NTI Northern Tier Energy LP Common Units Representing Limited Partner Interests (delisted)

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
		123 W. Mills Ave., Suite 200
		El Paso, Texas 79901
		( 915) 534-1400
001-35612		NORTHERN TIER ENERGY LP		80-0763623
		Delaware
		1250 W. Washington Street, Suite 300
		Tempe, Arizona 85281
		(602) 302-5450

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 þ		Accelerated filer o		Non-accelerated filer o		Smaller reporting company o

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•	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;

•	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;

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•	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 in Western's and NTI's Annual Reports on Form 10-K for the year ended December 31, 2015 (" 2015 10‑K").

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Part I

Financial Information

Item 1.	Financial Statements

WESTERN REFINING, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In thousands, except share and per share data)

	September 30, 2016				December 31, 2015
ASSETS
Current assets:
Cash and cash equivalents (WNRL: $16,542 and $44,605, respectively)	$	266,096			$	772,502
Restricted cash	195,000				—
Accounts receivable, trade, net of a reserve for doubtful accounts of $246 and $169, respectively (WNRL: $57,065 and $55,053, respectively)	447,327				359,237
Inventories (WNRL: $11,130 and $15,200, respectively)	660,738				547,538
Prepaid expenses (WNRL: $5,523 and $4,133, respectively)	129,138				73,213
Other current assets (WNRL: $6,066 and $5,943, respectively)	121,581				169,728
Total current assets	1,819,880				1,922,218
Restricted cash	—				69,106
Equity method investment	98,185				97,513
Property, plant and equipment, net (WNRL: $422,006 and $430,141, respectively)	2,357,291				2,305,171
Goodwill	1,289,443				1,289,443
Intangible assets, net (WNRL: $6,813 and $7,757, respectively)	84,543				84,945
Other assets (WNRL: $3,409 and $3,376, respectively)	65,783				64,997
Total assets	$	5,715,125			$	5,833,393
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable (WNRL: $9,171 and $10,501, respectively)	$	634,716			$	553,957
Accrued liabilities (WNRL: $34,181 and $30,624, respectively)	216,169				248,395
Current portion of long-term debt	10,500				5,500
Total current liabilities	861,385				807,852
Long-term liabilities:
Long-term debt, less current portion (WNRL: $312,835 and $437,467, respectively)	2,045,180				1,644,894
Lease financing obligations	54,541				53,232
Deferred income tax liability, net	416,951				312,914
Other liabilities (WNRL: $9 in both periods)	69,622				68,595
Total long-term liabilities	2,586,294				2,079,635
Commitments and contingencies
Equity:
Western shareholders' equity:
Common stock, par value $0.01, 240,000,000 shares authorized; 108,426,740 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 or outstanding	—				—
Additional paid-in capital	550,876				492,848
Retained earnings	1,112,895				1,167,938
Accumulated other comprehensive loss, net of tax	599				651
Treasury stock, 9,089,623 shares at cost	—				(363,168		)
Total Western shareholders' equity	1,665,455				1,299,297
Non-controlling interests	601,991				1,646,609
Total equity	2,267,446				2,945,906
Total liabilities and equity	$	5,715,125			$	5,833,393

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

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Table of Contents

WESTERN REFINING, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

(In thousands, except per share data)

	Three Months Ended								Nine Months Ended
	September 30,								September 30,
	2016				2015				2016				2015
Net sales	$	2,065,076			$	2,569,090			$	5,627,888			$	7,716,712
Operating costs and expenses:
Cost of products sold (exclusive of depreciation and amortization)	1,607,010				1,895,772				4,256,999				5,814,969
Direct operating expenses (exclusive of depreciation and amortization)	232,553				234,440				687,307				674,474
Selling, general and administrative expenses	57,320				54,465				166,657				169,808
Gain on disposal of assets, net	(279		)		(52		)		(1,181		)		(157		)
Maintenance turnaround expense	27,208				490				27,733				1,188
Depreciation and amortization	54,321				51,377				161,331				152,446
Total operating costs and expenses	1,978,133				2,236,492				5,298,846				6,812,728
Operating income	86,943				332,598				329,042				903,984
Other income (expense):
Interest income	141				186				436				550
Interest and debt expense	(34,456		)		(26,896		)		(88,065		)		(79,169		)
Other, net	3,380				4,327				13,825				11,557
Income before income taxes	56,008				310,215				255,238				836,922
Provision for income taxes	(11,700		)		(92,117		)		(68,481		)		(229,989		)
Net income	44,308				218,098				186,757				606,933
Less net income attributable to non-controlling interests	5,733				64,795				52,229				213,722
Net income attributable to Western Refining, Inc.	$	38,575			$	153,303			$	134,528			$	393,211
Net earnings per share:
Basic	$	0.36			$	1.61			$	1.37			$	4.12
Diluted	0.35				1.61				1.37				4.12
Weighted-average common shares outstanding:
Basic	108,424				94,826				97,802				95,308
Diluted	108,734				94,924				98,110				95,408
Cash dividends declared per common share	$	0.38			$	0.34			$	1.14			$	0.98

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

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WESTERN REFINING, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

(In thousands)

	Three Months Ended								Nine Months Ended
	September 30,								September 30,
	2016				2015				2016				2015
Net income	$	44,308			$	218,098			$	186,757			$	606,933
Other comprehensive income items:
Benefit plans:
Amortization of net prior service cost	—				—				(133		)		107
Reclassification of loss to income	—				13				11				38
Other comprehensive income (loss) before tax	—				13				(122		)		145
Income tax	—				(5		)		—				(14		)
Other comprehensive income (loss), net of tax	—				8				(122		)		131
Comprehensive income	44,308				218,106				186,635				607,064
Less comprehensive income attributable to non-controlling interests	5,733				64,795				52,159				213,788
Comprehensive income attributable to Western Refining, Inc.	$	38,575			$	153,311			$	134,476			$	393,276

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

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WESTERN REFINING, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(In thousands)

	Nine Months Ended
	September 30,
	2016				2015
Cash flows from operating activities:
Net income	$	186,757			$	606,933
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	161,331				152,446
Changes in fair value of commodity hedging instruments	54,698				42,073
Reserve for doubtful accounts	77				103
Amortization of loan fees and original issue discount	5,948				4,801
Stock-based compensation expense	17,490				12,576
Deferred income taxes	58,727				47
Change in lower of cost or market reserve	(102,519		)		(17,131		)
Excess tax benefit from stock-based compensation	(26		)		(879		)
Income from equity method investment, net of dividends	(850		)		(12,029		)
Gain on disposal of assets, net	(1,181		)		(157		)
Changes in operating assets and liabilities:
Accounts receivable	(88,976		)		54,738
Inventories	(10,681		)		(5,479		)
Prepaid expenses	(55,925		)		(10,706		)
Other assets	(7,768		)		(43,093		)
Accounts payable and accrued liabilities	69,572				(113,051		)
Other long-term liabilities	(8,797		)		(5,528		)
Net cash provided by operating activities	277,877				665,664
Cash flows from investing activities:
Capital expenditures	(235,097		)		(195,976		)
Increase in restricted cash	(195,000		)		—
Use of restricted cash	69,106				154,681
Return of capital from equity method investment	—				5,780
Proceeds from the sale of assets	3,912				1,061
Net cash used in investing activities	(357,079		)		(34,454		)
Cash flows from financing activities:
Additions to long-term debt	500,000				300,000
Payments on long-term debt and capital lease obligations	(7,150		)		(5,559		)
Borrowings on revolving credit facility	393,900				—
Repayments on revolving credit facility	(466,600		)		(269,000		)
Payments for NTI units related to merger	(859,893		)		—
Transaction costs for NTI merger	(11,741		)		—
Proceeds from issuance of WNRL common units	277,751				—
Offering costs for issuance of WNRL common units	(417		)		—
Deferred financing costs	(12,410		)		(6,820		)
Purchase of common stock for treasury	(75,000		)		(105,000		)
Distribution to non-controlling interest holders	(54,115		)		(173,687		)
Dividends paid	(111,555		)		(93,612		)
Excess tax benefit from stock-based compensation	26				879
Net cash used in financing activities	(427,204		)		(352,799		)
Net increase (decrease) in cash and cash equivalents	(506,406		)		278,411
Cash and cash equivalents at beginning of period	772,502				431,159
Cash and cash equivalents at end of period	$	266,096			$	709,570

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

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WESTERN REFINING, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. Organization

"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, 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 545 company-owned and franchised retail sites in the United States.

As of September 30, 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 “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 “Merger”). On June 23, 2016, following the approval of the Merger Agreement by NTI common unitholders, all closing conditions to the Merger were satisfied, and the Merger was successfully completed. We incurred $500 million of additional secured indebtedness under our amended term loan credit agreement to partially fund the Merger consideration. See Note 9, Long-Term Debt , and Note 21, Acquisitions , for further discussion.

At September 30, 2016 , we owned a 52.6% limited partner interest in Western Refining Logistics, LP ("WNRL" or the "Partnership") 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 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 on site at our St. Paul Park refinery and Cottage Grove tank farm to WNRL. These assets primarily receive, store and distribute crude oil, feedstock and refined products associated with the St. Paul Park refinery (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 ."

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

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

On October 30, 2015, we sold a 375 mile segment of the TexNew Mex Pipeline system to WNRL. This segment of the TexNew Mex Pipeline 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 WNRL financial and operational data presented includes the historical results of all assets acquired from Western in the St. Paul Park Logistics Transaction and the TexNew Mex Pipeline Transaction. The acquisitions from Western were a transfer of assets between entities under common control. Accordingly, the financial information contained herein for WNRL has been retrospectively adjusted, to include the historical results of the assets acquired, for periods prior to the effective date of the transactions.

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.

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WESTERN REFINING, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

2. Basis of Presentation and Significant Accounting Policies

The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with U.S. generally accepted accounting principles ("GAAP") for interim consolidated financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, these unaudited condensed consolidated financial statements do not include all of the information and footnotes required by GAAP for complete financial statements. In management's opinion, all adjustments (consisting of normal recurring accruals) considered necessary for a fair presentation have been included. Operating results for the three and nine months ended September 30, 2016 , are not necessarily indicative of the results that may be expected for the year ending December 31, 2016 , or for any other period.

The Condensed Consolidated Balance Sheet at December 31, 2015 , has been derived from the audited financial statements at that date but does not include all of the information and footnotes required by GAAP for complete financial statements. The accompanying condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2015 .

Principles of Consolidation

The accompanying condensed consolidated financial statements include the accounts of Western and our subsidiaries. We own 100% of NTI's general partner and, subsequent to the 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 their respective economic performance. We have reported a non-controlling interest for WNRL as of September 30, 2016 , of $602.0 million and non-controlling interests for NTI and WNRL of $1,646.6 million as of December 31, 2015 , in our Condensed Consolidated Balance Sheets. All intercompany accounts and transactions have been eliminated for all periods presented. Investments in significant non-controlled entities over which we have the ability to exercise significant influence are accounted for using the equity method.

Variable Interest Entity

WNRL is a variable interest entity ("VIE") as defined under GAAP. A VIE is a legal entity whose equity owners do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support or, as a group, the equity holders lack the power, through voting rights, to direct the activities that most significantly impact the entity's financial performance, the obligation to absorb the entity's expected losses or rights to expected residual returns. As the general partner of WNRL, we have the sole ability to direct the activities of WNRL that most significantly impact WNRL's financial performance, and therefore we consolidate WNRL. See Note 22, WNRL , for further discussion.

Goodwill and Other Unamortizable Intangible Assets

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 and other unamortizable intangible assets for impairment annually at June 30, or more frequently if indications of impairment exist.

The risk of goodwill and intangible asset impairment losses may increase to the extent that results of operations or cash flows decline at our St. Paul Park refinery or SuperAmerica operating segments. Impairment losses may result in a material, non-cash write-down of goodwill or intangible assets. Furthermore, impairment losses could have a material adverse effect on the Company’s results of operations and shareholders’ equity.

Use of Estimates and Seasonality

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 disclosure of contingent assets and liabilities as of the date of the financial statements and the reported amounts of revenues and expenses during the respective reporting period. Actual results could differ from those estimates.

Demand for gasoline is generally higher during the summer months than during the winter months. As a result, our operating results for the first and fourth calendar quarters are generally lower than those for the second and third calendar quarters of each year. During 2014, 2015 and continuing into 2016, the volatility in crude oil prices and refining margins contributed to the variability of our results of operations.

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WESTERN REFINING, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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.

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 condensed 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 are to be applied retrospectively, with early adoption permitted for periods beginning after December 15, 2016, and interim periods thereafter.

•

Lease accounting - the requirements were amended 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.

•

Employee share-based payment accounting - the 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. These provisions are effective for annual periods beginning after December 15, 2016, including interim periods within those annual periods. Early adoption is permitted in any interim or annual period.

•	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.

3. Segment Information

We have organized our operations into three segments, refining, WNRL and retail, based on manufacturing and marketing processes, the nature of our products and services and each segment's respective customer base. Prior to the Merger on June 23, 2016, we also reported NTI as a separate reportable segment. Following the completion of the Merger, NTI became a wholly-owned subsidiary of Western and, as a result, we have moved its assets and operations into our other reportable segments. 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. The St. Paul Park refinery and related operations are now included in the refining segment and the SuperAmerica retail and bakery assets and operations are now included in the retail

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WESTERN REFINING, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

segment. 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 and the TexNew Mex Pipeline System that 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 and the TexNew Mex Pipeline System from the refining segment to the WNRL segment.

Business Segments and Principal Products

Refining . Our refining segment includes the operations of three refineries. The El Paso refinery in El Paso, Texas, has a throughput capacity of 131,000 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 98,000 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 third-party suppliers. We also acquire refined products through exchange agreements and from 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, through commercial accounts and sales and exchanges with major oil companies.

We have an exclusive supply and marketing agreement with a third party, covering activities related to our refined product supply, sales and hedging in the Mid-Atlantic region. We recorded $4.0 million and $1.8 million in assets at September 30, 2016 and December 31, 2015 , respectively, related to this supply agreement in our Condensed Consolidated Balance Sheets. The revenues and costs recorded under the supply agreement included $6.1 million and $23.3 million in net hedging gains for the three months ended September 30, 2016 and 2015 , respectively, and gains of $32.1 million and $39.3 million for the nine months ended September 30, 2016 and 2015 , respectively. This supply agreement is due to expire at the end of 2016.

WNRL. WNRL owns and operates pipeline and gathering, terminalling, storage and transportation assets that provide logistics services to our refining segment in the Southwest and Upper Great Plains regions, including 692 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, refined product, asphalt and lubricant delivery trucks. WNRL distributes commercial wholesale petroleum products primarily in Arizona, California, Colorado, Nevada, New Mexico and Texas. WNRL purchases petroleum fuels and lubricants from our refining segment and from third-party suppliers.

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

Southwest Retail obtains the majority of its gasoline and diesel fuel supply from WNRL and purchases general merchandise and beverage and food products from various third-party suppliers. At September 30, 2016 , Southwest Retail operated 260 service stations and convenience stores located in Arizona, Colorado, New Mexico and Texas compared to 261 service stations and convenience stores at September 30, 2015 . In addition to its service stations and convenience stores, Southwest Retail sells various grades of gasoline and diesel fuel to commercial vehicle fleets through unmanned fleet fueling sites ("cardlocks"). At September 30, 2016 and 2015 , respectively, Southwest Retail operated 51 and 52 cardlocks located in Arizona, California, Colorado, New Mexico and Texas.

As of September 30, 2016 , SuperAmerica operated 170 retail convenience stores and supported the operations of 115 franchised retail convenience stores primarily in Minnesota and Wisconsin, compared to 165 and 102 at September 30, 2015 . 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 "last-in, first-out" ("LIFO") and lower of cost or market ("LCM") inventory adjustments. Intersegment revenues are reported at prices that approximate market.

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

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

Disclosures regarding our reportable segments with reconciliations to consolidated totals for the three and nine months ended September 30, 2016 and 2015 , are presented below:

	Three Months Ended								Nine Months Ended
	September 30,								September 30,
	2016				2015				2016				2015
	(In thousands)
Operating Results:
Refining (2)
Net sales	$	1,835,327			$	2,318,048			$	5,012,283			$	6,958,443
Intersegment eliminations	736,020				843,674				2,075,758				2,403,438
Net refining sales to external customers	1,099,307				1,474,374				2,936,525				4,555,005
WNRL (2)
Net sales	569,261				680,670				1,615,902				2,023,970
Intersegment eliminations	183,154				216,959				513,101				607,249
Net WNRL sales to external customers	386,107				463,711				1,102,801				1,416,721
Retail
Net sales	597,621				633,793				1,610,033				1,753,503
Intersegment eliminations	17,959				2,788				21,471				8,517
Net retail sales to external customers	579,662				631,005				1,588,562				1,744,986
Consolidated net sales to external customers	$	2,065,076			$	2,569,090			$	5,627,888			$	7,716,712
Operating income (loss)
Refining (1) (2)	$	89,158			$	312,602			$	338,803			$	900,405
WNRL (2)	13,271				18,424				43,056				41,454
Retail	11,832				24,937				21,193				36,356
Other	(27,318		)		(23,365		)		(74,010		)		(74,231		)
Operating income from segments	86,943				332,598				329,042				903,984
Other income (expense), net	(30,935		)		(22,383		)		(73,804		)		(67,062		)
Consolidated income before income taxes	$	56,008			$	310,215			$	255,238			$	836,922
Depreciation and amortization
Refining (2)	$	37,265			$	35,400			$	111,601			$	105,916
WNRL (2)	10,579				8,963				29,470				25,816
Retail	5,710				5,846				17,622				17,257
Other	767				1,168				2,638				3,457
Consolidated depreciation and amortization	$	54,321			$	51,377			$	161,331			$	152,446
Capital expenditures
Refining (2)	$	65,909			$	61,399			$	200,681			$	127,914

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	Three Months Ended								Nine Months Ended
	September 30,								September 30,
	2016				2015				2016				2015
	(In thousands)
WNRL (2)	8,530				10,648				24,378				52,150
Retail	3,593				3,903				8,528				13,175
Other	305				481				1,510				2,737
Consolidated capital expenditures	$	78,337			$	76,431			$	235,097			$	195,976
Total assets
Refining (2) (including $1,267,455 of goodwill)									$	4,394,967			$	3,574,746
WNRL (2)									528,554				601,215
Retail (including $21,988 of goodwill)									430,363				430,147
Other									361,241				1,234,285
Consolidated total assets									$	5,715,125			$	5,840,393

(1)

The effect of our economic hedging activity is included within the operating income of our refining segment as a component of cost of products sold. The cost of products sold within our refining segment included $0.1 million in net realized and unrealized economic hedging gains for the three months ended September 30, 2016 , $8.6 million in net realized and unrealized economic hedging losses for the nine months ended September 30, 2016 , respectively, and $27.2 million and $10.3 million in net realized and unrealized economic hedging gains for the three and nine months ended September 30, 2015 , respectively. Also included within cost of products sold for our refining segment is the net effect of non-cash LCM recoveries of $15.2 million and $102.5 million for the three and nine months ended September 30, 2016 , respectively, charges of $36.8 million for the three months ended September 30, 2015 and recoveries of $17.1 million for the nine months ended September 30, 2015 .

(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 and nine months ended September 30, 2015 . The information contained herein for WNRL has been retrospectively adjusted, to include the historical results of the St. Paul Park Logistics Assets and the TexNew Mex Pipeline System .

4. Fair Value Measurement

We utilize the market approach when measuring fair value of 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 September 30, 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 $0.02 million and $70.1 million consisting of short-term money market deposits and commercial paper were included in the Condensed Consolidated Balance Sheets as of September 30, 2016 and December 31, 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

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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 13, 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 September 30, 2016 and December 31, 2015 , and the basis for that measurement:

	Carrying Value at September 30, 2016				Fair Value Measurement Using												Netting Adjustments				Recorded Value at September 30, 2016
					Level 1				Level 2				Level 3
	(In thousands)
Gross financial assets:
Other current assets	$	34,060			$	—			$	34,060			$	—			$	(7,303	)		$	26,757
Other assets	4,455				—				4,455				—				(1,604		)		2,851
Gross financial liabilities:
Accrued liabilities	(10,449		)		—				(9,688		)		(761		)		5,992				(4,457		)
Other long-term liabilities	(3,068		)		—				(3,068		)		—				2,915				(153		)
	$	24,998			$	—			$	25,759			$	(761	)		$	—			$	24,998

	Carrying Value at December 31, 2015				Fair Value Measurement 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 Condensed 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 Condensed 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 three and nine months ended September 30, 2016 and 2015 .

	Three Months Ended								Nine Months Ended
	September 30,								September 30,
	2016				2015				2016				2015
	(In thousands)
Asset (liability) balance at beginning of period	$	(1,951	)		$	1,614			$	(5,756	)		$	330
Change in fair value	237				(2,505		)		537				—
Fair value of trades entered into during the period	—				—				—				(1,262		)
Fair value reclassification from Level 3 to Level 2	953				(288		)		4,458				(247		)
Liability balance at end of period	$	(761	)		$	(1,179	)		$	(761	)		$	(1,179	)

A hypothetical change of 10% to the estimated future cash flows attributable to our Level 3 commodity price swaps would result in a $0.1 million change in the estimated fair value at September 30, 2016 .

As of September 30, 2016 and December 31, 2015 , the carrying amount and estimated fair value of our debt was as follows:

	September 30, 2016				December 31, 2015
	(In thousands)
Western obligations:
Carrying amount	$	1,383,625			$	889,000
Fair value	1,380,125				867,178
NTI obligations:
Carrying amount	$	402,000			$	350,000
Fair value	412,500				360,500
WNRL obligations:
Carrying amount	$	320,300			$	445,000
Fair value	330,800				439,000

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

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

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5. Inventories

Inventories were as follows:

	September 30, 2016				December 31, 2015
	(In thousands)
Refined products (1)	$	259,125			$	201,928
Crude oil and other raw materials	348,109				288,403
Lubricants	11,118				14,996
Retail store merchandise	42,386				42,211
Inventories	$	660,738			$	547,538

(1)	Includes $15.8 million and $14.5 million of refined products inventory valued using the first-in, first-out ("FIFO") valuation method at September 30, 2016 and December 31, 2015 , respectively.

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

As of September 30, 2016 and December 31, 2015 , refined products valued under the LIFO method and crude oil and other raw materials totaled 10.4 million barrels and 10.0 million barrels, respectively. At September 30, 2016 and December 31, 2015 , the excess of the LIFO cost over the current cost of these crude oil, refined product and other feedstock and blendstock inventories was $193.3 million and $198.4 million , respectively.

During the three months ended September 30, 2016 and 2015 , cost of products sold included net non-cash recoveries of $79.5 million and $105.0 million , respectively, from changes in our LIFO reserves. During the nine months ended September 30, 2016 and 2015 , cost of products sold included net non-cash charges of $5.1 million and net non-cash recoveries of $129.0 million , 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 $72.6 million and $175.1 million at September 30, 2016 and December 31, 2015 , respectively. These non-cash LCM recoveries decreased cost of products sold by $15.2 million and $102.5 million for the three and nine months ended September 30, 2016 , respectively, and by $17.1 million for the nine months ended September 30, 2015 . The non-cash LCM charge for the three months ended September 30, 2015 , increased cost of products sold by $36.8 million .

Average LIFO cost per barrel of our refined products and crude oil and other raw materials inventories as of September 30, 2016 and December 31, 2015 , were as follows:

	September 30, 2016											December 31, 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	4,033			$	279,917			$	69.41			3,536			$	259,722			$	73.45
Crude oil and other	6,348			384,067				60.50				6,490			391,237				60.28
	10,381			$	663,984			63.96				10,026			$	650,959			64.93

6. Equity Method Investment

We own a 17% common equity interest in Minnesota Pipe Line Company, LLC ("MPL"). The carrying value of this equity method investment was $98.2 million and $97.5 million at September 30, 2016 and December 31, 2015 , respectively.

As of September 30, 2016 and December 31, 2015 , the carrying amount of the equity method investment was $21.2 million and $21.3 million , respectively, higher than the underlying net assets of the investee. We are amortizing this

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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.

We received distributions from MPL during the three and nine months ended September 30, 2016 and 2015 , of $10.2 million , $14.5 million , $4.2 million and $10.0 million , respectively. Equity income from MPL for the three and nine months ended September 30, 2016 and 2015 , was $5.3 million , $15.3 million , $4.2 million and $12.0 million , respectively. Equity income has been included in other, net in the accompanying Condensed Consolidated Statements of Operations.

7. Property, Plant and Equipment, Net

Property, plant and equipment, net was as follows:

	September 30, 2016				December 31, 2015
	(In thousands)
Refinery facilities and related equipment	$	2,198,560			$	2,113,650
Pipelines, terminals and transportation equipment	553,402				427,854
Retail facilities and related equipment	327,898				324,686
Wholesale facilities and related equipment	53,190				59,875
Corporate	52,105				50,607
	3,185,155				2,976,672
Accumulated depreciation	(1,070,501		)		(923,415		)
	2,114,654				2,053,257
Construction in progress	242,637				251,914
Property, plant and equipment, net	$	2,357,291			$	2,305,171

Depreciation expense was $53.3 million and $158.1 million for the three and nine months ended September 30, 2016 , respectively, and $50.4 million and $149.3 million for the three and nine months ended September 30, 2015 , respectively.

8. Intangible Assets, Net

Intangible assets, net was as follows:

	September 30, 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			$	(14,913	)		$	5,514			$	20,427			$	(13,729	)		$	6,698			3.5
Customer relationships	7,172				(4,102		)		3,070				7,551				(3,921		)		3,630				5.8
Rights-of-way and other	7,889				(2,388		)		5,501				6,839				(1,797		)		5,042				5.5
	35,488				(21,403		)		14,085				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	$	105,946			$	(21,403	)		$	84,543			$	104,392			$	(19,447	)		$	84,945

Intangible asset amortization expense for the three and nine months ended September 30, 2016 , was $0.7 million and $2.2 million , respectively, based on estimated useful lives ranging from 1 to 35  years. Intangible asset amortization expense for the three and nine months ended September 30, 2015 , was $0.7 million and $2.1 million , respectively, based on estimated useful lives ranging from 1 to 23  years.

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Estimated amortization expense for the indicated periods is as follows (in thousands):

Remainder of 2016	$	720
2017	2,880
2018	2,880
2019	2,212
2020	1,268
2021	980

9. Long-Term Debt

Long-term debt was as follows:

	September 30, 2016				December 31, 2015
	(In thousands)
Western obligations:
Revolving Credit Facility due 2019	$	—			$	—
Term Loan - 5.25% Credit Facility due 2020	534,875				539,000
6.25% Senior Unsecured Notes due 2021	350,000				350,000
Term Loan - 5.50% Credit Facility due 2023	498,750				—
Total Western obligations	1,383,625				889,000
NTI obligations:
Revolving Credit Facility due 2019	52,000				—
7.125% Senior Secured Notes due 2020	350,000				350,000
Total NTI obligations	402,000				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	50,245				33,606
Long-term debt	2,055,680				1,650,394
Current portion of long-term debt	(10,500		)		(5,500		)
Long-term debt, net of current portion	$	2,045,180			$	1,644,894

As of September 30, 2016 , annual maturities of long-term debt for the remainder of 2016 are $2.6 million . For 2017, 2018, 2019 and 2020, long-term debt maturities are $10.5 million , $30.8 million , $62.5 million and $872.0 million , respectively. Thereafter, total long-term debt maturities are $1,127.5 million .

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Interest and debt expense were as follows:

	Three Months Ended								Nine Months Ended
	September 30,								September 30,
	2016				2015				2016				2015
	(In thousands)
Contractual interest:
Western obligations	$	20,475			$	12,150			$	45,606			$	36,250
NTI obligations	6,918				6,970				20,707				20,173
WNRL obligations	6,039				5,854				19,144				15,481
	33,432				24,974				85,457				71,904
Amortization of loan fees	2,479				1,932				6,395				5,630
Amortization of original issuance discount	381				—				410				—
Other interest expense	1,287				747				3,727				2,973
Capitalized interest	(3,123		)		(757		)		(7,924		)		(1,338		)
Interest and debt expense	$	34,456			$	26,896			$	88,065			$	79,169

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

Western Obligations

Revolving Credit Facility

On 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 Revolving Credit 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 0.25% 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 and during the nine month period ended September 30, 2016 , we had no direct borrowings under the Western 2019 Revolving Credit Facility, with availability of $257.0 million at September 30, 2016 . This availability is net of $100.1 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

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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 Term Loan. 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 September 30, 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 wholly-owned subsidiary of Western, and is fully and unconditionally guaranteed on a joint and several basis by certain of Western's material wholly-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 certain of our wholly-owned domestic restricted subsidiaries. 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 September 30, 2016 . See Note 20, Condensed Consolidating Financial Information for further discussion.

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 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 wholly-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% ). 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 5.99% as of September 30, 2016 .

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 its general partner, Northern Tier Energy GP LLC ("NTI LLC"), and certain of its subsidiaries that are borrowers thereunder 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

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commitment fee ranging from 0.250% to 0.375% subject to adjustment based upon the average utilization ratio 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.

At September 30, 2016 , the availability under the NTI Revolving Credit Facility was $205.7 million . This availability is net of $52.0 million in direct borrowings and $47.6 million in outstanding letters of credit. The effective rate of interest, including contractual interest and amortization of loan fees, for the NTI Revolving Credit Facility was 5.91% as of September 30, 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 "). On October 17, 2016, NTI commenced a tender offer to repurchase for cash up to $195.0 million aggregate principal amount of the NTI 2020 Secured Notes . The tender offer expires on November 15, 2016.

NTI increased the principal amount of the NTI 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 NTI 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 . The issuance premium will be 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 September 30, 2016 .

The obligations under the NTI 2020 Secured Notes are fully and unconditionally guaranteed, jointly and severally, on a senior unsecured basis by NTI and on a senior secured basis by (i) all of NTI LLC’s restricted subsidiaries that borrow, or guarantee obligations, under the NTI Revolving Credit Facility or any other indebtedness of NTI LLC or another subsidiary of NTI LLC that guarantees the NTI 2020 Secured Notes and (ii) all other material wholly-owned domestic subsidiaries of NTI LLC. The indenture governing the NTI 2020 Secured Notes contains covenants that limit or restrict dividends or other payments from restricted subsidiaries. Indebtedness under the NTI 2020 Secured Notes is guaranteed by NTI and certain of its 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 and WNRL repaid its outstanding direct borrowings under the WNRL Revolving Credit Facility on February 11, 2015, with a portion of the proceeds from the issuance of its 7.5% Senior Notes due 2023 (the " 7.5% Senior Notes"), discussed below. On October 30, 2015, WNRL borrowed $145.0 million under the WNRL Revolving

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Credit Facility to partially fund the purchase of the TexNew Mex Pipeline System from Western. During the nine months ended September 30, 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. At September 30, 2016 , the availability under the WNRL Revolving Credit Facility was $479.0 million , net of $20.3 million in direct borrowings and $0.7 million in outstanding letters of credit. WNRL had no swing line borrowings outstanding under the WNRL Revolving Credit Facility as of September 30, 2016 . The interest rate for the borrowings under the WNRL Revolving Credit Facility was 4.50% as of September 30, 2016 . The effective rate of interest, including contractual interest and amortization of loan fees, for the WNRL Revolving Credit Facility was 3.34% as of September 30, 2016 .

7.5% Senior Notes

On February 11, 2015, WNRL entered into an indenture (the “WNRL Indenture”) among WNRL, WNRL Finance Corp., a Delaware corporation and wholly-owned subsidiary of the Partnership (“Finance Corp.” and together with the Partnership, the “Issuers”), the Guarantors named therein and U.S. Bank National Association, as trustee (the “Trustee”) under which the Issuers issued $300.0 million in aggregate principal amount of 7.5% Senior Notes due 2023. The Partnership will pay interest on the 7.5% Senior Notes semi-annually in cash in arrears on February 15 and August 15 of each year, beginning on August 15, 2015. The 7.5% Senior Notes will mature on February 15, 2023. WNRL used the proceeds from the notes to repay the full balance due under the WNRL Revolving Credit Facility on February 11, 2015. The effective rate of interest, including contractual interest and amortization of loan fees, for the 7.5% Senior Notes was 7.78% as of September 30, 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 7.5% Senior Notes to be due and payable immediately.

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10. Equity

Changes to equity during the nine months ended September 30, 2016 , were as follows:

	Western Shareholders' Equity				Non-controlling Interest				Total Equity
	(In thousands)
Balance at December 31, 2015	$	1,299,297			$	1,646,609			$	2,945,906
Net income	134,528				52,229				186,757
Other comprehensive loss, net of tax	(52		)		(70		)		(122		)
Dividends	(111,555		)		—				(111,555		)
Stock-based compensation	6,264				5,203				11,467
Tax deficiency from stock-based compensation	(434		)		—				(434		)
Distributions to non-controlling interests	—				(49,906		)		(49,906		)
NTI merger	(14,020		)		(1,329,348		)		(1,343,368		)
Transaction costs for NTI merger	(11,741		)		—				(11,741		)
Issuance of WNRL common units	—				277,751				277,751
Offering costs for issuance of WNRL common units	—				(477		)		(477		)
Treasury stock issuance	438,168				—				438,168
Treasury stock purchases	(75,000		)		—				(75,000		)
Balance at September 30, 2016	$	1,665,455			$	601,991			$	2,267,446

Changes to equity during the nine months ended September 30, 2015 , were as follows:

	Western Shareholders' Equity				Non-controlling Interest				Total Equity
	(In thousands)
Balance at December 31, 2014	$	1,119,708			$	1,667,936			$	2,787,644
Net income	393,211				213,722				606,933
Other comprehensive income, net of tax	65				66				131
Dividends	(93,612		)		—				(93,612		)
Stock-based compensation	3,216				8,814				12,030
Excess tax benefit from stock-based compensation	879				—				879
Distributions to non-controlling interests	—				(176,289		)		(176,289		)
Treasury stock purchases	(105,000		)		—				(105,000		)
Other	—				(221		)		(221		)
Balance at September 30, 2015	$	1,318,467			$	1,714,028			$	3,032,495

Share Issuance

Pursuant to the Merger Agreement, we issued 17.1 million shares of Western common stock including 11.6 million treasury shares on June 23, 2016. See Note 21, Acquisitions , for further discussion of the Merger.

Share Repurchase Programs

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. Our board of directors approved our current share repurchase program in September of 2015 ("September 2015 Program"). The September 2015 program is scheduled to expire on December 31, 2016. Our common stock repurchase programs are subject to discontinuance by our board of directors at any time.

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The following table summarizes our share repurchase activity for the September 2015 Program:

	Number of shares purchased			Cost of share purchases (In thousands)
Shares purchased at December 31, 2015	—			$	—
Shares purchased during Q1, 2016	2,462,350			75,000
Shares purchased at March 31, 2016	2,462,350			75,000
Shares purchased during Q2, 2016	—			—
Shares purchased at June 30, 2016	2,462,350			75,000
Shares purchased during Q3, 2016	—			—
Shares purchased at September 30, 2016	2,462,350			$	75,000

As of September 30, 2016 , we had $125.0 million remaining in authorized purchases under the September 2015 Program.

Dividends

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 (1)

October 13

October 24

November 8

0.38

—

Total

$

111,488

(1) The fourth quarter 2016 cash dividend of $0.38 per common share will result in an estimated aggregate payment of $41.2 million .

NTI Distributions

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

Declaration Date		Record Date		Payment Date		Distribution per Unit
February 3, 2016		February 12, 2016		February 19, 2016		$	0.38
June 13, 2016		June 23, 2016		June 23, 2016		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
February 1, 2016		February 11, 2016		February 26, 2016		$	0.3925
April 25, 2016		May 13, 2016		May 27, 2016		0.4025
July 26, 2016		August 12, 2016		August 26, 2016		0.4125
October 24, 2016		November 7, 2016		November 23, 2016		0.4225
Total						$	1.6300

In addition to its quarterly distributions, WNRL paid incentive distributions of $1.2 million , $2.9 million , $0.3 million and $0.5 million for the three and nine months ended September 30, 2016 and 2015 , respectively, to Western as its general partner and holder of its incentive distribution rights.

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11. Income Taxes

Compared to the federal statutory rate of 35% , our effective tax rates for the three and nine months ended September 30, 2016 and 2015 , were 20.9% , 26.8% , 29.7% and 27.5% , respectively. The effective tax rates for the three and nine months ended September 30, 2016 and 2015 , were lower than the statutory rate primarily due to the reduction of taxable income associated with the non-controlling interests in NTI and WNRL. In addition, we released reserves related to uncertain tax positions during the third quarter of 2016. As of June 23, 2016, all of NTI's taxable income became subject to income taxes at the Western consolidated level.

We are subject to examination by the Internal Revenue Service for tax years ended December 31, 2013, or after and by various state and local taxing jurisdictions for tax years ended December 31, 2012, or after.

We believe that it is more likely than not that the benefit from certain state net operating loss ("NOL") carryforwards related to the Yorktown refinery will not be realized. Accordingly, a valuation allowance of $20.8 million was previously provided against the deferred tax assets relating to these NOL carryforwards at September 30, 2016 . There was no change in the valuation allowance for the Yorktown NOL carryforwards from December 31, 2015 .

As of September 30, 2016 , we have recorded a liability of $34.5 million for unrecognized tax benefits, of which $18.7 million would affect our effective tax rate if recognized. There was a decrease of $6.7 million and $5.7 million , respectively, in our unrecognized tax benefits for the three and nine months ended September 30, 2016 . We believe that it is reasonably possible that a decrease of up to $5.6 million in unrecognized tax benefits, resulting from the expiration of statutes of limitations in various tax jurisdictions, may be necessary within the coming year. We also recognized $0.4 million , $0.9 million , $0.1 million and $0.3 million in interest and penalties for three and nine months ended September 30, 2016 and 2015 , respectively.

12. Retirement Plans

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

Pensions

The net periodic benefit cost associated with our cash balance plan for both the three and nine months ended September 30, 2016 and 2015 , was $0.6 million , $1.8 million , $0.7 million and $1.9 million , respectively.

Postretirement Obligations

The net periodic benefit cost associated with our postretirement medical benefit plans for the three and nine months ended September 30, 2016 and 2015 , was $0.03 million , $0.1 million , $0.2 million and $0.7 million , respectively.

Our benefit obligation at December 31, 2015 , for our postretirement medical benefit plans was $6.2 million . We fund our medical benefit plans on an as-needed basis.

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The following table presents cumulative changes in other comprehensive income (loss) 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 Condensed Consolidated Statements of Operations.

	Three Months Ended								Nine Months Ended
	September 30,								September 30,
	2016				2015				2016				2015
	(In thousands)
Beginning of period balance	$	599			$	(1,234	)		$	651			$	(1,291	)
Amortization of net prior service cost	—				—				(63		)		41
Reclassification of loss to income	—				13				11				38
Income tax	—				(5		)		—				(14		)
End of period balance	$	599			$	(1,226	)		$	599			$	(1,226	)

Defined Contribution Plan

Western sponsors defined contribution plans under which Western, NTI and WNRL participants may contribute a percentage of their eligible compensation to various investment choices offered by these plans. For the three and nine months ended September 30, 2016 and 2015 , we expensed $4.5 million , $13.6 million , $4.2 million and $12.8 million , respectively, in connection with these plans.

13. Crude Oil and Refined Product Risk Management

We enter into crude oil forward contracts primarily to facilitate the supply of crude oil to our refineries. During the nine months ended September 30, 2016 , 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, refined products and natural gas futures, swap contracts or options to mitigate the change in value for a portion of our LIFO inventory and refinery fuel gas volumes subject to market price fluctuations. We enter into swap contracts to fix differentials on a portion of our future crude oil purchases and to fix margins 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 Condensed Consolidated Balance Sheets and the related net gain or loss is recorded within cost of products sold in the Condensed 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 the hedging instruments to market at each period end.

The following tables summarize our economic hedging activity recognized within cost of products sold for the three and nine months ended September 30, 2016 and 2015 , and open commodity hedging positions as of September 30, 2016 and December 31, 2015 :

	Three Months Ended								Nine Months Ended
	September 30,								September 30,
	2016				2015				2016				2015
	(In thousands)
Economic hedging results
Realized hedging gain, net	$	27,757			$	26,949			$	46,110			$	52,325
Unrealized hedging gain (loss), net	(27,616		)		271				(54,698		)		(42,073		)
Total hedging gain (loss), net	$	141			$	27,220			$	(8,588	)		$	10,252

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	September 30, 2016				December 31, 2015
	(In thousands)
Open commodity hedging instruments (barrels)
Crude oil differential swaps, net long positions	5,622				5,155
Crude oil futures, net short positions	(687		)		(562		)
Refined product price and crack spread swaps, net short positions	(3,902		)		(5,645		)
Total open commodity hedging instruments, net long (short) positions	1,033				(1,052		)
Fair value of outstanding contracts, net
Other current assets	$	26,757			$	78,125
Other assets	2,851				11,881
Accrued liabilities	(4,457		)		(10,273		)
Other long-term liabilities	(153		)		—
Fair value of outstanding contracts - unrealized gain, net	$	24,998			$	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 Condensed 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 September 30, 2016 and December 31, 2015 :

	Gross Amounts of Recognized Assets (Liabilities)				Gross Amounts Offset in the Condensed Consolidated Balance Sheet				Net Amounts of Assets (Liabilities) Presented in the Condensed Consolidated Balance Sheet
As of September 30, 2016
	(In thousands)
Financial assets:
Current assets	$	34,060			$	(7,303	)		$	26,757
Other assets	4,455				(1,604		)		2,851
Financial liabilities:
Accrued liabilities	(10,449		)		5,992				(4,457		)
Other long-term liabilities	(3,068		)		2,915				(153		)
	$	24,998			$	—			$	24,998

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(Unaudited)

	Gross Amounts of Recognized Assets (Liabilities)				Gross Amounts Offset in the Condensed Consolidated Balance Sheet				Net Amounts of Assets (Liabilities) Presented in the Condensed Consolidated Balance Sheet
As of December 31, 2015
	(In thousands)
Financial assets:
Current assets	$	95,062			$	(16,937	)		$	78,125
Other assets	11,881				—				11,881
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 September 30, 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 $13.72 to $16.86 per contract. The information presents the notional volume of outstanding contracts by type of instrument and year of maturity (volumes in thousands of barrels):

	Notional Contract Volumes by Year of Maturity
	2016			2017
Inventory positions (futures and swaps):
Crude oil differential swaps, net long positions	3,042			2,580
Crude oil futures, net short positions	(687	)		—
Distillate - net short positions	(137	)		—
Refined products - net short positions	(315	)		(875	)
Natural gas futures - net long positions	151			329
Refined product positions (crack spread swaps):
Distillate - net short positions	(850	)		(1,680	)
Unleaded gasoline - net short positions	(525	)		—

14. Stock-Based Compensation

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 (the "2010 Incentive Plan") allow for restricted share unit awards ("RSUs") among other forms of awards. As of September 30, 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 September 30, 2016 , there were 658,506 unvested RSUs outstanding. We recorded stock compensation of $1.8 million , $4.5 million , $1.1 million and $3.2 million for the three and nine months ended September 30, 2016 and 2015 , respectively, which is included in selling, general and administrative expenses.

As of September 30, 2016 , the aggregate grant date fair value of outstanding RSUs was $21.2 million . The aggregate intrinsic value of outstanding RSUs was $17.4 million . The unrecognized compensation cost of unvested RSUs was $16.6 million . Unrecognized compensation costs for RSUs will be recognized over a weighted-average period of 2.63 years.

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The tax deficiency related to the RSUs that vested during the nine months ended September 30, 2016 , was $0.4 million using a statutory blended rate of 38.1% . There was no RSU vesting activity during the three months ended September 30, 2016 . The aggregate grant date fair value of the RSUs that vested during the nine months ended September 30, 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 three and nine months ended September 30, 2015 , was $0.03 million and $0.9 million , respectively, using a statutory blended rate of 38.1% . The aggregate grant date fair value of the RSUs that vested during the three and nine months ended September 30, 2015 , was $0.1 million and $3.7 million , respectively. The related aggregate intrinsic value of these RSUs was $0.2 million and $6.0 million , respectively, at the vesting date.

The following table summarizes our RSU activity for the nine months ended September 30, 2016 :

	Number of Units			Weighted Average Grant Date Fair Value
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 September 30, 2016	658,506			32.25

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

Effective upon the closing of the 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 Merger Agreement, all unvested equity awards at the time of the Merger were exchanged for Western phantom stock awards and performance cash awards under the NTI LTIP.

We incurred equity-based compensation expense of $3.0 million , $11.0 million , $2.4 million and $7.9 million for the three and nine months ended September 30, 2016 and 2015 , 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 September 30, 2016 , there was 255,560 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 September 30, 2016 , was $16.7 million . The aggregate intrinsic value of such phantom stock was $21.8 million . Total unrecognized compensation cost related to unvested phantom stock totaled $11.4 million as of September 30, 2016 , that is expected to be recognized over a weighted-average period of 1.5 years . The excess tax benefit related to the phantom stock that vested during the three and nine months ended September 30, 2016 , was $0.01 million using a statutory blended rate of 38.1% . The aggregate grant date fair value of the phantom stock that vested during the three and nine months ended September 30, 2016 , was $0.3 million . The related aggregate intrinsic value of the vested phantom stock was $0.3 million at the vesting date.

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A summary of our phantom stock award activity under the NTI LTIP for the nine months ended September 30, 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	(13,817	)		20.25
Awards forfeited	(12,132	)		20.25
Not vested at September 30, 2016	822,318			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. As of September 30, 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 $0.7 million , $2.0 million , $0.6 million and $1.5 million for the three and nine months ended September 30, 2016 and 2015 , respectively.

The aggregate grant date fair value of non-vested phantom units outstanding as of September 30, 2016 , was $7.5 million . The aggregate intrinsic value of such phantom units was $6.6 million . Total unrecognized compensation cost related to unvested phantom units totaled $6.2 million as of September 30, 2016 , that is expected to be recognized over a weighted-average period of 2.60 years.

A summary of WNRL's common and phantom unit award activity for the nine months ended September 30, 2016 , is set forth below:

	Number of Phantom Units			Weighted Average Grant Date Fair Value
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 September 30, 2016	285,155			26.42

15. 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.

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:

	Three Months Ended								Nine Months Ended
	September 30,								September 30,
	2016				2015				2016				2015
	(In thousands, except per share data)
Basic earnings per common share:
Allocation of earnings:
Net income attributable to Western Refining, Inc.	$	38,575			$	153,303			$	134,528			$	393,211
Distributed earnings	(41,269		)		(32,498		)		(111,555		)		(93,612		)
Undistributed income (loss) attributable to Western Refining, Inc.	$	(2,694	)		$	120,805			$	22,973			$	299,599
Weighted-average number of common shares outstanding	108,424				94,826				97,802				95,308
Basic earnings per common share:
Distributed earnings per share	$	0.38			$	0.34			$	1.14			$	0.98
Undistributed earnings (loss) per share	(0.02		)		1.27				0.23				3.14
Basic earnings per common share	$	0.36			$	1.61			$	1.37			$	4.12
Diluted earnings per common share:
Net income attributable to Western Refining, Inc.	$	38,575			$	153,303			$	134,528			$	393,211
Weighted-average diluted common shares outstanding	108,734				94,924				98,110				95,408
Diluted earnings per common share	$	0.35			$	1.61			$	1.37			$	4.12

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

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2016			2015			2016			2015
	(In thousands)
Weighted-average number of common shares outstanding	108,424			94,826			97,802			95,308
Restricted share units and phantom stock	310			98			308			100
Weighted-average number of diluted shares outstanding	108,734			94,924			98,110			95,408

A shareholder's interest in our common stock could become diluted as a result of vestings of RSUs and phantom stock. In calculating our fully diluted earnings per common share, we consider the impact of RSUs and phantom stock that have not vested. We include unvested awards 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.

16. Cash Flows

Restricted Cash

Restricted cash reported in our Condensed Consolidated Balance Sheet at September 30, 2016 , related to net proceeds from the sale of the St. Paul Park Logistics Assets to WNRL. This cash is restricted until the earlier of a) use of the cash to invest in capital assets to replace the collateral assets that were sold, b) acceptance by holders of the NTI 2020 Secured Notes of an offer to repurchase such notes at par or c) expiration of an offer to repurchase the NTI 2020 Secured Notes . NTI commenced a tender offer to repurchase for cash up to $195.0 million aggregate principal amount the NTI 2020 Secured Notes on October 17, 2016, and such offer expires on November 15, 2016. Any cash remaining after the offer to repurchase expires will become unrestricted and available for general corporate purposes.

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

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Supplemental Cash Flow Information

Supplemental disclosures of cash flow information were as follows:

	Nine Months Ended
	September 30,
	2016				2015
	(In thousands)
Non-cash operating activities were as follows:
Income taxes paid	$	40,562			$	210,656
Interest paid, excluding amounts capitalized	83,156				62,216
Non-cash investing activities were as follows:
Assets acquired through capital lease obligations	$	4,644			$	24,578
Accrued capital expenditures	33,111				31,744
PP&E derecognized from sale leaseback continuing involvement release	2,799				1,773
Transfer of capital spares from fixed asset to inventory	—				1,490
Transfer of capital spares from fixed assets to other assets	699				—
Transfer of capital spares from other assets to fixed assets	161				—
Non-cash financing activities were as follows:
Reduction of long-term debt proceeds from original issuance discount	$	10,250			$	—
Treasury stock issuance	438,168				—
Distributions accrued on unvested equity awards	—				2,602
Distributions receivable from equity method investee	—				4,250
Accrued offering costs for issuance of WNRL common units	60				—

17. 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. The building serves as our headquarters. In December 2007, we entered into an eleven -year lease agreement for an office building in Tempe, Arizona. The building centralized our operational and administrative offices in the Phoenix area.

We are party to 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 $54.5 million and $53.2 million is included in lease financing obligations in the accompanying Condensed Consolidated Balance Sheets as of September 30, 2016 and December 31, 2015 , respectively. The capital lease obligations include a deferred gain of $0.3 million . These capital leases were discounted using annual rates from 3.24% to 10.51% . Total remaining interest related to these leases was $41.0 million and $44.1 million at September 30, 2016 and December 31, 2015 , respectively. Average annual payments, including interest, for the next five years are $5.5 million with the remaining $73.0 million due through 2036 .

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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 September 30, 2016 :

	Operating				Capital
Remaining 2016	$	14,021			$	1,380
2017	54,078				5,419
2018	50,739				5,444
2019	45,648				5,553
2020	41,467				5,744
2021 and thereafter	346,889				73,027
Total minimum lease payments	$	552,842			96,567
Less amount that represents interest					40,951
Present value of net minimum capital lease payments					$	55,616

Total rental expense was $17.9 million , $53.9 million , $16.2 million and $47.8 million for the three and nine months ended September 30, 2016 and September 30, 2015 , respectively. Contingent rentals and subleases were not significant in any period.

18. Commitments and 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 September 30, 2016 and December 31, 2015 , we had consolidated environmental accruals of $18.0 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 $6.5 million remained as of September 30, 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.

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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. During the first quarter of 2016, we completed the capital expenditures required by the 2005 NMED Amended Agreement to implement one or more FCCU emission offset projects prior to the end of 2017. We incurred $0.1 million and $1.9 million , respectively, for the years ended December 31, 2015 and 2014, and $0.1 million for the nine months ended September 30, 2016 , to implement 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.

St. Paul Park Refinery

At September 30, 2016 and December 31, 2015 , liabilities for remediation and closure obligations and related operations at the St. Paul Park refinery totaled $7.6 million and $8.6 million , respectively, of which $2.4 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 September 30, 2016 , the estimated future cash flows to settle these discounted liabilities totaled $2.9 million and are discounted at a rate of 2.03% . Receivables for recoverable costs from the state, under programs to assist companies in clean-up efforts related to underground storage tanks at retail marketing outlets, and others were $0.1 million and $0.2 million at September 30, 2016 and December 31, 2015 , respectively.

On June 3, 2014, the St. Paul Park refinery was issued a National Pollutant Discharge Elimination Permit/State Disposal System Permit by the Minnesota Pollution Control Agency ("MPCA") relating to its upgraded wastewater treatment plant at its St. Paul Park refinery. This permit required the refinery to conduct additional testing of its remaining lagoon. The testing was completed in the fourth quarter of 2014, following the review of the test results and additional discussions with MPCA, we plan to close the remaining lagoon. At September 30, 2016 and December 31, 2015 , we estimated the remediation and closure costs to be $5.2 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 Merger, Evercore Group, L.L.C. (“Evercore”), and MergerCo (collectively, “Defendants”) (the “Merger Litigation”). The Merger Litigation appears to challenge the adequacy of disclosures made in connection with the Merger. Plaintiff seeks monetary damages and attorneys’ fees. The Merger Litigation is in the earliest stages of litigation. Western believes the Merger Litigation is without merit and intends to vigorously defend against it.

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

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significantly from period to period. The net cost of meeting our estimated renewable volume obligations, including sales and purchases of RINs, was $15.8 million , $51.9 million , $13.1 million and $25.8 million for the three and nine months ended September 30, 2016 and 2015 , 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 and entered into another settlement in May 2015, with the EPA regarding RINs we purchased that the EPA ultimately determined were invalid. While we do not know if the EPA will determine that other RINs we have purchased are invalid, at this time we do not expect any settlements we would enter into with the EPA would have a material effect on our financial condition, results of operations or cash flows.

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

19. Related Party Transactions

We lease office space in a building located in El Paso, Texas that is owned by an entity controlled by a member of our board of directors who is also an officer. The lease agreement expires in May 2017. Under the terms of the lease, we make annual payments of $0.2 million . For the three and nine months ended September 30, 2016 and 2015 , we made rental payments under this lease to the related party of $0.06 million , $0.18 million , $0.06 million and $0.18 million . We have no amounts due as of September 30, 2016 , related to this lease agreement.

Beginning on September 30, 2014, we began paying MPL for transportation services at published tariff rates. During the three and nine months ended September 30, 2016 and 2015 , we paid $12.3 million , $41.1 million , $13.9 million and $41.3 million , respectively, in crude transportation costs with MPL. Western's President and Chief Operating Officer is a member of MPL's board of managers.

20. Condensed Consolidating Financial Information

Separate condensed consolidating financial information of Western Refining, Inc. (the "Parent"), subsidiary guarantors and non-guarantors is presented below. At September 30, 2016 , the Parent and certain subsidiary guarantors have fully and unconditionally guaranteed our Western 2021 Senior Unsecured Notes on a joint and several basis. NTI and WNRL are subsidiaries that have not guaranteed the Western 2021 Senior Unsecured Notes. As a result of the Parent and certain subsidiaries' guarantee arrangements, we are required to present the following condensed consolidating financial information that should be read in conjunction with the accompanying condensed 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 and the TexNew Mex Pipeline Transaction, we have made corresponding retrospective adjustments to the condensed consolidating financial information for all periods presented. See Note 1, Organization , for additional information on this transaction.

As of September 30, 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, the general partner of NTI that we wholly own. Any recourse to NTI’s general partner would be limited to the extent of the general partner’s assets that other than its investment in NTI are not significant. Furthermore, the Parent's creditors have no recourse to the assets of NTI's general partner, NTI and its consolidated subsidiaries. See Note 9, 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

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(Unaudited)

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 9, 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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(Unaudited)

CONDENSED CONSOLIDATING BALANCE SHEETS

As of September 30, 2016

(In thousands)

	Parent				Guarantor Subsidiaries				Non-Guarantors				Eliminations				Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	21			$	234,970			$	31,105			$	—			$	266,096
Restricted cash	—				—				195,000				—				195,000
Accounts receivable, trade, net of a reserve for doubtful accounts	—				137,775				309,552				—				447,327
Accounts receivable, affiliate	15,778				71,656				3,378				(90,812		)		—
Inventories	—				380,161				280,577				—				660,738
Prepaid expenses	—				104,195				24,943				—				129,138
Other current assets	—				83,042				38,539				—				121,581
Total current assets	15,799				1,011,799				883,094				(90,812		)		1,819,880
Equity method investment	—				—				98,185				—				98,185
Property, plant and equipment, net	—				1,114,593				1,242,698				—				2,357,291
Goodwill	—				—				1,289,443				—				1,289,443
Intangible assets, net	—				31,947				52,596				—				84,543
Investment in subsidiaries	5,462,120				—				—				(5,462,120		)		—
Due from affiliate	—				2,460,977				—				(2,460,977		)		—
Other assets, net	—				32,195				33,588				—				65,783
Total assets	$	5,477,919			$	4,651,511			$	3,599,604			$	(8,013,909	)		$	5,715,125
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable, trade	$	—			$	306,033			$	328,683			$	—			$	634,716
Accounts payable, affiliate	—				—				90,812				(90,812		)		—
Accrued liabilities	10,960				107,907				97,302				—				216,169
Current portion of long-term debt	10,500				—				—				—				10,500
Total current liabilities	21,460				413,940				516,797				(90,812		)		861,385
Long-term liabilities:
Long-term debt, less current portion	1,330,027				—				715,153				—				2,045,180
Due to affiliate	2,460,977				—				—				(2,460,977		)		—
Lease financing obligations	—				45,333				9,208				—				54,541
Deferred income tax liability, net	—				380,508				36,443				—				416,951
Deficit in subsidiaries	—				497,548				—				(497,548		)		—
Other liabilities	—				59,349				10,273				—				69,622
Total long-term liabilities	3,791,004				982,738				771,077				(2,958,525		)		2,586,294
Equity:
Equity - Western	1,665,455				3,254,833				1,709,739				(4,964,572		)		1,665,455
Equity - Non-controlling interests	—				—				601,991				—				601,991
Total equity	1,665,455				3,254,833				2,311,730				(4,964,572		)		2,267,446
Total liabilities and equity	$	5,477,919			$	4,651,511			$	3,599,604			$	(8,013,909	)		$	5,715,125

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(Unaudited)

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	3,791,084				—				—				(3,791,084		)		—
Due from affiliate	—				1,623,553				—				(1,623,553		)		—
Other assets, net	—				42,166				22,831				—				64,997
Total assets	$	3,791,105			$	4,203,549			$	3,312,431			$	(5,473,692	)		$	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	1,623,553				—				—				(1,623,553		)		—
Lease financing obligations	—				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	2,479,880				669,237				841,832				(1,911,314		)		2,079,635
Equity:
Equity - Western	1,299,297				3,129,505				373,818				(3,503,323		)		1,299,297
Equity - Non-controlling interests	—				—				1,646,609				—				1,646,609
Total equity	1,299,297				3,129,505				2,020,427				(3,503,323		)		2,945,906
Total liabilities and equity	$	3,791,105			$	4,203,549			$	3,312,431			$	(5,473,692	)		$	5,833,393

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CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS AND COMPREHENSIVE INCOME

Three Months Ended September 30, 2016

(In thousands)

	Parent				Guarantor Subsidiaries				Non-Guarantors				Eliminations				Consolidated
Net sales	$	—			$	1,970,512			$	1,637,091			$	(1,542,527	)		$	2,065,076
Operating costs and expenses:
Cost of products sold (exclusive of depreciation and amortization)	—				1,733,544				1,415,993				(1,542,527		)		1,607,010
Direct operating expenses (exclusive of depreciation and amortization)	—				113,416				119,137				—				232,553
Selling, general and administrative expenses	46				29,887				27,387				—				57,320
Gain on disposal of assets, net	—				(217		)		(62		)		—				(279		)
Maintenance turnaround expense	—				366				26,842				—				27,208
Depreciation and amortization	—				27,286				27,035				—				54,321
Total operating costs and expenses	46				1,904,282				1,616,332				(1,542,527		)		1,978,133
Operating income (loss)	(46		)		66,230				20,759				—				86,943
Other income (expense):
Equity in earnings of subsidiaries	61,069				1,125				—				(62,194		)		—
Interest income	—				100				41				—				141
Interest and debt expense	(22,448		)		(788		)		(11,220		)		—				(34,456		)
Other, net	—				(1,301		)		4,681				—				3,380
Income (loss) before income taxes	38,575				65,366				14,261				(62,194		)		56,008
Provision for income taxes	—				(11,418		)		(282		)		—				(11,700		)
Net income (loss)	38,575				53,948				13,979				(62,194		)		44,308
Less net income attributable to non-controlling interests	—				—				5,733				—				5,733
Net income (loss) attributable to Western Refining, Inc.	$	38,575			$	53,948			$	8,246			$	(62,194	)		$	38,575
Comprehensive income attributable to Western Refining, Inc.	$	38,575			$	53,948			$	8,246			$	(62,194	)		$	38,575

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(Unaudited)

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS AND COMPREHENSIVE INCOME

Nine Months Ended September 30, 2016

(In thousands)

	Parent				Guarantor Subsidiaries				Non-Guarantors				Eliminations				Consolidated
Net sales	$	—			$	4,466,234			$	3,881,556			$	(2,719,902	)		$	5,627,888
Operating costs and expenses:
Cost of products sold (exclusive of depreciation and amortization)	—				3,780,557				3,196,344				(2,719,902		)		4,256,999
Direct operating expenses (exclusive of depreciation and amortization)	—				333,556				353,751				—				687,307
Selling, general and administrative expenses	139				82,283				84,235				—				166,657
Gain on disposal of assets, net	—				(208		)		(973		)		—				(1,181		)
Maintenance turnaround expense	—				891				26,842				—				27,733
Depreciation and amortization	—				79,620				81,711				—				161,331
Total operating costs and expenses	139				4,276,699				3,741,910				(2,719,902		)		5,298,846
Operating income (loss)	(139		)		189,535				139,646				—				329,042
Other income (expense):
Equity in earnings of subsidiaries	184,428				5,689				—				(190,117		)		—
Interest income	—				317				119				—				436
Interest and debt expense	(49,761		)		(2,284		)		(36,020		)		—				(88,065		)
Other, net	—				(208		)		14,033				—				13,825
Income (loss) before income taxes	134,528				193,049				117,778				(190,117		)		255,238
Provision for income taxes	—				(67,721		)		(760		)		—				(68,481		)
Net income (loss)	134,528				125,328				117,018				(190,117		)		186,757
Less net income attributable to non-controlling interests	—				—				52,229				—				52,229
Net income (loss) attributable to Western Refining, Inc.	$	134,528			$	125,328			$	64,789			$	(190,117	)		$	134,528
Comprehensive income attributable to Western Refining, Inc.	$	134,528			$	125,328			$	64,737			$	(190,117	)		$	134,476

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(Unaudited)

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS AND COMPREHENSIVE INCOME

Three Months Ended September 30, 2015

(In thousands)

	Parent				Guarantor Subsidiaries				Non-Guarantors				Eliminations				Consolidated
Net sales	$	—			$	1,846,297			$	1,478,695			$	(755,902	)		$	2,569,090
Operating costs and expenses:
Cost of products sold (exclusive of depreciation and amortization)	—				1,476,431				1,175,243				(755,902		)		1,895,772
Direct operating expenses (exclusive of depreciation and amortization)	—				111,871				122,569				—				234,440
Selling, general and administrative expenses	48				28,061				26,356				—				54,465
Gain on disposal of assets, net	—				(6		)		(46		)		—				(52		)
Maintenance turnaround expense	—				490				—				—				490
Depreciation and amortization	—				24,830				26,547				—				51,377
Total operating costs and expenses	48				1,641,677				1,350,669				(755,902		)		2,236,492
Operating income (loss)	(48		)		204,620				128,026				—				332,598
Other income (expense):
Equity in earnings of subsidiaries	166,608				6,647				—				(173,255		)		—
Interest income	—				106				80				—				186
Interest and debt expense	(13,257		)		(703		)		(12,936		)		—				(26,896		)
Other, net	—				(6		)		4,333				—				4,327
Income (loss) before income taxes	153,303				210,664				119,503				(173,255		)		310,215
Provision for income taxes	—				(92,114		)		(3		)		—				(92,117		)
Net income (loss)	153,303				118,550				119,500				(173,255		)		218,098
Less net income attributable to non-controlling interests	—				—				64,795				—				64,795
Net income (loss) attributable to Western Refining, Inc.	$	153,303			$	118,550			$	54,705			$	(173,255	)		$	153,303
Comprehensive income attributable to Western Refining, Inc.	$	153,303			$	118,558			$	54,705			$	(173,255	)		$	153,311

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CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS AND COMPREHENSIVE INCOME

Nine Months Ended September 30, 2015

(In thousands)

	Parent				Guarantor Subsidiaries				Non-Guarantors				Eliminations				Consolidated
Net sales	$	—			$	5,611,815			$	4,372,591			$	(2,267,694	)		$	7,716,712
Operating costs and expenses:
Cost of products sold (exclusive of depreciation and amortization)	—				4,612,431				3,470,232				(2,267,694		)		5,814,969
Direct operating expenses (exclusive of depreciation and amortization)	—				331,423				343,051				—				674,474
Selling, general and administrative expenses	142				87,486				82,180				—				169,808
Loss (gain) on disposal of assets, net	—				444				(601		)		—				(157		)
Maintenance turnaround expense	—				1,188				—				—				1,188
Depreciation and amortization	—				74,457				77,989				—				152,446
Total operating costs and expenses	142				5,107,429				3,972,851				(2,267,694		)		6,812,728
Operating income (loss)	(142		)		504,386				399,740				—				903,984
Other income (expense):
Equity in earnings of subsidiaries	433,921				8,576				—				(442,497		)		—
Interest income	—				308				242				—				550
Interest and debt expense	(40,568		)		(1,943		)		(36,658		)		—				(79,169		)
Other, net	—				(519		)		12,076				—				11,557
Income (loss) before income taxes	393,211				510,808				375,400				(442,497		)		836,922
Provision for income taxes	—				(229,635		)		(354		)		—				(229,989		)
Net income (loss)	393,211				281,173				375,046				(442,497		)		606,933
Less net income attributable to non-controlling interests	—				—				213,722				—				213,722
Net income (loss) attributable to Western Refining, Inc.	$	393,211			$	281,173			$	161,324			$	(442,497	)		$	393,211
Comprehensive income attributable to Western Refining, Inc.	$	393,211			$	281,197			$	161,365			$	(442,497	)		$	393,276

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(Unaudited)

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

Nine Months Ended September 30, 2016

(In thousands)

	Parent				Guarantor Subsidiaries				Non-Guarantors				Eliminations				Consolidated
Cash flows from operating activities:
Net cash provided by (used in) operating activities	$	(42,552	)		$	226,792			$	141,120			$	(47,483	)		$	277,877
Cash flows from investing activities:
Capital expenditures	—				(113,533		)		(121,804		)		240				(235,097		)
Return of capital from equity method investment	13,537				—				—				(13,537		)		—
Increase in restricted cash	—				—				(195,000		)		—				(195,000		)
Use of restricted cash	—				69,106				—				—				69,106
Contributions to affiliate	—				(603,987		)		(20,286		)		624,273				—
Proceeds from the sale of assets	—				348				3,804				(240		)		3,912
Net cash provided by (used in) investing activities	13,537				(648,066		)		(333,286		)		610,736				(357,079		)
Cash flows from financing activities:
Additions to long-term debt	500,000				—				—				—				500,000
Payments on long-term debt and capital lease obligations	(5,375		)		(748		)		(1,027		)		—				(7,150		)
Borrowings on revolving credit facility	—				—				393,900				—				393,900
Repayments on revolving credit facility	—				—				(466,600		)		—				(466,600		)
Payments for NTI units related to merger	(859,893		)		—				—				—				(859,893		)
Transaction costs for NTI merger	(11,741		)		—				—				—				(11,741		)
Proceeds from issuance of WNRL common units	—				—				277,751				—				277,751
Offering costs for issuance of WNRL common units	—				—				(417		)		—				(417		)
Deferred financing costs	(11,408		)		—				(1,002		)		—				(12,410		)
Distribution to affiliate	—				—				(61,020		)		61,020				—
Purchases of common stock for treasury	(75,000		)		—				—				—				(75,000		)
Distribution to non-controlling interest holders	—				—				(54,115		)		—				(54,115		)
Dividends paid	(111,555		)		—				—				—				(111,555		)
Contributions from affiliates	603,987				—				20,286				(624,273		)		—
Distribution to Western Refining, Inc.	—				—				—				—				—
Excess tax benefit from stock-based compensation	—				26				—				—				26
Net cash provided by (used in) financing activities	29,015				(722		)		107,756				(563,253		)		(427,204		)
Net decrease in cash and cash equivalents	—				(421,996		)		(84,410		)		—				(506,406		)
Cash and cash equivalents at beginning of year	21				656,966				115,515				—				772,502
Cash and cash equivalents at end of year	$	21			$	234,970			$	31,105			$	—			$	266,096

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(Unaudited)

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

Nine Months Ended September 30, 2015

(In thousands)

	Parent				Guarantor Subsidiaries				Non-Guarantors				Eliminations				Consolidated
Cash flows from operating activities:
Net cash provided by (used in) operating activities	$	67,772			$	345,293			$	383,762			$	(131,163	)		$	665,664
Cash flows from investing activities:
Capital expenditures	—				(108,988		)		(88,545		)		1,557				(195,976		)
Use of restricted cash	—				154,681				—				—				154,681
Return of capital from equity method investment	—				—				5,780				—				5,780
Contributions to affiliate	—				(158,652		)		(18,457		)		177,109				—
Proceeds from the sale of assets	—				2,028				590				(1,557		)		1,061
Net cash provided by (used in) investing activities	—				(110,931		)		(100,632		)		177,109				(34,454		)
Cash flows from financing activities:
Additions to long-term debt	—				—				300,000				—				300,000
Payments on long-term debt and capital lease obligations	(4,125		)		(658		)		(776		)		—				(5,559		)
Repayments on revolving credit facility	—				—				(269,000		)		—				(269,000		)
Distribution to affiliate	—				—				(131,163		)		131,163				—
Deferred financing costs	—				—				(6,820		)		—				(6,820		)
Purchases of common stock for treasury	(105,000		)		—				—				—				(105,000		)
Distribution to non-controlling interest holders	—				—				(173,687		)		—				(173,687		)
Dividends paid	(93,612		)		—				—				—				(93,612		)
Contributions from affiliates	134,965				—				42,144				(177,109		)		—
Excess tax benefit from stock-based compensation	—				879				—				—				879
Net cash provided by (used in) financing activities	(67,772		)		221				(239,302		)		(45,946		)		(352,799		)
Net increase in cash and cash equivalents	—				234,583				43,828				—				278,411
Cash and cash equivalents at beginning of year	21				288,986				142,152				—				431,159
Cash and cash equivalents at end of year	$	21			$	523,569			$	185,980			$	—			$	709,570

21. Acquisitions

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 and 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

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WESTERN REFINING, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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, 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 Merger of $11.7 million .

The 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 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 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.

The consolidated statements of operations include the results of the Merger beginning on June 23, 2016. 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 Merger consideration on January 1, 2015, resulting in increased interest and debt expense of $17.0 million for the nine months ended September 30, 2016 and $9.1 million and $27.1 million for the three and nine months ended September 30, 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 for the nine months ended September 30, 2016 and $19.1 million and $64.9 million , for the three and nine months ended September 30, 2015 , respectively.

	Unaudited Pro Forma for the
	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2015				2016				2015
	(In thousands)
Net sales	$	2,569,090			$	5,627,888			$	7,716,712
Operating income	332,598				329,042				903,984
Net income	189,905				162,768				514,874
Net income attributable to Western Refining, Inc.	184,319				145,862				498,715
Basic earnings per share	$	1.65			$	1.35			$	4.43
Diluted earnings per share	1.65				1.34				4.43

Merger and Reorganization Expenses

We incurred professional service fees in connection with the Merger transaction. Additionally, we incurred costs associated with initiating a plan of reorganization for various positions during the third quarter of 2016. In relation to this reorganization plan, it was determined that certain employees would be terminated during 2016 and 2017. We recognized $2.8 million and $4.0 million  of expense during the three and nine months ended September 30, 2016 , respectively, which included compensation related to the severance of employment and retention bonuses for selected employees. These costs have been included in Other, net in the accompanying Condensed Consolidated Statements of Operations. All reorganization and

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WESTERN REFINING, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

related costs are recognized in the Other category. 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 September 30, 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 Merger and Reorganization for the three and nine months ended September 30, 2016 :

	Three Months Ended								Nine Months Ended
	September 30,								September 30,
	2016				2015				2016				2015
	(In thousands)
Beginning liability for merger and reorganization costs	$	452			$	470			$	189			$	808
Third-party professional service fees	178				—				1,321				—
Reorganization and related personnel costs incurred during period	2,666				—				2,666				—
Cash payments to third-party professional service providers	(442		)		—				(1,133		)		—
Cash payments made to severed employees	(1,487		)		(112		)		(1,676		)		(450		)
Ending liability for merger and reorganization costs	$	1,367			$	358			$	1,367			$	358

22. WNRL

WNRL is a publicly held master limited partnership that owns and operates logistic assets that consist of pipeline and gathering, terminalling, storage and transportation assets, providing related services to our refining segment, including 692  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, refined product and lubricant delivery trucks. WNRL distributes commercial wholesale petroleum products primarily in Arizona, California, Colorado, Nevada, New Mexico and Texas. WNRL purchases petroleum fuels and lubricants from our refining segment and from third-party suppliers.

As of September 30, 2016 , we owned a 52.6% interest in WNRL and a 100% general partner interest. 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.

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 32.2% , 31.8% , 31.9% and 30.0% of WNRL’s total revenues for the three and nine month periods ended September 30, 2016 and 2015 , 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 WNRL, 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.

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WESTERN REFINING, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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.

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Item 2.	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 report. This discussion contains forward-looking statements that are based on 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" included in our Annual Report on Form 10-K for the year ended December 31, 2015 ("2015 Form 10-K") and elsewhere in this report. You should read "Risk Factors" and "Forward-Looking Statements" in this report. In this Item 2, all references to "Western Refining," "the Company," "Western," "we," "us," and "our" refer to Western Refining, Inc. and its consolidated subsidiaries including Western Refining Logistics, LP ("WNRL"), unless the context otherwise requires or where otherwise indicated.

Company Overview

We are an independent crude oil refiner and marketer of refined products incorporated in September 2005 under Delaware law with principal offices located in El Paso, Texas. Our common stock trades on the New York Stock Exchange ("NYSE") under the symbol “WNR.” We own certain operating assets directly; the controlling general partner interest and 100% limited partner interest in Northern Tier Energy ("NTI") and the controlling general partner interest, incentive distribution rights and a 52.6% limited partner interest in WNRL. WNRL common partnership units trade on the NYSE under the symbol "WNRL."

We produce refined products at our refineries in El Paso, Texas ( 131,000 barrels per day, or bpd), near Gallup, New Mexico ( 25,000 bpd) and St. Paul Park, Minnesota ( 98,000 bpd). We sell refined products primarily in Arizona, Colorado, Minnesota, New Mexico, Wisconsin, West Texas, the Mid-Atlantic region and Mexico through bulk distribution terminals and wholesale marketing networks. We also sell refined products through two retail networks with a total of 545 company-operated and franchised retail sites in the United States.

Our 100% ownership of the general partner gives us effective control of WNRL. 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, California, Colorado, Nevada, New Mexico and Texas.

As of September 30, 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 “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 “Merger”). On June 23, 2016, following the approval of the Merger Agreement by NTI common unitholders, all closing conditions to the Merger were satisfied, and the Merger was successfully completed. We incurred $500 million of additional secured indebtedness under our amended term loan credit agreement to partially fund the Merger consideration. See Note 9, Long-Term Debt and Note 21, Acquisitions , in the Notes to Condensed Consolidated Financial Statements for further discussion.

On September 15, 2016 , we sold certain assets consisting of terminals, transportation and storage assets and related land located on site at our St. Paul Park refinery and Cottage Grove tank farm to WNRL. These assets primarily receive, store and distribute crude oil, feedstock and refined products associated with the St. Paul Park refinery (the " St. Paul Park Logistics Assets "). WNRL acquired these assets from us in exchange for $195 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 ."

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

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

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

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We have organized our operations into three segments, refining, WNRL and retail, based on manufacturing and marketing processes, the nature of our products and services and each segment's respective customer base. Prior to the Merger on June 23, 2016, we also reported NTI as a separate reportable segment. Following the completion of the Merger, NTI became a wholly-owned subsidiary of Western and, as a result, we have moved its assets and operations into our other reportable segments. 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. The St. Paul Park refinery and related operations are now included in the refining segment and the SuperAmerica retail and bakery assets and operations are now included in the retail segment. We have retrospectively adjusted the historical segment financial data for the periods presented to reflect our revised segment presentation. See Note 3, Segment Information , in the Notes to Condensed Consolidated Financial Statements for further discussion of our business segments.

•	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 transportation 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.

Major Influences on Results of Operations

Summary of Third Quarter 2016

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

•	We averaged total throughput of 142,432 bpd at the El Paso refinery for the three months ended September 30, 2016 , a 2.5% increase from the three months ended September 30, 2015 .

•	We averaged throughput of 28,245 bpd at the Gallup refinery for the three months ended September 30, 2016 , a 10.1% increase from the three months ended September 30, 2015 .

•	We averaged throughput of 84,546 bpd at the St. Paul Park refinery for the three months ended September 30, 2016 , a 6.7% decrease from the three months ended September 30, 2015 . The decrease in average throughput over the prior year relates primarily to the turnaround of our No. 2 crude unit that commenced in September 2016.

•	WNRL issued 8,625,000 common units to the public in exchange for net proceeds of $185.3 million .

•	Dividends and distributions declared and paid:

◦	$0.38 per Western common share; and

◦	$0.4125 per WNRL common unit.

2016 Year-to-Date Operating and Financial Highlights

Net income attributable to Western was $134.5 million , or $1.37 per diluted share for the nine months ended September 30, 2016 , compared to $393.2 million , or $4.12 per diluted share for the nine months ended September 30, 2015 .

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Our operating income decreased $574.9 million from September 30, 2015 , to September 30, 2016 , as shown by segment in the following table:

	Nine Months Ended
	September 30,
	2016				2015				Change
	(In thousands)
Refining	$	338,803			$	900,405			$	(561,602	)
WNRL	43,056				41,454				1,602
Retail	21,193				36,356				(15,163		)
Other	(74,010		)		(74,231		)		221
Total operating income	$	329,042			$	903,984			$	(574,942	)

The WNRL financial and operational data presented includes the historical results of all assets acquired from Western in the St. Paul Park Logistics Transaction and the TexNew Mex Pipeline Transaction . These transactions were transfers of assets between entities under common control. The financial information for the affected reporting segments has been retrospectively adjusted to include or exclude the historical results of the transferred assets for periods prior to the effective date of the transactions. See Note 3, Segment Information , in the Notes to Condensed Consolidated Financial Statements for further discussion of these retrospective adjustments.

Overview of Segments

Petroleum based commodity values have significant influence, either directly or indirectly, on the results of operations and cash flows for each of our operating segments. The following key factors affect petroleum based commodity values:

•	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;

•	government regulation; and

•	availability and cost of Renewable Identification Numbers ("RINs") to meet our Renewable Fuel Standards ("RFS") obligations.

Refining . Our overall refining results of operations are significantly impacted by the difference between refinery revenues and the related cost of products sold. We define this difference as refinery gross margin, which 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. The following items have a significant impact on our overall refinery revenues, cost of products sold and other 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;

•	the impact of our economic hedging activity;

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

•	availability and cost of RINs to meet our RFS obligations;

•	fluctuations in our direct operating expenses;

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

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•	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.

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 process at our refineries, 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. Consolidated cost of products sold for the nine months ended September 30, 2016 , includes $8.6 million of realized and unrealized net losses from our economic hedging activities. The non-cash unrealized net losses included in the consolidated total were $54.7 million for the nine months ended September 30, 2016 .

Demand for gasoline is generally higher during the summer months than during the winter months. As a result, our operating results for the first and fourth calendar quarters are generally lower than those for the second and third calendar quarters of each year. During 2015 and 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.

Under an exclusive supply agreement with a third party, we receive monthly distribution amounts from the supplier equal to one-half of the amount by which our refined product sales in the Mid-Atlantic exceeds the supplier's costs of acquiring, transporting and hedging the refined product related to such sales. To the extent our refined product sales do not exceed the refined product costs during any month, we pay one-half of that amount to the supplier. Our payments to the supplier are limited to an aggregate annual amount of $2.0 million . This supply agreement is due to expire at the end of 2016.

WNRL. WNRL's terminal throughput volumes depend primarily on the volume of refined and other products produced at Western’s refineries that, in turn, is ultimately dependent on supply and demand for refined product, crude oil and other feedstocks and Western’s response to changes in demand and supply.

Earnings and cash flows from WNRL's wholesale business are primarily affected by the sales volumes and margins of gasoline, diesel fuel and lubricants sold and transportation revenues from crude oil and asphalt 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 due to lower demand for retail fuel. 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.

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Critical Accounting Policies and Estimates

We prepare our financial statements in conformity with U.S. generally accepted accounting principles ("GAAP"). In order to apply these principles, we must make judgments, assumptions and estimates based on the best available information at the time. Actual results may differ based on the continuing development of the information utilized and subsequent events, some of which we may have little or no control over. Our critical accounting policies could materially affect the amounts recorded in our financial statements. Our critical accounting policies, estimates and recent accounting pronouncements that potentially impact us are discussed in detail under Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations in our 2015 Form 10-K.

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 of the impact of recent accounting pronouncements, see Note 2, Basis of Presentation and Significant Accounting Policies , in the Notes to Condensed Consolidated Financial Statements.

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Results of Operations

The following tables summarize our consolidated and operating segment financial data and key operating statistics for the three and nine months ended September 30, 2016 and 2015 . The following data should be read in conjunction with our Condensed Consolidated Financial Statements and the notes thereto included elsewhere in this quarterly report.

Consolidated

Three Months Ended September 30, 2016 , Compared to the Three Months Ended September 30, 2015

	Three Months Ended
	September 30,
	2016				2015				Change
	(In thousands, except per share data)
Statements of Operations Data
Net sales (1)	$	2,065,076			$	2,569,090			$	(504,014	)
Operating costs and expenses:
Cost of products sold (exclusive of depreciation and amortization) (1)	1,607,010				1,895,772				(288,762		)
Direct operating expenses (exclusive of depreciation and amortization)	232,553				234,440				(1,887		)
Selling, general and administrative expenses	57,320				54,465				2,855
Gain on disposal of assets, net	(279		)		(52		)		(227		)
Maintenance turnaround expense	27,208				490				26,718
Depreciation and amortization	54,321				51,377				2,944
Total operating costs and expenses	1,978,133				2,236,492				(258,359		)
Operating income	86,943				332,598				(245,655		)
Other income (expense):
Interest income	141				186				(45		)
Interest and debt expense	(34,456		)		(26,896		)		(7,560		)
Other, net	3,380				4,327				(947		)
Income before income taxes	56,008				310,215				(254,207		)
Provision for income taxes	(11,700		)		(92,117		)		80,417
Net income	44,308				218,098				(173,790		)
Less net income attributable to non-controlling interests (2)	5,733				64,795				(59,062		)
Net income attributable to Western Refining, Inc.	$	38,575			$	153,303			$	(114,728	)
Basic earnings per share	$	0.36			$	1.61			$	(1.25	)
Diluted earnings per share	$	0.35			$	1.61			$	(1.26	)
Dividends declared per common share	$	0.38			$	0.34			$	0.04
Weighted average basic shares outstanding	108,424				94,826				13,598
Weighted average dilutive shares outstanding	108,734				94,924				13,810

(1)	Excludes $937.1 million and $1,063.4 million of intercompany sales and $937.1 million and $1,063.4 million of intercompany cost of products sold for the three months ended September 30, 2016 and September 30, 2015 , respectively.

(2)	Net income attributable to non-controlling interests for the three months ended September 30, 2016 , consisted of income from WNRL in the amount of $5.7 million . Net income attributable to non-controlling interests for the three months ended September 30, 2015 , consisted of income from NTI and WNRL in the amount of $59.2 million and $5.6 million , respectively.

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	Three Months Ended
	September 30,
	2016				2015				Change
	(In thousands)
Economic Hedging Activities Recognized within Cost of Products Sold
Realized hedging gain, net	$	27,757			$	26,949			$	808
Unrealized hedging gain (loss), net	(27,616		)		271				(27,887		)
Total hedging gain, net	$	141			$	27,220			$	(27,079	)
Cash Flow Data
Net cash provided by (used in):
Operating activities	$	161,019			$	373,620			$	(212,601	)
Investing activities	(269,218		)		(20,321		)		(248,897		)
Financing activities	176,011				(187,665		)		363,676
Capital expenditures	$	78,337			$	76,431			$	1,906

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):

	Three Months Ended
	September 30,
	2016				2015				Change
	(In thousands)
Net sales	$	2,065,076			$	2,569,090			$	(504,014	)
Cost of products sold (exclusive of depreciation and amortization)	1,607,010				1,895,772				(288,762		)
Gross margin	$	458,066			$	673,318			$	(215,252	)

Compared to the three months ended September 30, 2015 , our current quarter consolidated gross margin decreased by 32.0% . This decrease was primarily due to lower refining margins and economic hedging gains . We discuss refining margins and economic hedging activities under our refining segment.

Direct Operating Expenses (exclusive of depreciation and amortization). The decrease in direct operating expenses was primarily due to decreases of $2.6 million and $2.5 million in our refining and WNRL segments, respectively, partially offset by an increase of $3.3 million in our retail segment.

Selling, General and Administrative Expenses. The increase in selling, general and administrative expenses resulted from an increase of $4.7 million in our corporate overhead, partially offset by a decrease of $1.4 million and $1.0 million in our refining and retail segments, respectively. The increase in corporate overhead was primarily due to higher professional and legal expenses and information technology expenses in the current period.

Maintenance Turnaround Expense . We incurred turnaround expenses associated with the fall 2016 turnaround of the No. 2 crude unit at our St. Paul Park refinery during the third quarter of 2016 .

Depreciation and Amortization. The increase between periods was primarily due to additional depreciation associated with logistics assets capitalized through the ongoing expansion of our Delaware Basin logistics system.

Interest and Debt Expense . The increase in interest expense from prior periods was attributable to the interest incurred in 2016 on borrowings under the Western 2023 Term Loan Credit Facility that we issued during the second quarter of 2016 and borrowings under the NTI and WNRL revolving credit facilities that were outstanding during the three months ended September 30, 2016 , without a corresponding balance in the prior year period.

Provision for Income Taxes . The decrease in the provision for income taxes from prior periods was primarily due to the release of reserves related to uncertain tax positions in the current quarter.

 

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Nine Months Ended September 30, 2016 , Compared to the Nine Months Ended September 30, 2015

	Nine Months Ended
	September 30,
	2016				2015				Change
	(In thousands, except per share data)
Statements of Operations Data
Net sales (1)	$	5,627,888			$	7,716,712			$	(2,088,824	)
Operating costs and expenses:
Cost of products sold (exclusive of depreciation and amortization) (1)	4,256,999				5,814,969				(1,557,970		)
Direct operating expenses (exclusive of depreciation and amortization)	687,307				674,474				12,833
Selling, general and administrative expenses	166,657				169,808				(3,151		)
Gain on disposal of assets, net	(1,181		)		(157		)		(1,024		)
Maintenance turnaround expense	27,733				1,188				26,545
Depreciation and amortization	161,331				152,446				8,885
Total operating costs and expenses	5,298,846				6,812,728				(1,513,882		)
Operating income	329,042				903,984				(574,942		)
Other income (expense):
Interest income	436				550				(114		)
Interest and debt expense	(88,065		)		(79,169		)		(8,896		)
Other, net	13,825				11,557				2,268
Income before income taxes	255,238				836,922				(581,684		)
Provision for income taxes	(68,481		)		(229,989		)		161,508
Net income	186,757				606,933				(420,176		)
Less net income attributable to non-controlling interests (2)	52,229				213,722				(161,493		)
Net income attributable to Western Refining, Inc.	$	134,528			$	393,211			$	(258,683	)
Basic earnings per share	$	1.37			$	4.12			$	(2.75	)
Diluted earnings per share	$	1.37			$	4.12			$	(2.75	)
Dividends declared per common share	$	1.14			$	0.98			$	0.16
Weighted average basic shares outstanding	97,802				95,308				2,494
Weighted average dilutive shares outstanding	98,110				95,408				2,702

(1)	Excludes $2,610.3 million and $3,019.2 million of intercompany sales and $2,610.3 million and $3,019.2 million of intercompany cost of products sold for the nine months ended September 30, 2016 and September 30, 2015 , respectively.

(2)

Net income attributable to non-controlling interests for the nine months ended September 30, 2016 , consisted of income from NTI and WNRL in the amount of $35.3 million and $16.9 million , respectively. Net income attributable to non-controlling interests for the nine months ended September 30, 2015 , consisted of income from NTI and WNRL in the amount of $197.6 million and $16.2 million , respectively.

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	Nine Months Ended
	September 30,
	2016				2015				Change
	(In thousands)
Economic Hedging Activities Recognized within Cost of Products Sold
Realized hedging gain, net	$	46,110			$	52,325			$	(6,215	)
Unrealized hedging loss, net	(54,698		)		(42,073		)		(12,625		)
Total hedging gain (loss), net	$	(8,588	)		$	10,252			$	(18,840	)
Cash Flow Data
Net cash provided by (used in):
Operating activities	$	277,877			$	665,664			$	(387,787	)
Investing activities	(357,079		)		(34,454		)		(322,625		)
Financing activities	(427,204		)		(352,799		)		(74,405		)
Capital expenditures	$	235,097			$	195,976			$	39,121

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):

	Nine Months Ended
	September 30,
	2016				2015				Change
	(In thousands)
Net sales	$	5,627,888			$	7,716,712			$	(2,088,824	)
Cost of products sold (exclusive of depreciation and amortization)	4,256,999				5,814,969				(1,557,970		)
Gross margin	$	1,370,889			$	1,901,743			$	(530,854	)

Compared to the nine months ended September 30, 2015 , our consolidated gross margin decreased by 27.9% for the current period. This decrease was primarily due to economic hedging activities and lower refining margins. We discuss refining margins and economic hedging activities under our refining segment.

Direct Operating Expenses (exclusive of depreciation and amortization). The increase in direct operating expenses was primarily due to increases of $11.4 million and $1.7 million in our retail and refining segments, respectively.

Selling, General and Administrative Expenses. The decrease in selling, general and administrative expenses resulted from decreases of $3.9 million and $0.7 million in refining and WNRL segments, respectively, partially offset by increases of $1.1 million and $0.4 million in our corporate overhead and retail segments, respectively. The increase in corporate overhead was due to higher employee expenses in the current period.

Maintenance Turnaround Expense . We incurred turnaround expenses associated with the fall 2016 turnaround of the No. 2 crude unit at our St. Paul Park refinery during the first nine months of 2016 .

Depreciation and Amortization. The increase between periods was primarily due to additional depreciation associated with our logistics assets related to the TexNew Mex Pipeline System and the ongoing expansion of our Delaware Basin logistics system.

Interest and Debt Expense . The increase in interest expense from prior periods 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, the full nine month period of interest incurred in 2016 on the $300.0 million WNRL 2023 Senior Notes that WNRL issued during the first quarter of 2015 and borrowings under the NTI and WNRL revolving credit facilities that were outstanding during the nine months ended September 30, 2016 , without a corresponding balance in the prior year period.

Provision for Income Taxes . The decrease in the provision for income taxes from prior periods was primarily due to the release of reserves related to uncertain tax positions in the current period.

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Results by Segment

The following tables set forth our historical financial data by segment for the periods presented. We have organized our operations into three segments, refining, WNRL and retail, based on manufacturing and marketing processes, the nature of our products and services and each segment's respective customer base. Prior to the Merger on June 23, 2016, we also reported NTI as a separate reportable segment. Following the completion of the Merger, NTI became a wholly-owned subsidiary of Western and, as a result, we have moved its assets and operations into our other reportable segments. 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. The St. Paul Park refinery and related operations are now included in the refining segment and the SuperAmerica retail and bakery assets and operations are now included in the retail segment. We have retrospectively adjusted the historical segment financial data for the periods presented to reflect our revised segment presentation. See Note 3, Segment Information , in the Notes to Condensed Consolidated Financial Statements for more information.

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.

	Three Months Ended
	September 30,
	2016				2015				Change
	(In thousands)
Gross Margin by Segment
Refining	$	283,834			$	482,744			$	(198,910	)
WNRL	73,725				79,113				(5,388		)
Retail	100,507				111,691				(11,184		)
Other	—				(230		)		230
Consolidated gross margin	$	458,066			$	673,318			$	(215,252	)
Direct Operating Expenses by Segment
Refining	$	115,791			$	118,401			$	(2,610	)
WNRL	43,454				45,927				(2,473		)
Retail	73,388				70,112				3,276
Other	(80		)		—				(80		)
Consolidated direct operating expenses	$	232,553			$	234,440			$	(1,887	)
Depreciation and Amortization by Segment
Refining	$	37,265			$	35,400			$	1,865
WNRL	10,579				8,963				1,616
Retail	5,710				5,846				(136		)
Other	767				1,168				(401		)
Consolidated depreciation and amortization	$	54,321			$	51,377			$	2,944

See additional analysis under discussions of our refining, WNRL and retail segments.

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	Nine Months Ended
	September 30,
	2016				2015				Change
	(In thousands)
Gross Margin by Segment
Refining	$	869,137			$	1,401,105			$	(531,968	)
WNRL	220,520				216,686				3,834
Retail	281,232				284,182				(2,950		)
Other	—				(230		)		230
Consolidated gross margin	$	1,370,889			$	1,901,743			$	(530,854	)
Direct Operating Expenses by Segment
Refining	$	345,352			$	343,681			$	1,671
WNRL	131,103				131,156				(53		)
Retail	210,932				199,554				11,378
Other	(80		)		83				(163		)
Consolidated direct operating expenses	$	687,307			$	674,474			$	12,833
Depreciation and Amortization by Segment
Refining	$	111,601			$	105,916			$	5,685
WNRL	29,470				25,816				3,654
Retail	17,622				17,257				365
Other	2,638				3,457				(819		)
Consolidated depreciation and amortization	$	161,331			$	152,446			$	8,885

See additional analysis under discussions of our refining, WNRL and retail segments.

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Adjusted EBITDA

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.

Three Months Ended September 30, 2016 , Compared to the Three Months Ended September 30, 2015

	Three Months Ended
	September 30,
	2016				2015				Change
	(In thousands)
Net income attributable to Western Refining, Inc.	$	38,575			$	153,303			$	(114,728	)
Net income attributable to non-controlling interests	5,733				64,795				(59,062		)
Interest and debt expense	34,456				26,896				7,560
Provision for income taxes	11,700				92,117				(80,417		)
Gain on disposal of assets, net	(279		)		(52		)		(227		)
Depreciation and amortization	54,321				51,377				2,944
Maintenance turnaround expense	27,208				490				26,718
Net change in lower of cost or market inventory reserve	(15,166		)		36,795				(51,961		)
Unrealized loss (gain) on commodity hedging transactions	27,616				(271		)		27,887
Adjusted EBITDA	$	184,164			$	425,450			$	(241,286	)

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Nine Months Ended September 30, 2016 , Compared to the Nine Months Ended September 30, 2015

	Nine Months Ended
	September 30,
	2016				2015				Change
	(In thousands)
Net income attributable to Western Refining, Inc.	$	134,528			$	393,211			$	(258,683	)
Net income attributable to non-controlling interests	52,229				213,722				(161,493		)
Interest and debt expense	88,065				79,169				8,896
Provision for income taxes	68,481				229,989				(161,508		)
Gain on disposal of assets, net	(1,181		)		(157		)		(1,024		)
Depreciation and amortization	161,331				152,446				8,885
Maintenance turnaround expense	27,733				1,188				26,545
Net change in lower of cost or market inventory reserve	(102,519		)		(17,131		)		(85,388		)
Unrealized loss on commodity hedging transactions	54,698				42,073				12,625
Adjusted EBITDA	$	483,365			$	1,094,510			$	(611,145	)

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Refining Segment

Three Months Ended September 30, 2016 , Compared to the Three Months Ended September 30, 2015

	Three Months Ended
	September 30,
	2016				2015				Change
	(In thousands, except bpd and per barrel data)
Statement of Operations Data:
Net sales (including intersegment sales) (1)	$	1,835,327			$	2,318,048			$	(482,721	)
Operating costs and expenses:
Cost of products sold (exclusive of depreciation and amortization) (2)	1,551,493				1,835,304				(283,811		)
Direct operating expenses (exclusive of depreciation and amortization)	115,791				118,401				(2,610		)
Selling, general and administrative expenses	14,420				15,851				(1,431		)
Gain on disposal of assets, net	(8		)		—				(8		)
Maintenance turnaround expense	27,208				490				26,718
Depreciation and amortization	37,265				35,400				1,865
Total operating costs and expenses	1,746,169				2,005,446				(259,277		)
Operating income	$	89,158			$	312,602			$	(223,444	)
Key Operating Statistics
Total sales volume (bpd) (1) (3)	314,239				347,456				(33,217		)
Total refinery production (bpd)	253,365				252,420				945
Total refinery throughput (bpd) (4)	255,222				255,170				52
Per barrel of throughput:
Refinery gross margin (2) (5) (6)	$	12.02			$	20.65			$	(8.63	)
Direct operating expenses (7)	4.93				5.04				(0.11		)
Mid-Atlantic sales volume (barrels)	1,987				2,144				(157		)
Mid-Atlantic margin per barrel	$	0.77			$	(1.10	)		$	1.87

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The following tables set forth our refining throughput and production data for the periods and refineries presented:

El Paso Refinery

	Three Months Ended
	September 30,
	2016				2015				Change
Key Operating Statistics
Refinery product yields (bpd):
Gasoline	76,161				71,855				4,306
Diesel and jet fuel	56,574				55,667				907
Residuum	2,930				4,121				(1,191		)
Other	5,356				5,016				340
Total refinery production (bpd)	141,021				136,659				4,362
Refinery throughput (bpd):
Sweet crude oil	105,990				107,577				(1,587		)
Sour crude oil	27,566				23,854				3,712
Other feedstocks and blendstocks	8,876				7,485				1,391
Total refinery throughput (bpd) (4)	142,432				138,916				3,516
Total sales volume (bpd) (3)	154,648				149,861				4,787
Per barrel of throughput:
Refinery gross margin (2) (5) (6)	$	11.80			$	18.51			$	(6.71	)
Direct operating expenses (7)	3.71				3.64				0.07

Gallup Refinery

	Three Months Ended
	September 30,
	2016				2015				Change
Key Operating Statistics
Refinery product yields (bpd):
Gasoline	17,719				15,961				1,758
Diesel and jet fuel	8,831				7,878				953
Other	1,058				1,560				(502		)
Total refinery production (bpd)	27,608				25,399				2,209
Refinery throughput (bpd):
Sweet crude oil	24,985				23,888				1,097
Other feedstocks and blendstocks	3,260				1,776				1,484
Total refinery throughput (bpd) (4)	28,245				25,664				2,581
Total sales volume (bpd) (3)	37,022				33,489				3,533
Per barrel of throughput:
Refinery gross margin (2) (5) (6)	$	14.01			$	23.08			$	(9.07	)
Direct operating expenses (7)	8.10				9.10				(1.00		)

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St. Paul Park Refinery

	Three Months Ended
	September 30,
	2016				2015				Change
Key Operating Statistics
Refinery product yields (bpd):
Gasoline	42,896				43,914				(1,018		)
Distillate	25,667				30,404				(4,737		)
Residuum	9,212				10,091				(879		)
Other	6,960				5,953				1,007
Total refinery production (bpd)	84,735				90,362				(5,627		)
Refinery throughput (bpd):
Light crude oil	43,888				51,701				(7,813		)
Synthetic crude oil	18,769				14,735				4,034
Heavy crude oil	19,380				23,150				(3,770		)
Other feedstocks	2,509				1,004				1,505
Total refinery throughput (bpd) (4)	84,546				90,590				(6,044		)
Total sales volume (bpd) (3)	90,906				99,617				(8,711		)
Per barrel of throughput:
Refinery gross margin (2) (5) (6)	$	11.20			$	24.57			$	(13.37	)
Direct operating expenses (7)	5.94				5.68				0.26

(1)	Refining net sales for the three months ended September 30, 2016 and 2015 , includes $148.3 million and $409.1 million , respectively, in crude oil sales to third parties, representing a period average of 37,027 bpd and 73,630 bpd, respectively.

(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 our individual refineries.

	Three Months Ended
	September 30,
	2016				2015				Change
	(In thousands)
Realized hedging gain, net	$	27,757			$	26,949			$	808
Unrealized hedging gain (loss), net	(27,616		)		271				(27,887		)
Total hedging gain, net	$	141			$	27,220			$	(27,079	)

(3)

Sales volume includes sales of refined products sourced primarily from our refinery production as well as refined products purchased from third parties. We purchase additional refined products from third parties to supplement supply to our customers. These products are similar to the products that we currently manufacture and represented 6.0% and 6.2% of our total consolidated sales volumes for the three months ended September 30, 2016 and 2015 , respectively. The majority of the purchased refined products are distributed through our refined product sales activities in the Mid-Atlantic region where we satisfy our refined product customer sales requirements through a third-party supply agreement.

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

(5)

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

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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:

	Three Months Ended
	September 30,
	2016				2015				Change
	(In thousands)
Refinery net sales (including intersegment sales)	$	1,714,913			$	2,163,163			$	(448,250	)
Mid-Atlantic sales	120,414				154,885				(34,471		)
Net sales (including intersegment sales)	$	1,835,327			$	2,318,048			$	(482,721	)
Refinery cost of products sold (exclusive of depreciation and amortization)	$	1,432,610			$	1,678,390			$	(245,780	)
Mid-Atlantic cost of products sold	118,883				156,914				(38,031		)
Cost of products sold (exclusive of depreciation and amortization)	$	1,551,493			$	1,835,304			$	(283,811	)

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

	Three Months Ended
	September 30,
	2016				2015				Change
	(In thousands, except per barrel data)
Refinery net sales (including intersegment sales)	$	1,714,913			$	2,163,163			$	(448,250	)
Refinery cost of products sold (exclusive of depreciation and amortization)	1,432,610				1,678,390				(245,780		)
Depreciation and amortization	37,265				35,400				1,865
Gross profit	245,038				449,373				(204,335		)
Plus depreciation and amortization	37,265				35,400				1,865
Refinery gross margin	$	282,303			$	484,773			$	(202,470	)
Refinery gross margin per throughput barrel	$	12.02			$	20.65			$	(8.63	)
Gross profit per throughput barrel	$	10.44			$	19.14			$	(8.70	)

(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 changes in this reserve are included in the combined refinery gross margin but are not included in those measures for the individual refineries. The following table calculates the combined refinery gross margin per 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:

	Three Months Ended
	September 30,
	2016				2015				Change
	(In thousands, except per barrel data)
Refinery gross margin	$	282,303			$	484,773			$	(202,470	)
Net change in lower of cost or market inventory reserve	(15,167		)		36,022				(51,189		)
Refinery gross margin, excluding LCM adjustment	$	267,136			$	520,795			$	(253,659	)
Refinery gross margin, excluding LCM adjustment, per refinery throughput barrel	$	11.38			$	22.18			$	(10.80	)

(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.

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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):

	Three Months Ended
	September 30,
	2016				2015				Change
	(In thousands)
Net sales	$	1,835,327			$	2,318,048			$	(482,721	)
Cost of products sold (exclusive of depreciation and amortization)	1,551,493				1,835,304				(283,811		)
Gross margin	$	283,834			$	482,744			$	(198,910	)

Refining 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 hedging activities, refinery gross margin per throughput barrel decreased in a manner generally consistent with the decrease in industry benchmarks. The Gulf Coast benchmark 3:2:1 crack spread (the "GC 3:2:1") declined to $13.29 in the third quarter of 2016 from $21.43 in the third quarter of 2015 . 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 the third quarter of 2016 , this differential decreased to an average of $0.97 per barrel from an average of $4.03 per barrel for the third quarter of 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. The differential averaged a WTI Midland discount of $0.31 per barrel during the third quarter of 2016 compared to $0.71 per barrel during the third quarter 2015 . The Group 3 6:3:2:1 benchmark crack spread decreased from an average of $15.77 per barrel for the three months ended September 30, 2015 , to an average of $9.85 per barrel for the three months ended September 30, 2016 .

Refinery gross margin was also affected by third quarter 2016 net realized and unrealized economic hedging gains of $0.1 million compared to gains of $27.2 million during the third quarter of 2015 . We enter into hedge contracts to manage our exposure to commodity price risks or to fix sales margins on a portion of our 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 refinery gross margin.

Other impacts to margin include the net cost of RINs, which was $15.8 million for the three months ended September 30, 2016 , compared to $14.4 million for the three months ended September 30, 2015 . The increase in the net cost was primarily the result of an industry increase in the unit cost of RINs. Total refinery throughput increased by 0.005 million barrels quarter over quarter. Our refined product sales volume decreased to 28.9 million barrels during the third quarter of 2016 from 32.0 million barrels during the third quarter of 2015 . The impact to cost of products sold of non-cash lower of cost or market ("LCM") inventory recoveries for the three months ended September 30, 2016 was $15.2 million compared to a charge of $36.0 million for the same period in 2015 .

Direct Operating Expenses (exclusive of depreciation and amortization). Direct operating expenses decreased quarter over quarter primarily due to decrease maintenance expenses in our St. Paul Park Refinery ( $8.1 million ), lower outside support services expenses ( $1.8 million ), lower chemical and energy expenses ( $1.1 million ) and lower employee expenses ( $1.1 million ), partially offset by an increase in environmental expenses ( $5.4 million ) and transportation expenses in our St. Paul Park Refinery ( $4.1 million ).

Selling, General and Administrative Expenses . The decrease in selling, general and administrative expenses was primarily due to a decrease in insurance expense ( $0.7 million ), information technology expenses ( $0.4 million ), employee expenses ( $0.1 million ) and travel expenses ( $0.1 million ).

Maintenance Turnaround Expense . We incurred turnaround expenses associated with the fall 2016 turnaround of the No. 2 crude unit at our St. Paul Park refinery during the third quarter of 2016 .

Depreciation and Amortization. Depreciation and amortization increased due to additional depreciation associated with recently capitalized assets.

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Nine Months Ended September 30, 2016 , Compared to the Nine Months Ended September 30, 2015

	Nine Months Ended
	September 30,
	2016				2015				Change
	(In thousands, except bpd and per barrel data)
Statement of Operations Data:
Net sales (including intersegment sales) (1)	$	5,012,283			$	6,958,443			$	(1,946,160	)
Operating costs and expenses:
Cost of products sold (exclusive of depreciation and amortization) (2)	4,143,146				5,557,338				(1,414,192		)
Direct operating expenses (exclusive of depreciation and amortization)	345,352				343,681				1,671
Selling, general and administrative expenses	45,631				49,559				(3,928		)
Loss on disposal of assets, net	17				356				(339		)
Maintenance turnaround expense	27,733				1,188				26,545
Depreciation and amortization	111,601				105,916				5,685
Total operating costs and expenses	4,673,480				6,058,038				(1,384,558		)
Operating income	$	338,803			$	900,405			$	(561,602	)
Key Operating Statistics
Total sales volume (bpd) (1) (3)	312,131				339,005				(26,874		)
Total refinery production (bpd)	258,166				256,828				1,338
Total refinery throughput (bpd) (4)	260,024				259,154				870
Per barrel of refinery throughput:
Refinery gross margin (2) (5) (6)	$	12.13			$	19.79			$	(7.66	)
Direct operating expenses (7)	4.85				4.86				(0.01		)
Mid-Atlantic sales volume (barrels)	5,689				6,597				(908		)
Mid-Atlantic margin per barrel	$	0.88			$	0.15			$	0.73

The following tables set forth our refining throughput and production data for the periods and refineries presented:

El Paso Refinery

	Nine Months Ended
	September 30,
	2016				2015				Change
Key Operating Statistics
Refinery product yields (bpd):
Gasoline	74,054				70,613				3,441
Diesel and jet fuel	55,871				55,804				67
Residuum	2,876				4,730				(1,854		)
Other	5,080				4,503				577
Total refinery production (bpd)	137,881				135,650				2,231
Refinery throughput (bpd):
Sweet crude oil	104,513				106,850				(2,337		)
Sour crude oil	26,261				23,055				3,206
Other feedstocks and blendstocks	8,614				7,604				1,010
Total refinery throughput (bpd) (4)	139,388				137,509				1,879
Total sales volume (bpd) (3)	148,753				150,404				(1,651		)
Per barrel of refinery throughput:
Refinery gross margin (2) (5) (6)	$	11.05			$	18.65			$	(7.60	)
Direct operating expenses (7)	3.81				3.96				(0.15		)

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Gallup Refinery

	Nine Months Ended
	September 30,
	2016				2015				Change
Key Operating Statistics
Refinery product yields (bpd):
Gasoline	16,607				17,065				(458		)
Diesel and jet fuel	7,548				8,137				(589		)
Other	1,243				1,525				(282		)
Total refinery production (bpd)	25,398				26,727				(1,329		)
Refinery throughput (bpd):
Sweet crude oil	23,149				24,776				(1,627		)
Other feedstocks and blendstocks	2,755				2,331				424
Total refinery throughput (bpd) (4)	25,904				27,107				(1,203		)
Total sales volume (bpd) (3)	35,033				33,339				1,694
Per barrel of refinery throughput:
Refinery gross margin (2) (5) (6)	$	12.48			$	19.85			$	(7.37	)
Direct operating expenses (7)	8.72				8.30				0.42

St. Paul Park Refinery

	Nine Months Ended
	September 30,
	2016				2015				Change
Key Operating Statistics
Refinery product yields (bpd):
Gasoline	47,158				45,155				2,003
Distillate	30,417				32,791				(2,374		)
Residuum	11,036				10,742				294
Other	6,276				5,763				513
Total refinery production (bpd)	94,887				94,451				436
Refinery throughput (bpd):
Light crude oil	53,692				55,779				(2,087		)
Synthetic crude oil	13,850				12,303				1,547
Heavy crude oil	24,325				24,629				(304		)
Other feedstocks	2,863				1,827				1,036
Total refinery throughput (bpd) (4)	94,730				94,538				192
Total sales volume (bpd) (3)	101,064				100,630				434
Per barrel of throughput:
Refinery gross margin (2) (5) (6)	$	10.27			$	20.57			$	(10.30	)
Direct operating expenses (7)	5.08				5.04				0.04

(1)	Refining net sales for the nine months ended September 30, 2016 and 2015 , includes $341.3 million and $848.2 million , respectively, representing a period average of 29,875 bpd and 62,248 bpd, respectively, in crude oil sales to third parties.

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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 our individual refineries.

	Nine Months Ended
	September 30,
	2016				2015				Change
	(In thousands)
Realized hedging gain, net	$	46,110			$	52,325			$	(6,215	)
Unrealized hedging loss, net	(54,698		)		(42,073		)		(12,625		)
Total hedging gain (loss), net	$	(8,588	)		$	10,252			$	(18,840	)

(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 5.8% and 6.8% of our total consolidated sales volumes for the nine months ended September 30, 2016 and 2015 , respectively. The majority of the purchased refined products are distributed through our refined product sales activities in the Mid-Atlantic region where we satisfy our refined product customer sales requirements through a third-party supply agreement.

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

(5)

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

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:

	Nine Months Ended
	September 30,
	2016				2015				Change
	(In thousands)
Refinery net sales (including intersegment sales)	$	4,680,900			$	6,461,580			$	(1,780,680	)
Mid-Atlantic sales	331,383				496,863				(165,480		)
Net sales (including intersegment sales)	$	5,012,283			$	6,958,443			$	(1,946,160	)
Refinery cost of products sold (exclusive of depreciation and amortization)	$	3,816,760			$	5,061,474			$	(1,244,714	)
Mid-Atlantic cost of products sold	326,386				495,864				(169,478		)
Cost of products sold (exclusive of depreciation and amortization)	$	4,143,146			$	5,557,338			$	(1,414,192	)

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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:

	Nine Months Ended
	September 30,
	2016				2015				Change
	(In thousands, except per barrel data)
Net sales (including intersegment sales)	$	4,680,900			$	6,461,580			$	(1,780,680	)
Cost of products sold (exclusive of depreciation and amortization)	3,816,760				5,061,474				(1,244,714		)
Depreciation and amortization	111,601				105,916				5,685
Gross profit	752,539				1,294,190				(541,651		)
Plus depreciation and amortization	111,601				105,916				5,685
Refinery gross margin	$	864,140			$	1,400,106			$	(535,966	)
Refinery gross margin per throughput barrel	$	12.13			$	19.79			$	(7.66	)
Gross profit per throughput barrel	$	10.56			$	18.29			$	(7.73	)

(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 changes in this reserve are included in the combined refinery gross margin but are not included in those measures for the individual refineries. The following table calculates the combined refinery gross margin per 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:

	Nine Months Ended
	September 30,
	2016				2015				Change
	(In thousands, except per barrel data)
Refinery gross margin	$	864,140			$	1,400,106			$	(535,966	)
Net change in lower of cost or market inventory reserve	(101,708		)		(16,598		)		(85,110		)
Refinery gross margin, excluding LCM adjustment	$	762,432			$	1,383,508			$	(621,076	)
Refinery gross margin, excluding LCM adjustment, per refinery throughput barrel	$	10.70			$	19.56			$	(8.86	)

(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):

	Nine Months Ended
	September 30,
	2016				2015				Change
	(In thousands)
Net sales	$	5,012,283			$	6,958,443			$	(1,946,160	)
Cost of products sold (exclusive of depreciation and amortization)	4,143,146				5,557,338				(1,414,192		)
Gross margin	$	869,137			$	1,401,105			$	(531,968	)

Refining 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 hedging activities, refinery gross margin per throughput barrel decreased in a manner generally consistent with the decrease in industry benchmarks. The GC 3:2:1 declined to $12.45 in the first nine months of 2016 from $20.72 in the first nine months of 2015 . 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

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the first nine months of 2016 , this differential decreased to an average of $0.44 per barrel from an average of $4.37 per barrel for the first nine months of 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 the nine months ended September 30, 2016 , the WTI Midland/Cushing differential averaged a discount of $0.12 per barrel, compared to an average discount of $0.57 for the first nine months of 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 benchmark crack spread decreased from an average of $14.35 per barrel for the first nine months of September 30, 2015 , to an average of $8.22 per barrel for the first nine months of September 30, 2016 .

Refinery gross margin was also affected by net realized and unrealized economic hedging losses of $8.6 million for the first nine months of 2016 , compared to net realized and unrealized economic hedging gains of $10.3 million for the first nine months of 2015 . We enter into hedge contracts to manage our exposure to commodity price risks or to fix sales margins on a portion of our 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.

Other impacts to margin include the net cost of RINs, which was $51.9 million for the first nine months of 2016 , compared to $32.8 million for the first nine months of 2015 . This $19.1 million increase in RINs cost primarily results from an industry increase in the unit cost of RINs. Total refinery throughput increased by 0.5 million barrels. Our refined product sales volume decreased to 85.5 million barrels during the first nine months of 2016 from 92.5 million barrels during the first nine months of 2015 . Offsetting these negative impacts on our overall refining margin was the impact to cost of products sold of non-cash LCM inventory recoveries of $101.7 million for the nine months ended September 30, 2016 , compared to a recovery of $16.6 million for the same period in 2015 .

Direct Operating Expenses (exclusive of depreciation and amortization). Direct operating expenses increased primarily as a result of increases in transportation expenses in our St. Paul Park refinery ( $9.5 million ), environmental expenses ( $4.1 million ), railcar lease expense of $2.7 million due to new short-term leases in 2016 and property taxes ( $2.3 million ). Offsetting these increases were decreases in energy, chemical and catalyst expense ( $6.3 million ) due to lower natural gas prices, operating materials and supplies ( $4.3 million ), outside support services ( $2.2 million ), maintenance expenses in our St. Paul Park refinery ( $1.8 million ), insurance expense ( $1.2 million ) and expense allocations to WNRL ( $1.2 million ).

Selling, General and Administrative Expenses . The decrease in selling, general and administrative expenses was primarily due to $1.8 million paid in 2015 to terminate a supply agreement without corresponding current period activity, lower insurance expense ( $1.6 million ), information technology expenses ( $1.3 million ) and outside support services ( $0.2 million ). Offsetting these decreases were increased employee expenses ( $1.3 million ).

Maintenance Turnaround Expense . We incurred turnaround expenses associated with the fall 2016 turnaround of the No. 2 crude unit at our St. Paul Park refinery during the first nine months of 2016 .

Depreciation and Amortization. Depreciation and amortization increased due to additional depreciation associated with recently capitalized logistics assets.

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WNRL

WNRL's financial and operational data presented includes the historical results of the assets acquired from Western in the St. Paul Park Logistics Transaction and the TexNew Mex Pipeline Transaction. These recent transactions 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 St. Paul Park Logistics Assets and the TexNew Mex Pipeline System into WNRL.

Three Months Ended September 30, 2016 , Compared to the Three Months Ended September 30, 2015

	Three Months Ended
	September 30,
	2016				2015				Change
	(In thousands)
Statement of Operations Data:
Net sales	$	569,261			$	680,670			$	(111,409	)
Operating costs and expenses:
Cost of products sold	495,536				601,557				(106,021		)
Direct operating expenses	43,454				45,927				(2,473		)
Selling, general and administrative expenses	6,483				5,812				671
Gain on disposal of assets, net	(62		)		(13		)		(49		)
Depreciation and amortization	10,579				8,963				1,616
Total operating costs and expenses	555,990				662,246				(106,256		)
Operating income	$	13,271			$	18,424			$	(5,153	)

	Three Months Ended
	September 30,
	2016				2015				Change
Key Operating Statistics
Pipeline and gathering (bpd):
Mainline movements:
Permian/Delaware Basin system	49,709				56,745				(7,036		)
Four Corners system (1)	53,070				66,602				(13,532		)
TexNew Mex system	7,504				14,834				(7,330		)
Gathering (truck offloading):
Permian/Delaware Basin system	15,514				25,961				(10,447		)
Four Corners system	9,577				16,487				(6,910		)
Terminalling, transportation and storage (bpd):
Shipments into and out of storage (includes asphalt):	416,761				408,787				7,974
Wholesale:
Fuel gallons sold (in thousands)	313,600				305,566				8,034
Fuel gallons sold to retail (included in fuel gallons sold above) (in thousands)	87,131				81,538				5,593
Fuel margin per gallon (2)	$	0.030			$	0.029			$	0.001
Lubricant gallons sold (in thousands)	1,355				2,998				(1,643		)
Lubricant margin per gallon (3)	$	1.05			$	0.70			$	0.35
Asphalt trucking volume (bpd)	5,620				—				5,620
Crude oil trucking volume (bpd)	36,144				49,620				(13,476		)
Average crude oil revenue per barrel	$	2.11			$	2.51			$	(0.40	)

(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.

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(2)	Fuel margin per gallon is a measurement calculated by dividing the difference between fuel sales, net of transportation charges, and cost of fuel sales for our wholesale business by the number of gallons sold. 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 the number of gallons sold. 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 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):

	Three Months Ended
	September 30,
	2016				2015				Change
	(In thousands)
Net sales	$	569,261			$	680,670			$	(111,409	)
Cost of products sold (exclusive of depreciation and amortization)	495,536				601,557				(106,021		)
Gross margin	$	73,725			$	79,113			$	(5,388	)

WNRL's gross margin decreased by $5.4 million primarily due to decreased fee based revenues of $4.3 million . Fee based revenue decreased due to lower mainline movement volumes compared to 2015 and reduced crude oil trucking revenue of $4.2 million , in addition, lubricant margins decreased $1.2 million . Wholesale fuel sales revenue decreased due to overall pricing declines. The average price per gallon sold in the three months ended September 30, 2016 was $1.58 , compared to $1.90 for the three months ended September 30, 2015 . Partially offsetting the margin decrease was new activity in 2016 that includes $1.9 million in fees generated by WNRL's St. Paul Park Logistics Assets and $2.1 million in asphalt trucking fees, in addition, wholesale fuel margins increased $0.6 million .

Direct Operating Expenses (exclusive of depreciation and amortization). Direct operating expenses decreased primarily due to lower maintenance ( $1.1 million ), employee expenses ( $0.4 million ), chemical additives used in the pipeline transportation process ( $0.4 million ), outside support services ( $0.4 million ), insurance ( $0.3 million ) and lower fuel expense for WNRL's transportation department ( $0.2 million ). Offsetting these decreases were increased operating expenses for WNRL's St. Paul Park Logistics Assets period over period ( $0.4 million ).

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

Selling, General and Administrative Expenses. Selling, general and administrative expenses increased primarily due to greater expense allocations ( $0.4 million ) and professional and legal services related to acquisitions ( $0.3 million ).

Depreciation and Amortization. Depreciation and amortization increased due to the ongoing expansion of WNRL's Delaware Basin and Four Corners logistics systems.

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Nine Months Ended September 30, 2016 , Compared to the Nine Months Ended September 30, 2015

	Nine Months Ended
	September 30,
	2016				2015				Change
	(In thousands)
Statement of Operations Data:
Net sales	$	1,615,902			$	2,023,970			$	(408,068	)
Operating costs and expenses:
Cost of products sold	1,395,382				1,807,284				(411,902		)
Direct operating expenses	131,103				131,156				(53		)
Selling, general and administrative expenses	17,854				18,517				(663		)
Gain on disposal of assets, net	(963		)		(257		)		(706		)
Depreciation and amortization	29,470				25,816				3,654
Total operating costs and expenses	1,572,846				1,982,516				(409,670		)
Operating income	$	43,056			$	41,454			$	1,602

	Nine Months Ended
	September 30,
	2016				2015				Change
Key Operating Statistics
Pipeline and gathering (bpd):
Mainline movements:
Permian/Delaware Basin system	51,709				45,784				5,925
Four Corners system (1)	54,523				54,719				(196		)
TexNew Mex system	10,132				6,131				4,001
Gathering (truck offloading):
Permian/Delaware Basin system	17,948				24,207				(6,259		)
Four Corners system	11,151				13,387				(2,236		)
Terminalling, transportation and storage (bpd):
Shipments into and out of storage (includes asphalt)	399,415				396,506				2,909
Wholesale:
Fuel gallons sold (in thousands)	940,029				919,808				20,221
Fuel gallons sold to retail (included in fuel gallons sold above) (in thousands)	250,693				235,824				14,869
Fuel margin per gallon (2)	$	0.028			$	0.031			$	(0.003	)
Lubricant gallons sold (in thousands)	5,402				8,969				(3,567		)
Lubricant margin per gallon (3)	$	0.85			$	0.71			$	0.14
Asphalt trucking volume (bpd)	4,461				—				4,461
Crude oil trucking volume (bpd)	37,909				47,245				(9,336		)
Average crude oil revenue per barrel	$	2.17			$	2.58			$	(0.41	)

(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 measurement calculated by dividing the difference between fuel sales, net of transportation charges, and cost of fuel sales for our wholesale business by the number of gallons sold. 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 the number of gallons sold. Lubricant margin is a measure frequently used in the petroleum products wholesale industry to measure operating results related to lubricant sales.

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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):

	Nine Months Ended
	September 30,
	2016				2015				Change
	(In thousands)
Net sales	$	1,615,902			$	2,023,970			$	(408,068	)
Cost of products sold (exclusive of depreciation and amortization)	1,395,382				1,807,284				(411,902		)
Gross margin	$	220,520			$	216,686			$	3,834

WNRL's gross margin increased by $3.8 million primarily due to increased fee based revenue of $8.7 million . Fee based revenues increased due to higher mainline volume movements compared to 2015. New activity in 2016 includes $1.9 million in fees generated by WNRL's St. Paul Park Logistics Assets and $5.8 million in asphalt trucking fees. Partially offsetting the margin increase were decreased wholesale fuel margins of $2.6 million , reduced crude oil trucking revenue of $7.5 million and a $3.0 million decrease in lubricant margins. Wholesale fuel sales revenue decreased due to overall pricing declines. The average price per gallon sold in the first nine months of 2016 , was $1.47 compared to $1.90 for the first nine months of 2015 .

Direct Operating Expenses (exclusive of depreciation and amortization). Direct operating expenses were relatively flat, but included decreases due to maintenance ( $2.7 million ), lower fuel expense for WNRL's transportation department ( $1.2 million ) and chemical additives used in the pipeline transportation process ( $1.1 million ), partially offset by higher outside support services ( $1.7 million ) due to in-line inspections for pipeline segments and various tank repairs, higher employee expenses ( $1.5 million ) resulting from an increase in the number of drivers in WNRL's truck fleet, increased environmental expenses ( $0.5 million ) and increased operating expenses for WNRL's St. Paul Park Logistics Assets period over period ( $0.8 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 primarily due to decreased professional and legal services ( $0.5 million ) related to acquisitions and other taxes ( $0.3 million ), partially offset by increased public company costs ( $0.2 million ).

Gain on disposal of assets, net . The increase in 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. Depreciation and amortization increased due to assets capitalized in WNRL's TexNew Mex Pipeline Acquisition, the ongoing expansion of WNRL's Delaware Basin and Four Corners logistics systems.

.

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Retail Segment

Three Months Ended September 30, 2016 , Compared to the Three Months Ended September 30, 2015

	Three Months Ended
	September 30,
	2016				2015				Change
	(In thousands, except per gallon data)
Statement of Operations Data
Net sales (including intersegment sales)	$	597,621			$	633,793			$	(36,172	)
Operating costs and expenses:
Cost of products sold (exclusive of depreciation and amortization)	497,114				522,102				(24,988		)
Direct operating expenses (exclusive of depreciation and amortization)	73,388				70,112				3,276
Selling, general and administrative expenses	9,786				10,835				(1,049		)
Gain on disposal of assets, net	(209		)		(39		)		(170		)
Depreciation and amortization	5,710				5,846				(136		)
Total operating costs and expenses	585,789				608,856				(23,067		)
Operating income	$	11,832			$	24,937			$	(13,105	)
Key Operating Statistics
Southwest Retail:
Retail fuel gallons sold	105,304				92,939				12,365
Average retail fuel sales price per gallon, net of excise taxes	$	1.79			$	2.26			$	(0.47	)
Average retail fuel cost per gallon, net of excise taxes	1.60				1.95				(0.35		)
Retail fuel margin per gallon (1)	0.19				0.31				(0.12		)
Merchandise sales	$	88,151			$	83,146			$	5,005
Merchandise margin (2)	28.8		%		29.4		%		(0.6		)%
Cardlock fuel gallons sold	16,630				16,990				(360		)
Cardlock fuel margin per gallon	$	0.122			$	0.176			$	(0.054	)
SuperAmerica:
Retail fuel gallons sold	79,539				78,414				1,125
Retail fuel margin per gallon (1)	$	0.22			$	0.27			$	(0.05	)
Merchandise sales	99,535				100,645				(1,110		)
Merchandise margin (2)	25.8		%		25.8		%		—		%

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

	Three Months Ended
	September 30,
	2016				2015				Change
	(In thousands, except per gallon data)
Net Sales
Retail fuel sales, net of excise taxes	$	359,916			$	408,801			$	(48,885	)
Merchandise sales	187,686				183,791				3,895
Cardlock sales	25,042				33,184				(8,142		)
Other sales	24,977				8,017				16,960
Net sales	$	597,621			$	633,793			$	(36,172	)
Cost of Products Sold
Retail fuel cost of products sold, net of excise taxes	$	321,843			$	359,142			$	(37,299	)
Merchandise cost of products sold	136,597				133,346				3,251
Cardlock cost of products sold	22,920				30,141				(7,221		)
Other cost of products sold	15,754				(527		)		16,281
Cost of products sold	$	497,114			$	522,102			$	(24,988	)
Gross margin	$	100,507			$	111,691			$	(11,184	)
Retail fuel margin per gallon (1)	$	0.21			$	0.29			$	(0.08	)

(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 retail gross margin was the result of lower same store Southwest Retail fuel gross margin of $8.7 million , partially offset by increased same store Southwest Retail merchandise gross margin of $0.8 million . The net effect in Southwest Retail of 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 retail gross margin of $1.0 million . SuperAmerica gross margin decreased by $3.3 million due lower fuel margins at company-owned locations.

Direct Operating Expenses (exclusive of depreciation and amortization). Direct operating expenses for the three months ended September 30, 2016 , increased from the three months ended September 30, 2015 . There was an increase in Southwest Retail same store direct operating expenses of $0.7 million and the net effect of four outlets that closed in the third and fourth quarters of 2015 and one retail outlet added in the second and third quarters of 2016 was a $0.7 million increase in expenses. The increase was also due to higher SuperAmerica direct operating expenses of $1.5 million resulting from greater lease expenses.

Selling, General and Administrative Expenses. The decrease in selling, general and administrative expenses was primarily due to lower SuperAmerica employee and professional and legal expenses and decreased cardlock employee expenses of $0.3 million .

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Nine Months Ended September 30, 2016 , Compared to the Nine Months Ended September 30, 2015

	Nine Months Ended
	September 30,
	2016				2015				Change
	(In thousands, except per gallon data)
Statement of Operations Data
Net sales (including intersegment sales)	$	1,610,033			$	1,753,503			$	(143,470	)
Operating costs and expenses:
Cost of products sold (exclusive of depreciation and amortization)	1,328,801				1,469,321				(140,520		)
Direct operating expenses (exclusive of depreciation and amortization)	210,932				199,554				11,378
Selling, general and administrative expenses	31,720				31,369				351
Gain on disposal of assets, net	(235		)		(354		)		119
Depreciation and amortization	17,622				17,257				365
Total operating costs and expenses	1,588,840				1,717,147				(128,307		)
Operating income	$	21,193			$	36,356			$	(15,163	)
Key Operating Statistics
Southwest Retail:
Retail fuel gallons sold	295,323				267,102				28,221
Average retail fuel sales price per gallon, net of excise taxes	$	1.66			$	2.10			$	(0.44	)
Average retail fuel cost per gallon, net of excise taxes	1.50				1.89				(0.39		)
Retail fuel margin per gallon (1)	0.16				0.21				(0.05		)
Merchandise sales	$	249,187			$	234,014			$	15,173
Merchandise margin (2)	29.2		%		29.5		%		(0.3		)%
Operating retail outlets at period end	260				261				(1		)
Cardlock fuel gallons sold	48,398				50,013				(1,615		)
Cardlock fuel margin per gallon	$	0.123			$	0.174			$	(0.051	)
Operating cardlocks at period end	51				52				(1		)
SuperAmerica:
Retail fuel gallons sold	231,087				227,673				3,414
Retail fuel margin per gallon (1)	$	0.23			$	0.23			$	—
Merchandise sales	279,963				279,058				905
Merchandise margin (2)	26.0		%		25.9		%		0.1		%
Company-operated retail outlets at period end	170				165				5
Franchised retail outlets at period end	115				102				13

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

	Nine Months Ended
	September 30,
	2016				2015				Change
	(In thousands, except per gallon data)
Net Sales
Retail fuel sales, net of excise taxes	$	963,670			$	1,115,571			$	(151,901	)
Merchandise sales	529,150				513,072				16,078
Cardlock sales	74,302				100,960				(26,658		)
Other sales	42,911				23,900				19,011
Net sales	$	1,610,033			$	1,753,503			$	(143,470	)
Cost of Products Sold
Retail fuel cost of products sold, net of excise taxes	$	862,609			$	1,006,717			$	(144,108	)
Merchandise cost of products sold	383,680				371,719				11,961
Cardlock cost of products sold	68,101				92,077				(23,976		)
Other cost of products sold	14,411				(1,192		)		15,603
Cost of products sold	$	1,328,801			$	1,469,321			$	(140,520	)
Gross margin	$	281,232			$	284,182			$	(2,950	)
Retail fuel margin per gallon (1)	$	0.19			$	0.22			$	(0.03	)

(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 $7.4 million and a decrease in cardlock gross margin of $2.7 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 retail gross margin of $2.0 million . Southwest Retail same store merchandise gross margin increased by $2.0 million . SuperAmerica gross margin increased by $2.9 million due higher fuel and merchandise margins due to the expansion of the company-owned locations by 5 stores and franchised locations by 13 stores.

Direct Operating Expenses (exclusive of depreciation and amortization). Direct operating expenses for the nine months ended September 30, 2016 , increased from the nine months ended September 30, 2015 . This increase was primarily due to higher SuperAmerica employee expense of $2.7 million due to a Minnesota state mandated increase in the minimum wage in mid-2015. Additionally, SuperAmerica incurred higher store lease expense and maintenance expense of $2.6 million and $1.1 million during the nine months ended September 30, 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 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 $1.4 million in expenses. Additionally, there was an increase in same store Southwest Retail employee and maintenance expense of $2.0 million and $0.4 million , respectively, partially offset by a decrease in same store Southwest Retail insurance expense and credit card processing fees of $0.4 million and, $0.3 million , respectively.

Selling, General and Administrative Expenses. The increase in selling, general and administrative expenses was primarily due to higher SuperAmerica professional and legal and property tax expenses, partially offset by decreased cardlock employee expenses of $0.7 million .

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NTI

General Instruction H(2)(a) of Form 10-Q 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-Q its management's narrative analysis of the results of operations explaining the reasons for material changes in revenue and expenses for the year-to-date periods presented. Set forth below are the operating results of NTI, as presented in NTI's standalone financial statements in its Condensed Consolidated Statements of Operations for the nine months ended September 30, 2016 and 2015 . 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.

Nine Months Ended September 30, 2016 , Compared to the Nine Months Ended September 30, 2015

	Nine Months Ended
	September 30,
	2016				2015				Change
	(In millions)
Statements of Operations Data
Revenue (1)	$	2,149.0			$	2,645.2			$	(496.2	)
Operating costs and expenses:
Cost of products sold (exclusive of depreciation and amortization) (1)	1,685.0				1,957.7				(272.7		)
Direct operating expenses (exclusive of depreciation and amortization)	238.3				220.8				17.5
Selling, general and administrative expenses	66.2				62.9				3.3
Merger-related expenses	2.6				—				2.6
Maintenance turnaround expense	26.8				9.4				17.4
Depreciation and amortization	35.0				32.6				2.4
Income from equity method investment	(15.3		)		(12.0		)		(3.3		)
Other (gain) loss	(0.7		)		0.4				(1.1		)
Total operating costs and expenses	2,037.9				2,271.8				(233.9		)
Operating income	111.1				373.4				(262.3		)
Other income (expense):
Interest and debt expense	(18.5		)		(22.5		)		4
Income before income taxes	92.6				350.9				(258.3		)
Provision for income taxes	(3.7		)		(7.3		)		3.6
Net income	$	88.9			$	343.6			$	(254.7	)

(1)	Includes excise taxes of $323.5 million and $296.6 million for the nine months ended September 30, 2016 and 2015 , respectively.

Revenue . Revenue for the nine months ended September 30, 2016 , was $2,149.0 million compared to $2,645.2 million for the nine months ended September 30, 2015 , a decrease of 18.8% . Refining revenue decreased 21.8% and retail revenue decreased 9.3% compared to the nine months ended September 30, 2015 . Refining revenue decreased primarily due to lower refined product prices due to market conditions, partially offset by increased sales volumes of 0.4% in the 2016 period. Retail revenue decreased primarily due to lower fuel prices due to market conditions, partially offset by an increase in fuel gallons sold of 1.5% . Excise taxes included in revenue increased by $26.9 million for the 2016 period over the 2015 period.

Cost of sales . Cost of sales totaled $1,685.0 million for the nine months ended September 30, 2016 , compared to $1,957.7 million for the nine months ended September 30, 2015 , a decrease of 13.9% . Refining cost of sales decreased 15.6% and retail cost of sales decreased 11.6% compared to the nine months ended September 30, 2015 . The decrease was primarily due to lower crude oil costs and a $61.9 million benefit from a lower of cost or market inventory adjustment, partially offset by an increase of 0.4% in refining sales volumes. The decreased retail cost of sales was primarily due to lower costs of fuel products. Lastly, excise taxes included in cost of sales increased by $26.9 million for the 2016 period over the 2015 period.

Direct operating expenses . Direct operating expenses totaled $238.3 million for the nine months ended September 30, 2016 , compared to $220.8 million for the nine months ended September 30, 2015 , an increase of 7.9% , due primarily to higher

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spending on refinery maintenance projects due to the more temperate weather experienced in the 2016 period compared to the 2015 period. The higher direct operating expenses were also driven by higher retail personnel costs in the 2016 period. These increases in costs were partially offset by reduced utilization of third-party trucking firms in North Dakota due primarily to a shift in 2016 whereby we purchased more crude oil from barrels already on the pipeline or at storage facilities as opposed to at the wellhead.

Turnaround and related expenses . Turnaround and related expenses totaled $26.8 million for the nine months ended September 30, 2016 , compared to $9.4 million for the nine months ended September 30, 2015 . The turnaround costs in the nine months ended September 30, 2016 , include turnaround and related costs incurred for the fall 2016 turnaround of our No. 2 crude unit. Such costs in the corresponding 2015 period relate to planning costs for a third quarter 2015 turnaround on our sulfur recovery unit.

Depreciation and amortization . Depreciation and amortization was $35.0 million for the nine months ended September 30, 2016 , compared to $32.6 million for the nine months ended September 30, 2015 , an increase of 7.4% . This increase was due primarily to increased refining assets placed in service since September 30, 2015 , the most significant of which were improvements to a firewater system, truck loading terminal and parking facilities along with retail stores acquired under capital leases.

Selling, general and administrative expenses . Selling, general and administrative expenses were $66.2 million for the nine months ended September 30, 2016 , compared to $62.9 million for the nine months ended September 30, 2015 . This increase of 5.2% relates primarily to higher equity-based compensation expense resulting from new grants and performance award adjustments.

Merger-related expenses . Legal and advisory costs of $2.6 million were incurred during the nine months ended September 30, 2016 , as a result of the Merger Agreement with Western Refining. No such costs were incurred during the 2015 period.

Income from equity method investments . Income from equity method investments was $15.3 million for the nine months ended September 30, 2016 , compared to $12.0 million for the nine months ended September 30, 2015 . This increase was driven by higher equity income due to reduced spending on maintenance projects on the pipeline in the 2016 period.

Other (gain) loss . Other (gain) loss was a $0.7 million gain for the nine months ended September 30, 2016 , compared to $0.4 million loss for the nine months ended September 30, 2015 , driven primarily by fluctuations in the exchange rate between our functional currency, the U.S. dollar and the Canadian dollar.

Interest expense, net . Interest expense, net was $18.5 million for the nine months ended September 30, 2016 and $22.5 million for the nine months ended September 30, 2015 . This decrease relates primarily to the $4.9 million higher capitalization of interest expense on several large refining capital projects.

Income tax provision . The income tax provision for the nine months ended September 30, 2016 , was $3.7 million compared to $7.3 million for the nine months ended September 30, 2015 . This decrease was due primarily to lower income within retail.

Net income . Our net income was $88.9 million for the nine months ended September 30, 2016 , compared to $343.6 million for the nine months ended September 30, 2015 . This decrease in net income is primarily attributable to a $223.5 million decrease in gross margin, a $17.5 million increase in direct operating expenses and a $3.3 million increase selling, general and administrative expenses. These unfavorable factors were partially offset by $3.3 million higher income from our equity method investment and other cost savings.

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Outlook

Our refining margins, excluding hedging activities, were weaker at the El Paso, Gallup and St. Paul Park refineries in the third quarter of 2016 compared to the third quarter of 2015 . The GC 3:2:1 decreased from an average of $21.43 per barrel for the three months ended September 30, 2015 , to an average of $13.29 for the three months ended September 30, 2016 . The GC 3:2:1 for October 2016 averaged $13.25 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 $15.77 per barrel for the three months ended September 30, 2015 , to an average of $9.85 per barrel for the three months ended September 30, 2016 . The Group 3 6:3:2:1 averaged $7.73 per barrel for October 2016 .

Both Western and NTI base 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 $0.31 per barrel for the third quarter of 2016 , which, compared to a discount of $0.71 per barrel that we realized in El Paso during the third quarter of 2015 , negatively impacted our El Paso refining margins in the current quarter. The WTI Midland/Cushing differential has averaged a discount of $0.52 per barrel thus far in the fourth quarter of 2016 .

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 $1.25 per barrel for the third quarter of 2016 compared to $2.36 per barrel for the third quarter of 2015 . The Bakken/WTI discount averaged $0.72 per barrel for October 2016. The WCS/WTI discount averaged $13.71 per barrel for the third quarter of 2016 versus $14.47 per barrel for the third quarter of 2015 . The WCS/WTI discount averaged $14.17 per barrel for October 2016 .

The prices of crude oil and refined products have been volatile thus far in 2016. 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 the first nine months of 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 the first nine months of 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 cash from operations, cash on hand and Western revolving credit facility availability. To a lesser extent, we also generate liquidity from the issuance of debt and equity securities and sales of assets to WNRL.

As of September 30, 2016 , we had cash and cash equivalents of $266.1 million , including NTI cash of $14.6 million and WNRL cash of $16.5 million and no direct borrowings under the Western revolving credit facility. In addition to cash and cash equivalents, we had restricted cash of $195.0 million . Western had $492.0 million in total liquidity as of September 30, 2016 , defined as Western’s cash and cash equivalents plus net availability under Western's revolving credit facility. Western, NTI and WNRL had net availability under their revolving credit facilities of $257.0 million , $205.7 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 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 Merger consideration. See Note 21, Acquisitions , in the Notes to Condensed Consolidated Financial Statements 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 the nine months ended September 30, 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 $52.0 million and $20.3 million under the NTI and WNRL revolving credit facilities, respectively, as of September 30, 2016 . See Note 9, Long-Term Debt , in the Notes to Condensed Consolidated Financial Statements for detailed information regarding our financing.

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

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

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. Our board of directors approved our current $200 million share repurchase program in September of 2015 (the "September 2015 Program") that is scheduled to expire on December 31, 2016. We have repurchased 2.5 million shares of our common stock at a cost of $75.0 million under the September 2015 Program. As of September 30, 2016 , we had $125.0 million remaining in authorized expenditures under the September 2015 Program.

We will repurchase shares from time-to-time through open market transactions, block trades, privately negotiated transactions or otherwise and subject to market conditions, as well as corporate, regulatory and other considerations. The share repurchase program may be modified or discontinued at any time by our board of directors.

Cash Flows

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

	Nine Months Ended
	September 30,
	2016				2015				Change
	(In thousands)
Net cash provided by operating activities	$	277,877			$	665,664			$	(387,787	)
Net cash used in investing activities	(357,079		)		(34,454		)		(322,625		)
Net cash used in financing activities	(427,204		)		(352,799		)		(74,405		)
Net increase (decrease) in cash and cash equivalents	$	(506,406	)		$	278,411			$	(784,817	)

The decrease in net cash from operating activities period over period was primarily the result of the decrease in net income and the results of our commodity hedging activity, offset by changes in our working capital as disclosed in our Condensed Consolidated Statements of Cash Flows for the nine months ended September 30, 2016 and 2015 .

Cash flows from operating activities for the nine months ended September 30, 2016 , combined with $500.0 million in additions to Western's long-term debt, $393.9 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 ( $235.1 million ) including the use of $69.1 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 ( $287.5 million );

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

• Payment of cash dividends ( $111.6 million );

• Purchase of treasury stock ( $75.0 million );

• Payment of distributions to non-controlling interest holders ( $54.1 million );

• Payment of deferred financing costs ( $12.4 million ); and

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

Cash flows used in operating activities for the nine months ended September 30, 2015 , combined with $300.0 million in additions to WNRL long-term debt, were primarily used for the following investing and financing activities:

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Investing Activities:

• Fund capital expenditures ( $196.0 million ) including the use of $154.7 million of restricted cash.

Financing Activities:

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

• Payments of distributions to non-controlling interest holders ( $173.7 million );

• Purchase of treasury stock ( $105.0 million );

• Payment of cash dividends ( $93.6 million ); and

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

Future Capital Expenditures

We expect to fund future capital expenditures primarily through cash from operations supplemented as needed by borrowings under our revolving credit facilities. The following table summarizes our 2016 forecasted spending allocation between sustaining, discretionary and regulatory projects for 2016 :

	Western (1)				WNRL				Totals
	(In thousands)
Sustaining	$	80,000			$	7,100			$	87,100
Discretionary	150,000				20,000				170,000
Regulatory	30,000				2,900				32,900
Total	$	260,000			$	30,000			$	290,000

(1)	Western's capital expenditure forecast for the full year 2016 is $260.0 million , of which $241.1 million is for our refining segment, $14.0 million for our retail segment and $4.9 million for other general projects.

The majority of Western's planned discretionary capital expenditures relate to crude oil logistics projects in the Permian Basin and discretionary growth projects at the St. Paul Park Refinery. WNRL’s discretionary capital expenditures primarily relate to construction of a 10-inch pipeline connection from its pipeline system in the Four Corners region of Northern New Mexico to the TexNew Mex Pipeline System and continued expansion of its Permian Delaware Basin system.

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Capital Structure

Our capital structure at September 30, 2016 and 2015 , was as follows:

	September 30, 2016				September 30, 2015
	(In thousands)
Debt, including current maturities:
Western obligations:
Revolving Credit Facility due 2019	$	—			$	—
Term Loan - 5.25% Credit Facility due 2020	534,875				540,375
6.25% Senior Unsecured Notes due 2021	350,000				350,000
Term Loan - 5.50% Credit Facility due 2023	498,750				—
Total Western obligations	1,383,625				890,375
NTI obligations:
Revolving Credit Facility due 2019	52,000				—
7.125% Senior Secured Notes due 2020	350,000				350,000
Total NTI obligations	402,000				350,000
WNRL obligations:
Revolving Credit Facility due 2018	20,300				—
7.5% Senior Notes due 2023	300,000				300,000
Total WNRL obligations	320,300				300,000
Less unamortized discount, premium and debt issuance costs	50,245				35,284
Long-term debt	2,055,680				1,505,091
Equity	2,267,446				3,032,495
Total capitalization	$	4,323,126			$	4,537,586

See Note 9, Long-Term Debt and Note 10, Equity , in the Notes to Condensed Consolidated Financial Statements for further information.

Contractual Obligations and Commercial Commitments

We include a complete summary of our future contractual obligations and commercial commitments as of December 31, 2015 , in our 2015 Form 10-K under Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations, Contractual Obligations and Commercial Commitments.

Dividends

We anticipate paying future quarterly dividends, subject to the board of directors' approval and compliance with the restrictions in our outstanding financing agreements. The table below summarizes our 2016 cash dividend declarations, payments and scheduled payments through October 28, 2016 :

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 (1)

October 13

October 24

November 8

0.38

—

Total

$

111,488

(1)	The fourth quarter 2016 cash dividend of $0.38 per common share will result in an estimated aggregate payment of $41.2 million .

Off-Balance Sheet Arrangements

We have no off-balance sheet arrangements.

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Item 3.	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 September 30, 2016 , we held 10.4 million barrels of crude oil, refined product and other inventories valued under the LIFO valuation method with an average cost of $63.96 per barrel. At September 30, 2016 , the excess of the LIFO cost over the current cost of these crude oil, refined product and other feedstock and blendstock inventories was $193.3 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 Condensed Consolidated Statements of Operations.

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

The following tables summarize our economic hedging activity recognized within cost of products sold for the three and nine months ended September 30, 2016 and 2015 and open commodity hedging positions as of September 30, 2016 and December 31, 2015 :

	Three Months Ended								Nine Months Ended
	September 30,								September 30,
	2016				2015				2016				2015
	(In thousands)
Economic hedging results
Realized hedging gain, net	$	27,757			$	26,949			$	46,110			$	52,325
Unrealized hedging gain (loss), net	(27,616		)		271				(54,698		)		(42,073		)
Total hedging gain (loss), net	$	141			$	27,220			$	(8,588	)		$	10,252

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	September 30, 2016				December 31, 2015
	(In thousands)
Open commodity hedging instruments (barrels)
Crude oil differential swaps, net long positions	5,622				5,155
Crude oil futures, net short positions	(687		)		(562		)
Refined product price and crack spread swaps, net short positions	(3,902		)		(5,645		)
Total open commodity hedging instruments, net long (short) positions	1,033				(1,052		)
Fair value of outstanding contracts, net
Other current assets	$	26,757			$	78,125
Other assets	2,851				11,881
Accrued liabilities	(4,457		)		(10,273		)
Other long-term liabilities	(153		)		—
Fair value of outstanding contracts - unrealized gain, net	$	24,998			$	79,733

During the three and nine months ended September 30, 2016 and 2015 , we did not have any commodity derivative instruments that were designated or accounted for as hedges.

Item 4.	Controls and Procedures

Western Refining, Inc.

Under the supervision and with the participation of our management, including the Chief Executive Officer and Chief Financial Officer, we evaluated the effectiveness of our disclosure controls and procedures, as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as of September 30, 2016 . Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of September 30, 2016 .

There were no changes in our internal control over financial reporting during the quarter ended September 30, 2016 , that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Northern Tier Energy LP

Under the supervision and with the participation of NTI's management, including its Chief Executive Officer and Chief Financial Officer, NTI evaluated the effectiveness of its disclosure controls and procedures, as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as of September 30, 2016 . Based on that evaluation, NTI's Chief Executive Officer and Chief Financial Officer concluded that its disclosure controls and procedures were effective as of September 30, 2016 .

There were no changes in NTI's internal control over financial reporting during the quarter ended September 30, 2016 , that have materially affected, or are reasonably likely to materially affect, its internal control over financial reporting.

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Part II

Other Information

Item 1. 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 proceedings 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 18, Commitments and Contingencies , in the Notes to Condensed Consolidated Financial Statements 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 17 , Commitments and Contingencies , in NTI's Notes to Condensed Consolidated Financial Statements for further discussion.

Item 1A. Risk Factors

Western Refining, Inc.

There have been no other material changes in our risk factors during the nine months ended September 30, 2016 , from those previously disclosed in the section entitled "Risk Factors" in our 2015  Form 10-K under Part I, Item 1A. Risk Factors and in our Quarterly Report on Form 10-Q for the period ended March 31, 2016, under Part II, Item 1A. Risk Factors .

Northern Tier Energy LP

There have been no material changes from the risk factors disclosed in the section entitled "Risk Factors" in NTI's 2015  Form 10-K under Part I, Item 1A. Risk Factors.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

Since 2012, our board of directors has approved five separate 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 the September 2015 Program for up to $200 million for the repurchase of our outstanding common stock. The September 2015 Program is scheduled to expire on December 31, 2016 and is subject to discontinuance by our board of directors at any time. We did not purchase any shares of our common stock during the three months ended September 30, 2016 .

We may repurchase shares from time-to-time through open market transactions, block trades, privately negotiated transactions or otherwise and subject to market conditions, as well as corporate, regulatory and other considerations. The share repurchase programs may be modified or discontinued at any time by our board of directors.

Our payment of dividends is limited under the terms of our Western 2019 Revolving Credit Agreement, our Western 2021 Senior Unsecured Notes, our Western 2020 and Western 2023 Term Loan Credit Facilities, and in part, depends on our ability to satisfy certain financial covenants. Also, as a holding company, we rely on dividends or advances from our subsidiaries to fund any dividends. The ability of our subsidiaries including NTI and WNRL to pay us dividends is restricted by covenants in their respective debt instruments and any future financing agreements.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

None.

Item 5. Other Information                                                 

None.

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Item 6. Exhibits

Exhibit Index

Western Refining, Inc. ***

Exhibit Number		Exhibit Title
10.1		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)
10.2		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)
10.3*		Employment Agreement, effective August 15, 2016, by and between Western Refining GP, LLC and Gary R. Dalke.
31.1*		Certification Statement of Chief Executive Officer and Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32.1**		Certification Statement of Chief Executive Officer and Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
101		Interactive Data Files

*		Filed herewith.
**		Furnished herewith.
***		Reports filed under the Securities Exchange Act of 1934, as amended, (Form 10-K, Form 10-Q and Form 8-K) are filed under File No. 001-32721.

Northern Tier Energy LP ***

Number		Exhibit Title
10.1		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)
10.2		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 Executive Officer and Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32.2**		Certification Statement of Chief Executive Officer and Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
101		Interactive Data Files

*		Filed herewith.
**		Furnished herewith.
***		Reports filed under the Securities Exchange Act of 1934, as amended, (Form 10-K, Form 10-Q and Form 8-K) are filed under File No. 001-35612.

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SIGNATURES

WESTERN REFINING, INC.

Pursuant to the requirements 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/ Karen B. Davis		Executive Vice President and Chief Financial Officer		November 2, 2016
Karen B. Davis		(Principal Financial Officer and Duly Authorized Signatory)

    

NORTHERN TIER ENERGY, LP

BY: NORTHERN TIER ENERGY GP, LLC

Pursuant to the requirements 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/ Karen B. Davis		Executive Vice President and Chief Financial Officer of Northern Tier Energy GP LLC		November 2, 2016
Karen B. Davis		(Principal Financial Officer and Principal Accounting Officer)

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NORTHERN TIER ENERGY LP

FORM 10-Q FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2016

TABLE OF CONTENTS

 

			Page
PART I - FINANCIAL INFORMATION			88
	ITEM 1.	Condensed Consolidated Financial Statements (Unaudited)	88
		Condensed Consolidated Balance Sheets as of September 30, 2016 and December 31, 2015	88
		Condensed Consolidated Statements of Operations and Comprehensive Income for the three and nine months ended September 30, 2016 and 2015	89
		Condensed Consolidated Statements of Cash Flows for the nine months ended September 30, 2016 and 2015	90
		Notes to Condensed Consolidated Financial Statements	91

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PART I - FINANCIAL INFORMATION

ITEM 1. Financial Statements

NORTHERN TIER ENERGY LP

CONDENSED CONSOLIDATED BALANCE SHEETS

(in millions, except unit data, unaudited)

 

	September 30, 2016				December 31, 2015
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	14.6			$	70.9
Restricted cash	195.0				—
Accounts receivable, net	255.9				186.0
Inventories	290.5				241.2
Other current assets	31.1				21.3
Total current assets	787.1				519.4
NON-CURRENT ASSETS
Equity method investments	82.8				82.1
Property, plant and equipment, net	504.3				487.8
Intangible assets	33.8				33.8
Other assets	14.3				14.2
Total Assets	$	1,422.3			$	1,137.3
LIABILITIES AND EQUITY
CURRENT LIABILITIES
Accounts payable	$	331.9			$	301.4
Accrued liabilities	74.7				61.8
Total current liabilities	406.6				363.2
NON-CURRENT LIABILITIES
Long-term debt	395.5				342.0
Lease financing obligation	9.2				11.1
Other liabilities	25.7				27.9
Total liabilities	837.0				744.2
Commitments and contingencies
EQUITY
Partners' capital (92,947,533 and 92,833,486 units issued and outstanding at September 30, 2016 and December 31, 2015, respectively)	585.3				392.9
Accumulated other comprehensive income	—				0.2
Total equity	585.3				393.1
Total Liabilities and Equity	$	1,422.3			$	1,137.3

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

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NORTHERN TIER ENERGY LP

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

AND COMPREHENSIVE INCOME

(in millions, unaudited)

 

	Three Months Ended								Nine Months Ended
	September 30, 2016				September 30, 2015				September 30, 2016				September 30, 2015
REVENUE (a)	$	732.3			$	891.6			$	2,149.0			$	2,645.2
COSTS, EXPENSES AND OTHER
Cost of sales (a)	584.7				666.6				1,685.0				1,957.7
Direct operating expenses	83.2				75.2				238.3				220.8
Turnaround and related expenses	24.6				7.8				26.8				9.4
Depreciation and amortization	12.1				11.0				35.0				32.6
Selling, general and administrative expenses	20.5				20.5				66.2				62.9
Merger-related expenses	1.5				—				2.6				—
Income from equity method investments	(5.3		)		(4.2		)		(15.3		)		(12.0		)
Other (gain) loss	(0.6		)		0.1				(0.7		)		0.4
OPERATING INCOME	11.6				114.6				111.1				373.4
Interest expense, net	(5.8		)		(7.5		)		(18.5		)		(22.5		)
INCOME BEFORE INCOME TAXES	5.8				107.1				92.6				350.9
Income tax provision	(2.2		)		(3.6		)		(3.7		)		(7.3		)
NET INCOME	3.6				103.5				88.9				343.6
Other comprehensive income, net of tax:
Post-employment benefit plans gain (loss)	—				—				(0.2		)		0.1
COMPREHENSIVE INCOME	$	3.6			$	103.5			$	88.7			$	343.7
Cash distributions declared per common unit	$	—			$	1.19			$	0.56			$	2.76
SUPPLEMENTAL INFORMATION:
(a) Excise taxes included in revenues and cost of sales	$	104.6			$	93.6			$	323.5			$	296.6

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

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NORTHERN TIER ENERGY LP

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions, unaudited)

 

	Nine Months Ended
	September 30, 2016				September 30, 2015
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	88.9			$	343.6
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	35.0				32.6
Non-cash interest expense	1.5				1.5
Equity-based compensation expense	11.0				7.9
Gain from the change in fair value of outstanding derivatives	(6.1		)		(0.3		)
Deferred income tax benefit	(0.8		)		—
Equity investment earnings, net of dividends	(0.8		)		(6.2		)
Change in lower of cost or market inventory adjustment	(61.8		)		(12.2		)
Other	(0.5		)		—
Changes in assets and liabilities, net:
Accounts receivable	(69.9		)		54.1
Inventories	11.9				(20.2		)
Other current assets	(7.6		)		(3.3		)
Accounts payable and accrued expenses	46.2				(81.2		)
Other, net	(2.9		)		1.0
Net cash provided by operating activities	44.1				317.3
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures	(99.2		)		(35.2		)
Increase in restricted cash	(195.0		)		—
Net cash used in investing activities	(294.2		)		(35.2		)
CASH FLOWS FROM FINANCING ACTIVITIES
Borrowings from revolving credit arrangement	339.5				—
Repayments of revolving credit arrangement	(287.5		)		—
Proceeds from sale to entity under common control	195.0				—
Equity distributions	(53.2		)		(255.4		)
Net cash provided by (used in) financing activities	193.8				(255.4		)
CASH AND CASH EQUIVALENTS
Change in cash and cash equivalents	(56.3		)		26.7
Cash and cash equivalents at beginning of period	70.9				87.9
Cash and cash equivalents at end of period	$	14.6			$	114.6

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

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NORTHERN TIER ENERGY LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

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 is a master limited partnership (“MLP”) for U.S. federal income tax purposes.

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”). SPPR owns a 17% interest in MPL Investments Inc. (“MPLI”) and a 17% interest in Minnesota Pipe Line Company, LLC (“MPL”). MPLI 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 19 ).

Refining Business

As of September 30, 2016 , the St. Paul Park refinery owned by SPPR, which is located in St. Paul Park, Minnesota, had total crude oil throughput capacity of 98,000 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, Western Refining Logistics, LP ("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.

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Retail Business

As of September 30, 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 unaudited condensed consolidated financial statements have been prepared in accordance with U.S. generally accepted accounting principles (“GAAP”) for interim financial information. Accordingly, they do not include all of the information and footnotes required by GAAP for complete financial statements. In the opinion of management, all adjustments (consisting of normal recurring accruals) considered necessary for a fair presentation of the results for the periods reported have been included. Operating results for the nine months ended September 30, 2016 , are not necessarily indicative of the results that may be expected for the year ending December 31, 2016 , or for any other period. The condensed consolidated balance sheet at December 31, 2015 , has been derived from the audited financial statements of NTE LP at that date but does not include all of the information and footnotes required by GAAP for complete financial statements. The accompanying condensed consolidated financial statements should be read in conjunction with the Company’s 2015 Annual Report on Form 10-K.

2 . SUMMARY OF PRINCIPAL ACCOUNTING POLICIES

The significant accounting policies set forth in Note 2 to the consolidated financial statements in the Company's 2015 Annual Report on Form 10-K, appropriately represent, in all material respects, the current status of accounting policies and are incorporated herein by reference.

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 condensed consolidated financial statements.

The Company’s common equity interest 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 3 for 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 September 30, 2016 and December 31, 2015 , and is included in other noncurrent assets within the condensed 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 condensed 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 Note 18 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, terminal and related assets, NTOT and includes the Company’s interest in MPL and MPLI, and

•	Retail – comprised of 170 Company operated convenience stores and 115 franchisee operated convenience stores as of September 30, 2016 , primarily in Minnesota and Wisconsin. The retail segment also includes the operation of NTB.

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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. 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 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.

When property, plant and equipment depreciated on an individual basis is sold or otherwise disposed of, any gains or losses are reported in the condensed 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 condensed 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 condensed 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 condensed 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.

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.

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 the Company does not produce renewable fuels, increasing the volume of

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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. The Company anticipates 2016 will be consistent with this history.

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.

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 of Sales

Cost of sales in the condensed 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 condensed 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 condensed consolidated statements of operations and comprehensive income. These taxes totaled $104.6 million and $93.6 million for the three months ended September 30, 2016 and 2015 , respectively, and $323.5 million and $296.6 million for the nine months ended September 30, 2016 and 2015 , respectively.

Accounting Developments

In May 2014, the FASB issued ASU No. 2014-09 “Revenue from Contracts with Customers,” which provides guidance for revenue recognition. The 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. In August 2014, the FASB issued ASU No. 2015-14 which deferred the effective date of ASU 2014-09. This guidance will now be effective for the Company's financial statements in the annual period beginning after December 15, 2017. The Company is evaluating the effect of adopting this new accounting guidance and does not expect adoption will have a material impact on NTE's results of operations, cash flows or financial position.

In February 2016, the FASB issued ASU No. 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.

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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 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. 2016-09 "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.

3 . RELATED PARTY TRANSACTIONS

As of September 30, 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 will acquire all of NTE LP's outstanding common units not already owned by Western (see Note 19 ). The transaction closed on June 23, 2016 (see Note 19 ).

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 $48.9 million . The proceeds from this transaction, reduced by the book value of the assets sold was $146.1 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 fees. 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.

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In addition to the Contribution Agreement, the Company engaged in the following related party transactions with unconsolidated affiliates for the three and nine months ended September 30, 2016 and 2015 :

			Three Months Ended								Nine Months Ended
(in millions)	Location in Statement of Operations and Comprehensive Income		September 30, 2016				September 30, 2015				September 30, 2016				September 30, 2015
Western Refining:
Asphalt sales	Revenue		$	8.9			$	7.5			$	28.0			$	35.3
Feedstock sales	Revenue		—				0.1				—				0.6
Railcar rental	Revenue		0.1				—				0.2				0.2
Refined product purchases	Cost of sales		—				1.5				—				1.5
Tank and terminal service fees	Cost of sales		1.9				—				1.9				—
Shared services purchases	Selling, general and administrative expenses		0.8				1.0				2.5				2.6
Minnesota Pipe Line Company:
Pipeline transportation purchases	Cost of sales		12.3				13.9				41.1				41.3

The Company had the following outstanding receivables and payables with non-consolidated related parties at September 30, 2016 and December 31, 2015 :

(in millions)	Balance Sheet Location		September 30, 2016				December 31, 2015
Net receivable (payable) with related party:
Western Refining, Inc.	Accounts receivable, net		$	1.9			$	2.8
Western Refining Logistics, LP	Accounts payable		(1.2		)		—
Minnesota Pipe Line Company	Accounts payable		(1.2		)		(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.

The Company’s effective tax rate for the three months ended September 30, 2016 and 2015 , was 37.9% and 3.4% , respectively. For the nine months ended September 30, 2016 and 2015 , the effective tax rate was 4.0% and 2.1% , respectively. For the nine months ended September 30, 2016 and 2015 , the Company's consolidated federal and state expected statutory tax rates were 40.4% and 40.9% , respectively. The Company's effective tax rate for the nine months ended September 30, 2016 and 2015 , was lower than the statutory rate primarily due to the fact that only the retail operations of the Company are taxable entities.

5 . INVENTORIES

 

	September 30,				December 31,
(in millions)	2016				2015
Crude oil and refinery feedstocks	$	158.8			$	171.8
Refined products	161.6				162.0
Merchandise	22.6				22.8
Supplies and sundry items	20.1				19.0
	363.1				375.6
Lower of cost or market inventory reserve	(72.6		)		(134.4		)
Total	$	290.5			$	241.2

Inventories accounted for under the LIFO method comprised 88% and 89% of the total inventory value at September 30, 2016 and December 31, 2015 , respectively, prior to the application of the lower of cost or market reserve.

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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 $72.6 million and $134.4 million at September 30, 2016 and December 31, 2015 , respectively.

6 . EQUITY METHOD INVESTMENTS

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 $82.8 million and $82.1 million at September 30, 2016 and December 31, 2015 , respectively.

As of September 30, 2016 and December 31, 2015 , the carrying amount of the equity method investment in MPL was $5.8 million and $5.9 million higher, respectively, than the underlying net assets of the investee, respectively. 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 $10.2 million and $4.2 million in distributions from its equity method investments in the three months ended September 30, 2016 and 2015 , respectively, and $14.5 million and $10.0 million , respectively, for the nine months ended September 30, 2016 and 2015 . At September 30, 2015, $4.2 million of these distributions were declared but unpaid. Equity income from the Company's equity method investments was $5.3 million and $4.2 million for the three months ended September 30, 2016 and 2015 , respectively, and $15.3 million and $12.0 million for the nine months ended September 30, 2016 and 2015 , respectively.

7 . PROPERTY, PLANT AND EQUIPMENT

Major classes of property, plant and equipment (“PP&E”) consisted of the following:  

	Estimated		September 30,				December 31,
(in millions)	Useful Lives		2016				2015
Land			$	7.1			$	9.0
Retail stores and equipment	2 - 22 years		76.6				72.3
Refinery and equipment	5 - 24 years		431.6				457.2
Buildings and building improvements	25 years		13.0				11.7
Software	5 years		18.9				18.9
Vehicles	5 years		5.8				5.6
Other equipment	2 - 7 years		12.0				10.4
Precious metals			10.4				10.2
Assets under construction			119.1				73.3
			694.5				668.6
Less: Accumulated depreciation			(190.2		)		(180.8		)
Property, plant and equipment, net			$	504.3			$	487.8

PP&E includes gross assets acquired under capital leases of $10.8 million and $13.3 million at September 30, 2016 and December 31, 2015 , respectively, with related accumulated depreciation of $2.1 million and $2.0 million , respectively. The Company had depreciation expense related to capitalized software of $0.8 million and $0.9 million for the three months ended September 30, 2016 and 2015 , respectively, and $2.8 million for both the nine months ended September 30, 2016 and 2015 . The Company capitalized interest expense related to capital projects within the refining segment of $2.0 million and zero for the three months ended September 30, 2016 and 2015 , respectively, and $4.9 million and zero for the nine months ended September 30, 2016 and 2015 .

8 . INTANGIBLE ASSETS

Intangible assets are comprised of franchise rights and trade names amounting to $33.8 million at both September 30, 2016 and December 31, 2015 . At both September 30, 2016 and December 31, 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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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 condensed consolidated balance sheets and any related net gain or loss is recorded as a gain or loss in the condensed 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 September 30, 2016 and December 31, 2015 , the Company had open commodity derivative instruments as follows:

	September 30, 2016			December 31, 2015
Crude oil and refined products (thousands of barrels):
Futures - long	—			90
Futures - short	869			933
Swaps - long	4,438			5,155
Swaps - short	750			525
Forwards - long	3,747			4,445
Forwards - short	2,863			2,572
Natural gas (thousands of MMBTUs):
Swaps	1,598			1,554

The information below presents the notional volume of outstanding contracts by type of instrument and year of maturity at September 30, 2016 :

	Notional Contract Volumes by Year of Maturity
	2016			2017
Crude oil and refined products (thousands of barrels):
Futures - short	869			—
Swaps - long	2,159			2,279
Swaps - short	750			—
Forwards - long	3,747			—
Forwards - short	2,863			—
Natural gas (thousands of MMBTUs):
Swaps	321			1,277

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Fair Value of Derivative Instruments

The following tables provide information about the fair values of the Company's derivative instruments as of September 30, 2016 and December 31, 2015 and the line items in the condensed 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 $7.5 million and $6.0 million as of September 30, 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.

			September 30, 2016
(in millions)	Balance Sheet Location		Assets				Liabilities
Commodity instruments:
Swaps	Other current assets		$	4.0			$	2.2
Swaps	Accrued liabilities		0.5				0.9
Swaps	Other assets		1.3				0.8
Futures	Accrued liabilities		—				2.8
Forwards	Other current assets		2.4				—
Forwards	Accrued liabilities		—				2.9
Total			$	8.2			$	9.6
			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 Hedging 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.

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Recognized gains and losses on derivatives were as follows:

	Three Months Ended								Nine Months Ended
(in millions)	September 30, 2016				September 30, 2015				September 30, 2016				September 30, 2015
Gain (loss) on the change in fair value of outstanding derivatives	$	(3.8	)		$	(1.3	)		$	6.1			$	0.3
Settled derivative gains (losses)	(0.8		)		3.9				(13.6		)		1.1
Total recognized gain (loss)	$	(4.6	)		$	2.6			$	(7.5	)		$	1.4
Gain (loss) recognized in cost of sales	$	(4.4	)		$	3.4			$	(8.2	)		$	3.3
Gain (loss) recognized in operating expenses	(0.2		)		(0.8		)		0.7				(1.9		)
Total recognized net gain (loss) on derivatives	$	(4.6	)		$	2.6			$	(7.5	)		$	1.4

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 BBB+ by Standard and Poor’s and A3 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 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 ratio 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.

As of September 30, 2016 , the borrowing base under the ABL Facility was $305.3 million and availability under the ABL Facility was $205.7 million . This availability is net of $52.0 million in direct borrowings and $47.6 million in outstanding letters of credit. The borrowers under the ABL Facility had $52.0 million in borrowings under the ABL Facility at September 30, 2016 , located in Long-term debt on the condensed consolidated balance sheet.

2020 Secured Notes

As of September 30, 2016 and December 31, 2015 , the Company had $350.0 million of outstanding aggregate principal of our 7.125% senior secured notes due 2020 (the “2020 Secured Notes”). A portion of these notes were issued with an offering premium of $4.2 million , which is being amortized to Interest expense, net over the remaining term of the notes. Additionally, professional service costs were incurred in both the issuance of the 2020 Secured Notes and the establishment of the ABL Facility which are presented within Long-term debt in the condensed consolidated balance sheets. The carrying value of these costs at September 30, 2016 and December 31, 2015 , was $9.5 million and $11.6 million , respectively.

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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.

11 . EQUITY

Western indirectly owns 100% of Northern Tier Energy GP LLC and 100.0% 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 19 ).

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 generated in such quarter, if any. 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

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expected to be based on the amount of available cash generated in such quarter. Available cash for each quarter was generally equal to 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).

Subsequent to the merger with Western, Northern Tier changed its distribution policy to distribute cash to entities controlled directly or indirectly by Western on a discretionary basis with respect to timing and amount, subject to the restricted payments tests in the 2020 Secured Notes and ABL Facility, maintaining cash reserves sufficient to cover expected working capital needs, turnaround and capital spending needs, debt service, hedging net losses, and certain other contractual obligations deemed necessary or appropriate by the board of directors of our general partner.

The following table details the quarterly distributions paid to common unitholders for each of the quarters in the year ended December 31, 2015 and the nine months ended September 30, 2016 :

Date Declared		Date Paid		Common Units and equivalents at record date (in millions)		Distribution per common unit and equivalent				Total Distribution (in millions)
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 during 2016						$	0.56			$	52.7

Changes in Partners' Equity

(in millions)	Partners' Capital				Accumulated Other Comprehensive Income				Total Partners' Equity
Balance at December 31, 2015	$	392.9			$	0.2			$	393.1
Net income	88.9				—				88.9
Asset sale to entity under common control	146.1				—				146.1
Distributions	(52.7		)		—				(52.7		)
Equity-based compensation expense	10.4				—				10.4
Other	(0.3		)		—				(0.3		)
Amortization of net prior service cost and deferred loss on defined benefit plans	—				(0.2		)		(0.2		)
Balance at September 30, 2016	$	585.3			$	—			$	585.3

From the beginning of the year to immediately prior to our merger with Western on June 23, 2016 , the Company's common units issued and outstanding increased by 114,047 , which was primarily attributable to the conversion of phantom units into common units upon vesting (see Note 14 ). Upon our merger with Western, 100% of our limited common units were indirectly owned by Western.

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

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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 September 30, 2016 and December 31, 2015 :

	Balance at				Quoted prices in active markets				Significant other observable inputs				Unobservable inputs
(in millions)	September 30, 2016				(Level 1)				(Level 2)				(Level 3)
ASSETS
Cash and cash equivalents	$	14.6			$	14.6			$	—			$	—
Restricted cash	195.0				195.0				—				—
Other current assets
Derivative asset - current	4.1				—				4.1				—
Other assets
Derivative asset - long-term	0.6				—				0.6				—
	$	214.3			$	209.6			$	4.7			$	—
LIABILITIES
Accrued liabilities
Derivative liability - current	$	6.1			$	—			$	6.1			$	—
	$	6.1			$	—			$	6.1			$	—

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	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 both September 30, 2016 and December 31, 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 nine months ended September 30, 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 nine months ended September 30, 2016 and 2015 , there were no impairments of such assets.

The carrying value of debt, which is reported on the Company’s condensed 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). 

	September 30, 2016								December 31, 2015
(in millions)	Carrying Amount				Fair Value				Carrying Amount				Fair Value
2020 Secured Notes	$	350.0			$	360.5			$	350.0			$	360.5
Outstanding borrowings on ABL Facility	52.0				52.0				—				—
Total	$	402.0			$	412.5			$	350.0			$	360.5

13 . ASSET RETIREMENT OBLIGATIONS

The following table summarizes the changes in asset retirement obligations:  

	Nine Months Ended
(in millions)	September 30, 2016				September 30, 2015
Asset retirement obligation balance at beginning of period	$	2.4			$	2.4
Costs incurred to remediate	(0.2		)		(0.3		)
Accretion expense	0.2				0.2
Asset retirement obligation balance at end of period	$	2.4			$	2.3

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.

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The Company recognized equity-based compensation expense of $3.0 million and $2.4 million for the three months ended September 30, 2016 , and 2015 , respectively and $11.0 million and $7.9 million for the nine months ended September 30, 2016 , and 2015 , respectively, related to these plans. This expense is included in selling, general and administrative expenses in the condensed consolidated statements of operations and comprehensive income.

AMENDED LTIP

Approximately 0.2 million Western common share equivalents are reserved for issuance under the Amended LTIP as of September 30, 2016 . The Amended LTIP permits the award 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 September 30, 2016 , approximately 0.8 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 estimated a forfeiture rate which was subject to revision depending on the actual forfeiture experience.

As of September 30, 2016 , the total unrecognized compensation cost for stock and cash awards under the Amended LTIP was $11.4 million .

Restricted Common Units

Legacy NTI Service-based Restricted Common Unit Awards

As of September 30, 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
	restricted common units			Average Grant				Average Term
	(in thousands)			Date Value				Until Maturity
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 September 30, 2016	—			$	—			—

Phantom Common Units

Legacy NTI Service-based Phantom Common Unit Awards

As of September 30, 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.

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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, 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 September 30, 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 September 30, 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 September 30, 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 September 30, 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 1.3 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 September 30, 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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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 $1.8 million and $1.6 million for the three months ended September 30, 2016 and 2015 , respectively, and $6.0 million and $5.6 million for the nine months ended September 30, 2016 and 2015 , respectively.

Cash Balance Plan

The Company sponsors a defined benefit cash balance pension plan (the “Cash Balance Plan”) for eligible employees. Company 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 net periodic benefit cost related to the Cash Balance Plan for both the three months ended September 30, 2016 and 2015 , was $0.6 million and for the nine months ended September 30, 2016 and 2015 , was $1.8 million and $1.9 million , respectively, related primarily to current period service costs.

16 . SUPPLEMENTAL CASH FLOW INFORMATION

Supplemental cash flow information is as follows:  

	Nine Months Ended
(in millions)	September 30, 2016				September 30, 2015
Net cash from operating activities included:
Interest paid	$	15.2			$	15.6
Income taxes paid	0.1				2.7
Noncash investing activities included:
Capital expenditures included in accounts payable	$	15.6			$	9.6
PP&E derecognized from sale leaseback continuing involvement release	2.8				1.8
Book value of tank and terminal related assets sold to WNRL	48.9				—
Common equity investment in WNRL	14.0				—
PP&E additions resulting from a capital lease	0.3				—
Noncash financing activities included:
Distributions accrued on unvested equity awards	$	—			$	2.6
Increase in equity due to proceeds received exceeding book value of assets sold to WNRL	146.1				—

We reported the cash proceeds from the sale of the SPPR Logistics Assets to WNRL as restricted cash in our Condensed Consolidated Balance Sheet at September 30, 2016 . This cash is restricted until the earlier of a) use of the cash to invest in capital projects to replace the collateral assets that we sold, b) acceptance by holders of our 2020 Secured Notes of an offer to repurchase such notes at par or c) expiration of an offer to repurchase for cash up to $195.0 million aggregate principal amount the 2020 Secured Notes. The Company commenced a tender offer to repurchase the 2020 Secured Notes on October 17, 2016, and such offer expires on November 15, 2016. Any cash remaining after the offer to repurchase expires will become unrestricted and available for general corporate purposes.

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17 . 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. The plaintiff purports to bring the action also on behalf of others similarly situated and seeks statutory penalties, injunctive relief, and other remedies. The Company is vigorously defending itself.

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 September 30, 2016 and December 31, 2015 , accruals for remediation and closure obligations totaled $7.6 million and $8.6 million , respectively. Of the $7.6 million and $8.6 million accrued, $2.4 million and $2.6 million are recorded on a discounted basis at September 30, 2016 and December 31, 2015 , respectively. These discounted liabilities are expected to be settled over at least the next 21 years. At September 30, 2016 , the estimated future cash flows to settle these discounted liabilities totaled $2.9 million , and are discounted at a rate of 2.03% . Receivables for recoverable costs from the state, under programs to assist companies in clean-up efforts related to underground storage tanks at retail marketing outlets, and others were $0.1 million and $0.2 million at September 30, 2016 and December 31, 2015 , respectively. 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 September 30, 2016 and December 31, 2015 , the Company estimates the remaining remediation costs to be approximately $5.2 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.

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.

18 . 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.

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Operating results for the Company’s operating segments are as follows:

	Three Months Ended September 30, 2016
(in millions)	Refining				Retail				Other				Total
Revenues
Customer	$	452.7			$	279.6			$	—			$	732.3
Intersegment	154.1				—				—				154.1
Segment revenues	606.8				279.6				—				886.4
Elimination of intersegment revenues	—				—				(154.1		)		(154.1		)
Total revenues	$	606.8			$	279.6			$	(154.1	)		$	732.3
Income (loss) from operations	$	14.4			$	4.4			$	(7.2	)		$	11.6
Income from equity method investment	$	5.3			$	—			$	—			$	5.3
Depreciation and amortization	$	9.7			$	2.2			$	0.2			$	12.1
Capital expenditures	$	42.8			$	1.6			$	0.1			$	44.5

	Three Months Ended September 30, 2015
(in millions)	Refining				Retail				Other				Total
Revenues
Customer	$	584.0			$	307.6			$	—			$	891.6
Intersegment	178.3				—				—				178.3
Segment revenues	762.3				307.6				—				1,069.9
Elimination of intersegment revenues	—				—				(178.3		)		(178.3		)
Total revenues	$	762.3			$	307.6			$	(178.3	)		$	891.6
Income (loss) from operations	$	111.1			$	8.6			$	(5.1	)		$	114.6
Income from equity method investment	$	4.2			$	—			$	—			$	4.2
Depreciation and amortization	$	8.8			$	2.0			$	0.2			$	11.0
Capital expenditures	$	16.4			$	1.1			$	—			$	17.5

	Nine Months Ended September 30, 2016
(in millions)	Refining				Retail				Other				Total
Revenues
Customer	$	1,373.3			$	775.7			$	—			$	2,149.0
Intersegment	419.0				—				—				419.0
Segment revenues	1,792.3				775.7				—				2,568.0
Elimination of intersegment revenues	—				—				(419.0		)		(419.0		)
Total revenues	$	1,792.3			$	775.7			$	(419.0	)		$	2,149.0
Income (loss) from operations	$	124.6			$	9.2			$	(22.7	)		$	111.1
Income from equity method investment	$	15.3			$	—			$	—			$	15.3
Depreciation and amortization	$	27.9			$	6.5			$	0.6			$	35.0
Capital expenditures	$	95.7			$	3.2			$	0.3			$	99.2

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	Nine Months Ended September 30, 2015
(in millions)	Refining				Retail				Other				Total
Revenues
Customer	$	1,789.7			$	855.5			$	—			$	2,645.2
Intersegment	502.0				—				—				502.0
Segment revenues	2,291.7				855.5				—				3,147.2
Elimination of intersegment revenues	—				—				(502.0		)		(502.0		)
Total revenues	$	2,291.7			$	855.5			$	(502.0	)		$	2,645.2
Income (loss) from operations	$	374.7			$	16.9			$	(18.2	)		$	373.4
Income from equity method investment	$	12.0			$	—			$	—			$	12.0
Depreciation and amortization	$	26.3			$	5.7			$	0.6			$	32.6
Capital expenditures	$	30.7			$	4.2			$	0.3			$	35.2

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				Other				Total
At September 30, 2016	$	1,266.8			$	132.0			$	23.5			$	1,422.3
At December 31, 2015	$	917.4			$	138.7			$	81.2			$	1,137.3

Total assets for the refining and retail segments exclude all intercompany balances. All cash and cash equivalents are included in Other. All property, plant and equipment are located in the United States.

19 . 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.

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•	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, 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 $1.5 million  and $2.6 million of expense during the three and nine months ended September 30, 2016 , 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 September 30, 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 expense activity for the three and nine months ended September 30, 2016 :

		Three Months Ended								Nine Months Ended
(in millions)		September 30, 2016				September 30, 2015				September 30, 2016				September 30, 2015
Beginning liability for merger and reorganization costs		$	0.4			$	0.5			$	0.2			$	0.8
Third-party professional service fees		0.2				—				1.3				—
Reorganization and related personnel costs incurred during period		1.3				—				1.3				—
Cash payments to third-party professional service providers		(0.4		)		—				(1.1		)		—
Cash payments made to severed employees		(0.4		)		(0.1		)		(0.6		)		(0.4		)
Ending liability for merger and reorganization costs		$	1.1			$	0.4			$	1.1			$	0.4

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