treasury Stock, Shares | shares	4,976,039	4,976,039	4,976,039	4,976,039		0
Treasury Stock, Value | $	$ 200,000	$ 200,000	$ 200,000	$ 200,000		$ 0
Treasury Stock, Shares, Acquired | shares	0	0	4,976,039
Treasury Stock, Value, Acquired, Cost Method | $	$ 0	$ 0	$ 200,000
Share Repurchase Program - Authorized November 2014 [Member]
Equity, Class of Treasury Stock [Line Items]
Treasury Stock, Shares | shares	4,140,614	4,140,614	1,492,874	4,140,614		0
Treasury Stock, Value | $	$ 164,222	$ 164,222	$ 59,222	$ 164,222		$ 0
Treasury Stock, Shares, Acquired | shares	0	2,647,740	1,492,874
Treasury Stock, Value, Acquired, Cost Method | $	$ 0	$ 105,000	$ 59,222
Share Repurchase Program - Authorized September 2015 [Member]
Equity, Class of Treasury Stock [Line Items]
Treasury Stock, Shares | shares	2,462,350	0	0	0		0
Treasury Stock, Value | $	$ 75,000	$ 0	$ 0	$ 0		$ 0
Treasury Stock, Shares, Acquired | shares	2,462,350	0	0
Treasury Stock, Value, Acquired, Cost Method | $	$ 75,000	$ 0	$ 0

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Equity - Dividends (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended					12 Months Ended
	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Dividends Payable [Line Items]
Payments of Ordinary Dividends, Common Stock		$ 41,202	$ 41,202	$ 34,685	$ 35,601	$ 152,690
Cash dividends declared per common share		$ 0.38	$ 0.38	$ 0.38	$ 0.38	$ 1.52	$ 1.36	$ 3.08
Subsequent Event [Member]
Dividends Payable [Line Items]
Payments of Ordinary Dividends, Common Stock	$ 41,300
Cash dividends declared per common share	$ 0.38

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Equity - Distributions (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended					6 Months Ended	12 Months Ended
	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Jun. 30, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Distribution Made to Limited Partner [Line Items]
Distribution Made to Limited Partner, Distributions Declared, Per Unit		$ 0.4225
Western Refining Logistics, LP [Member]
Distribution Made to Limited Partner [Line Items]
Distribution Made to Limited Partner, Distributions Declared, Per Unit			$ 0.4125	$ 0.4025	$ 0.3925		$ 1.6300
Incentive Distribution, Distribution							$ 4.4	$ 1.1
Northern Tier Energy LP [Member]
Distribution Made to Limited Partner [Line Items]
Distribution Made to Limited Partner, Distributions Declared, Per Unit				$ 0.18	$ 0.38	$ 0.56	$ 1.74	$ 3.80	$ 2.71
Subsequent Event [Member] | Western Refining Logistics, LP [Member]
Distribution Made to Limited Partner [Line Items]
Distribution Made to Limited Partner, Distributions Declared, Per Unit	$ 0.4375

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Equity - NTI (Details) - shares shares in Millions	1 Months Ended	12 Months Ended
	Jun. 30, 2016	Dec. 31, 2016
Northern Tier Energy GP LLC [Member] | Public [Member]
Class of Stock [Line Items]
Limited Liability Company (LLC) or Limited Partnership (LP), Managing Member or General Partner, Ownership Interest		100.00%
Common Stock [Member] | Northern Tier Energy LP [Member]
Class of Stock [Line Items]
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares	17.1

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Equity - NTI Distributions (Details) - USD ($) $ / shares in Units, $ in Millions												3 Months Ended			6 Months Ended	9 Months Ended	12 Months Ended
	Dec. 27, 2016	Jun. 14, 2016	Feb. 04, 2016	Nov. 05, 2015	Aug. 06, 2015	May 06, 2015	Feb. 06, 2015	Nov. 05, 2014	Aug. 06, 2014	May 06, 2014	Feb. 07, 2014	Dec. 31, 2016	Jun. 30, 2016	Mar. 31, 2016	Jun. 30, 2016	Sep. 30, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Nov. 03, 2015	Aug. 04, 2015	Nov. 04, 2014	Aug. 05, 2014
Distribution Made to Limited Partner [Line Items]
Distribution Made to Limited Partner, Distributions Declared, Per Unit												$ 0.4225
Northern Tier Energy LP [Member]
Distribution Made to Limited Partner [Line Items]
Distribution Made to Limited Partner, Declaration Date								Nov. 04, 2014
Maximum Number Of Days For Cash Distribution To Unitholders																	60 days
Distribution Made to Limited Partner, Distribution Date								Nov. 25, 2014
Limited Partners' Capital Account, Units Outstanding												92,947,533					92,947,533	92,833,486
Distribution Made to Limited Partner, Distributions Declared, Per Unit													$ 0.18	$ 0.38	$ 0.56		$ 1.74	$ 3.80	$ 2.71
Distribution Made to Limited Partner, Cash Distributions Paid																	$ 163.6	$ 355.3	$ 251.8
Cash Distribution [Member] | Northern Tier Energy LP [Member]
Distribution Made to Limited Partner [Line Items]
Distribution Made to Limited Partner, Declaration Date		Jun. 13, 2016	Feb. 03, 2016	Nov. 03, 2015	Aug. 04, 2015	May 05, 2015	Feb. 05, 2015		Aug. 05, 2014	May 06, 2014	Feb. 07, 2014
Distribution Made to Limited Partner, Distribution Date		Jun. 23, 2016	Feb. 19, 2016	Nov. 25, 2015	Aug. 28, 2015	May 29, 2015	Feb. 27, 2015		Aug. 29, 2014	May 30, 2014	Feb. 28, 2014
Limited Partners' Capital Account, Units Outstanding			94,200,000			93,700,000	93,700,000			93,000,000	92,700,000					93,000,000				93,700,000	93,700,000	93,100,000	93,000,000
Distribution Made to Limited Partner, Distributions Declared, Per Unit		$ 0.18	$ 0.38	$ 1.04	$ 1.19	$ 1.08	$ 0.49	$ 1.00	$ 0.53	$ 0.77	$ 0.41					$ 0.56		$ 3.80	$ 2.71
Distribution Made to Limited Partner, Cash Distributions Paid	$ 110.0	$ 16.7	$ 36.0	$ 97.3	$ 111.3	$ 100.8	$ 45.9	$ 92.9	$ 49.3	$ 71.6	$ 38.0					$ 52.7		$ 355.3	$ 251.8

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Equity - NTI EPU (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Class of Stock [Line Items]
Net income attributable to Western Refining, Inc.	$ (9,589)	$ 38,575	$ 65,415	$ 30,538	$ 13,545	$ 153,303	$ 133,919	$ 105,989	$ 124,939	$ 406,756	$ 559,926
Weighted average number of common shares outstanding:									100,473	94,899	90,708
Weighted average number of diluted shares outstanding									100,868	94,999	101,190
Basic	$ (0.09)	$ 0.36	$ 0.70	$ 0.34	$ 0.14	$ 1.61	$ 1.40	$ 1.11	$ 1.24	$ 4.28	$ 6.17
Diluted earnings per common share	$ (0.09)	$ 0.35	$ 0.70	$ 0.33	$ 0.14	$ 1.61	$ 1.40	$ 1.11	$ 1.24	$ 4.28	$ 5.61
Northern Tier Energy LP [Member]
Class of Stock [Line Items]
Net income attributable to Western Refining, Inc.	$ (12,400)	$ 3,600	$ 70,600	$ 14,700	$ (12,600)	$ 103,500	$ 128,900	$ 111,200	$ 76,500	$ 331,000	$ 241,600
Basic				$ 0.16	$ (0.14)	$ 1.11	$ 1.39	$ 1.20		$ 3.58
Diluted earnings per common share				$ 0.16	$ (0.14)	$ 1.11	$ 1.39	$ 1.20		$ 3.56

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Earnings Per Share - Schedule of Earnings Per Share (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Basic Earnings (loss) per common share:
Distributed earnings									$ (153,691)	$ (129,211)	$ (293,746)
Undistributed Earnings (Loss) Allocated to Participating Securities, Basic									0	0	3
Preferred Stock Dividends and Other Adjustments									0	0	3
Undistributed income (loss) available to common shareholders									$ (28,752)	$ 277,545	$ 266,180
Weighted average number of common shares outstanding:									100,473,000	94,899,000	90,708,000
Earnings Per Share, Basic, Distributed									$ 1.53	$ 1.36	$ 3.24
Undistributed earnings (loss) per common share									(0.29)	2.92	2.93
Basic earnings (loss) per common share	$ (0.09)	$ 0.36	$ 0.70	$ 0.34	$ 0.14	$ 1.61	$ 1.40	$ 1.11	$ 1.24	$ 4.28	$ 6.17
Diluted earnings (loss) per common share:
Net income attributable to Western Refining, Inc.	$ (9,589)	$ 38,575	$ 65,415	$ 30,538	$ 13,545	$ 153,303	$ 133,919	$ 105,989	$ 124,939	$ 406,756	$ 559,926
Tax effected interest related to convertible debt									0	0	8,010
Net income (loss) available to common shareholders, assuming dilution									$ 124,939	$ 406,756	$ 567,936
Weighted average number of diluted shares outstanding									100,868,000	94,999,000	101,190,000
Diluted earnings per common share	$ (0.09)	$ 0.35	$ 0.70	$ 0.33	$ 0.14	$ 1.61	$ 1.40	$ 1.11	$ 1.24	$ 4.28	$ 5.61
Incremental Common Shares Attributable to Share-based Payment Arrangements									395,000	100,000	133,000
Weighted Average Number of Shares, Restricted Stock											884
Incremental Common Shares Attributable to Conversion of Debt Securities									0	0	10,349,000

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Cash Flows (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Supplemental Cash Flow Elements [Abstract]
Income taxes paid	$ 38,227	$ 283,330	$ 227,953
Interest paid	124,037	95,012	83,943
Accrued capital expenditures	28,934	53,361	9,189
Assets acquired through capital lease obligations	4,644	29,082	0
PP&E derecognized from sale leaseback continuing involvement release	2,799	1,773	0
Transfer of capital spares	860	1,490	0
Reduction of long-term debt proceeds for original issuance discount	10,250	0	0
Treasury stock issuance	438,168	0	0
Accrued financing costs	67	0	0
Issuance of common shares for redemption of Western Convertible Notes	0	0	357,608
Distributions accrued on unvested NTI equity awards	$ 0	$ 4,210	$ 0

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Cash Flows (NTI) (Details) - USD ($) $ in Thousands		12 Months Ended
	Sep. 14, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Other Significant Noncash Transactions [Line Items]
Interest paid		$ 124,037	$ 95,012	$ 83,943
Accrued capital expenditures		28,934	53,361	9,189
Northern Tier Energy LP [Member]
Other Significant Noncash Transactions [Line Items]
Interest paid		28,600	29,000	22,500
Income Taxes Paid		100	6,100	5,000
Accrued capital expenditures		11,400	13,800	2,900
Property Plant And Equipment Derecognized Related To Sale Lease Back Transactions		2,800	1,800	0
Change in accrued distributions on participating equity awards			4,200	0
Property Plant And Equipment Recognized Additions Resulting From Capital Lease		300	$ 4,500	$ 1,700
St. Paul Park Logistics Assets [Member] | Western Refining Logistics, LP [Member]
Other Significant Noncash Transactions [Line Items]
Book value of assets sold	$ 48,700
Restricted cash [Member] | St. Paul Park Logistics Assets [Member] | Western Refining Logistics, LP [Member]
Other Significant Noncash Transactions [Line Items]
Other Significant Noncash Transaction, Value of Consideration Received		$ 195,000
Common Units [Member] | Northern Tier Energy LP [Member]
Other Significant Noncash Transactions [Line Items]
Partners' Capital, Other	$ 146,300

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Contingencies (Details)	1 Months Ended		3 Months Ended								12 Months Ended			33 Months Ended	60 Months Ended
	May 31, 2014 USD ($)	May 31, 2000 USD ($)	Dec. 31, 2016 USD ($) employees	Sep. 30, 2016 USD ($)	Jun. 30, 2016 USD ($)	Mar. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)	Sep. 30, 2015 USD ($)	Jun. 30, 2015 USD ($)	Mar. 31, 2015 USD ($)	Dec. 31, 2016 USD ($) employees	Dec. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)	Jul. 31, 2012 USD ($)	Dec. 31, 2013 USD ($)
Loss Contingencies [Line Items]
Accrual for Environmental Loss Contingencies			$ 13,784,000				$ 18,294,000				$ 13,784,000	$ 18,294,000
Cost of products sold (exclusive of depreciation and amortization)			1,721,812,000	$ 1,607,010,000	$ 1,602,628,000	$ 1,047,361,000	1,706,406,000	$ 1,895,772,000	$ 2,177,887,000	$ 1,741,310,000	5,978,811,000	7,521,375,000	$ 12,719,963,000
Environmental Issue [Member] | Texas Natural Resources Conservation Commision [Member] | El Paso Facility [Member]
Loss Contingencies [Line Items]
Litigation Settlement, Amount	$ 200,000
Environmental Issue [Member] | Texas Natural Resources Conservation Commision [Member] | Maximum [Member] | El Paso Facility [Member]
Loss Contingencies [Line Items]
Accrual for Environmental Loss Contingencies			6,500,000								6,500,000
Loss Contingency Accrual, Insurance-related Assessment, Policy Surcharge Asset		$ 20,000,000
Product Liability Contingency, Third Party Recovery, Percentage		60.00%
Environmental Issue [Member] | Four Corners 2005 Consent Agreements [Member] | Four Corners Refineries [Member]
Loss Contingencies [Line Items]
Litigation Settlement, Amount														$ 2,700,000
Loss Contingency, Loss in Period											100,000	100,000	1,900,000		$ 50,800,000
Environmental Issue [Member] | Gallup 2014 Environmental Protection Division of NMED Settlement [Member] | Four Corners Refineries [Member]
Loss Contingencies [Line Items]
Litigation Settlement, Amount	$ 100,000
Environmental Costs Recognized, Capitalized in Period												0
Environmental Issue [Member] | Gallup 2017 EPA RCRA Order [Member] | Four Corners Refineries [Member]
Loss Contingencies [Line Items]
Accrual for Environmental Loss Contingencies			100,000								100,000
Environmental Issue [Member] | NTI MPCA Waste Water Permit [Member] | Maximum [Member] | St. Paul Park, Minnesota [Member]
Loss Contingencies [Line Items]
Loss Contingency, Estimate of Possible Loss			900,000				6,000,000				900,000	6,000,000
Gain (Loss) Related to Litigation Settlement												3,500,000
Environmental Issue [Member] | Renewable Identification Number [Member]
Loss Contingencies [Line Items]
Cost of products sold (exclusive of depreciation and amortization)											65,400,000	35,500,000	$ 28,200,000
Northern Tier Energy LP [Member]
Loss Contingencies [Line Items]
Accrual for Environmental Loss Contingencies, Discount			600,000								600,000
Accrual for Environmental Loss Contingencies			3,400,000				8,600,000				3,400,000	8,600,000
Northern Tier Energy LP [Member] | Environmental Issue [Member]
Loss Contingencies [Line Items]
Accrual for Environmental Loss Contingencies, Discount			$ 2,500,000				2,600,000				$ 2,500,000	2,600,000
Fair Value Assumptions, Expected Term											21 years
Accrual for Environmental Loss Contingencies, Discount Rate			2.82%								2.82%
Effect on Future Cash Flows, Amount											$ 3,100,000
Accrual for Environmental Loss Contingencies			$ 3,400,000				8,600,000				3,400,000	8,600,000
Loss Contingency, Receivable			$ 100,000				$ 100,000				$ 100,000	$ 100,000
Retail Group [Member] | Northern Tier Energy LP [Member]
Loss Contingencies [Line Items]
Entity Number of Employees | employees			26								26

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Contingencies (NTI) (Details) - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Sep. 30, 2015	Dec. 31, 2016	Dec. 31, 2015
Loss Contingencies [Line Items]
Accrual for Environmental Loss Contingencies		$ 13,784	$ 18,294
Northern Tier Energy LP [Member]
Loss Contingencies [Line Items]
Accrual for Environmental Loss Contingencies		3,400	8,600
Accrual for Environmental Loss Contingencies, Gross		4,000
Accrual for Environmental Loss Contingencies, Discount		(600)
Accrual for Environmental Loss Contingencies, Undiscounted, Next Twelve Months		1,400
Accrual for Environmental Loss Contingencies, Undiscounted, Second Year		300
Accrual for Environmental Loss Contingencies, Undiscounted, Third Year		100
Accrual for Environmental Loss Contingencies, Undiscounted, Fourth Year		100
Accrual for Environmental Loss Contingencies, Undiscounted, Fifth Year		100
Accrual for Envrionmental Loss Contingencies, Undiscounted, after fifth year		$ 2,000
Super America Franchising Company [Member]
Loss Contingencies [Line Items]
Standard License Term Of Franchise Store Agreements		10 years
Groundwater Contamination [Member] | Northern Tier Energy LP [Member]
Loss Contingencies [Line Items]
Accrual for Environmental Loss Contingencies		$ 2,500	2,600
Period Of Remediation Liabilities		21 years
Accrual for Environmental Loss Contingencies, Gross		$ 3,100
Accrual for Environmental Loss Contingencies, Discount		$ (600)
Accrual for Environmental Loss Contingencies, Discount Rate		2.82%
Receivables For Recoverable Costs		$ 100	100
Accrual for Environmental Loss Contingencies, Undiscounted, Next Twelve Months		500
Accrual for Environmental Loss Contingencies, Undiscounted, Second Year		300
Accrual for Environmental Loss Contingencies, Undiscounted, Third Year		100
Accrual for Environmental Loss Contingencies, Undiscounted, Fourth Year		100
Accrual for Environmental Loss Contingencies, Undiscounted, Fifth Year		100
Accrual for Envrionmental Loss Contingencies, Undiscounted, after fifth year		2,000
Wastewater Lagoon [Member] | Northern Tier Energy LP [Member]
Loss Contingencies [Line Items]
Accrual for Environmental Loss Contingencies		900
Accrual for Environmental Loss Contingencies, Gross		900
Accrual for Environmental Loss Contingencies, Discount		0
Accrual for Environmental Loss Contingencies, Undiscounted, Next Twelve Months		900	$ 6,000
Litigation Settlement, Amount	$ 3,500
Accrual for Environmental Loss Contingencies, Undiscounted, Second Year		0
Accrual for Environmental Loss Contingencies, Undiscounted, Third Year		0
Accrual for Environmental Loss Contingencies, Undiscounted, Fourth Year		0
Accrual for Environmental Loss Contingencies, Undiscounted, Fifth Year		0
Accrual for Envrionmental Loss Contingencies, Undiscounted, after fifth year		0
Settled Litigation [Member] | Telephone Consumer Protection Act [Member] | Minimum [Member]
Loss Contingencies [Line Items]
Loss Contingency, Estimate of Possible Loss		2,200
Settled Litigation [Member] | Telephone Consumer Protection Act [Member] | Maximum [Member]
Loss Contingencies [Line Items]
Loss Contingency, Estimate of Possible Loss		$ 3,500

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Concentration of Risk (Details)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Concentration Risk [Line Items]
Major Customer Above Benchmark, Number	0	0
PMI Trading Limited [Member] | Sales [Member] | Customer Concentration Risk [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	6.00%	6.30%	5.50%
Minimum [Member] | Sales [Member] | Customer Concentration Risk [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	10.00%

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Leases and Other Commitments - Operating Leases (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Operating Leased Assets [Line Items]
Operating Leases, Future Minimum Payments Due	$ 546,803
Operating Leases, Rent Expense, Net [Abstract]
Operating Leases, Rent Expense, Net	71,600	$ 64,700	$ 53,700
Operating Leases, Future Minimum Payments Due [Abstract]
2017	55,675
2018	52,509
2019	47,269
2020	42,420
2021	43,284
2022 and thereafter	305,646
Sulfuric Acid Regeneration Units [Member]
Operating Leased Assets [Line Items]
Operating Leases, Future Minimum Payments Due	$ 15,700

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Leases and Other Commitments - Capital Leases (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)
Capital Leased Assets [Line Items]
Capital Leases, Future Minimum Payments Due, Next Twelve Months	$ 5,419
Capital Leases, Future Minimum Payments Due	95,190
Capital Leases, Future Minimum Payments Due in Five Years	5,891
Capital Leases, Future Minimum Payments Due in Four Years	5,744
Capital Leases, Future Minimum Payments Due in Three Years	5,553
Capital Leases, Future Minimum Payments Due in Two Years	$ 5,444
Capital Leased Assets, Number of Units	38
Description of Lessee Leasing Arrangements, Capital Leases	20
Capital Lease Obligations, Current	$ 1,300	$ 1,000
Lease financing obligation	54,163	53,232
Deferred Gain on Sale of Property	200
Capital Leases, Future Minimum Payments, Interest Included in Payments	39,960	$ 44,100
Capital Leases, Future Minimum Payments, Annual, Due in Next Five Years	5,600
Capital Leases, Future Minimum Payments Due Thereafter	67,139
Capital Leases, Future Minimum Payments, Present Value of Net Minimum Payments	$ 55,230
Minimum [Member]
Capital Leased Assets [Line Items]
Discount Rate, Capital Leases	3.24%
Maximum [Member]
Capital Leased Assets [Line Items]
Discount Rate, Capital Leases	10.51%
El Paso Office Building [Member]
Capital Leased Assets [Line Items]
Description of Lessee Leasing Arrangements, Operating Leases	10
Office Building, Tempe [Member]
Capital Leased Assets [Line Items]
Description of Lessee Leasing Arrangements, Operating Leases	11

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Leases and Other Commitments - NTI Capital Leases (Details) $ in Thousands	Dec. 31, 2016 USD ($) stores_stations Store	Dec. 31, 2015 USD ($)
Capital Leased Assets [Line Items]
Number of Stores | stores_stations	544
Capital Leases, Future Minimum Payments, Interest Included in Payments	$ 39,960	$ 44,100
Capital Leases, Future Minimum Payments Due	95,190
Capital Leases, Future Minimum Payments Due Thereafter	67,139
Capital Leases, Future Minimum Payments Due in Five Years	5,891
Capital Leases, Future Minimum Payments Due in Four Years	5,744
Capital Leases, Future Minimum Payments Due in Three Years	5,553
Capital Leases, Future Minimum Payments Due in Two Years	5,444
Capital Leases, Future Minimum Payments Due, Next Twelve Months	5,419
Capital Leases, Future Minimum Payments, Present Value of Net Minimum Payments	55,230
Northern Tier Energy LP [Member]
Capital Leased Assets [Line Items]
Capital Leases, Future Minimum Payments, Interest Included in Payments	8,400
Capital Leases, Future Minimum Payments Due	17,600
Capital Leases, Future Minimum Payments Due Thereafter	12,200
Capital Leases, Future Minimum Payments Due in Five Years	1,100
Capital Leases, Future Minimum Payments Due in Four Years	1,100
Capital Leases, Future Minimum Payments Due in Three Years	1,100
Capital Leases, Future Minimum Payments Due in Two Years	1,000
Capital Leases, Future Minimum Payments Due, Next Twelve Months	1,100
Capital Leases, Future Minimum Payments, Present Value of Net Minimum Payments	$ 9,200
Marathon [Member] | Northern Tier Energy LP [Member]
Capital Leased Assets [Line Items]
Number of Stores | Store	135
Number of Stores Under Lease | Store	133

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Leases and Other Commitments - NTI Operating Leases (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Operating Leased Assets [Line Items]
Operating Leases, Future Minimum Payments Due	$ 546,803
2022 and thereafter	305,646
2021	43,284
2020	42,420
2019	47,269
2018	52,509
2017	55,675
Capital Leases, Future Minimum Payments, Interest Included in Payments	39,960	$ 44,100
Northern Tier Energy LP [Member]
Operating Leased Assets [Line Items]
Operating Leases, Rent Expense	28,300	$ 25,100	$ 25,400
Operating Leases, Future Minimum Payments Due	273,500
2022 and thereafter	139,200
2021	27,200
2020	25,600
2019	26,200
2018	27,500
2017	27,800
Total Leases, Future Minimum Payments Due, Next Twelve Months	28,900
Total Leases, Future Minimum Payments Due in Two Years	28,500
Total Leases, Future Minimum Payments Due in Three Years	27,300
Total Leases, Future Minimum Payments Due in Four Years	26,700
Total Leases, Future Minimum Payments Due in Five Years	28,300
Total Leases, Future Minimum Payments Due Thereafter	151,400
Total Leases, Future Minimum Payments Due	291,100
Capital Leases, Future Minimum Payments, Interest Included in Payments	8,400
Total Leases, Future Minimum Payments, Present Value of Net Minimum Payments	$ 282,700

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Related Party Transactions (Details) - USD ($)	6 Months Ended	12 Months Ended
	Jun. 30, 2014	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
El Paso Office Building [Member]
Related Party Transaction [Line Items]
Related Party Transaction, Expenses from Transactions with Related Party		$ 200,000
Operating Leases, Rent Expense		200,000	$ 214,000	$ 214,000
Capital Lease Obligations		0
Northern Tier Energy LP [Member]
Related Party Transaction [Line Items]
Operating Leases, Rent Expense		28,300,000	25,100,000	25,400,000
Northern Tier Energy LP [Member] | Minnesota Pipe Line Company [Member]
Related Party Transaction [Line Items]
Gas Gathering, Transportation, Marketing and Processing Costs		$ 52,200,000	$ 55,400,000	$ 12,600,000
Shipping, Handling and Transportation Costs	$ 0

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Related Party Transactions (NTI) (Details) bbl in Millions		12 Months Ended
	Sep. 14, 2016 USD ($)	Dec. 31, 2016 USD ($) mi bbl	Dec. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)	Sep. 30, 2016 mi bbl
Related Party Transaction [Line Items]
Active Storage Capacity | bbl		12.4
Accounts Payable [Member] | Minnesota Pipe Line Company, LLC [Member]
Related Party Transaction [Line Items]
Due to Affiliate		$ (1,500,000)	$ (2,700,000)
Accounts Receivable [Member] | Western Refining, Inc. [Member]
Related Party Transaction [Line Items]
Due from Affiliates		$ 3,700,000	2,800,000
Northern Tier Energy LP [Member]
Related Party Transaction [Line Items]
Limited Liability Company (LLC) or Limited Partnership (LP), Managing Member or General Partner, Ownership Interest		100.00%
Northern Tier Energy LP [Member] | Public [Member]
Related Party Transaction [Line Items]
Limited Liability Company (LLC) or Limited Partnership (LP), Managing Member or General Partner, Ownership Interest		100.00%
Northern Tier Energy LP [Member] | Accounts Receivable [Member] | Western Refining Logistics, LP [Member]
Related Party Transaction [Line Items]
Due to Affiliate		$ (2,000,000)	0
Western Refining Logistics, LP [Member]
Related Party Transaction [Line Items]
Limited Liability Company (LLC) or Limited Partnership (LP), Managing Member or General Partner, Ownership Interest		100.00%
Northern Tier Energy GP LLC [Member] | Public [Member]
Related Party Transaction [Line Items]
Limited Liability Company (LLC) or Limited Partnership (LP), Managing Member or General Partner, Ownership Interest		100.00%
Sale Of Asphalt [Member] | Northern Tier Energy LP [Member] | Western Refining, Inc. [Member]
Related Party Transaction [Line Items]
Related Party Transaction, Amounts of Transaction		$ 32,000,000	46,600,000	$ 19,000,000
Sale of Feedstock [Member] | Northern Tier Energy LP [Member] | Western Refining, Inc. [Member]
Related Party Transaction [Line Items]
Related Party Transaction, Amounts of Transaction		0	600,000	0
Sublease of Rail Cars [Member] | Northern Tier Energy LP [Member] | Western Refining, Inc. [Member]
Related Party Transaction [Line Items]
Related Party Transaction, Amounts of Transaction		200,000	200,000	100,000
Purchase of Crude Oil [Member] | Northern Tier Energy LP [Member] | Western Refining, Inc. [Member]
Related Party Transaction [Line Items]
Related Party Transaction, Amounts of Transaction		0	0	6,300,000
Purchases Of Refined Product [Member] | Northern Tier Energy LP [Member] | Western Refining, Inc. [Member]
Related Party Transaction [Line Items]
Related Party Transaction, Amounts of Transaction		0	1,500,000	0
Tank and Terminal Service Fees [Member] | Northern Tier Energy LP [Member] | Western Refining, Inc. [Member]
Related Party Transaction [Line Items]
Related Party Transaction, Amounts of Transaction		13,600,000	0	0
shared service [Member] | Northern Tier Energy LP [Member] | Western Refining, Inc. [Member]
Related Party Transaction [Line Items]
Related Party Transaction, Amounts of Transaction		600,000	3,600,000	1,100,000
shared service [Member] | Northern Tier Energy LP [Member] | Western Refining Logistics, LP [Member]
Related Party Transaction [Line Items]
Related Party Transaction, Amounts of Transaction		400,000	0	0
Crude Transportation Costs [Member] | Northern Tier Energy LP [Member] | Minnesota Pipe Line Company, LLC [Member]
Related Party Transaction [Line Items]
Related Party Transaction, Amounts of Transaction		$ 52,200,000	$ 55,400,000	$ 12,600,000
St. Paul Park Logistics Assets [Member]
Related Party Transaction [Line Items]
Pipeline, Miles | mi					2.5
St. Paul Park Logistics Assets [Member] | Northern Tier Energy LP [Member]
Related Party Transaction [Line Items]
Pipeline, Miles | mi		2.5
St. Paul Park Logistics Assets [Member] | Western Refining Logistics, LP [Member]
Related Party Transaction [Line Items]
Book value of assets sold	$ 48,700,000
St. Paul Park Logistics Assets [Member] | Crude Oil Storage Tanks [Member]
Related Party Transaction [Line Items]
Active Storage Capacity | bbl					4.0
St. Paul Park Logistics Assets [Member] | Crude Oil Storage Tanks [Member] | Northern Tier Energy LP [Member]
Related Party Transaction [Line Items]
Active Storage Capacity | bbl		4.0
Restricted cash [Member] | St. Paul Park Logistics Assets [Member] | Western Refining Logistics, LP [Member]
Related Party Transaction [Line Items]
Other Significant Noncash Transaction, Value of Consideration Received		$ 195,000,000
Common Units [Member] | St. Paul Park Logistics Assets [Member] | Western Refining Logistics, LP [Member]
Related Party Transaction [Line Items]
Business Combination, Consideration Transferred, Equity Interests Issued and Issuable	628,224
Common Units [Member] | Northern Tier Energy LP [Member]
Related Party Transaction [Line Items]
Partners' Capital, Other	$ 146,300,000
Minnesota Pipe Line Company [Member]
Related Party Transaction [Line Items]
Equity Method Investment, Ownership Percentage		17.00%
Minnesota Pipe Line Company [Member] | Northern Tier Energy LP [Member]
Related Party Transaction [Line Items]
Equity Method Investment, Ownership Percentage		17.00%

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Condensed Consolidating Financial Information - Condensed Balance Sheet (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Assets, Current [Abstract]
Cash and cash equivalents	$ 268,581	$ 772,502	$ 431,159	$ 468,070
Accounts receivable, trade, net of a reserve for doubtful accounts	423,171	359,237
Accounts receivable, affiliate	0	0
Inventories	771,989	547,538
Prepaid expenses	95,355	73,213
Other current assets	113,421	169,728
Total current assets	1,672,517	1,922,218
Restricted cash	0	69,106
Property, plant and equipment, net	2,364,482	2,305,171
Goodwill	1,289,443	1,289,443
Intangible assets, net	83,812	84,945
Equity method investment	102,685	97,513
Investment in subsidiaries	0	0
Due from affiliate	0	0
Other assets	47,458	64,997
Total assets	5,560,397	5,833,393	5,642,186
Liabilities, Current [Abstract]
Accounts payable, trade	753,933	553,957
Accounts payable, affiliate	0	0
Accrued liabilities	219,607	248,395
Current portion of long-term debt	10,500	5,500
Total current liabilities	984,040	807,852
Long-term debt, less current portion	1,871,805	1,644,894
Due to affiliate	0	0
Lease financing obligation	54,163	53,232
Deferred income tax liability, net	260,293	312,914
Deficit in subsidiaries	0	0
Other liabilities	93,136	68,595
Total long-term liabilities	2,279,397	2,079,635
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest [Abstract]
Equity - Western	1,696,860	1,299,297
Non-controlling interest	600,100	1,646,609
Total equity	2,296,960	2,945,906	2,787,644	2,570,587
Total liabilities and equity	5,560,397	5,833,393
Reportable Legal Entities [Member] | Parent Company [Member]
Assets, Current [Abstract]
Cash and cash equivalents	21	21	21	21
Accounts receivable, trade, net of a reserve for doubtful accounts	0	0
Accounts receivable, affiliate	16,832	0
Inventories	0	0
Prepaid expenses	0	0
Other current assets	0	0
Total current assets	16,853	21
Restricted cash		0
Property, plant and equipment, net	0	0
Goodwill	0	0
Intangible assets, net	0	0
Equity method investment	0	0
Investment in subsidiaries	5,348,171	3,790,958
Due from affiliate	0	0
Other assets	0	0
Total assets	5,365,024	3,790,979
Liabilities, Current [Abstract]
Accounts payable, trade	0	0
Accounts payable, affiliate	0	920
Accrued liabilities	5,655	5,508
Current portion of long-term debt	10,500	5,500
Total current liabilities	16,155	11,928
Long-term debt, less current portion	1,208,703	856,327
Due to affiliate	2,443,306	1,623,427
Lease financing obligation	0	0
Deferred income tax liability, net	0	0
Deficit in subsidiaries	0	0
Other liabilities	0	0
Total long-term liabilities	3,652,009	2,479,754
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest [Abstract]
Equity - Western	1,696,860	1,299,297
Non-controlling interest	0	0
Total equity	1,696,860	1,299,297
Total liabilities and equity	5,365,024	3,790,979
Reportable Legal Entities [Member] | Guarantor Subsidiaries [Member]
Assets, Current [Abstract]
Cash and cash equivalents	224,431	656,966	288,986	296,905
Accounts receivable, trade, net of a reserve for doubtful accounts	117,007	122,593
Accounts receivable, affiliate	72,760	55,550
Inventories	448,012	311,589
Prepaid expenses	80,199	55,699
Other current assets	74,832	135,139
Total current assets	1,017,241	1,337,536
Restricted cash		69,106
Property, plant and equipment, net	1,117,958	1,099,787
Goodwill	0	0
Intangible assets, net	31,516	31,401
Equity method investment	0	0
Investment in subsidiaries	0	0
Due from affiliate	2,443,306	1,623,427
Other assets	27,425	42,166
Total assets	4,637,446	4,203,423
Liabilities, Current [Abstract]
Accounts payable, trade	372,570	262,550
Accounts payable, affiliate	0	0
Accrued liabilities	124,628	142,257
Current portion of long-term debt	0	0
Total current liabilities	497,198	404,807
Long-term debt, less current portion	0	0
Due to affiliate	0	0
Lease financing obligation	45,007	42,168
Deferred income tax liability, net	222,372	275,634
Deficit in subsidiaries	501,776	287,761
Other liabilities	79,501	63,674
Total long-term liabilities	848,656	669,237
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest [Abstract]
Equity - Western	3,291,592	3,129,379
Non-controlling interest	0	0
Total equity	3,291,592	3,129,379
Total liabilities and equity	4,637,446	4,203,423
Reportable Legal Entities [Member] | Non-Guarantor Subsidiaries [Member]
Assets, Current [Abstract]
Cash and cash equivalents	44,129	115,515	142,152	171,144
Accounts receivable, trade, net of a reserve for doubtful accounts	306,164	236,644
Accounts receivable, affiliate	3,736	3,505
Inventories	323,977	235,949
Prepaid expenses	15,156	17,514
Other current assets	38,589	34,589
Total current assets	731,751	643,716
Restricted cash		0
Property, plant and equipment, net	1,246,524	1,205,384
Goodwill	1,289,443	1,289,443
Intangible assets, net	52,296	53,544
Equity method investment	102,685	97,513
Investment in subsidiaries	0	0
Due from affiliate	0	0
Other assets	20,033	22,831
Total assets	3,442,732	3,312,431
Liabilities, Current [Abstract]
Accounts payable, trade	381,363	291,407
Accounts payable, affiliate	93,328	58,135
Accrued liabilities	89,324	100,630
Current portion of long-term debt	0	0
Total current liabilities	564,015	450,172
Long-term debt, less current portion	663,102	788,567
Due to affiliate	0	0
Lease financing obligation	9,156	11,064
Deferred income tax liability, net	37,921	37,280
Deficit in subsidiaries	0	0
Other liabilities	13,635	4,921
Total long-term liabilities	723,814	841,832
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest [Abstract]
Equity - Western	1,554,803	373,818
Non-controlling interest	600,100	1,646,609
Total equity	2,154,903	2,020,427
Total liabilities and equity	3,442,732	3,312,431
Consolidation, Eliminations [Member]
Assets, Current [Abstract]
Cash and cash equivalents	0	0	$ 0	$ 0
Accounts receivable, trade, net of a reserve for doubtful accounts	0	0
Accounts receivable, affiliate	(93,328)	(59,055)
Inventories	0	0
Prepaid expenses	0	0
Other current assets	0	0
Total current assets	(93,328)	(59,055)
Restricted cash		0
Property, plant and equipment, net	0	0
Goodwill	0	0
Intangible assets, net	0	0
Equity method investment	0	0
Investment in subsidiaries	(5,348,171)	(3,790,958)
Due from affiliate	(2,443,306)	(1,623,427)
Other assets	0	0
Total assets	(7,884,805)	(5,473,440)
Liabilities, Current [Abstract]
Accounts payable, trade	0	0
Accounts payable, affiliate	(93,328)	(59,055)
Accrued liabilities	0	0
Current portion of long-term debt	0	0
Total current liabilities	(93,328)	(59,055)
Long-term debt, less current portion	0	0
Due to affiliate	(2,443,306)	(1,623,427)
Lease financing obligation	0	0
Deferred income tax liability, net	0	0
Deficit in subsidiaries	(501,776)	(287,761)
Other liabilities	0	0
Total long-term liabilities	(2,945,082)	(1,911,188)
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest [Abstract]
Equity - Western	(4,846,395)	(3,503,197)
Non-controlling interest	0	0
Total equity	(4,846,395)	(3,503,197)
Total liabilities and equity	$ (7,884,805)	$ (5,473,440)

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Condensed Consolidating Financial Information - Condensed Statement of Operations and Comprehensive Income (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Condensed Income Statements, Captions [Line Items]
Net sales	$ 2,115,325	$ 2,065,076	$ 2,107,308	$ 1,455,504	$ 2,070,324	$ 2,569,090	$ 2,828,892	$ 2,318,730	$ 7,743,213	$ 9,787,036	$ 15,153,573
Operating costs and expenses:
Cost of products sold (exclusive of depreciation and amortization)	1,721,812	1,607,010	1,602,628	1,047,361	1,706,406	1,895,772	2,177,887	1,741,310	5,978,811	7,521,375	12,719,963
Direct operating expenses (exclusive of depreciation and amortization)	240,716	232,553	231,169	223,585	228,451	234,440	224,723	215,311	928,023	902,925	850,634
Selling, general and administrative expenses	51,204	57,320	56,052	53,285	55,437	54,465	59,540	55,803	217,861	225,245	226,020
Merger and reorganization costs	8,453	2,844	735	408					12,440	0	12,878
Loss (gain) and impairments on disposal of assets, net	(90)	(279)	(772)	(130)	208	(52)	(387)	282	(1,271)	51	8,530
Maintenance turnaround expense	19,404	27,208	400	125	836	490	593	105	47,137	2,024	48,469
Depreciation and amortization	55,456	54,321	54,359	52,651	52,845	51,377	51,143	49,926	216,787	205,291	190,566
Total operating costs and expenses	2,096,955	1,980,977	1,944,571	1,377,285	2,044,183	2,236,492	2,513,499	2,062,737	7,399,788	8,856,911	14,057,060
Operating income	18,370	84,099	162,737	78,219	26,141	332,598	315,393	255,993	343,425	930,125	1,096,513
Other income (expense):
Income (Loss) from Equity Method Investments									0	0	0
Interest income	256	141	131	164	153	186	201	163	692	703	1,188
Interest and debt expense	(35,226)	(34,456)	(26,928)	(26,681)	(26,434)	(26,896)	(27,316)	(24,957)	(123,291)	(105,603)	(97,062)
Gains (Losses) on Extinguishment of Debt	(3,916)	0	0	0					(3,916)	0	(9)
Other, net	7,152	6,224	5,076	6,512	1,604	4,327	4,024	3,206	24,964	13,161	2,046
Income before income taxes	(13,364)	56,008	141,016	58,214	1,464	310,215	292,302	234,405	241,874	838,386	1,002,676
Provision for income taxes	13,613	(11,700)	(38,152)	(18,629)	6,034	(92,117)	(78,435)	(59,437)	(54,868)	(223,955)	(292,604)
Net income	249	44,308	102,864	39,585	7,498	218,098	213,867	174,968	187,006	614,431	710,072
Less net income attributed to non-controlling interests	9,838	5,733	37,449	9,047	(6,047)	64,795	79,948	68,979	62,067	207,675	150,146
Net income attributable to Western Refining, Inc.	$ (9,589)	$ 38,575	$ 65,415	$ 30,538	$ 13,545	$ 153,303	$ 133,919	$ 105,989	124,939	406,756	559,926
Comprehensive income attributable to Western Refining, Inc.									125,514	408,698	558,985
Reportable Legal Entities [Member] | Non-Guarantor Subsidiaries [Member]
Condensed Income Statements, Captions [Line Items]
Net sales									5,270,300	5,602,023	8,749,303
Operating costs and expenses:
Cost of products sold (exclusive of depreciation and amortization)									4,385,318	4,521,462	7,772,189
Direct operating expenses (exclusive of depreciation and amortization)									474,273	459,915	441,806
Selling, general and administrative expenses									106,408	106,471	111,754
Merger and reorganization costs									4,681		12,878
Loss (gain) and impairments on disposal of assets, net									(1,064)	(569)	65
Maintenance turnaround expense									45,765	0	0
Depreciation and amortization									110,034	105,649	96,731
Total operating costs and expenses									5,125,415	5,192,928	8,435,423
Operating income									144,885	409,095	313,880
Other income (expense):
Income (Loss) from Equity Method Investments									0	0	0
Interest income									266	314	393
Interest and debt expense									(48,094)	(48,782)	(25,732)
Gains (Losses) on Extinguishment of Debt									0		0
Other, net									23,165	12,669	2,650
Income before income taxes									120,222	373,296	291,191
Provision for income taxes									(2,615)	(47)	(459)
Net income									117,607	373,249	290,732
Less net income attributed to non-controlling interests									62,067	207,675	150,146
Net income attributable to Western Refining, Inc.									55,540	165,574	140,586
Comprehensive income attributable to Western Refining, Inc.									55,355	166,861	140,122
Reportable Legal Entities [Member] | Guarantor Subsidiaries [Member]
Condensed Income Statements, Captions [Line Items]
Net sales									6,178,382	7,543,712	11,004,242
Operating costs and expenses:
Cost of products sold (exclusive of depreciation and amortization)									5,298,962	6,358,612	9,531,146
Direct operating expenses (exclusive of depreciation and amortization)									453,750	443,010	425,428
Selling, general and administrative expenses									111,268	118,585	114,080
Merger and reorganization costs									7,759		0
Loss (gain) and impairments on disposal of assets, net									(207)	620	8,465
Maintenance turnaround expense									1,372	2,024	48,469
Depreciation and amortization									106,753	99,642	93,835
Total operating costs and expenses									5,979,657	7,022,493	10,221,423
Operating income									198,725	521,219	782,819
Other income (expense):
Income (Loss) from Equity Method Investments									16,603	11,551	17,059
Interest income									426	389	795
Interest and debt expense									(3,087)	(2,717)	(1,044)
Gains (Losses) on Extinguishment of Debt									0		0
Other, net									1,799	492	(604)
Income before income taxes									214,466	530,934	799,025
Provision for income taxes									(52,253)	(223,908)	(292,145)
Net income									162,213	307,026	506,880
Less net income attributed to non-controlling interests									0	0	0
Net income attributable to Western Refining, Inc.									162,213	307,026	506,880
Comprehensive income attributable to Western Refining, Inc.									162,973	307,681	506,403
Reportable Legal Entities [Member] | Parent Company [Member]
Condensed Income Statements, Captions [Line Items]
Net sales									0	0	0
Operating costs and expenses:
Cost of products sold (exclusive of depreciation and amortization)									0	0	0
Direct operating expenses (exclusive of depreciation and amortization)									0	0	0
Selling, general and administrative expenses									185	189	186
Merger and reorganization costs									0		0
Loss (gain) and impairments on disposal of assets, net									0	0	0
Maintenance turnaround expense									0	0	0
Depreciation and amortization									0	0	0
Total operating costs and expenses									185	189	186
Operating income									(185)	(189)	(186)
Other income (expense):
Income (Loss) from Equity Method Investments									201,150	461,049	630,407
Interest income									0	0	0
Interest and debt expense									(72,110)	(54,104)	(70,286)
Gains (Losses) on Extinguishment of Debt									(3,916)		(9)
Other, net									0	0	0
Income before income taxes									124,939	406,756	559,926
Provision for income taxes									0	0	0
Net income									124,939	406,756	559,926
Less net income attributed to non-controlling interests									0	0	0
Net income attributable to Western Refining, Inc.									124,939	406,756	559,926
Comprehensive income attributable to Western Refining, Inc.									124,939	406,756	559,926
Consolidation, Eliminations [Member]
Condensed Income Statements, Captions [Line Items]
Net sales									(3,705,469)	(3,358,699)	(4,599,972)
Operating costs and expenses:
Cost of products sold (exclusive of depreciation and amortization)									(3,705,469)	(3,358,699)	(4,583,372)
Direct operating expenses (exclusive of depreciation and amortization)									0	0	(16,600)
Selling, general and administrative expenses									0	0	0
Merger and reorganization costs									0		0
Loss (gain) and impairments on disposal of assets, net									0	0	0
Maintenance turnaround expense									0	0	0
Depreciation and amortization									0	0	0
Total operating costs and expenses									(3,705,469)	(3,358,699)	(4,599,972)
Operating income									0	0	0
Other income (expense):
Income (Loss) from Equity Method Investments									(217,753)	(472,600)	(647,466)
Interest income									0	0	0
Interest and debt expense									0	0	0
Gains (Losses) on Extinguishment of Debt									0		0
Other, net									0	0	0
Income before income taxes									(217,753)	(472,600)	(647,466)
Provision for income taxes									0	0	0
Net income									(217,753)	(472,600)	(647,466)
Less net income attributed to non-controlling interests									0	0	0
Net income attributable to Western Refining, Inc.									(217,753)	(472,600)	(647,466)
Comprehensive income attributable to Western Refining, Inc.									$ (217,753)	$ (472,600)	$ (647,466)

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Condensed Consolidating Financial Information - Condensed Statement of Cash Flows (Details) - USD ($) $ in Thousands		12 Months Ended
	Jun. 10, 2009	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Net Cash Provided by (Used in) Operating Activities [Abstract]
Net Cash Provided by (Used in) Operating Activities		$ 383,747	$ 843,083	$ 737,633
Net Cash Provided by (Used in) Investing Activities [Abstract]
Payments to Acquire Productive Assets		(300,969)	(290,863)	(223,271)
Return of capital on equity method investment		0	0	7,480
Payments to Fund Long-term Loans to Related Parties		0	0	0
Increase in restricted cash		(195,000)	(170,000)	(320,000)
Use of restricted cash		264,106	267,903	152,991
Proceeds from Sale of Productive Assets		5,521	1,114	1,936
Net Cash Provided by (Used in) Investing Activities		(226,342)	(191,846)	(380,864)
Net Cash Provided by (Used in) Financing Activities [Abstract]
Additions to long-term debt		500,000	300,000	79,311
Repayments of Long-term Debt		(135,392)	(7,368)	(6,072)
Distribution to non-controlling interest holders		(66,311)	(238,366)	(173,637)
Borrowings on revolving credit facility		466,900	145,000	269,000
Repayments of Lines of Credit		591,600	269,000	0
Payments to Acquire Additional Interest in Subsidiaries		(859,893)	0	0
Other Payments to Acquire Businesses		(11,741)	0	0
Payments of Financing Costs		(12,727)	(6,820)	(9,649)
Payments of Distributions to Affiliates		0	0	0
Purchases of common stock for treasury		(75,000)	(105,000)	(259,222)
Payments of Dividends		(153,691)	(129,211)	(293,746)
Proceeds from issuance of WNRL common units		277,751	0	0
Payments of Stock Issuance Costs	$ (600)	(655)	0	0
Excess tax benefit from stock-based compensation		1,033	871	1,144
Payments of Capital Distribution			0	0
Payments of Distributions to Affiliates		0	0	0
Convertible debt redemption		0	0	(809)
Net cash used in financing activities		(661,326)	(309,894)	(393,680)
Net increase (decrease) in cash and cash equivalents		(503,921)	341,343	(36,911)
Cash and cash equivalents		268,581	772,502	431,159	$ 468,070
Reportable Legal Entities [Member] | Parent Company [Member]
Net Cash Provided by (Used in) Operating Activities [Abstract]
Net Cash Provided by (Used in) Operating Activities		(41,614)	87,364	(54,846)
Net Cash Provided by (Used in) Investing Activities [Abstract]
Payments to Acquire Productive Assets		0	0	0
Return of capital on equity method investment		97,379		0
Payments to Fund Long-term Loans to Related Parties		0	0	0
Increase in restricted cash		0	0	0
Use of restricted cash		0	0	0
Proceeds from Sale of Productive Assets		0	0	0
Net Cash Provided by (Used in) Investing Activities		97,379	0	0
Net Cash Provided by (Used in) Financing Activities [Abstract]
Additions to long-term debt		500,000	0	0
Repayments of Long-term Debt		(133,000)	(5,500)	(5,759)
Distribution to non-controlling interest holders		0	0	0
Borrowings on revolving credit facility		0	0	0
Repayments of Lines of Credit		0	0
Payments to Acquire Additional Interest in Subsidiaries		(859,893)
Other Payments to Acquire Businesses		(11,741)
Payments of Financing Costs		(11,503)	0	(4,182)
Payments of Distributions to Affiliates		0	0	0
Purchases of common stock for treasury		(75,000)	(105,000)	(259,222)
Payments of Dividends		(153,691)	(129,211)	(293,746)
Proceeds from issuance of WNRL common units		0
Payments of Stock Issuance Costs		0
Excess tax benefit from stock-based compensation		0	0	0
Payments of Capital Distribution			0	0
Payments of Distributions to Affiliates		689,063	152,347	618,564
Convertible debt redemption				(809)
Net cash used in financing activities		(55,765)	(87,364)	54,846
Net increase (decrease) in cash and cash equivalents		0	0	0
Cash and cash equivalents		21	21	21	21
Reportable Legal Entities [Member] | Guarantor Subsidiaries [Member]
Net Cash Provided by (Used in) Operating Activities [Abstract]
Net Cash Provided by (Used in) Operating Activities		331,819	433,863	520,972
Net Cash Provided by (Used in) Investing Activities [Abstract]
Payments to Acquire Productive Assets		(145,760)	(157,600)	(99,204)
Return of capital on equity method investment		0		0
Payments to Fund Long-term Loans to Related Parties		(689,063)	(178,243)	(678,628)
Increase in restricted cash		0	(170,000)	(320,000)
Use of restricted cash		69,106	267,903	152,991
Proceeds from Sale of Productive Assets		1,365	2,028	1,260
Net Cash Provided by (Used in) Investing Activities		(764,352)	(235,912)	(943,581)
Net Cash Provided by (Used in) Financing Activities [Abstract]
Additions to long-term debt		0	0	0
Repayments of Long-term Debt		(1,035)	(842)	0
Distribution to non-controlling interest holders		0	0	0
Borrowings on revolving credit facility		0	0	0
Repayments of Lines of Credit		0	0
Payments to Acquire Additional Interest in Subsidiaries		0
Other Payments to Acquire Businesses		0
Payments of Financing Costs		0	0	0
Payments of Distributions to Affiliates		0	0	0
Purchases of common stock for treasury		0	0	0
Payments of Dividends		0	0	0
Proceeds from issuance of WNRL common units		0
Payments of Stock Issuance Costs		0
Excess tax benefit from stock-based compensation		1,033	871	1,144
Proceeds from Partnership Contribution			170,000	320,000
Payments of Distributions to Affiliates		0	0	93,546
Convertible debt redemption				0
Net cash used in financing activities		(2)	170,029	414,690
Net increase (decrease) in cash and cash equivalents		(432,535)	367,980	(7,919)
Cash and cash equivalents		224,431	656,966	288,986	296,905
Reportable Legal Entities [Member] | Non-Guarantor Subsidiaries [Member]
Net Cash Provided by (Used in) Operating Activities [Abstract]
Net Cash Provided by (Used in) Operating Activities		182,302	502,676	403,087
Net Cash Provided by (Used in) Investing Activities [Abstract]
Payments to Acquire Productive Assets		(156,356)	(134,820)	(124,067)
Return of capital on equity method investment		0		7,480
Payments to Fund Long-term Loans to Related Parties		(20,092)	(27,888)	(119,147)
Increase in restricted cash		(195,000)	0	0
Use of restricted cash		195,000	0	0
Proceeds from Sale of Productive Assets		5,303	643	676
Net Cash Provided by (Used in) Investing Activities		(171,145)	(162,065)	(235,058)
Net Cash Provided by (Used in) Financing Activities [Abstract]
Additions to long-term debt		0	300,000	79,311
Repayments of Long-term Debt		(1,357)	(1,026)	(313)
Distribution to non-controlling interest holders		(66,311)	(238,366)	(173,637)
Borrowings on revolving credit facility		466,900	145,000	269,000
Repayments of Lines of Credit		591,600	269,000
Payments to Acquire Additional Interest in Subsidiaries		0
Other Payments to Acquire Businesses		0
Payments of Financing Costs		(1,224)	(6,820)	(5,467)
Payments of Distributions to Affiliates		(186,139)	(180,820)	(131,580)
Purchases of common stock for treasury		0	0	0
Payments of Dividends		0	0	0
Proceeds from issuance of WNRL common units		277,751
Payments of Stock Issuance Costs		(655)
Excess tax benefit from stock-based compensation		0	0	0
Payments of Capital Distribution			(170,000)	(320,000)
Payments of Distributions to Affiliates		20,092	53,784	85,665
Convertible debt redemption				0
Net cash used in financing activities		(82,543)	(367,248)	(197,021)
Net increase (decrease) in cash and cash equivalents		(71,386)	(26,637)	(28,992)
Cash and cash equivalents		44,129	115,515	142,152	171,144
Consolidation, Eliminations [Member]
Net Cash Provided by (Used in) Operating Activities [Abstract]
Net Cash Provided by (Used in) Operating Activities		(88,760)	(180,820)	(131,580)
Net Cash Provided by (Used in) Investing Activities [Abstract]
Payments to Acquire Productive Assets		1,147	1,557	0
Return of capital on equity method investment		(97,379)		0
Payments to Fund Long-term Loans to Related Parties		709,155	206,131	797,775
Increase in restricted cash		0	0	0
Use of restricted cash		0	0	0
Proceeds from Sale of Productive Assets		(1,147)	(1,557)	0
Net Cash Provided by (Used in) Investing Activities		611,776	206,131	797,775
Net Cash Provided by (Used in) Financing Activities [Abstract]
Additions to long-term debt		0	0	0
Repayments of Long-term Debt		0	0	0
Distribution to non-controlling interest holders		0	0	0
Borrowings on revolving credit facility		0	0	0
Repayments of Lines of Credit		0	0
Payments to Acquire Additional Interest in Subsidiaries		0
Other Payments to Acquire Businesses		0
Payments of Financing Costs		0	0	0
Payments of Distributions to Affiliates		186,139	180,820	131,580
Purchases of common stock for treasury		0	0	0
Payments of Dividends		0	0	0
Proceeds from issuance of WNRL common units		0
Payments of Stock Issuance Costs		0
Excess tax benefit from stock-based compensation		0	0	0
Payments of Capital Distribution			0	0
Payments of Distributions to Affiliates		(709,155)	(206,131)	(797,775)
Convertible debt redemption				0
Net cash used in financing activities		(523,016)	(25,311)	(666,195)
Net increase (decrease) in cash and cash equivalents		0	0	0
Cash and cash equivalents		$ 0	$ 0	$ 0	$ 0

XML

Condensed Consolidating Financial Information - Consolidated Entities (Details) - USD ($) $ in Thousands	2 Months Ended	3 Months Ended								12 Months Ended
	Dec. 31, 2013	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Segment Reporting Information [Line Items]
Net Cash Provided by (Used in) Operating Activities										$ 383,747	$ 843,083	$ 737,633
Net Cash Provided by (Used in) Investing Activities										(226,342)	(191,846)	(380,864)
Net income attributable to Western Refining, Inc.		$ (9,589)	$ 38,575	$ 65,415	$ 30,538	$ 13,545	$ 153,303	$ 133,919	$ 105,989	124,939	406,756	559,926
Total equity	$ 2,570,587	2,296,960				2,945,906				2,296,960	2,945,906	2,787,644
Liabilities						2,887,487					2,887,487
Income (Loss) from Equity Method Investments										0	0	0
Investment in subsidiaries		0				0				0	0
Total assets		5,560,397				5,833,393				5,560,397	5,833,393	5,642,186
Deficit in subsidiaries		0				0				0	0
Equity - Western		1,696,860				1,299,297				1,696,860	1,299,297
Comprehensive income attributable to Western Refining, Inc.										125,514	408,698	558,985
Net cash used in financing activities										(661,326)	(309,894)	(393,680)
Western Refining Logistics GP, LLC [Member]
Segment Reporting Information [Line Items]
Limited Liability Company (LLC) or Limited Partnership (LP), Members or Limited Partners, Ownership Interest	100.00%
Consolidation, Eliminations [Member]
Segment Reporting Information [Line Items]
Net Cash Provided by (Used in) Operating Activities										(88,760)	(180,820)	(131,580)
Net Cash Provided by (Used in) Investing Activities										611,776	206,131	797,775
Net income attributable to Western Refining, Inc.										(217,753)	(472,600)	(647,466)
Total equity		(4,846,395)				(3,503,197)				(4,846,395)	(3,503,197)
Liabilities						(1,970,243)					(1,970,243)
Income (Loss) from Equity Method Investments										(217,753)	(472,600)	(647,466)
Investment in subsidiaries		5,348,171				3,790,958				5,348,171	3,790,958
Advances to Affiliate						3,503,197					3,503,197
Total assets		(7,884,805)				(5,473,440)				(7,884,805)	(5,473,440)
Deficit in subsidiaries		501,776				287,761				501,776	287,761
Equity - Western		(4,846,395)				(3,503,197)				(4,846,395)	(3,503,197)
Comprehensive income attributable to Western Refining, Inc.										(217,753)	(472,600)	(647,466)
Net cash used in financing activities										$ (523,016)	(25,311)	(666,195)
Western Refining Logistics, LP [Member]
Segment Reporting Information [Line Items]
Limited Liability Company (LLC) or Limited Partnership (LP), Members or Limited Partners, Ownership Interest										52.60%
Parent Company [Member] | Reportable Legal Entities [Member]
Segment Reporting Information [Line Items]
Net Cash Provided by (Used in) Operating Activities										$ (41,614)	87,364	(54,846)
Net Cash Provided by (Used in) Investing Activities										97,379	0	0
Net income attributable to Western Refining, Inc.										124,939	406,756	559,926
Total equity		1,696,860				1,299,297				1,696,860	1,299,297
Liabilities						2,491,682					2,491,682
Income (Loss) from Equity Method Investments										201,150	461,049	630,407
Investment in subsidiaries		(5,348,171)				(3,790,958)				(5,348,171)	(3,790,958)
Total assets		5,365,024				3,790,979				5,365,024	3,790,979
Deficit in subsidiaries		0				0				0	0
Equity - Western		1,696,860				1,299,297				1,696,860	1,299,297
Comprehensive income attributable to Western Refining, Inc.										124,939	406,756	559,926
Net cash used in financing activities										(55,765)	(87,364)	54,846
Guarantor Subsidiaries [Member] | Reportable Legal Entities [Member]
Segment Reporting Information [Line Items]
Net Cash Provided by (Used in) Operating Activities										331,819	433,863	520,972
Net Cash Provided by (Used in) Investing Activities										(764,352)	(235,912)	(943,581)
Net income attributable to Western Refining, Inc.										162,213	307,026	506,880
Total equity		3,291,592				3,129,379				3,291,592	3,129,379
Liabilities						1,074,044					1,074,044
Income (Loss) from Equity Method Investments										16,603	11,551	17,059
Investment in subsidiaries		0				0				0	0
Total assets		4,637,446				4,203,423				4,637,446	4,203,423
Deficit in subsidiaries		(501,776)				(287,761)				(501,776)	(287,761)
Equity - Western		3,291,592				3,129,379				3,291,592	3,129,379
Comprehensive income attributable to Western Refining, Inc.										162,973	307,681	506,403
Net cash used in financing activities										(2)	170,029	414,690
Non-Guarantor Subsidiaries [Member] | Reportable Legal Entities [Member]
Segment Reporting Information [Line Items]
Net Cash Provided by (Used in) Operating Activities										182,302	502,676	403,087
Net Cash Provided by (Used in) Investing Activities										(171,145)	(162,065)	(235,058)
Net income attributable to Western Refining, Inc.										55,540	165,574	140,586
Total equity		2,154,903				2,020,427				2,154,903	2,020,427
Liabilities						1,292,004					1,292,004
Income (Loss) from Equity Method Investments										0	0	0
Investment in subsidiaries		0				0				0	0
Total assets		3,442,732				3,312,431				3,442,732	3,312,431
Deficit in subsidiaries		0				0				0	0
Equity - Western		$ 1,554,803				373,818				1,554,803	373,818
Comprehensive income attributable to Western Refining, Inc.										55,355	166,861	140,122
Net cash used in financing activities										$ (82,543)	(367,248)	(197,021)
Scenario, Previously Reported [Member]
Segment Reporting Information [Line Items]
Net Cash Provided by (Used in) Operating Activities											843,083	737,633
Net Cash Provided by (Used in) Investing Activities											(191,846)	(380,864)
Net income attributable to Western Refining, Inc.											406,756	559,926
Total equity						2,945,906					2,945,906
Liabilities						2,887,487					2,887,487
Income (Loss) from Equity Method Investments											0	0
Investment in subsidiaries						0					0
Total assets						5,833,393					5,833,393
Comprehensive income attributable to Western Refining, Inc.											408,698	558,985
Net cash used in financing activities											(309,894)	(393,680)
Scenario, Previously Reported [Member] | Consolidation, Eliminations [Member]
Segment Reporting Information [Line Items]
Net Cash Provided by (Used in) Operating Activities											(180,820)	(131,580)
Net Cash Provided by (Used in) Investing Activities											178,243	772,174
Net income attributable to Western Refining, Inc.											(503,519)	(682,154)
Total equity						(3,568,804)					(3,568,804)
Liabilities						(2,251,876)					(2,251,876)
Income (Loss) from Equity Method Investments											(503,519)	(682,154)
Investment in subsidiaries						3,568,804					3,568,804
Total assets						(5,820,680)					(5,820,680)
Comprehensive income attributable to Western Refining, Inc.											(503,519)	(682,154)
Net cash used in financing activities											2,577	(640,594)
Scenario, Previously Reported [Member] | Parent Company [Member] | Reportable Legal Entities [Member]
Segment Reporting Information [Line Items]
Net Cash Provided by (Used in) Operating Activities											87,364	(54,846)
Net Cash Provided by (Used in) Investing Activities											0	0
Net income attributable to Western Refining, Inc.											406,756	559,926
Total equity						1,299,297					1,299,297
Liabilities						2,665,302					2,665,302
Income (Loss) from Equity Method Investments											461,049	630,407
Investment in subsidiaries						(3,964,578)					(3,964,578)
Total assets						3,964,599					3,964,599
Comprehensive income attributable to Western Refining, Inc.											406,756	559,926
Net cash used in financing activities											(87,364)	54,846
Scenario, Previously Reported [Member] | Guarantor Subsidiaries [Member] | Reportable Legal Entities [Member]
Segment Reporting Information [Line Items]
Net Cash Provided by (Used in) Operating Activities											433,863	520,972
Net Cash Provided by (Used in) Investing Activities											(235,912)	(943,581)
Net income attributable to Western Refining, Inc.											337,945	541,568
Total equity						3,194,986					3,194,986
Liabilities						1,182,057					1,182,057
Income (Loss) from Equity Method Investments											42,470	51,747
Investment in subsidiaries						(395,774)					(395,774)
Total assets						4,377,043					4,377,043
Comprehensive income attributable to Western Refining, Inc.											338,600	541,091
Net cash used in financing activities											170,029	414,690
Scenario, Previously Reported [Member] | Non-Guarantor Subsidiaries [Member] | Reportable Legal Entities [Member]
Segment Reporting Information [Line Items]
Net Cash Provided by (Used in) Operating Activities											502,676	403,087
Net Cash Provided by (Used in) Investing Activities											(134,177)	(209,457)
Net income attributable to Western Refining, Inc.											165,574	140,586
Total equity						2,020,427					2,020,427
Liabilities						1,292,004					1,292,004
Income (Loss) from Equity Method Investments											0	0
Investment in subsidiaries						0					0
Total assets						3,312,431					3,312,431
Comprehensive income attributable to Western Refining, Inc.											166,861	140,122
Net cash used in financing activities											(395,136)	(222,622)
Scenario, Adjustment [Member]
Segment Reporting Information [Line Items]
Net Cash Provided by (Used in) Operating Activities											0	0
Net Cash Provided by (Used in) Investing Activities											0	0
Net income attributable to Western Refining, Inc.											0	0
Total equity						0					0
Liabilities						0					0
Income (Loss) from Equity Method Investments											0	0
Investment in subsidiaries						0					0
Total assets						0					0
Comprehensive income attributable to Western Refining, Inc.											0	0
Net cash used in financing activities											0	0
Scenario, Adjustment [Member] | Consolidation, Eliminations [Member]
Segment Reporting Information [Line Items]
Net Cash Provided by (Used in) Operating Activities											0	0
Net Cash Provided by (Used in) Investing Activities											27,888	25,601
Net income attributable to Western Refining, Inc.											30,919	34,688
Total equity						65,607					65,607
Liabilities						281,633					281,633
Income (Loss) from Equity Method Investments											30,919	34,688
Investment in subsidiaries						(65,607)					(65,607)
Total assets						347,240					347,240
Comprehensive income attributable to Western Refining, Inc.											30,919	34,688
Net cash used in financing activities											(27,888)	(25,601)
Scenario, Adjustment [Member] | Parent Company [Member] | Reportable Legal Entities [Member]
Segment Reporting Information [Line Items]
Net Cash Provided by (Used in) Operating Activities											0	0
Net Cash Provided by (Used in) Investing Activities											0	0
Net income attributable to Western Refining, Inc.											0	0
Total equity						0					0
Liabilities						(173,620)					(173,620)
Income (Loss) from Equity Method Investments											0	0
Investment in subsidiaries						173,620					173,620
Total assets						(173,620)					(173,620)
Comprehensive income attributable to Western Refining, Inc.											0	0
Net cash used in financing activities											0	0
Scenario, Adjustment [Member] | Guarantor Subsidiaries [Member] | Reportable Legal Entities [Member]
Segment Reporting Information [Line Items]
Net Cash Provided by (Used in) Operating Activities											0	0
Net Cash Provided by (Used in) Investing Activities											0	0
Net income attributable to Western Refining, Inc.											(30,919)	(34,688)
Total equity						(65,607)					(65,607)
Liabilities						(108,013)					(108,013)
Income (Loss) from Equity Method Investments											(30,919)	(34,688)
Investment in subsidiaries						(108,013)					(108,013)
Total assets						(173,620)					(173,620)
Comprehensive income attributable to Western Refining, Inc.											(30,919)	(34,688)
Net cash used in financing activities											0	0
Scenario, Adjustment [Member] | Non-Guarantor Subsidiaries [Member] | Reportable Legal Entities [Member]
Segment Reporting Information [Line Items]
Net Cash Provided by (Used in) Operating Activities											0	0
Net Cash Provided by (Used in) Investing Activities											(27,888)	(25,601)
Net income attributable to Western Refining, Inc.											0	0
Total equity						0					0
Liabilities						0					0
Income (Loss) from Equity Method Investments											0	0
Investment in subsidiaries						0					0
Total assets						$ 0					0
Comprehensive income attributable to Western Refining, Inc.											0	0
Net cash used in financing activities											$ 27,888	$ 25,601

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Quarterly Financial Information (Unaudited) (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Quarterly Financial Information Disclosure [Abstract]
Net sales	$ 2,115,325	$ 2,065,076	$ 2,107,308	$ 1,455,504	$ 2,070,324	$ 2,569,090	$ 2,828,892	$ 2,318,730	$ 7,743,213	$ 9,787,036	$ 15,153,573
Operating costs and expenses:
Cost of products sold (exclusive of depreciation and amortization)	1,721,812	1,607,010	1,602,628	1,047,361	1,706,406	1,895,772	2,177,887	1,741,310	5,978,811	7,521,375	12,719,963
Direct operating expenses (exclusive of depreciation and amortization)	240,716	232,553	231,169	223,585	228,451	234,440	224,723	215,311	928,023	902,925	850,634
Selling, general and administrative expenses	51,204	57,320	56,052	53,285	55,437	54,465	59,540	55,803	217,861	225,245	226,020
Merger and reorganization costs	8,453	2,844	735	408					12,440	0	12,878
Loss (gain) and impairments on disposal of assets, net	(90)	(279)	(772)	(130)	208	(52)	(387)	282	(1,271)	51	8,530
Maintenance turnaround expense	19,404	27,208	400	125	836	490	593	105	47,137	2,024	48,469
Depreciation and amortization	55,456	54,321	54,359	52,651	52,845	51,377	51,143	49,926	216,787	205,291	190,566
Total operating costs and expenses	2,096,955	1,980,977	1,944,571	1,377,285	2,044,183	2,236,492	2,513,499	2,062,737	7,399,788	8,856,911	14,057,060
Operating income	18,370	84,099	162,737	78,219	26,141	332,598	315,393	255,993	343,425	930,125	1,096,513
Other income (expense):
Interest income	256	141	131	164	153	186	201	163	692	703	1,188
Interest and debt expense	(35,226)	(34,456)	(26,928)	(26,681)	(26,434)	(26,896)	(27,316)	(24,957)	(123,291)	(105,603)	(97,062)
Loss on extinguishment of debt	3,916	0	0	0					3,916	0	9
Other, net	7,152	6,224	5,076	6,512	1,604	4,327	4,024	3,206	24,964	13,161	2,046
Income before income taxes	(13,364)	56,008	141,016	58,214	1,464	310,215	292,302	234,405	241,874	838,386	1,002,676
Provision for income taxes	13,613	(11,700)	(38,152)	(18,629)	6,034	(92,117)	(78,435)	(59,437)	(54,868)	(223,955)	(292,604)
Net income	249	44,308	102,864	39,585	7,498	218,098	213,867	174,968	187,006	614,431	710,072
Less net income attributed to non-controlling interests	9,838	5,733	37,449	9,047	(6,047)	64,795	79,948	68,979	62,067	207,675	150,146
Net income attributable to Western Refining, Inc.	$ (9,589)	$ 38,575	$ 65,415	$ 30,538	$ 13,545	$ 153,303	$ 133,919	$ 105,989	$ 124,939	$ 406,756	$ 559,926
Net earnings per share:
Basic	$ (0.09)	$ 0.36	$ 0.70	$ 0.34	$ 0.14	$ 1.61	$ 1.40	$ 1.11	$ 1.24	$ 4.28	$ 6.17
Diluted earnings per common share	$ (0.09)	$ 0.35	$ 0.70	$ 0.33	$ 0.14	$ 1.61	$ 1.40	$ 1.11	$ 1.24	$ 4.28	$ 5.61

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Quarterly Financial Information (Unaudited) (NTI) (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Operating income	$ 18,370	$ 84,099	$ 162,737	$ 78,219	$ 26,141	$ 332,598	$ 315,393	$ 255,993	$ 343,425	$ 930,125	$ 1,096,513
Net income attributable to Western Refining, Inc.	$ (9,589)	$ 38,575	$ 65,415	$ 30,538	$ 13,545	$ 153,303	$ 133,919	$ 105,989	$ 124,939	$ 406,756	$ 559,926
Basic	$ (0.09)	$ 0.36	$ 0.70	$ 0.34	$ 0.14	$ 1.61	$ 1.40	$ 1.11	$ 1.24	$ 4.28	$ 6.17
Diluted earnings per common share	$ (0.09)	$ 0.35	$ 0.70	$ 0.33	$ 0.14	$ 1.61	$ 1.40	$ 1.11	$ 1.24	$ 4.28	$ 5.61
Northern Tier Energy LP [Member]
Revenues	$ 739,600	$ 732,300	$ 812,300	$ 604,400	$ 759,800	$ 891,600	$ 959,800	$ 793,800	$ 2,888,600	$ 3,405,000	$ 5,556,000
Operating income	(5,500)	11,600	77,700	21,800	(5,300)	114,600	139,300	119,500	105,600	368,100	275,300
Net income attributable to Western Refining, Inc.	$ (12,400)	$ 3,600	$ 70,600	$ 14,700	$ (12,600)	$ 103,500	$ 128,900	$ 111,200	$ 76,500	$ 331,000	$ 241,600
Basic				$ 0.16	$ (0.14)	$ 1.11	$ 1.39	$ 1.20		$ 3.58
Diluted earnings per common share				$ 0.16	$ (0.14)	$ 1.11	$ 1.39	$ 1.20		$ 3.56

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Western Refining Logistics, L.P. - (Details) bbl in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2016 USD ($) mi shares bbl	Dec. 31, 2015 shares	Dec. 31, 2014
Variable Interest Entity [Line Items]
Active Storage Capacity | bbl	12.4
Western Refining Logistics, LP [Member]
Variable Interest Entity [Line Items]
Active Storage Capacity | bbl	12.4
Pipeline, Miles | mi	705
Western Refining, Inc. [Member] | Common Units [Member]
Variable Interest Entity [Line Items]
Limited Partners' Capital Account, Units Outstanding | shares		9,207,847
Western Refining Logistics, LP [Member]
Variable Interest Entity [Line Items]
Limited Liability Company (LLC) or Limited Partnership (LP), Members or Limited Partners, Ownership Interest	52.60%
Subordinated Units [Member] | Western Refining, Inc. [Member] | Subordinated Units [Member]
Variable Interest Entity [Line Items]
Limited Partners' Capital Account, Units Outstanding | shares	22,811,000
Customer Concentration Risk [Member] | Sales Revenue, Net [Member] | Western Refining, Inc. [Member]
Variable Interest Entity [Line Items]
Concentration Risk, Percentage	31.60%	30.20%	28.90%
Property, Plant and Equipment [Member] | Western Refining Logistics, LP [Member]
Variable Interest Entity [Line Items]
Assets Held-for-sale, Not Part of Disposal Group | $	$ 7.3
Inventories [Member] | Western Refining Logistics, LP [Member]
Variable Interest Entity [Line Items]
Assets Held-for-sale, Not Part of Disposal Group | $	$ 10.1

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Western Refining Logistics, L.P. - St. Paul Park Logistics Transaction (Details) bbl in Millions		1 Months Ended	3 Months Ended
	Sep. 14, 2016 USD ($)	Oct. 31, 2014 USD ($)	Sep. 30, 2016 USD ($) mi bbl	Dec. 31, 2016 bbl
Business Acquisition [Line Items]
Proceeds from Divestiture of Businesses		$ 320,000,000
Active Storage Capacity | bbl				12.4
St. Paul Park Logistics Assets [Member]
Business Acquisition [Line Items]
Pipeline, Miles | mi			2.5
Western Refining Logistics, LP [Member] | St. Paul Park Logistics Assets [Member]
Business Acquisition [Line Items]
Proceeds from Divestiture of Businesses			$ 195,000,000
Common Units [Member] | Western Refining Logistics, LP [Member] | St. Paul Park Logistics Assets [Member]
Business Acquisition [Line Items]
Business Combination, Consideration Transferred, Equity Interests Issued and Issuable	$ 628,224
Pipelines, Inactive [Member] | St. Paul Park Logistics Assets [Member]
Business Acquisition [Line Items]
Pipeline Segments			1
Crude Oil Storage Tanks [Member] | St. Paul Park Logistics Assets [Member]
Business Acquisition [Line Items]
Active Storage Capacity | bbl			4.0
Pipelines [Member] | St. Paul Park Logistics Assets [Member]
Business Acquisition [Line Items]
Pipeline Segments			2

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Western Refining Logistics, L.P. - TexNew Mex Pipeline System Acquisition (Details)	1 Months Ended	3 Months Ended
	Oct. 31, 2014 USD ($)	Dec. 31, 2015 USD ($) mi bbl	Dec. 31, 2016 mi bbl	Oct. 30, 2015
Business Acquisition [Line Items]
Active Storage Capacity | bbl			12,400,000
TexNew Mex 16 inch pipeline [Member] | Pipelines [Member]
Business Acquisition [Line Items]
Pipeline, Miles | mi		375
Western Refining Logistics, LP [Member]
Business Acquisition [Line Items]
Pipeline, Miles | mi			705
Active Storage Capacity | bbl			12,400,000
Payments for (Proceeds from) Businesses and Interest in Affiliates	$ 51,000,000
Western Refining Logistics, LP [Member] | TexNew Mex 16 inch pipeline [Member] | Pipelines [Member]
Business Acquisition [Line Items]
Long-term Purchase Commitment, Minimum Volume Required | bbl		80,000
TexNew Mex 16 inch pipeline [Member]
Business Acquisition [Line Items]
Economic Rights, Crude Oil Throughput, Percent				80.00%
TexNew Mex 16 inch pipeline [Member] | Western Refining Logistics, LP [Member]
Business Acquisition [Line Items]
Payments to Acquire Businesses, Gross		$ 170,000,000
Long-term Purchase Commitment, Minimum Volume Required | bbl		13,000
Economic Rights, Crude Oil Throughput, Percent				20.00%
Payments for (Proceeds from) Businesses and Interest in Affiliates		$ 25,000,000
Common Units [Member] | TexNew Mex 16 inch pipeline [Member] | Western Refining Logistics, LP [Member]
Business Acquisition [Line Items]
Business Combination, Consideration Transferred, Equity Interests Issued and Issuable		421,031
TexNew Mex Units [Member] | TexNew Mex 16 inch pipeline [Member] | Western Refining Logistics, LP [Member]
Business Acquisition [Line Items]
Business Combination, Consideration Transferred, Equity Interests Issued and Issuable		80,000
Revolving Credit Facility [Member] | Revolving Credit Agreement - WNRL [Member] | Western Refining Logistics, LP [Member]
Business Acquisition [Line Items]
Proceeds from Lines of Credit		$ 145,000,000

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Western Refining Logistics, L.P. - WRW Dropdown (Details) $ in Millions	1 Months Ended
	Oct. 31, 2014 USD ($) bbl $ / gal	Oct. 30, 2015 USD ($)	Oct. 15, 2014 USD ($) shares
Business Acquisition [Line Items]
Proceeds from Divestiture of Businesses | $	$ 320.0
Business Acquisitions, Number of Units Acquired | shares			1,160,092
Intercompany Agreements, Description	10
Revolving Credit Agreement - WNRL [Member] | Revolving Credit Facility [Member]
Business Acquisition [Line Items]
Long-term Line of Credit | $		$ 145.0	$ 269.0
Western Refining Logistics, LP [Member]
Business Acquisition [Line Items]
Payments for (Proceeds from) Businesses and Interest in Affiliates | $	$ 51.0
Fuel Distribution and Supply Agreement [Member]
Business Acquisition [Line Items]
Long-term Purchase Commitment, Minimum Quantity Required | bbl	645,000
Profit Margin, per Gallon | $ / gal	0.03
Crude Oil Trucking Transportation Services Agreement [Member]
Business Acquisition [Line Items]
Long-term Purchase Commitment, Minimum Quantity Required | bbl	1,525,000
Product Supply Agreement [Member]
Business Acquisition [Line Items]
Long-term Purchase Commitment, Minimum Quantity Required | bbl	79,000

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NTI - Acquisition Information (Details) - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Mar. 31, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Oct. 15, 2014
Business Acquisition [Line Items]
Increase in Restricted Cash		$ 195,000	$ 170,000	$ 320,000
Business Acquisitions, Number of Units Acquired					1,160,092
Western Refining Logistics, LP [Member]
Business Acquisition [Line Items]
Limited Liability Company (LLC) or Limited Partnership (LP), Members or Limited Partners, Ownership Interest		52.60%
Northern Tier Energy LP [Member]
Business Acquisition [Line Items]
Increase in Restricted Cash			$ 0	$ 0
Limited Liability Company (LLC) or Limited Partnership (LP), Members or Limited Partners, Ownership Interest	38.30%	100.00%
Western Refining Logistics, LP [Member] | Northern Tier Energy LP [Member]
Business Acquisition [Line Items]
Equity Method Investment, Ownership Percentage		1.00%

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NTI - NTI Merger (Details) - USD ($) $ / shares in Units, shares in Millions	1 Months Ended	3 Months Ended	6 Months Ended	9 Months Ended	12 Months Ended
	Jun. 30, 2016	Mar. 31, 2016	Jun. 30, 2016	Sep. 30, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Jun. 23, 2016
Business Acquisition [Line Items]
Payments to Acquire Additional Interest in Subsidiaries					$ 859,893,000	$ 0	$ 0
Adjustments to Additional Paid in Capital, Stock Issued, Issuance Costs					$ 11,741,000
Northern Tier Energy LP [Member]
Business Acquisition [Line Items]
Adjustments to Additional Paid in Capital, Stock Issued, Issuance Costs				$ 11,700,000
Business Combination, Separately Recognized Transactions, Net Gains and Losses				$ 0
Northern Tier Energy LP [Member] | Common Stock [Member]
Business Acquisition [Line Items]
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares	17.1
Western Acquisition Holdings, LLC [Member]
Business Acquisition [Line Items]
Limited Liability Company (LLC) or Limited Partnership (LP), Members or Limited Partners, Ownership Interest					100.00%
Northern Tier Energy LP [Member]
Business Acquisition [Line Items]
Limited Liability Company (LLC) or Limited Partnership (LP), Managing Member or General Partner, Ownership Interest					100.00%
Limited Liability Company (LLC) or Limited Partnership (LP), Members or Limited Partners, Ownership Interest		38.30%			100.00%
Debt Instrument, Face Amount						$ 350,000,000
Northern Tier Energy LP [Member] | Northern Tier Energy LP [Member]
Business Acquisition [Line Items]
Payments to Acquire Additional Interest in Subsidiaries			$ 859,900,000
Northern Tier Energy LP [Member] | Northern Tier Energy LP [Member] | Common Stock [Member]
Business Acquisition [Line Items]
Payment of shares to acquire business, per unit								$ 0.2986
MergerCo HoldCo [Member]
Business Acquisition [Line Items]
Limited Liability Company (LLC) or Limited Partnership (LP), Members or Limited Partners, Ownership Interest					100.00%
Minimum [Member] | Northern Tier Energy LP [Member] | Northern Tier Energy LP [Member]
Business Acquisition [Line Items]
Cash payments to acquire business, per unit								15.00
Minimum [Member] | Northern Tier Energy LP [Member] | Northern Tier Energy LP [Member] | Common Stock [Member]
Business Acquisition [Line Items]
Payment of shares to acquire business, per unit								0.28896
Maximum [Member] | Northern Tier Energy LP [Member] | Northern Tier Energy LP [Member]
Business Acquisition [Line Items]
Cash payments to acquire business, per unit								15.357
Maximum [Member] | Northern Tier Energy LP [Member] | Northern Tier Energy LP [Member] | Common Stock [Member]
Business Acquisition [Line Items]
Payment of shares to acquire business, per unit								$ 0.7036
Public [Member] | Northern Tier Energy LP [Member]
Business Acquisition [Line Items]
Limited Liability Company (LLC) or Limited Partnership (LP), Managing Member or General Partner, Ownership Interest					100.00%

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NTI - Pro Forma (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Jun. 23, 2016
Business Acquisition [Line Items]
Net sales	$ 2,115,325	$ 2,065,076	$ 2,107,308	$ 1,455,504	$ 2,070,324	$ 2,569,090	$ 2,828,892	$ 2,318,730	$ 7,743,213	$ 9,787,036	$ 15,153,573
Operating income	$ 18,370	$ 84,099	$ 162,737	$ 78,219	$ 26,141	$ 332,598	$ 315,393	$ 255,993	343,425	930,125	$ 1,096,513
Northern Tier Energy LP [Member]
Business Acquisition [Line Items]
Business Acquisition, Pro Forma Net Income (Loss)									$ 163,129	$ 521,014
Business Acquisition, Pro Forma Earnings Per Share, Basic									$ 1.26	$ 4.46
Business Acquisition, Pro Forma Earnings Per Share, Diluted									$ 1.25	$ 4.46
Business Acquisition, Pro Forma Interest Expense									$ 16,800	$ 36,100
Business Acquisition, Pro Forma Income Tax Expense (Benefit)									(7,000)	(57,300)
Business Acquisitions, Pro Forma Net Income (Loss) Attributable to Parent									$ 136,385	$ 499,859
Term Loan, due 2023 [Member] | Line of Credit [Member]
Business Acquisition [Line Items]
Debt Instrument, Face Amount												$ 500,000

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NTI - Restructuring Costs (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Corporate, Non-Segment [Member] | Other Nonoperating Income (Expense) [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring and Related Cost, Incurred Cost	$ 6,300
Northern Tier Energy LP [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring Reserve	189	$ 808	$ 0
Restructuring Reserve	2,574	189	808
Employee Severance [Member] | Northern Tier Energy LP [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring Charges	4,650	0	12,878
Other Restructuring Costs	0	0	(4,789)
Payments for Restructuring	(2,468)	(619)	(7,281)
Other Restructuring [Member] | Northern Tier Energy LP [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring Charges	1,662	0	0
Payments for Restructuring	$ (1,459)	$ 0	$ 0

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NTI - NTI Merger Transaction (Details) - USD ($) $ / shares in Units, $ in Thousands, shares in Millions	1 Months Ended	3 Months Ended	6 Months Ended	12 Months Ended
	Jun. 30, 2016	Mar. 31, 2016	Jun. 30, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Jun. 23, 2016
Business Acquisition [Line Items]
Payments to Acquire Additional Interest in Subsidiaries				$ 859,893	$ 0	$ 0
Northern Tier Energy LP [Member]
Business Acquisition [Line Items]
Limited Liability Company (LLC) or Limited Partnership (LP), Managing Member or General Partner, Ownership Interest				100.00%
Limited Liability Company (LLC) or Limited Partnership (LP), Members or Limited Partners, Ownership Interest		38.30%		100.00%
Western Acquisition Holdings, LLC [Member]
Business Acquisition [Line Items]
Limited Liability Company (LLC) or Limited Partnership (LP), Members or Limited Partners, Ownership Interest				100.00%
MergerCo HoldCo [Member]
Business Acquisition [Line Items]
Limited Liability Company (LLC) or Limited Partnership (LP), Members or Limited Partners, Ownership Interest				100.00%
Public [Member] | Northern Tier Energy GP LLC [Member]
Business Acquisition [Line Items]
Limited Liability Company (LLC) or Limited Partnership (LP), Managing Member or General Partner, Ownership Interest				100.00%
Public [Member] | Northern Tier Energy LP [Member]
Business Acquisition [Line Items]
Limited Liability Company (LLC) or Limited Partnership (LP), Managing Member or General Partner, Ownership Interest				100.00%
Northern Tier Energy LP [Member] | Northern Tier Energy LP [Member]
Business Acquisition [Line Items]
Payments to Acquire Additional Interest in Subsidiaries			$ 859,900
Common Stock [Member] | Northern Tier Energy LP [Member]
Business Acquisition [Line Items]
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares	17.1
Common Stock [Member] | Northern Tier Energy LP [Member] | Northern Tier Energy LP [Member]
Business Acquisition [Line Items]
Payment of shares to acquire business, per unit							$ 0.2986
Common Stock [Member] | Western Refining, Inc. [Member] | Merger Agreement Dated December Two Thousand Fifteen [Member] | Northern Tier Energy LP [Member]
Business Acquisition [Line Items]
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares			17.1
Minimum [Member] | Northern Tier Energy LP [Member] | Northern Tier Energy LP [Member]
Business Acquisition [Line Items]
Cash payments to acquire business, per unit							15.00
Minimum [Member] | Common Stock [Member] | Northern Tier Energy LP [Member] | Northern Tier Energy LP [Member]
Business Acquisition [Line Items]
Payment of shares to acquire business, per unit							0.28896
Maximum [Member] | Northern Tier Energy LP [Member] | Northern Tier Energy LP [Member]
Business Acquisition [Line Items]
Cash payments to acquire business, per unit							15.357
Maximum [Member] | Common Stock [Member] | Northern Tier Energy LP [Member] | Northern Tier Energy LP [Member]
Business Acquisition [Line Items]
Payment of shares to acquire business, per unit							$ 0.7036

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NTI - NTI Merger & Reorganization Expenses (Details) - USD ($) $ in Thousands	3 Months Ended				12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Business Acquisition [Line Items]
Merger and reorganization costs	$ 8,453	$ 2,844	$ 735	$ 408	$ 12,440	$ 0	$ 12,878
Equity based compensation related to reorganization					0	0	4,800
Northern Tier Energy LP [Member]
Business Acquisition [Line Items]
Restructuring Reserve				$ 200	200	800	0
Merger and reorganization costs					4,700	2,500	0
Restructuring Reserve	$ 2,500				2,500	200	800
Third Party Professional Service [Member] | Northern Tier Energy LP [Member]
Business Acquisition [Line Items]
Merger and reorganization costs					1,700	0	0
Payments for Restructuring					(1,400)	0	0
Employee Severance [Member] | Northern Tier Energy LP [Member]
Business Acquisition [Line Items]
Merger and reorganization costs							12,900
Reorganization and Related Costs					3,000	0
Payments for Restructuring					$ (1,000)	$ (600)	$ (7,300)

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Tesoro Merger (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	3 Months Ended					12 Months Ended
	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Jun. 10, 2009
Business Acquisition [Line Items]
Common Stock, Par or Stated Value Per Share		$ 0.01				$ 0.01	$ 0.01	$ 0.01	$ 0.01
Cash dividends declared per common share		0.38	$ 0.38	$ 0.38	$ 0.38	$ 1.52	$ 1.36	$ 3.08
Tesoro Merger [Member]
Business Acquisition [Line Items]
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares						10.8
Business Acquisition, Share Price		$ 37.30				$ 37.30
Business Acquisition, Transaction Costs		$ 6.1				$ 6.1
Common Stock [Member]
Business Acquisition [Line Items]
Common Stock, Par or Stated Value Per Share		$ 0.01				$ 0.01
Common Stock [Member] | Tesoro Merger [Member]
Business Acquisition [Line Items]
Payment of shares to acquire business, per unit		$ 0.4350				$ 0.4350
Subsequent Event [Member]
Business Acquisition [Line Items]
Cash dividends declared per common share	$ 0.38
Tesoro [Member] | Subsequent Event [Member]
Business Acquisition [Line Items]
Cash dividends declared per common share	$ 0.55