Western Refining, Inc. - FORM 10-Q

Attached files

file	filename
EX-32.2 - EXHIBIT 32.2 - Western Refining, Inc.	exhibit322-wnrx63015.htm
EX-31.1 - EXHIBIT 31.1 - Western Refining, Inc.	exhibit311-wnrx63015.htm
EX-31.2 - EXHIBIT 31.2 - Western Refining, Inc.	exhibit312-wnrx63015.htm
EX-32.1 - EXHIBIT 32.1 - Western Refining, Inc.	exhibit321-wnrx63015.htm

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q



þ		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
		For the quarterly period ended June 30, 2015



o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
		For the transition period from _____ to _____

Commission File Number: 001-32721

WESTERN REFINING, INC.

(Exact name of registrant as specified in its charter)



Delaware		20-3472415
(State or other jurisdiction of		(I.R.S. Employer
incorporation or organization)		Identification No.)

123 W. Mills Ave., Suite 200		79901
El Paso, Texas		(Zip Code)
(Address of principal executive offices)

Registrant’s telephone number, including area code: (915) 534-1400

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.



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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ

As of July 31, 2015, there were 95,583,528 shares outstanding, par value $0.01, of the registrant’s common stock.

WESTERN REFINING, INC. AND SUBSIDIARIES

INDEX



Part I. Financial Information	1

Item 1. Financial Statements (Unaudited)	1

Condensed Consolidated Balance Sheets as of June 30, 2015 and December 31, 2014	1

Condensed Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2015 and 2014	2

Condensed Consolidated Statements of Comprehensive Income for the Three and Six Months Ended June 30, 2015 and 2014	3

Condensed Consolidated Statements of Cash Flows for the Three and Six Months Ended June 30, 2015 and 2014	4

Notes to Condensed Consolidated Financial Statements	5

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	42

Item 3. Quantitative and Qualitative Disclosure About Market Risk	75

Item 4. Controls and Procedures	76

Part II. Other Information	76

Item 1A. Risk Factors	76

Item 2. Unregistered Sale of Equity Securities	76

Item 3. Defaults Upon Senior Securities	76

Item 4. Mine Safety Disclosures	76

Item 5. Other Information	77

Item 6. Exhibits	77

Signatures	78

EX-31.1
EX-31.2
EX-32.1
EX-32.2
EX-101

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Forward-Looking Statements

As provided by the safe harbor provisions of the Private Securities Litigation Reform Act of 1995, certain statements included throughout this Quarterly Report on Form 10-Q and in particular under the section entitled Part I — Item 2, Management’s Discussion and Analysis of Financial Condition and Results of Operations relating to matters that are not historical fact should be deemed forward-looking statements that represent management’s beliefs and assumptions based upon currently available information. These forward-looking statements relate to matters such as our industry, including the regulation of our industry, business strategy, future operations, our expectations for margins and crack spreads, the discount between West Texas Intermediate ("WTI") crude oil and Dated Brent crude oil as well as the discount between WTI Cushing and WTI Midland crude oils, volatility of crude oil prices, additions to pipeline capacity in the Permian Basin and at Cushing, Oklahoma, expected share repurchases and dividends, volatility in pricing of Renewable Identification Numbers ("RINs"), taxes, capital expenditures, liquidity and capital resources and other financial and operating information. Forward-looking statements also include those regarding the timing of completion of certain operational and maintenance improvements we are making at our refineries, future operational and refinery efficiencies and cost savings, timing of future maintenance turnarounds, the amount or sufficiency of future cash flows and earnings growth, future expenditures, future contributions related to pension and postretirement obligations, our ability to manage our inventory price exposure through commodity hedging instruments, the impact upon our business of existing and future state and federal regulatory requirements, environmental loss contingency accruals, projected remediation costs or requirements and the expected outcomes of legal proceedings in which we are involved. We have used the words “anticipate,” “assume,” “believe,” “budget,” “continue,” “could,” “estimate,” “expect,” “forecast,” “intend,” “may,” “plan,” “position,” “potential,” “predict,” “project,” “strategy,” “will,” “future” and similar terms and phrases to identify forward-looking statements in this report.

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

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


•	changes in crack spreads;


•	changes in the spread between WTI crude oil and West Texas Sour crude oil, also known as the sweet/sour spread;


•	changes in the spread between WTI crude oil and Dated Brent crude oil;


•	changes in the spread between WTI Cushing crude oil and WTI Midland crude oil;


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


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


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


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


•	changes in the underlying demand for our refined products;


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


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


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


•	changes in the availability and cost of capital;


•	actions of customers and competitors;


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

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•	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 our Annual Report on Form 10-K for the year ended December 31, 2014 ("2014 10‑K") that are incorporated herein by this reference.

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

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

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Part I

Financial Information


Item 1.	Financial Statements

WESTERN REFINING, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In thousands, except share and per share data)



	June 30, 2015			December 31, 2014
ASSETS
Current assets:
Cash and cash equivalents	$	543,936		$	431,159
Accounts receivable, trade, net of a reserve for doubtful accounts of $574 and $484, respectively	590,162			467,527
Inventories	687,074			629,237
Prepaid expenses	110,445			88,415
Other current assets	152,565			152,125
Total current assets	2,084,182			1,768,463
Restricted cash	68,275			167,009
Equity method investment	97,976			96,080
Property, plant and equipment, net	2,209,784			2,153,189
Goodwill	1,289,443			1,289,443
Intangible assets, net	84,984			85,952
Other assets, net	118,905			122,422
Total assets	$	5,953,549		$	5,682,558
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	725,388		$	681,803
Accrued liabilities	247,735			268,449
Deferred income tax liability, net	42,338			57,949
Current portion of long-term debt	5,500			5,500
Total current liabilities	1,020,961			1,013,701
Long-term liabilities:
Long-term debt, less current portion	1,542,740			1,515,037
Lease financing obligations	49,397			27,489
Deferred income tax liability, net	304,934			296,860
Other liabilities	37,931			41,827
Total long-term liabilities	1,935,002			1,881,213
Commitments and contingencies
Equity:
Western shareholders' equity:
Common stock, par value $0.01, 240,000,000 shares authorized; 102,766,270 and 102,642,540 shares issued, respectively	1,028			1,026
Preferred stock, par value $0.01, 10,000,000 shares authorized; no shares issued or outstanding	—			—
Additional paid-in capital	490,742			487,748
Retained earnings	1,069,187			890,393
Accumulated other comprehensive loss, net of tax	(1,234		)	(1,291		)
Treasury stock, 7,182,742 and 6,441,883 shares, respectively at cost	(283,168		)	(258,168		)
Total Western shareholders' equity	1,276,555			1,119,708
Non-controlling interests	1,721,031			1,667,936
Total equity	2,997,586			2,787,644
Total liabilities and equity	$	5,953,549		$	5,682,558

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 OPERATIONS

(Unaudited)

(In thousands, except per share data)



	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2015			2014			2015			2014
Net sales	$	2,828,892		$	4,351,290		$	5,147,622		$	8,076,433
Operating costs and expenses:
Cost of products sold (exclusive of depreciation and amortization)	2,177,887			3,731,169			3,919,197			6,891,906
Direct operating expenses (exclusive of depreciation and amortization)	224,723			203,463			440,034			401,812
Selling, general and administrative expenses	59,540			54,640			115,343			113,372
Affiliate severance costs	—			3,479			—			12,878
Loss (gain) on disposal of assets, net	(387		)	119			(105		)	1,005
Maintenance turnaround expense	593			—			698			46,446
Depreciation and amortization	51,143			47,848			101,069			94,258
Total operating costs and expenses	2,513,499			4,040,718			4,576,236			7,561,677
Operating income	315,393			310,572			571,386			514,756
Other income (expense):
Interest income	201			221			364			416
Interest expense and other financing costs	(27,316		)	(27,801		)	(52,273		)	(56,758		)
Loss on extinguishment of debt	—			(1		)	—			(9		)
Other, net	4,024			983			7,230			2,465
Income before income taxes	292,302			283,974			526,707			460,870
Provision for income taxes	(78,435		)	(93,407		)	(137,872		)	(142,606		)
Net income	213,867			190,567			388,835			318,264
Less net income attributable to non-controlling interests	79,948			33,871			148,927			76,022
Net income attributable to Western Refining, Inc.	$	133,919		$	156,696		$	239,908		$	242,242

Net earnings per share:
Basic	$	1.40		$	1.88		$	2.51		$	2.97
Diluted	1.40			1.56			2.51			2.44
Weighted average common shares outstanding:
Basic	95,539			83,556			95,553			81,653
Diluted	95,626			102,657			95,654			102,655

Cash dividends declared per common share	$	0.34		$	0.26		$	0.64		$	0.52

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						Six Months Ended
	June 30,						June 30,
	2015			2014			2015			2014
Net income	$	213,867		$	190,567		$	388,835		$	318,264
Other comprehensive income items:
Benefit plans:
Amortization of net prior service cost	107			—			107			81
Reclassification of loss to income	12			5			25			10
Other comprehensive income before tax	119			5			132			91
Income tax	(4		)	(2		)	(9		)	(4		)
Other comprehensive income, net of tax	115			3			123			87
Comprehensive income	213,982			190,570			388,958			318,351
Less comprehensive income attributable to non-controlling interests	80,014			33,871			148,993			76,072
Comprehensive income attributable to Western Refining, Inc.	$	133,968		$	156,699		$	239,965		$	242,279

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)



	Six Months Ended
	June 30,
	2015			2014
Cash flows from operating activities:
Net income	$	388,835		$	318,264
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	101,069			94,258
Changes in fair value of commodity hedging instruments	42,344			(119,350		)
Reserve for doubtful accounts	90			294
Amortization of loan fees and original issue discount	3,151			11,285
Loss on extinguishment of debt	—			9
Stock-based compensation expense	8,541			13,142
Deferred income taxes	(7,537		)	56,145
Excess tax benefit from stock-based compensation	(848		)	(1,099		)
Income from equity method investment	(7,793		)	939
Loss (gain) on disposal of assets, net	(105		)	1,005
Changes in operating assets and liabilities:
Accounts receivable	(122,725		)	(117,536		)
Inventories	(57,837		)	10,916
Prepaid expenses	(22,030		)	(78,859		)
Other assets	(34,472		)	9,568
Accounts payable and accrued liabilities	4,999			80,557
Other long-term liabilities	(3,638		)	(1,151		)
Net cash provided by operating activities	292,044			278,387
Cash flows from investing activities:
Capital expenditures	(119,545		)	(90,619		)
Decrease in restricted cash	98,735			—
Return of capital from equity method investment	5,780			1,360
Proceeds from the sale of assets	897			810
Net cash used in investing activities	(14,133		)	(88,449		)
Cash flows from financing activities:
Additions to long-term debt	300,000			—
Payments on long-term debt and capital lease obligations	(3,761		)	(3,116		)
Payments on revolving credit facility	(269,000		)	—
Deferred financing costs	(6,820		)	—
Purchase of treasury stock	(25,000		)	(5,930		)
Distribution to non-controlling interest holders	(100,287		)	(75,964		)
Dividends paid	(61,114		)	(41,475		)
Convertible debt redemption	—			(809		)
Excess tax benefit from stock-based compensation	848			1,099
Net cash used in financing activities	(165,134		)	(126,195		)
Net increase in cash and cash equivalents	112,777			63,743
Cash and cash equivalents at beginning of period	431,159			468,070
Cash and cash equivalents at end of period	$	543,936		$	531,813

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 three refineries: one in El Paso, Texas, one near Gallup, New Mexico and one in St. Paul Park, Minnesota. We sell refined products primarily 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 526 company-owned and franchised retail sites in the U.S.

At June 30, 2015, we owned a 38.4% limited partner interest in Northern Tier Energy LP ("NTI"). We control NTI through our 100% ownership of its general partner. NTI owns and operates a refinery in St. Paul Park, Minnesota. NTI has a retail-marketing network of 264 convenience stores. NTI directly operates 165 of these stores and supports 99 stores through franchise agreements. NTI's primary areas of operation include Minnesota and Wisconsin.

At June 30, 2015, we owned a 66.1% limited partner interest in Western Refining Logistics, LP ("WNRL") and the public held a 33.9% limited partner interest. We control WNRL through our 100% ownership of the general partner of WNRL and our majority ownership of WNRL's limited partnership interests. WNRL owns and operates a wholesale business that operates primarily in the Southwest as well as logistics assets consisting of pipeline and gathering, terminalling, storage and transportation assets. WNRL operates its logistics assets primarily for the benefit of the Company.

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

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

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 the opinion of management, all adjustments (consisting of normal recurring accruals) considered necessary for a fair presentation have been included. Operating results for the three and six months ended June 30, 2015, are not necessarily indicative of the results that may be expected for the year ending December 31, 2015, or for any other period.

The Condensed Consolidated Balance Sheet at December 31, 2014, 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, 2014.

The condensed consolidated financial statements include the accounts of Western Refining, Inc. and subsidiaries in which we have a controlling interest. We own a 38.4% limited partner interest in NTI and a 66.1% limited partner interest in WNRL. We own 100% of NTI's and WNRL's respective general partners. As the general partner of NTI and WNRL, we have the ability to direct the activities of NTI and WNRL that most significantly impact their respective economic performance.

Principles of Consolidation

The accompanying condensed consolidated financial statements include the accounts of Western and subsidiaries in which we have a controlling interest. All intercompany accounts and transactions have been eliminated for all periods presented. Investments in significant non-controlled entities are accounted for using the equity method.

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WESTERN REFINING, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

We have reported non-controlling interests for NTI and WNRL of $1,721.0 million and $1,667.9 million in our Condensed Consolidated Balance Sheets as of June 30, 2015 and December 31, 2014, respectively.

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. We conducted our annual goodwill and intangible asset valuation analysis as of June 30, 2015, and we found no indications of impairment.

Use of Estimates and Seasonality

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

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

Recent Accounting Pronouncements

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

From time to time, new accounting pronouncements are issued by various standard setting bodies that may have an impact on our accounting and reporting. We are currently evaluating the effect that certain of these new accounting requirements may have on our accounting and related reporting and disclosures in our consolidated financial statements.

•

Recognition and reporting of revenues - the requirements were amended to remove inconsistencies in revenue requirements and to provide a more complete framework for addressing revenue issues across a broad range of industries and transaction types. The revised standard’s core principle is that a company should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. These provisions are effective January 1, 2018, and are to be applied retrospectively, with early adoption permitted for periods beginning after December 15, 2016, and interim periods thereafter.

•

Evaluation of going concern - management of an entity is required to evaluate whether there is substantial doubt about the entity’s ability to continue as a going concern and to provide related footnote disclosures. The new requirements will become effective for annual periods beginning after December 15, 2016, and interim periods thereafter with early application permitted. The changed requirements are intended to reduce diversity in the timing and content of footnote disclosures.


•	Consolidation considerations - reporting entities are required to evaluate whether certain legal entities should be consolidated effective for interim and annual periods beginning after December 15, 2015.


•	Presentation of debt issuance costs - debt issuance costs are presented as an offset to the related debt and will become effective for interim and annual periods beginning after December 15, 2015.


•	Accounting for internal use software licenses - entities will be required to evaluate their accounting for hosted software licenses and service contracts effective for interim and annual periods beginning after December 15, 2015.

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WESTERN REFINING, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

3. Segment Information

We changed our reportable segments during the fourth quarter of 2014 due to changes in our organization. We treated the assets that we sold to WNRL in the Wholesale Acquisition 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 WRW assets for periods prior to the effective date of the transaction. The primary effects of this reporting change were:


•	The wholesale segment moved into the WNRL segment, except for unmanned fleet fueling ("cardlock") operations and product sales activity in the Mid-Atlantic region;

•Mid-Atlantic region product sales activity moved into the refining segment; and

•Cardlock related activity moved into the retail segment.

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

Refining. We report the operations of two refineries in our refining segment: one in El Paso, Texas (the "El Paso refinery") with a 131,000 barrel per day ("bpd") capacity and one near Gallup, New Mexico (the "Gallup refinery") with a 25,000 bpd capacity. Our refineries make various grades of gasoline, diesel fuel and other products from crude oil, other feedstocks and blending components. We purchase crude oil, other feedstocks and blending components from various third-party suppliers. We also acquire refined products through exchange agreements and from various third-party suppliers to supplement supply to our customers. We sell these products to WNRL, other independent wholesalers and retailers, 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 $0.3 million in liabilities and $0.1 million in assets at June 30, 2015 and December 31, 2014, respectively, related to this supply agreement in our Condensed Consolidated Balance Sheets. The revenues and costs recorded under the supply agreement included $5.5 million and $9.5 million in net hedging losses for the three months ended June 30, 2015 and 2014, respectively, and $16.0 million in net hedging gains and $9.4 million in net hedging losses for the six months ended June 30, 2015 and 2014, respectively.

NTI. NTI is an independent crude oil refiner and marketer of refined products with a 98,000 bpd refinery in St. Paul Park, Minnesota and a network of retail convenience stores selling various grades of gasoline, diesel fuel and convenience store merchandise, primarily in Minnesota and Wisconsin. NTI's operations are separate from those of Western. At June 30, 2015, NTI included the operations of 165 retail convenience stores and supported 99 franchised retail convenience stores. NTI's refinery supplies the majority of the gasoline and diesel fuel sold through its retail convenience stores.

WNRL. WNRL owns and operates certain logistics assets that consist of pipeline and gathering, terminalling, storage and transportation assets, providing related services primarily to our refining segment in the Southwest, including approximately 300 miles of pipelines and 8.1 million barrels of active storage capacity. WNRL also owns a wholesale business that operates primarily in the Southwest. The majority of WNRL's logistics assets are integral to the operations of the El Paso and Gallup refineries. WNRL's wholesale business includes the operations of several lubricant and bulk petroleum distribution plants and a fleet of crude oil, refined product and lubricant delivery trucks. WNRL distributes commercial wholesale petroleum products primarily in Arizona, California, Colorado, Nevada, New Mexico and Texas. WNRL purchases petroleum fuels and lubricants from our refining segment and from third-party suppliers.

Retail. Our retail segment located in the Southwest sells various grades of gasoline, diesel fuel, convenience store merchandise and beverage and food products to the general public through retail convenience stores and various grades of gasoline and diesel fuel to commercial vehicle fleets through cardlocks. WNRL supplies the majority of gasoline and diesel fuel that our retail segment sells. We purchase general merchandise and beverage and food products from various third-party suppliers. At June 30, 2015, the retail segment operated 262 service stations and convenience stores or kiosks located in Arizona, Colorado, New Mexico and Texas compared to 229 service stations and convenience stores or kiosks at June 30, 2014. The additional stores were added under various operating and capital leases. At June 30, 2015, the retail segment included 52 cardlocks located in Arizona, California and New Mexico compared to 52 cardlocks at June 30, 2014.

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 and NTI segments also include 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

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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.

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

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

Disclosures regarding our reportable segments with reconciliations to consolidated totals for the three and six months ended June 30, 2015 and 2014, are presented below:



	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2015		2014 (3)		2015		2014 (3)
	(In thousands)
Operating Results:
Refining
Net sales	$	1,819,032	$	2,742,701	$	3,310,473	$	5,068,515
Intersegment eliminations (1)	665,814		947,693		1,208,356		1,763,398
Net refining sales to external customers	1,153,218		1,795,008		2,102,117		3,305,117
NTI
Net sales	852,820		1,499,321		1,550,596		2,756,699
Intersegment eliminations (1)	16,056		10,098		29,046		11,082
Net NTI sales to external customers	836,764		1,489,223		1,521,550		2,745,617
WNRL
Net sales	734,501		970,337		1,341,897		1,834,947
Intersegment eliminations (1)	210,638		273,721		388,887		510,305
Net WNRL sales to external customers	523,863		696,616		953,010		1,324,642
Retail
Net sales	318,072		375,232		576,674		710,516
Intersegment eliminations (1)	3,025		5,138		5,729		10,051
Net retail sales to external customers	315,047		370,094		570,945		700,465
Other
Net sales	—		349		—		592
Intersegment eliminations (1)	—		—		—		—
Net other sales to external customers	—		349		—		592

Consolidated net sales to external customers	$	2,828,892	$	4,351,290	$	5,147,622	$	8,076,433

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	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2015			2014 (3)			2015			2014 (3)
Operating income (loss)
Refining (2)	$	184,013		$	248,254		$	330,737		$	387,261
NTI (2)	125,135			58,606			233,122			125,936
WNRL	22,293			17,474			41,766			34,235
Retail	4,657			3,375			4,216			2,545
Other	(20,705		)	(17,137		)	(38,455		)	(35,221		)
Operating income from segments (2)	315,393			310,572			571,386			514,756
Other income (expense), net	(23,091		)	(26,598		)	(44,679		)	(53,886		)
Income before income taxes	$	292,302		$	283,974		$	526,707		$	460,870

Depreciation and amortization
Refining	$	21,884		$	20,397		$	43,522		$	39,865
NTI	19,515			19,362			38,880			38,347
WNRL	4,737			4,454			9,475			8,606
Retail	4,031			2,817			7,317			5,752
Other	976			818			1,875			1,688
Consolidated depreciation and amortization	$	51,143		$	47,848		$	101,069		$	94,258

Capital expenditures
Refining	$	41,980		$	21,924		$	77,888		$	55,544
NTI	11,155			11,209			17,828			18,390
WNRL	7,850			3,708			15,764			12,087
Retail	4,717			2,329			6,119			3,670
Other	648			851			1,946			928
Consolidated capital expenditures	$	66,350		$	40,021		$	119,545		$	90,619

Total assets
Refining							$	1,853,598		$	1,863,784
NTI (including $1,289,443 and $1,297,043 of goodwill, respectively)							2,402,056			2,965,655
WNRL							382,028			394,224
Retail							251,977			210,127
Other							1,063,890			362,978
Consolidated total assets (including $1,289,443 and $1,297,043 of goodwill, respectively)							$	5,953,549		$	5,796,768

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(1)	Intersegment sales of $895.5 million, $1,632.0 million, $1,236.7 million and $2,294.8 million have been eliminated in consolidation for the three and six months ended June 30, 2015 and 2014, respectively.

(2)

The effect of our economic hedging activity is included within operating income of our refining and NTI segments as a component of cost of products sold. The cost of products sold within our refining segment includes $12.1 million and $15.8 million in net realized and unrealized economic hedging losses for the three and six months ended June 30, 2015, respectively, and $49.1 million and $139.7 million in net realized and unrealized economic hedging gains for the three and six months ended June 30, 2014, respectively. NTI cost of products sold includes $2.4 million, $1.1 million, $1.9 million and $2.8 million in net realized and unrealized economic hedging losses for the three and six months ended June 30, 2015 and 2014, respectively.

(3)

WNRL's financial data includes the Predecessor's historical financial results and an allocated portion of corporate general and administrative expenses, previously reported as Other, for the three and six months ended June 30, 2014. Refining operating results include activity of our Mid-Atlantic business that was previously recorded within our wholesale segment. Net sales to external customers and intersegment sales for our retail segment include the operating results of cardlock stations that were formerly recorded in our wholesale segment. Other operating results include activity of the wholesale fleet service department that was previously recorded within our wholesale segment.

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 in which 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 June 30, 2015 and December 31, 2014, due to their short-term maturities. Our fair value assessment incorporates a variety of considerations, including the short-term duration of the instruments and an evaluation of counterparty credit risk. Cash equivalents totaling $70.0 million consisting of short-term money market deposits and commercial paper, were included in the Condensed Consolidated Balance Sheets as of June 30, 2015 and December 31, 2014.

We maintain cash deposits with various counterparties in support of our hedging and trading activities. These deposits are required by counterparties as collateral and cannot be offset against the fair value of open contracts except in the event of default. Certain of our commodity derivative contracts under master netting arrangements include both asset and liability positions. We have elected to offset the fair value amounts recognized for multiple similar derivative instruments executed with the same counterparty under the column "Netting Adjustments" below; however, fair value amounts by hierarchy level are presented on a gross basis in the tables below. See Note 13, Crude Oil and Refined Product Risk Management, for further discussion of master netting arrangements.

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The following tables represent our assets and liabilities for Western's commodity hedging contracts measured at fair value on a recurring basis as of June 30, 2015 and December 31, 2014, and the basis for that measurement:



	Carrying Value at June 30, 2015			Fair Value Measurement Using							Netting Adjustments			Net Fair Value at June 30, 2015
	Carrying Value at June 30, 2015			Level 1		Level 2			Level 3		Netting Adjustments			Net Fair Value at June 30, 2015
	(In thousands)
Gross financial assets:
Other current assets	$	78,285		$	—	$	77,364		$	921	$	(15,027	)	$	63,258
Other assets	28,656			—		27,963			693		(625		)	28,031
Gross financial liabilities:
Accrued liabilities	(17,202		)	—		(17,202		)	—		14,582			(2,620		)
Other long-term liabilities	(2,117		)	—		(2,117		)	—		1,070			(1,047		)
	$	87,622		$	—	$	86,008		$	1,614	$	—		$	87,622



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

Commodity hedging contracts designated as Level 3 financial assets consist 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 (all related to commodity price swap contracts) for the three and six months ended June 30, 2015 and 2014.



	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2015			2014			2015			2014
	(In thousands)
Asset (liability) balance at beginning of period	$	1,710		$	3,232		$	330		$	(1,935	)
Change in fair value	43			2,226			(1		)	5,987
Fair value of trades entered into during the period	—			(238		)	1,450			(238		)
Fair value reclassification from Level 3 to Level 2	(139		)	(1,475		)	(165		)	(69		)
Asset balance at end of period	$	1,614		$	3,745		$	1,614		$	3,745

A hypothetical change of 10% to the estimated future cash flows attributable to our Level 3 commodity price swaps would result in a $0.2 million change in the estimated fair value.

As of June 30, 2015 and December 31, 2014, the carrying amount and estimated fair value of our debt was as follows:



	June 30, 2015		December 31, 2014
	(In thousands)
Western obligations:
Carrying amount	$	891,750	$	894,500
Fair value	895,532		878,360
NTI obligations:
Carrying amount	$	356,490	$	357,037
Fair value	365,750		351,313
WNRL obligations:
Carrying amount	$	300,000	$	269,000
Fair value	312,000		269,000

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).

5. Inventories

Inventories were as follows:



	June 30, 2015		December 31, 2014
	(In thousands)
Refined products (1)	$	283,827	$	257,476
Crude oil and other raw materials	344,429		318,565
Lubricants	16,035		14,265
Retail store merchandise	42,783		38,931
Inventories	$	687,074	$	629,237


(1)	Includes $17.7 million and $18.2 million of inventory valued using the first-in, first-out ("FIFO") valuation method at June 30, 2015 and December 31, 2014, respectively.

We value our refinery inventories of crude oil, other raw materials and asphalt inventories at the lower of cost or market under the LIFO valuation method. Other than refined products inventories held by WNRL and our retail segment, refined

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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. Retail refined product inventory is valued using the FIFO inventory valuation method. Retail merchandise inventory is valued using the retail inventory method.

As of June 30, 2015 and December 31, 2014, refined products valued under the LIFO method and crude oil and other raw materials totaled 9.4 million barrels and 9.3 million barrels, respectively. At June 30, 2015 and December 31, 2014, the excess of the LIFO cost over the current cost of these crude oil, refined product and other feedstock and blendstock inventories was $52.4 million and $28.4 million, respectively.

During the three months ended June 30, 2015 and 2014, cost of products sold included net non-cash charges of $89.6 million and $7.5 million, respectively, from changes in our LIFO reserves. During the six months ended June 30, 2015 and 2014, cost of products sold included net non‑cash credits of $24.0 million and $26.2 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 $24.6 million and $78.6 million at June 30, 2015 and December 31, 2014, respectively.

Average LIFO cost per barrel of our refined products and crude oil and other raw materials inventories as of June 30, 2015 and December 31, 2014, was as follows:



	June 30, 2015					December 31, 2014
	Barrels	LIFO Cost		Average LIFO Cost Per Barrel		Barrels	LIFO Cost		Average LIFO Cost Per Barrel
	(In thousands, except cost per barrel)
Refined products	3,774	$	279,824	$	74.15	3,707	$	283,333	$	76.43
Crude oil and other	5,632	355,329		63.09		5,577	355,470		63.74
	9,406	$	635,153	67.53		9,284	$	638,803	68.81

6. Equity Method Investment

NTI owns a 17% common equity interest in Minnesota Pipe Line Company, LLC ("MPL"). The carrying value of this equity method investment was $98.0 million and $96.1 million at June 30, 2015 and December 31, 2014, respectively.

As of June 30, 2015 and December 31, 2014, the carrying amount of the equity method investment was $21.4 million and $21.6 million greater, respectively, than the underlying net assets of the investee. We are amortizing this difference over the remaining life of MPL’s primary asset (the fixed asset life of the pipeline).

NTI recognized distributions from MPL during the three and six months ended June 30, 2015, of $2.1 million and $5.8 million, respectively. Distributions from MPL during the three and six months ended June 30, 2014, were each $1.4 million. Equity income (loss) from MPL for the three and six months ended June 30, 2015 and 2014, was $4.2 million, $7.8 million, $(2.4) million and $(0.9) million, respectively. Equity income has been included in other, net in the accompanying Condensed Consolidated Statements of Operations.

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7. Property, Plant and Equipment, Net

Property, plant and equipment, net was as follows:



	June 30, 2015			December 31, 2014
	(In thousands)
Refinery facilities and related equipment	$	2,252,330		$	2,217,013
Pipelines, terminals and transportation equipment	451,044			369,080
Retail facilities and related equipment	318,516			288,338
Wholesale facilities and related equipment	59,235			57,158
Corporate	50,210			48,871
	3,131,335			2,980,460
Accumulated depreciation	(921,551		)	(827,271		)
Property, plant and equipment, net	$	2,209,784		$	2,153,189

Depreciation expense was $50.1 million and $99.0 million for the three and six months ended June 30, 2015, respectively, and $46.8 million and $92.2 million for the three and six months ended June 30, 2014, respectively.

8. Intangible Assets, Net

Intangible assets, net was as follows:



	June 30, 2015							December 31, 2014							Weighted Average Amortization Period (Years)
	Gross Carrying Value		Accumulated Amortization			Net Carrying Value		Gross Carrying Value		Accumulated Amortization			Net Carrying Value		Weighted Average Amortization Period (Years)
	(In thousands)
Amortizable assets:
Licenses and permits	$	20,427	$	(12,938	)	$	7,489	$	20,427	$	(12,148	)	$	8,279	4.8
Customer relationships	7,551		(3,643		)	3,908		7,551		(3,366		)	4,185		7.0
Rights-of-way and other	7,946		(3,934		)	4,012		7,878		(3,613		)	4,265		7.6
	35,924		(20,515		)	15,409		35,856		(19,127		)	16,729
Unamortizable assets:
Franchise rights and trademarks	50,500		—			50,500		50,500		—			50,500
Liquor licenses	19,075		—			19,075		18,723		—			18,723
Intangible assets, net	$	105,499	$	(20,515	)	$	84,984	$	105,079	$	(19,127	)	$	85,952

Intangible asset amortization expense for the three and six months ended June 30, 2015, was $0.7 million and $1.4 million, respectively, based on estimated useful lives ranging from 1 to 23 years. Intangible asset amortization expense for the three and six months ended June 30, 2014, was $0.7 million and $1.4 million, respectively, based on estimated useful lives ranging from 1 to 23 years.

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



Remainder of 2015	$	1,360
2016	2,620
2017	2,679
2018	2,678
2019	2,011
2020	1,066

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9. Long-Term Debt

Long-term debt was as follows:



	June 30, 2015			December 31, 2014
	(In thousands)
Western obligations:
Revolving Credit Facility due 2019	$	—		$	—
Term Loan Credit Facility due 2020	541,750			544,500
6.25% Senior Unsecured Notes due 2021	350,000			350,000
Total Western obligations	891,750			894,500
NTI obligations:
Revolving Credit Facility due 2018	—			—
7.125% Senior Secured Notes due 2020, net of unamortized premium of $6,490 and $7,037, respectively	356,490			357,037
Total NTI obligations	356,490			357,037
WNRL obligations:
Revolving Credit Facility due 2018	—			269,000
7.5% Senior Notes due 2023	300,000			—
Total WNRL obligations	300,000			269,000
Long-term debt	1,548,240			1,520,537
Current portion of long-term debt	(5,500		)	(5,500		)
Long-term debt, net of current portion	$	1,542,740		$	1,515,037

As of June 30, 2015, annual maturities of long-term debt for the remainder of 2015 are $2.8 million. From 2016 through 2019, long-term debt maturities are $5.5 million. Thereafter, total long-term debt maturities are $1,517.0 million.

Interest expense and other financing costs were as follows:



	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2015			2014			2015			2014
	(In thousands)
Contractual interest:
Western obligations	$	12,093		$	14,778		$	24,100		$	30,044
NTI obligations	6,612			5,372			13,203			10,708
WNRL obligations	5,901			227			9,627			452
	24,606			20,377			46,930			41,204
Amortization of loan fees	1,912			2,079			3,698			4,176
Amortization of original issuance discount	—			3,308			—			7,352
Other interest expense	1,151			2,148			2,226			4,353
Capitalized interest	(353		)	(111		)	(581		)	(327		)
Interest expense and other financing costs	$	27,316		$	27,801		$	52,273		$	56,758

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.

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Western Obligations

Revolving Credit Facility

On October 2, 2014, we entered into the Third Amended and Restated Revolving Credit Agreement ("Western 2019 Revolving Credit Facility"). Lenders committed $900.0 million, all of which will mature on October 2, 2019. The commitments under the Western 2019 Revolving Credit Facility may be increased in the future to $1.4 billion, subject to certain conditions (including the agreement of financial institutions, in their sole discretion, to provide such additional commitments). The amended terms of the agreement include revised borrowing rates. Borrowings can be either base rate loans plus a margin ranging from 0.50% to 1.00% or LIBOR loans plus a margin ranging from 1.50% to 2.00%, subject to adjustment based upon the average excess availability. The Western 2019 Revolving Credit Facility also provides for a quarterly commitment fee ranging from 0.25% 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 six month period ended June 30, 2015, we had no direct borrowings under the Western 2019 Revolving Credit Facility, with availability of $419.5 million. This availability is net of $71.6 million in outstanding letters of credit.

Term Loan Credit Agreement

On November 12, 2013, we entered into a term loan credit agreement (the "Western 2020 Term Loan Credit Facility"). The Western 2020 Term Loan Credit Facility provides for loans of $550.0 million, matures on November 12, 2020, and provides for quarterly principal payments of $1.4 million until September 30, 2020, with the remaining balance then outstanding due on the maturity date. The Western 2020 Term Loan Credit Facility bears interest at a rate based either on the base rate (as defined in the Western 2020 Term Loan Credit Facility) plus 2.25% or the Eurodollar Rate (as defined in the Western 2020 Term Loan Credit Facility) plus 3.25% (with a Eurodollar Rate floor of 1.00%). The Western 2020 Term Loan Credit Facility is secured by both the El Paso and Gallup refineries and is fully and unconditionally guaranteed on a joint and several basis by substantially all of Western's material subsidiaries. The Western 2020 Term Loan Credit Facility contains customary restrictive covenants including limitations of debt, investments and dividends and does not contain any financial maintenance covenants.

6.25% Senior Unsecured Notes

On March 25, 2013, we entered into an indenture (the "Western 2021 Indenture") for the issuance of $350.0 million in aggregate principal amount of 6.25% Senior Unsecured Notes due 2021 (the "Western 2021 Senior Unsecured Notes"). The Western 2021 Senior Unsecured Notes are guaranteed on a senior unsecured basis by each of our wholly-owned domestic restricted subsidiaries. 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.

5.75% Convertible Senior Unsecured Notes

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

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

Our payment of dividends is limited under the terms of the Western 2019 Revolving Credit Facility, the Western 2021 Senior Unsecured Notes and the Western 2020 Term Loan Credit Facility, and in part, depends on our ability to satisfy certain financial covenants. Note guarantors will be released if they cease to be a Restricted Subsidiary as the result of a transaction permitted under the terms of the indenture, including through the disposition of capital stock of the guarantor.

NTI Obligations

Revolving Credit Facility

On September 29, 2014, NTI amended its senior secured Revolving Credit Facility (the "NTI Revolving Credit Facility"), increasing the aggregate principal amount available prior to the amendment 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. Obligations under the NTI Revolving Credit Facility are secured by substantially all of NTI’s assets. Indebtedness under the NTI Revolving Credit Facility is recourse to Northern Tier Energy GP LLC, its general partner, and is guaranteed by NTI and certain of its subsidiaries. Borrowings under the NTI Revolving Credit Facility bear interest at either (a) an alternative 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 based upon the average excess availability. In addition to paying interest on outstanding borrowings, NTI is also required to pay quarterly commitment fees ranging from 0.250% to 0.375% and letter of credit fees ranging from 1.50% to 2.00%. The NTI Revolving Credit Facility contains certain covenants, including but not limited to, limitations on debt, investments and dividends and the maintenance of a minimum fixed charge coverage ratio in certain circumstances. NTI incurred financing costs of $3.0 million associated with the amended NTI Revolving Credit Facility.

As of June 30, 2015, the availability under the NTI Revolving Credit Facility was $253.5 million. This availability is net of $30.6 million in outstanding letters of credit. There were no borrowings under the NTI Revolving Credit Facility during the six month period ended June 30, 2015.

7.125% Secured Notes

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

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

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

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WNRL Obligations

Revolving Credit Facility

On October 16, 2013, WNRL entered into a $300.0 million senior secured revolving credit facility ("WNRL Revolving Credit Facility"). WNRL has the ability to increase the total commitment of the WNRL Revolving Credit Facility by up to $200.0 million for a total facility size of up to $500.0 million, subject to 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 obligations are guaranteed by all of WNRL's 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. WNRL creditors under the WNRL Revolving Credit Facility have no recourse to Western's assets, except to the extent of the assets of Western Refining Logistics GP, LLC, the general partner of WNRL that Western wholly owns. 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.

During the six months ended June 30, 2015, WNRL repaid its outstanding direct borrowings under the WNRL Revolving Credit Facility with a portion of the proceeds from the issuance of its 7.5% Senior Notes, discussed below, resulting in no direct or swing line borrowings under the WNRL Revolving Credit Facility as of June 30, 2015. As of June 30, 2015, the availability under the WNRL Revolving Credit Facility was $299.3 million. This availability is net of $0.7 million in outstanding letters of credit.

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.

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 WNRL (“Finance Corp.” and together with WNRL, the “Issuers”), the guarantors named therein and U.S. Bank National Association, as trustee under which the Issuers issued $300.0 million in aggregate principal amount of 7.5% Senior Notes due 2023 (the "WNRL 2023 Senior Notes"). WNRL will pay interest on the WNRL 2023 Senior Notes semi-annually in cash in arrears on February 15 and August 15 of each year, beginning on August 15, 2015. The WNRL 2023 Senior Notes will mature on February 15, 2023. WNRL used the proceeds from the notes to repay the full balance due under the WNRL Revolving Credit Facility on February 11, 2015.

The WNRL Indenture contains covenants that limit WNRL’s and its restricted subsidiaries’ ability to, among other things: (i) incur, assume or guarantee additional indebtedness or issue preferred units, (ii) create liens to secure indebtedness, (iii) pay distributions on equity securities, repurchase equity securities or redeem subordinated indebtedness, (iv) make investments, (v) effect distributions, loans or other asset transfers from WNRL’s restricted subsidiaries, (vi) consolidate with or merge with or into, or sell substantially all of WNRL’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 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 WNRL 2023 Senior Notes to be due and payable immediately.

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10. Equity

Changes to equity during the six months ended June 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	239,908			148,927			388,835
Other comprehensive income, net of tax	57			66			123
Dividends	(61,114		)	—			(61,114		)
Stock-based compensation	2,148			5,851			7,999
Excess tax benefit from stock-based compensation	848			—			848
Distributions to non-controlling interests	—			(101,528		)	(101,528		)
Treasury stock purchases	(25,000		)	—			(25,000		)
Other	—			(221		)	(221		)
Balance at June 30, 2015	$	1,276,555		$	1,721,031		$	2,997,586

Changes to equity during the six months ended June 30, 2014, were as follows:



	Western Shareholders' Equity			Non-controlling Interest			Total Equity
	(In thousands)
Balance at December 31, 2013	$	894,052		$	1,676,535		$	2,570,587
Net income	242,242			76,022			318,264
Convertible debt redemption	(809		)	—			(809		)
Convertible debt settlement - treasury stock issuance in additional paid-in capital	(142,640		)	—			(142,640		)
Other comprehensive income, net of tax	37			50			87
Dividends	(41,475		)	—			(41,475		)
Stock-based compensation	2,228			10,914			13,142
Excess tax benefit from stock-based compensation	1,099			—			1,099
Distributions to non-controlling interests	—			(75,964		)	(75,964		)
Offering costs	—			66			66
Treasury stock purchases	(18,325		)	—			(18,325		)
Treasury stock issuance	357,608			—			357,608
Balance at June 30, 2014	$	1,294,017		$	1,687,623		$	2,981,640

Share Repurchase Programs

Our board of directors approved our current share repurchase program in November 2014 (the "November 2014 Program") authorizing us to repurchase up to $200 million of our outstanding common stock. Subject to market conditions as well as corporate, regulatory and other considerations, we will repurchase shares from time-to-time through open market transactions, block trades, privately negotiated transactions or otherwise. The November 2014 Program will expire in November 2015 and is 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 November 2014 Program:



	Number of shares purchased	Cost of share purchases (In thousands)
Shares purchased at December 31, 2014	1,492,874	$	59,222
Shares purchased during Q1, 2015	740,859	25,000
Shares purchased at March 31, 2015	2,233,733	84,222
Shares purchased during Q2, 2015	—	—
Shares purchased at June 30, 2015	2,233,733	$	84,222

As of June 30, 2015, we had $115.8 million remaining in authorized expenditures under the November 2014 Program.

Dividends

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

Declaration Date

Record Date

Payment Date

Dividend per Common Share

Total Payment (In thousands)

First quarter

February 6

February 20

March 6

0.30

28,638

Second quarter

April 21

May 5

May 20

0.34

32,476

Third quarter (1)

July 17

July 27

August 12

0.34

—

Total

61,114

(1) The third quarter 2015 cash dividend of $0.34 per common share will result in an aggregate payment of approximately $32.5 million.

Total dividends declared were $0.34, $0.64, $0.26 and $0.52 per common share, including those declared related to participating securities, for the three and six months ended June 30, 2015 and 2014, respectively.

NTI Distributions

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



Declaration Date	Record Date	Payment Date	Distribution per Unit
February 5, 2015	February 21, 2015	February 27, 2015	$	0.49
May 5, 2015	May 18, 2015	May 29, 2015	1.08
August 4, 2015	August 17, 2015	August 28, 2015	1.19
Total			$	2.76

WNRL Distributions

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



Declaration Date	Record Date	Payment Date	Distribution per Common and Subordinated Unit
January 30, 2015	February 13, 2015	February 23, 2015	$	0.3325
May 1, 2015	May 15, 2015	May 26, 2015	0.3475
July 31, 2015	August 14, 2015	August 24, 2015	0.3650
Total			$	1.0450

In addition to its quarterly distributions, WNRL paid incentive distributions of $0.14 million and $0.16 million for the three and six months ended June 30, 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 six months ended June 30, 2015 and 2014, were 26.8%, 26.2%, 32.9% and 30.9%, respectively. The effective tax rates for the three and six months ended June 30, 2015 and 2014, were lower than the statutory rate primarily due to the reduction of taxable income associated with the non-controlling interests in NTI and WNRL.

We are subject to examination by the Internal Revenue Service for tax years ending December 31, 2012, or after and by various state and local taxing jurisdictions for tax years ending December 31, 2011, 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 provided against the deferred tax assets relating to these NOL carryforwards at June 30, 2015. There was no change in the valuation allowance for the Yorktown NOL carryforwards from December 31, 2014.

As of June 30, 2015, we have recorded a liability of $13.8 million for unrecognized tax benefits, of which $13.8 million would affect our effective tax rate if recognized. We recognized a net change of $0.1 million and $0.2 million for unrecognized benefits that includes $0.1 million and $0.2 million in interest and penalties for the three and six months ended June 30, 2015, respectively.

12. Retirement Plans

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

Pensions

The net periodic benefit cost associated with NTI's cash balance plan for the three and six months ended June 30, 2015 and 2014, was $0.7 million, $1.3 million, $0.5 million and $1.1 million, respectively.

Postretirement Obligations

The net periodic benefit cost associated with our postretirement medical benefit plans for both the three and six months ended June 30, 2015 and 2014, was $0.2 million, $0.5 million, $0.2 million and $0.4 million, respectively.

Our benefit obligation at December 31, 2014, for our postretirement medical benefit plans was $9.8 million. We fund our medical benefit plans on an as-needed basis.

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



	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2015			2014			2015			2014
	(In thousands)
Beginning of period balance	$	(1,283	)	$	(316	)	$	(1,291	)	$	(350	)
Amortization of net prior service cost	41			—			41			31
Reclassification of loss to income	12			5			25			10
Income tax	(4		)	(2		)	(9		)	(4		)
End of period balance	$	(1,234	)	$	(313	)	$	(1,234	)	$	(313	)

Defined Contribution Plan

Western sponsors a 401(k) defined contribution plan under which Western and WNRL participants may contribute a percentage of their eligible compensation to various investment choices offered by the plan. For the three and six months ended June 30, 2015 and 2014, we expensed $2.6 million, $4.6 million, $2.3 million and $3.9 million, respectively, in connection with this plan.

NTI sponsors qualified defined contribution plans for eligible employees. For the three and six months ended June 30, 2015 and 2014, NTI expensed $1.8 million, $4.0 million, $1.7 million and $4.1 million, respectively, in connection with its qualified defined contribution plans.

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13. Crude Oil and Refined Product Risk Management

We enter into crude oil forward contracts to facilitate the supply of crude oil to our refineries. During the six months ended June 30, 2015, 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 also use crude oil and refined products futures, swap contracts or options to mitigate the change in value for a portion of our LIFO inventory volumes subject to market price fluctuations and swap contracts to fix the margin on a portion of our future gasoline and distillate production. The physical volumes are not exchanged; these contracts are net settled with cash. These hedging activities do not qualify for hedge accounting treatment.

The fair value of these contracts is reflected in the 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 six months ended June 30, 2015 and 2014, and open commodity hedging positions as of June 30, 2015 and December 31, 2014:



	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2015			2014		2015			2014
	(In thousands)
Economic hedging results
Realized hedging gain, net	$	7,823		$	1,812	$	25,376		$	17,556
Unrealized hedging gain (loss), net	(22,287		)	45,379		(42,344		)	119,350
Total hedging gain (loss), net	$	(14,464	)	$	47,191	$	(16,968	)	$	136,906



	June 30, 2015			December 31, 2014
	(In thousands)
Open commodity hedging instruments (barrels)
Crude oil and refined product futures, net long (short) positions	2,907			(864		)
Refined product crack spread swaps, net short positions	(10,827		)	(8,781		)
Total open barrels commodity hedging instruments, net short positions	(7,920		)	(9,645		)

Fair value of outstanding contracts, net
Other current assets	$	63,258		$	79,722
Other assets	28,031			56,533
Accrued liabilities	(2,620		)	(4,889		)
Other long-term liabilities	(1,047		)	(1,400		)
Fair value of outstanding contracts - unrealized gain, net	$	87,622		$	129,966

Offsetting Assets and Liabilities

Western's derivative financial instruments are subject to master netting arrangements to manage counterparty credit risk associated with derivatives; however, Western does not offset the fair value amounts recorded for derivative instruments under these agreements in the 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.

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The following table presents offsetting information regarding Western's commodity hedging contracts as of June 30, 2015 and December 31, 2014:



	Gross Amounts of Recognized Assets (Liabilities)			Gross Amounts Offset in the Consolidated Balance Sheet			Net Amounts of Assets (Liabilities) Presented in the Consolidated Balance Sheet
As of June 30, 2015	Gross Amounts of Recognized Assets (Liabilities)			Gross Amounts Offset in the Consolidated Balance Sheet
	(In thousands)
Gross financial assets:
Current assets	$	78,285		$	(15,027	)	$	63,258
Other assets	28,656			(625		)	28,031
Gross financial liabilities:
Accrued liabilities	(17,202		)	14,582			(2,620		)
Other long-term liabilities	(2,117		)	1,070			(1,047		)
	$	87,622		$	—		$	87,622



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

Our commodity hedging activities are initiated within guidelines established by management and approved by our board of directors. Due to mark-to-market accounting during the term of the various commodity hedging contracts, significant unrealized, non-cash net gains and losses could be recorded in our results of operations. Additionally, we may be required to collateralize any mark-to-market losses on outstanding commodity hedging contracts.

As of June 30, 2015, we had outstanding crude oil and refined product hedging instruments that were entered into as economic hedges. Settlement prices for our unleaded gasoline crack spread swaps range from $22.06 to $22.06 per contract. Settlement prices for our distillate crack spread swaps range from $17.14 to $20.53 per contract. The information below presents the notional volume of outstanding contracts by type of instrument and year of maturity (volumes in thousands of barrels):



	Notional Contract Volumes by Year of Maturity
	2015		2016		2017
Inventory positions (futures and swaps):
Crude oil and refined products — net short positions	(802	)	—		—
Natural gas futures — net long positions	1,501		2,207		—
Refined product positions (crack spread swaps):
Distillate — net short positions	(3,672	)	(3,930	)	(825	)
Unleaded gasoline — net short positions	(2,400	)	—		—

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14. Stock-Based Compensation

The Western Refining 2006 Long-Term Incentive Plan (the "2006 LTIP") and the 2010 Incentive Plan of Western Refining (the "2010 Incentive Plan") allow for restricted share unit awards ("RSUs") among other forms of awards. As of June 30, 2015, there were 19,856 and 2,730,269 shares of common stock reserved for future grants under the 2006 LTIP and the 2010 Incentive Plan, respectively. Awards granted under both plans vest over a scheduled vesting period of either one, three or five years and their market value at the date of the grant is amortized over the vesting period on a straight-line basis. Effective March 25, 2015, our board of directors approved administrative amendments to the 2010 Incentive Plan.

As of June 30, 2015, there were 406,649 unvested RSUs outstanding. The final vesting for remaining awards of restricted shares occurred during the first quarter of 2014. We recorded stock compensation of $1.1 million, $2.1 million, $1.0 million and $2.2 million for the three and six months ended June 30, 2015 and 2014, respectively, which is included in selling, general and administrative expenses.

As of June 30, 2015, the aggregate grant date fair value of outstanding RSUs was $15.2 million. The aggregate intrinsic value of outstanding RSUs was $17.7 million. The unrecognized compensation cost of unvested RSUs was $12.8 million. Unrecognized compensation costs for RSUs will be recognized over a weighted average period of 3.79 years.

The excess tax benefit related to the RSUs that vested during the three and six months ended June 30, 2015, was $0.5 million and $0.8 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 six months ended June 30, 2015, was $1.6 million and $3.6 million, respectively. The related aggregate intrinsic value of these RSUs was $3.0 million and $5.8 million, respectively, at the vesting date.

The excess tax benefit related to the RSUs and restricted shares that vested during the three and six months ended June 30, 2014, was $1.3 million and $1.1 million, respectively, using a statutory blended rate of 38.3%. The aggregate grant date fair value of the RSUs and restricted shares that vested during the three and six months ended June 30, 2014, was $1.4 million and $4.0 million, respectively. The related aggregate intrinsic value of these RSUs and restricted shares was $4.7 million and $6.8 million, respectively, at the vesting date.

The following table summarizes our restricted share unit activity for the six months ended June 30, 2015:



	Number of Units		Weighted Average Grant Date Fair Value
Not vested at December 31, 2014	380,695		$	30.14
Awards granted	155,828		48.26
Awards vested	(123,730	)	28.84
Awards forfeited	(6,144	)	36.76
Not vested at June 30, 2015	406,649		37.39

NTI 2012 Long-Term Incentive Plan

NTI has approximately 7.5 million common units reserved for issuance under the NTI 2012 Long-Term Incentive Plan ("NTI LTIP"). The NTI LTIP permits the award of unit options, restricted units, phantom units, distribution equivalent rights, unit appreciation rights and other awards that derive their value from the market price of NTI's common units. As of June 30, 2015, approximately 1.1 million units were outstanding under the NTI LTIP. NTI recognizes the expense on all NTI LTIP awards ratably from the grant date until all units become unrestricted or vest. Awards generally vest ratably over a three-year period beginning on the award's first anniversary date. Compensation expense related to these restricted units is based on the grant date fair value as determined by the closing market price on the grant date, reduced by the fair value of estimated forfeitures. For awards to employees, NTI estimates a forfeiture rate which is subject to revision depending on the actual forfeiture experience.

As of June 30, 2015, the total unrecognized compensation cost for units awarded under the NTI LTIP was $18.2 million.

NTI incurred $2.9 million, $5.5 million, $2.9 million and $10.3 million of unit-based compensation expense for the three and six months ended June 30, 2015 and 2014, respectively.

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(Unaudited)

Restricted Common Units

As of June 30, 2015, NTI had 0.3 million restricted common units outstanding. Upon vesting, these common units will no longer be restricted. All restricted common units participate in distributions on an equal basis with NTI common units and must be paid no later than 30 days after the distribution date to common unitholders. For restricted common unit awards outstanding at June 30, 2015, the forfeiture rates on NTI LTIP awards ranged from zero to 30%, depending on the employee classification and the length of the award's vesting period. NTI has one restricted common unit award with a clause stating distributions are to be accrued until the underlying units vest, at which time the accrued distributions applicable to those units will be paid to the award holder. The accrued distributions on that award at June 30, 2015 and December 31, 2014, were $0.8 million and $0.4 million, respectively.

Phantom Common Units

Service-based Awards

During 2014, NTI began awarding service-based phantom common units to key employees. As of June 30, 2015, NTI had 0.6 million service-based phantom common units outstanding. Upon vesting, NTI may settle these units in NTI common units or cash at the discretion of NTI's board of directors or its Compensation Committee. Like the restricted common units, the phantom common units participate in distributions on an equal basis with common units. However, distributions on phantom common units are accrued until the underlying units vest at which time the distributions are paid in cash. In the event that unvested phantom common units are canceled, any accrued distributions on the underlying units are forfeited by the grantee. As of June 30, 2015 and December 31, 2014, NTI had $1.2 million and $0.8 million, respectively, in accrued service-based phantom common unit distributions included in accrued liabilities in the Condensed Consolidated Balance Sheets. For phantom common unit awards outstanding at June 30, 2015, the forfeiture rates on NTI LTIP awards ranged from zero to 20%, depending on the employee classification.

Performance-based Phantom Units

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

Performance Condition Awards. The 0.3 million NTI Performance LTIPs include 0.2 million performance condition awards. The fair value of performance condition awards is estimated using the market price of NTI's common units on the grant date and NTI management's assessment of the probability of the number of performance condition awards that will ultimately be awarded. The estimated fair value of these performance condition awards is amortized over a three-year vesting period using the straight-line method. On a quarterly basis, NTI estimates the ultimate payout percentage, relative to target, and adjusts compensation expense accordingly. At June 30, 2015, NTI estimates that 200% of the target unit count will be achieved at the end of the vesting term.

Market Condition Awards. The 0.3 million NTI Performance LTIPs include less than 0.1 million market condition awards. The estimated fair value for market condition awards is estimated using a Monte Carlo simulation model as of the grant date and the related expense is amortized over a three-year vesting period using the straight-line method. The compensation expense relating to the market condition awards is determined at the award's date and expensed ratably at a fixed rate over the vesting term. However, for purposes of the phantom common unit activity table below, NTI estimates at June 30, 2015, that 75% of the target unit count will be achieved at the end of the vesting term.

Expected volatilities are based on the historical volatility over the most recent three-year period. The risk-free rate is based on the U.S. Treasury yield curve in effect at the date of valuation. The assumptions used in the Monte Carlo simulation used to value NTI's market condition awards as of June 30, 2015, are presented below:



Expected volatility	34.10	%
Risk-free interest rate	0.84	%

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As of June 30, 2015, NTI had $0.4 million in accrued performance-based phantom common unit distributions included in accrued liabilities in the Condensed Consolidated Balance Sheet.

A summary of the NTI LTIP common unit activity for the six months ended June 30, 2015, is set forth below:



	Restricted Units				Phantom Units
	Restricted Units				Service-Based Units		Performance-Based Units	Total		Weighted Average Grant Date Fair Value
	Number of Units		Weighted Average Grant Date Fair Value		Number of Units		Number of Units	Total		Weighted Average Grant Date Fair Value
Not vested at December 31, 2014	396,109		$	24.73	337,693		—	337,693		$	26.99
Awards granted	1,026		24.90		419,085		181,049	600,134		23.27
Incremental performance units	—		—		—		67,895	67,895		23.44
Awards vested	(66,329	)	25.82		(80,611	)	—	(80,611	)	27.01
Awards forfeited	—		—		(111,170	)	—	(111,170	)	26.56
Not vested at June 30, 2015	330,806		24.51		564,997		248,944	813,941		24.04

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 June 30, 2015, there were 4.2 million phantom units reserved for future grants under the WNRL LTIP.

The fair value of the phantom units is determined based on the closing price of WNRL common units on the grant date. The estimated fair value of the phantom units is amortized on a straight-line basis over the scheduled vesting periods of individual awards. WNRL incurred unit-based compensation expense of $0.5 million, $0.9 million, $0.4 million and $0.6 million for the three and six months ended June 30, 2015 and 2014, respectively.

The aggregate grant date fair value of non-vested phantom units outstanding as of June 30, 2015, was $7.8 million. The aggregate intrinsic value of such phantom units was $8.0 million. Total unrecognized compensation cost related to unvested phantom units totaled $6.9 million as of June 30, 2015, that is expected to be recognized over a weighted average period of 3.94 years.

A summary of WNRL's common and phantom unit award activity for the six months ended June 30, 2015, is set forth below:



	Number of Phantom Units		Weighted Average Grant Date Fair Value
Not vested at December 31, 2014	280,251		$	28.30
Awards granted	56,485		29.48
Awards vested	(51,951	)	27.97
Awards forfeited	(11,913	)	30.78
Not vested at June 30, 2015	272,872		28.50

15. Earnings per Share

In periods subsequent to March 31, 2014, we applied the treasury stock method for determining the number of fully dilutive shares outstanding used in our computation of fully diluted earnings per share. In periods prior to April 1, 2014, we followed the provisions related to the two-class method for the purpose of determining earnings per share. As discussed in Note 14, Stock-Based Compensation, we previously granted shares of restricted stock to certain employees and outside directors. Although ownership of these shares did not transfer to the recipients until the shares vested, recipients had voting and nonforfeitable dividend rights on these shares from the date of grant. Accordingly, we utilized the two-class method to determine our earnings per share. The final vesting for restricted stock awards occurred during the first quarter of 2014.

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

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



	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2015			2014			2015			2014
	(In thousands, except per share data)
Basic earnings per common share:
Allocation of earnings:
Net income attributable to Western Refining, Inc.	$	133,919		$	156,696		$	239,908		$	242,242
Distributed earnings	(32,476		)	(20,745		)	(61,114		)	(41,475		)
Income allocated to participating securities	—			—			—			(4		)
Distributed earnings allocated to participating securities	—			—			—			1
Undistributed income available to Western Refining, Inc.	$	101,443		$	135,951		$	178,794		$	200,764
Weighted average number of common shares outstanding (1)	95,539			83,556			95,553			81,653
Basic earnings per common share:
Distributed earnings per share	$	0.34		$	0.25		$	0.64		$	0.51
Undistributed earnings per share	1.06			1.63			1.87			2.46
Basic earnings per common share	$	1.40		$	1.88		$	2.51		$	2.97

Diluted earnings per common share:
Net income attributable to Western Refining, Inc.	$	133,919		$	156,696		$	239,908		$	242,242
Tax effected interest related to convertible debt	—			3,606			—			8,010
Net income available to Western Refining, Inc., assuming dilution	$	133,919		$	160,302		$	239,908		$	250,252
Weighted average diluted common shares outstanding	95,626			102,657			95,654			102,655
Diluted earnings per common share	$	1.40		$	1.56		$	2.51		$	2.44

(1) Excludes the weighted average number of common shares outstanding associated with participating securities of 1,783 shares for the six months ended June 30, 2014.

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



	Three Months Ended		Six Months Ended
	June 30,		June 30,
	2015	2014	2015	2014
	(In thousands)
Weighted average number of common shares outstanding	95,539	83,556	95,553	81,653
Common equivalent shares from Western Convertible Notes	—	19,001	—	20,870
Restricted shares and share units	87	100	101	132
Weighted average number of diluted shares outstanding	95,626	102,657	95,654	102,655

A shareholder's interest in our common stock could become diluted as a result of vestings of RSUs and, prior to the settlement of the Western Convertible Notes during the second quarter of 2014 (see Note 9, Long-Term Debt for further discussion), conversion of the Western Convertible Notes through issuance of shares of our common stock. In calculating our fully diluted earnings per common share, we consider the impact of RSUs that have not vested and common equivalent shares related to the Western Convertible Notes. We include unvested RSUs in our diluted earnings calculation when the trading price

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of our common stock equals or exceeds the per share or per share unit grant price. Common equivalent shares from the Western Convertible Notes are generally included in our diluted earnings calculation when net income exceeds certain thresholds above which the effect of the shares becomes dilutive. The Western Convertible Notes were converted into actual shares of our common stock during the first six months of 2014.

16. Cash Flows

Restricted Cash

Restricted cash reported in our Condensed Consolidated Balance Sheets at June 30, 2015 and December 31, 2014, relates to net proceeds from the sale of Western wholesale assets to WNRL. This cash is restricted through October 14, 2015, and must be used to either fund capital projects or to repay amounts outstanding under the Western 2020 Term Loan Credit Facility.

Supplemental Cash Flow Information

Supplemental disclosures of cash flow information were as follows:



	Six Months Ended
	June 30,
	2015		2014
	(In thousands)
Income taxes paid	$	146,480	$	65,846
Interest paid, excluding amounts capitalized	40,792		45,733

Non-cash investing and financing activities were as follows:
Assets acquired through capital lease obligations	24,578		—
Accrued capital expenditures	26,381		1,368
PP&E derecognized from sale leaseback continuing involvement release	1,773		—
Transfer of capital spares from fixed asset to inventory	1,365		—
Distributions accrued on unvested NTI equity awards	1,241		—
Issuance of common shares for redemption of Western Convertible Notes	—		357,608
Treasury stock purchased, not yet settled	—		12,395

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 2036. We expect that in the normal course of business, these leases will be renewed or replaced by other leases. Certain of our lease agreements provide for the fair value purchase of the leased asset at the end of the lease. Rent expense for operating leases that provide for periodic rent escalations or rent holidays over the term of the lease and for renewal periods that are reasonably assured at the inception of the lease 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 E.I. du Pont de Nemours ("DuPont"), DuPont constructed and operates two sulfuric acid regeneration plants on property we lease to DuPont within our El Paso refinery. 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, Arizona area.

We are party to thirty-one capital leases, with initial terms of 20 years, expiring in 2017 through 2035. The current portion of our capital lease obligations of $1.0 million and $0.6 million is included in accrued liabilities and the non-current portion of

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$49.4 million and $27.5 million is included in lease financing obligations in the accompanying Condensed Consolidated Balance Sheets as of June 30, 2015 and December 31, 2014, respectively. The capital lease obligations include a deferred gain of $2.4 million. These capital leases were discounted using annual interest rates between 3.24% and 10.51%. Total remaining interest related to these leases was $41.7 million and $21.6 million at June 30, 2015 and December 31, 2014, respectively. Annual payments, including interest, average $4.6 million through the end of 2019 with the remaining $69.0 million due through 2035. Of the thirty-one capital leases, twelve are NTI obligations with annual lease payments, including interest, that average $0.8 million annually through the end of 2019 with the remaining $8.2 million due through 2034. There is no recourse to Western on the NTI capital leases. The remaining nineteen capital leases are held by our retail segment and make up the balance of the annual payments for the periods noted above.

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 June 30, 2015:



	Operating		Capital
Remaining 2015	$	28,966	$	2,299
2016	50,209		4,652
2017	46,954		4,563
2018	43,724		4,584
2019	40,057		4,691
2020 and thereafter	328,329		68,956
Total minimum lease payments	$	538,239	89,745
Less amount that represents interest			41,732
Present value of net minimum capital lease payments			$	48,013

Total rental expense was $15.7 million, $31.6 million, $13.9 million and $27.5 million for the three and six months ended June 30, 2015 and June 30, 2014, respectively. Contingent rentals and subleases were not significant in any period.

18. 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 June 30, 2015 and December 31, 2014, we had consolidated environmental accruals of $20.4 million and $18.5 million, respectively.

El Paso Refinery

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

In May 2000, we entered into an Agreed Order with the TCEQ for remediation of the south side of our El Paso refinery property. We purchased a non-cancelable Pollution and Legal Liability and Clean-Up Cost Cap Insurance policy that covers

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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 $7.0 million remained as of June 30, 2015. In addition, a subsidiary of Chevron is obligated under a settlement agreement to pay 60% of any Agreed Order environmental clean-up costs that exceed the $20.0 million policy coverage.

In September 2011, we and the U.S. Environmental Protection Agency (the “EPA”) entered into a Consent Decree under the Petroleum Refinery Enforcement Initiative (“EPA Initiative”). Under the EPA Initiative, the EPA is investigating industry-wide non-compliance with certain Clean Air Act rules. The EPA Initiative has resulted in many refiners entering into similar consent decrees typically requiring penalties and substantial capital expenditures for additional air pollution control equipment. The Consent Decree does not require any soil or groundwater remediation or clean-up.

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

In April 2014, we entered two Agreed Orders with TCEQ to settle unresolved air enforcement at our El Paso refinery between 2004 and April 2008. We paid $0.2 million in penalties in May 2014 that included funding a Supplemental Environmental Project benefiting El Paso County.

Four Corners Refineries

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

We incurred $50.8 million in total capital expenditures between 2009 and 2013 to address the requirements of the 2005 NMED Amended Agreement. These capital expenditures were primarily for installation of emission controls on the heaters, boilers and Fluid Catalytic Cracking Unit ("FCCU") and for reducing sulfur in fuel gas to reduce emissions of sulfur dioxide, NOx and particulate matter from our Gallup refinery. We will incur additional capital expenditures to implement one or more FCCU offset projects to be completed by the end of 2017. In 2014, we incurred $1.9 million to implement FCCU emissions offset projects. We paid penalties between 2009 and 2012 totaling $2.7 million.

Bloomfield 2007 NMED Remediation Order. In July 2007, we received a final administrative compliance order from the NMED alleging that releases of contaminants and hazardous substances that have occurred at the Bloomfield refinery over the course of its operation prior to June 1, 2007, have resulted in soil and groundwater contamination. Among other things, the order requires that we investigate the extent of such releases, perform interim remediation measures and implement corrective measures. Prior to July 2007, with the approval of the NMED and the New Mexico Oil Conservation Division, we placed into operation certain remediation measures that remain operational. As of June 30, 2015, we have expended $4.3 million and have accrued the remaining estimated costs of $3.7 million for implementing the investigation, interim measures and the reasonably known corrective actions of the order.

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

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

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

NTI

At June 30, 2015 and December 31, 2014, liabilities for remediation and closure obligations by NTI totaled $10.2 million and $8.7 million, respectively. These liabilities consist of $2.6 million and $2.9 million recorded on a discounted basis as of June 30, 2015 and December 31, 2014, respectively. These discounted liabilities are expected to be settled over at least the next 22 years. At June 30, 2015, the estimated future cash flows to settle these discounted liabilities totaled $3.3 million and are discounted at a rate of 2.90%. Receivables for recoverable costs from the state, under programs to assist companies in clean-up efforts related to underground storage tanks at retail marketing outlets, and others were $0.2 million at June 30, 2015 and December 31, 2014, respectively.

On June 3, 2014, the St. Paul Park refinery was issued a National Pollutant Discharge Elimination Permit/State Disposal System Permit by the Minnesota Pollution Control Agency ("MPCA") relating to its upgraded wastewater treatment plant at its St. Paul Park refinery. This permit required the refinery to conduct additional testing of its remaining lagoon. The testing was completed in the fourth quarter of 2014, following NTI's review of the test results and additional discussions with MPCA, NTI now regards the likelihood of future remediation and closure costs related to the lagoon as probable. At June 30, 2015, NTI estimated the remaining remediation costs to be approximately $7.6 million subject to further engineering and methodology studies. Some of this cost may be recoverable from Marathon Petroleum under an agreement entered into in connection with NTI's December 2010 acquisition of the St. Paul Park refinery, among other assets, from Marathon. However, at June 30, 2015, it is unclear how much, if any, of NTI's future costs may be eligible for reimbursement by Marathon, and as such, NTI has not recognized any receivable pertaining to this matter at this time.

Other Matters

The EPA has issued Renewable Fuels Standards ("RFS"), that require us and other refiners to blend renewable fuels into the refined products produced at our refineries. Annually, the EPA is required to establish a volume of renewable fuels that refineries must blend into their refined petroleum fuels. However, the EPA has not established the final renewable blending volume level for 2014 or 2015. To the extent we are unable to blend at the rate necessary to satisfy the EPA mandated volume, we purchase Renewable Identification Numbers ("RINs"). The purchase price for RINs is volatile and may vary significantly from period to period. Historically, the cost of purchased RINs has not had a significant impact on our operating results. We anticipate 2014 and 2015 will be consistent with this history. The net cost of meeting our estimated renewable volume obligations, including sales and purchases of RINs, was $6.5 million, $12.7 million, $1.3 million and $11.3 million for the three and six months ended June 30, 2015 and 2014, respectively.

In addition, the EPA has investigated and brought enforcement actions against companies it believes produced invalid RINs. We may have purchased RINs the EPA will determine are invalid. Previously, we have entered into settlements 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.

In August 2014, the TCEQ offered an expedited settlement with a proposed penalty of $0.2 million related to enforcement issued to our retail segment. We agreed to the settlement, which became effective in July 2015, and have paid the penalty of less than $0.1 million. The settlement is pending final approval by the TCEQ Commissioners. The settlement requires no capital expenditures or soil or groundwater remediation or clean-up.

In April 2015, we successfully re-negotiated the collective bargaining agreement covering the El Paso refinery employees. The resulting six year labor agreement is scheduled to expire in April of 2021.

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

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19. Related Party Transactions

We lease office space in a building located in El Paso, Texas, which is owned by an entity that is controlled by one of our officers. The lease agreement expires in May 2017. Under the terms of the lease, we make annual payments of $0.2 million. For the three and six months ended June 30, 2015 and 2014, we made rental payments under this lease to the related party of $0.06 million, $0.1 million, $0.06 million and $0.1 million, respectively. We have no amounts due as of June 30, 2015, related to this lease agreement.

MPL is also a related party of NTI. However, NTI had a crude oil supply and logistics agreement with a third party until September 30, 2014, and had no direct supply transactions with MPL prior to this date. Beginning on September 30, 2014, NTI began paying MPL for transportation services at published tariff rates.

20. Condensed Consolidating Financial Information

Separate condensed consolidating financial information of Western Refining, Inc. (the "Parent") and subsidiary guarantors and non-guarantors is presented below. At June 30, 2015, the Parent and certain subsidiary guarantors have fully and unconditionally guaranteed our Western 2021 Unsecured Notes on a joint and several basis. As a result of these guarantee arrangements, we are required to present condensed consolidating financial information. This information should be read in conjunction with the accompanying consolidated financial statements and notes thereto.

NTI, WNRL and Navajo Convenient Stores Co., LLC are subsidiaries that have not guaranteed the Western 2021 Senior Unsecured Notes. NTI and WNRL are publicly-traded master limited partnerships. As of June 30, 2015, we owned a 38.4% limited partnership interest in NTI and a 66.1% limited partnership interest in WNRL and the non-economic general partner interests of both entities. We are the primary beneficiary of WNRL's earnings and cash flows. We exercise control of both NTI and WNRL through our 100% ownership of the respective general partners. Accordingly, NTI and WNRL are consolidated with the other accounts of Western.

Due to the change in the guarantor structure resulting from WNRL's acquisition of WRW, the condensed consolidating financial information for the three and six months ended June 30, 2014 has been revised.

Our transactions with WNRL including fees paid under our pipeline, terminalling and services agreements are eliminated and have no significant impact on our condensed consolidated financial statements. During the six months ended June 30, 2015, there have been no significant intercompany accounts or transactions between Western and NTI. All intercompany accounts and transactions with NTI and WNRL are eliminated in our condensed consolidated financial statements.

NTI's long-term debt is comprised of its NTI 2020 Secured Notes and the NTI Revolving Credit Facility. NTI creditors under the NTI 2020 Secured Notes and the NTI Revolving Credit Facility have no recourse to the Parent's assets except to the extent of the assets of Northern Tier Energy GP LLC, the general partner of NTI that we wholly own. Any recourse to NTI’s general partner would be limited to the extent of the general partner’s assets that other than its investment in NTI are not significant. Furthermore, the Parent's creditors have no recourse to the assets of NTI's general partner, NTI and its consolidated subsidiaries. See Note 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 and truck fleet, for transporting refined and other products through its terminals and pipelines, for providing storage in its storage tanks and at its terminals and selling refined products through its wholesale distribution network. We do not provide financial or equity support through any liquidity arrangements and/or debt guarantees to WNRL.

WNRL's long-term debt is comprised of the WNRL 2023 Senior Notes and the WNRL Revolving Credit Facility. With the exception of the assets of Western Refining Logistics GP, LLC, the general partner of WNRL, creditors have no recourse to our assets. Any recourse to WNRL’s general partner would be limited to the extent of the Western Refining Logistics GP, LLC's assets which, other than its investment in WNRL, are not significant. Furthermore, our creditors have no recourse to the assets of WNRL and its consolidated subsidiaries. See Note 9, Long-Term Debt, for a description of WNRL’s debt obligations.

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

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

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WESTERN REFINING, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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

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WESTERN REFINING, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

CONDENSED CONSOLIDATING BALANCE SHEETS

As of June 30, 2015

(In thousands)



	Parent		Guarantor Subsidiaries		Non-Guarantors		Eliminations			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	21	$	337,441	$	206,474	$	—		$	543,936
Accounts receivable, trade, net of a reserve for doubtful accounts	—		262,974		327,188		—			590,162
Accounts receivable, affiliate	522		68,089		5,206		(73,817		)	—
Inventories	—		379,188		307,886		—			687,074
Prepaid expenses	—		87,509		22,936		—			110,445
Other current assets	—		122,737		29,828		—			152,565
Total current assets	543		1,257,938		899,518		(73,817		)	2,084,182
Restricted cash	—		68,275		—		—			68,275
Equity method investment	—		—		97,976		—			97,976
Property, plant and equipment, net	—		1,161,982		1,047,802		—			2,209,784
Goodwill	—		—		1,289,443		—			1,289,443
Intangible assets, net	—		35,285		49,699		—			84,984
Investment in subsidiaries	3,849,034		—		—		(3,849,034		)	—
Due from affiliate	—		1,706,131		—		(1,706,131		)	—
Other assets, net	30,344		61,172		27,389		—			118,905
Total assets	$	3,879,921	$	4,290,783	$	3,411,827	$	(5,628,982	)	$	5,953,549
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable, trade	$	—	$	358,893	$	366,495	$	—		$	725,388
Accounts payable, affiliate	—		—		73,817		(73,817		)	—
Accrued liabilities	5,485		152,082		90,168		—			247,735
Current deferred income tax liability, net	—		42,338		—		—			42,338
Current portion of long-term debt	5,500		—		—		—			5,500
Total current liabilities	10,985		553,313		530,480		(73,817		)	1,020,961
Long-term liabilities:
Long-term debt, less current portion	886,250		—		656,490		—			1,542,740
Due to affiliate	1,706,131		—		—		(1,706,131		)	—
Lease financing obligation	—		42,589		6,808		—			49,397
Deferred income tax liability, net	—		267,654		37,280		—			304,934
Deficit in subsidiaries	—		355,236		—		(355,236		)	—
Other liabilities	—		36,765		1,166		—			37,931
Total long-term liabilities	2,592,381		702,244		701,744		(2,061,367		)	1,935,002
Equity:
Equity - Western	1,276,555		3,035,226		458,572		(3,493,798		)	1,276,555
Equity - Non-controlling interest	—		—		1,721,031		—			1,721,031
Total equity	1,276,555		3,035,226		2,179,603		(3,493,798		)	2,997,586
Total liabilities and equity	$	3,879,921	$	4,290,783	$	3,411,827	$	(5,628,982	)	$	5,953,549

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WESTERN REFINING, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

CONDENSED CONSOLIDATING BALANCE SHEETS

As of December 31, 2014

(In thousands)



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

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WESTERN REFINING, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS AND COMPREHENSIVE INCOME

Three Months Ended June 30, 2015

(In thousands)



	Parent			Guarantor Subsidiaries			Non-Guarantors			Eliminations			Consolidated
Net sales	$	—		$	1,983,821		$	1,587,321		$	(742,250	)	$	2,828,892
Operating costs and expenses:
Cost of products sold (exclusive of depreciation and amortization)	—			1,647,312			1,272,825			(742,250		)	2,177,887
Direct operating expenses (exclusive of depreciation and amortization)	—			111,020			113,703			—			224,723
Selling, general and administrative expenses	47			29,924			29,569			—			59,540
Loss (gain) on disposal of assets, net	—			69			(456		)	—			(387		)
Maintenance turnaround expense	—			593			—			—			593
Depreciation and amortization	—			26,891			24,252			—			51,143
Total operating costs and expenses	47			1,815,809			1,439,893			(742,250		)	2,513,499
Operating income (loss)	(47		)	168,012			147,428			—			315,393
Other income (expense):
Equity in earnings of subsidiaries	147,554			10,525			—			(158,079		)	—
Interest income	—			105			96			—			201
Interest expense and other financing costs	(13,588		)	(733		)	(12,995		)	—			(27,316		)
Other, net	—			(558		)	4,582			—			4,024
Income before income taxes	133,919			177,351			139,111			(158,079		)	292,302
Provision for income taxes	—			(78,287		)	(148		)	—			(78,435		)
Net income	133,919			99,064			138,963			(158,079		)	213,867
Less net income attributable to non-controlling interest	—			—			79,948			—			79,948
Net income attributable to Western Refining, Inc.	$	133,919		$	99,064		$	59,015		$	(158,079	)	$	133,919
Comprehensive income attributable to Western Refining, Inc.	$	133,919		$	99,072		$	59,056		$	(158,079	)	$	133,968

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WESTERN REFINING, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS AND COMPREHENSIVE INCOME

Six Months Ended June 30, 2015

(In thousands)



	Parent			Guarantor Subsidiaries			Non-Guarantors			Eliminations			Consolidated
Net sales	$	—		$	3,766,921		$	2,892,493		$	(1,511,792	)	$	5,147,622
Operating costs and expenses:
Cost of products sold (exclusive of depreciation and amortization)	—			3,136,000			2,294,989			(1,511,792		)	3,919,197
Direct operating expenses (exclusive of depreciation and amortization)	—			220,989			219,045			—			440,034
Selling, general and administrative expenses	94			59,478			55,771			—			115,343
Loss (gain) on disposal of assets, net	—			450			(555		)	—			(105		)
Maintenance turnaround expense	—			698			—			—			698
Depreciation and amortization	—			52,714			48,355			—			101,069
Total operating costs and expenses	94			3,470,329			2,617,605			(1,511,792		)	4,576,236
Operating income (loss)	(94		)	296,592			274,888			—			571,386
Other income (expense):
Equity in earnings of subsidiaries	267,313			20,665			—			(287,978		)	—
Interest income	—			202			162			—			364
Interest expense and other financing costs	(27,311		)	(1,240		)	(23,722		)	—			(52,273		)
Other, net	—			(513		)	7,743			—			7,230
Income before income taxes	239,908			315,706			259,071			(287,978		)	526,707
Provision for income taxes	—			(137,521		)	(351		)	—			(137,872		)
Net income	239,908			178,185			258,720			(287,978		)	388,835
Less net income attributable to non-controlling interest	—			—			148,927			—			148,927
Net income attributable to Western Refining, Inc.	$	239,908		$	178,185		$	109,793		$	(287,978	)	$	239,908
Comprehensive income attributable to Western Refining, Inc.	$	239,908		$	178,201		$	109,834		$	(287,978	)	$	239,965

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WESTERN REFINING, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS AND COMPREHENSIVE INCOME

Three Months Ended June 30, 2014

(In thousands)



	Parent			Guarantor Subsidiaries			Non-Guarantors			Eliminations			Consolidated
Net sales	$	—		$	3,148,824		$	2,494,068		$	(1,291,602	)	$	4,351,290
Operating costs and expenses:
Cost of products sold (exclusive of depreciation and amortization)	—			2,759,358			2,258,960			(1,287,149		)	3,731,169
Direct operating expenses (exclusive of depreciation and amortization)	—			104,435			103,481			(4,453		)	203,463
Selling, general and administrative expenses	47			26,838			27,755			—			54,640
Affiliate severance costs	—			—			3,479			—			3,479
Loss (gain) on disposal of assets, net	—			189			(70		)	—			119
Depreciation and amortization	—			24,032			23,816			—			47,848
Total operating costs and expenses	47			2,914,852			2,417,421			(1,291,602		)	4,040,718
Operating income (loss)	(47		)	233,972			76,647			—			310,572
Other income (expense):
Equity in earnings of subsidiaries	175,780			13,823			—			(189,603		)	—
Interest income	—			132			89			—			221
Interest expense and other financing costs	(19,045		)	(2,223		)	(6,533		)	—			(27,801		)
Loss on extinguishment of debt	8			(9		)	—			—			(1		)
Other, net	—			478			505			—			983
Income before income taxes	156,696			246,173			70,708			(189,603		)	283,974
Provision for income taxes	—			(93,322		)	(85		)	—			(93,407		)
Net income	156,696			152,851			70,623			(189,603		)	190,567
Less net income attributable to non-controlling interest	—			—			33,871			—			33,871
Net income attributable to Western Refining, Inc.	$	156,696		$	152,851		$	36,752		$	(189,603	)	$	156,696
Comprehensive income attributable to Western Refining, Inc.	$	156,696		$	152,854		$	36,752		$	(189,603	)	$	156,699

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WESTERN REFINING, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS AND COMPREHENSIVE INCOME

Six Months Ended June 30, 2014

(In thousands)



	Parent			Guarantor Subsidiaries			Non-Guarantors			Eliminations			Consolidated
Net sales	$	—		$	5,838,867		$	4,679,404		$	(2,441,838	)	$	8,076,433
Operating costs and expenses:
Cost of products sold (exclusive of depreciation and amortization)	—			5,130,859			4,194,515			(2,433,468		)	6,891,906
Direct operating expenses (exclusive of depreciation and amortization)	—			205,837			204,345			(8,370		)	401,812
Selling, general and administrative expenses	93			53,983			59,296			—			113,372
Affiliate severance costs	—			—			12,878			—			12,878
Loss (gain) on disposal of assets, net	—			1,087			(82		)	—			1,005
Maintenance turnaround expense	—			46,446			—			—			46,446
Depreciation and amortization	—			47,305			46,953			—			94,258
Total operating costs and expenses	93			5,485,517			4,517,905			(2,441,838		)	7,561,677
Operating income (loss)	(93		)	353,350			161,499			—			514,756
Other income (expense):
Equity in earnings of subsidiaries	281,582			27,119			—			(308,701		)	—
Interest income	—			239			177			—			416
Interest expense and other financing costs	(39,247		)	(4,485		)	(13,026		)	—			(56,758		)
Loss on extinguishment of debt	—			(9		)	—			—			(9		)
Other, net	—			644			1,821			—			2,465
Income before income taxes	242,242			376,858			150,471			(308,701		)	460,870
Provision for income taxes	—			(142,402		)	(204		)	—			(142,606		)
Net income	242,242			234,456			150,267			(308,701		)	318,264
Less net income attributable to non-controlling interest	—			—			76,022			—			76,022
Net income attributable to Western Refining, Inc.	$	242,242		$	234,456		$	74,245		$	(308,701	)	$	242,242
Comprehensive income attributable to Western Refining, Inc.	$	242,242		$	234,462		$	74,276		$	(308,701	)	$	242,279

Table of Contents

WESTERN REFINING, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

Six Months Ended June 30, 2015

(In thousands)



	Parent			Guarantor Subsidiaries			Non-Guarantors			Eliminations			Consolidated
Cash flows from operating activities:
Net cash provided by (used in) operating activities	$	31,237		$	91,814		$	246,135		$	(77,142	)	$	292,044
Cash flows from investing activities:
Capital expenditures	—			(85,953		)	(34,240		)	648			(119,545		)
Decrease in restricted cash	—			98,735			—			—			98,735
Return of capital from equity method investment	—			—			5,780			—			5,780
Contributions to affiliate	—			(57,627		)	—			57,627			—
Proceeds from the sale of assets	—			1,118			427			(648		)	897
Net cash provided by (used in) investing activities	—			(43,727		)	(28,033		)	57,627			(14,133		)
Cash flows from financing activities:
Additions to long-term debt	—			—			300,000			—			300,000
Payments on long-term debt and capital lease obligations	(2,750		)	(480		)	(531		)	—			(3,761		)
Payments on revolving credit facility	—			—			(269,000		)	—			(269,000		)
Deferred financing costs	—			—			(6,820		)	—			(6,820		)
Distribution to affiliate	—			—			(77,142		)	77,142			—
Purchases of treasury stock	(25,000		)	—			—			—			(25,000		)
Distribution to non-controlling interest holders	—			—			(100,287		)	—			(100,287		)
Dividends paid	(61,114		)	—			—			—			(61,114		)
Contributions from affiliates	57,627			—			—			(57,627		)	—
Excess tax benefit from stock-based compensation	—			848			—			—			848
Net cash provided by (used in) financing activities	(31,237		)	368			(153,780		)	19,515			(165,134		)
Net increase in cash and cash equivalents	—			48,455			64,322			—			112,777
Cash and cash equivalents at beginning of year	21			288,986			142,152			—			431,159
Cash and cash equivalents at end of year	$	21		$	337,441		$	206,474		$	—		$	543,936

Table of Contents

WESTERN REFINING, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

Six Months Ended June 30, 2014

(In thousands)



	Parent			Guarantor Subsidiaries			Non-Guarantors			Eliminations			Consolidated
Cash flows from operating activities:
Net cash provided by (used in) operating activities	$	(43,125	)	$	213,948		$	165,641		$	(58,077	)	$	278,387
Cash flows from investing activities:
Capital expenditures	—			(60,142		)	(30,477		)	—			(90,619		)
Return of capital from equity method investment	—			—			1,360			—			1,360
Contributions to affiliate	—			(106,907		)	—			106,907			—
Proceeds from the sale of assets	—			327			483			—			810
Net cash provided by (used in) investing activities	—			(166,722		)	(28,634		)	106,907			(88,449		)
Cash flows from financing activities:
Payments on long-term debt and capital lease obligations	(3,009		)	—			(107		)	—			(3,116		)
Distribution to affiliate	—			—			(58,077		)	58,077			—
Purchases of treasury stock	(5,930		)	—			—			—			(5,930		)
Distribution to non-controlling interest holders	—			—			(75,964		)	—			(75,964		)
Dividends paid	(41,475		)	—			—			—			(41,475		)
Convertible debt redemption	(809		)	—			—			—			(809		)
Contributions from affiliates	94,348			—			12,559			(106,907		)	—
Excess tax benefit from stock-based compensation	—			1,099			—			—			1,099
Net cash provided by (used in) financing activities	43,125			1,099			(121,589		)	(48,830		)	(126,195		)
Net increase in cash and cash equivalents	—			48,325			15,418			—			63,743
Cash and cash equivalents at beginning of year	21			296,905			171,144			—			468,070
Cash and cash equivalents at end of year	$	21		$	345,230		$	186,562		$	—		$	531,813

Table of Contents


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, 2014 ("2014 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 Northern Tier Energy LP ("NTI") and 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 a 38.4% limited partner interest in NTI and the controlling general partner interest, Incentive Distribution Rights and a 66.1% limited partner interest in WNRL. NTI and WNRL common partnership units trade on the NYSE under the symbols "NTI" and "WNRL," respectively.

We produce refined products at our refineries in El Paso, Texas (131,000 barrels per day, or bpd), near Gallup, New Mexico (25,000 bpd) and NTI's refinery in St. Paul Park, Minnesota (98,000 bpd). We sell refined products primarily in Arizona, Colorado, Minnesota, New Mexico, Wisconsin, West Texas, the Mid-Atlantic region and Mexico, through bulk distribution terminals and wholesale marketing networks and we sell refined products through two retail networks with a total of 526 company-owned and franchised retail sites in the U.S.

NTI owns and operates a refinery in St. Paul Park, Minnesota and has a retail-marketing network of 264 convenience stores. NTI directly operates 165 of these stores and supports 99 stores through franchise agreements. NTI's primary areas of operation include Minnesota and Wisconsin.

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

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

We changed our reportable segments during the fourth quarter of 2014 due to changes in our organization and have retrospectively adjusted our historical and financial data to account for these changes. Our operations include four business segments: refining, NTI, WNRL and retail. See Note 3, Segment Information, for further discussion of our business segments.

A description of our four reportable business segments follows:


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


•	NTI. NTI owns and operates refining and transportation assets and operates and supports retail convenience stores primarily in Minnesota and Wisconsin.

•

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


•	Retail. Our retail segment operates retail convenience stores and unmanned commercial fleet fueling ("cardlock") locations located in the Southwest. The retail convenience stores sell gasoline, diesel fuel and convenience store merchandise.

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Major Influences on Results of Operations

Summary of Second Quarter 2015


•	We averaged total throughput of 134,315 bpd at the El Paso refinery for the three months ended June 30, 2015, a 3.5% decrease from the three months ended June 30, 2014.


•	We averaged total throughput of 27,686 bpd at the Gallup refinery for the three months ended June 30, 2015, a 4.9% increase from the three months ended June 30, 2014.


•	NTI averaged total throughput of 98,954 bpd at the St. Paul Park refinery for the three months ended June 30, 2015, a 6.4% increase from the three months ended June 30, 2014.


•	We declared and paid dividends of $0.34 per common share for an aggregate payment of $32.5 million.


•	NTI declared and paid a quarterly cash distribution of $1.08 per unit.


•	WNRL declared and paid a quarterly cash distribution of $0.3475 per unit.

2015 Year-to-Date Operating and Financial Highlights

Net income attributable to Western was $239.9 million, or $2.51 per diluted share for the six months ended June 30, 2015, compared to $242.2 million, or $2.44 per diluted share for the six months ended June 30, 2014.

Our operating income increased $56.6 million from June 30, 2014, to June 30, 2015, as shown by segment in the following table:



	Six Months Ended
	June 30,
	2015			2014			Change
	(In thousands)
Refining	$	330,737		$	387,261		$	(56,524	)
NTI	233,122			125,936			107,186
WNRL	41,766			34,235			7,531
Retail	4,216			2,545			1,671
Corporate	(38,455		)	(35,221		)	(3,234		)
Total operating income	$	571,386		$	514,756		$	56,630

The WNRL financial and operational data presented include the historical results of all assets acquired from Western in the Wholesale Acquisition. This acquisition from Western was a transfer of assets between entities under common control. The financial information for the affected reporting segments has been retrospectively adjusted to include or exclude the historical results of the transferred WRW assets for periods prior to the effective date of the transaction. See Note 3, Segment Information, for further discussion of these retrospective adjustments.

Overview of Segments

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


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


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


•	seasonal fluctuations in demand for refined products;


•	the impact of our economic hedging activity;


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


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


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

Key factors affecting petroleum based commodity values include: supply and demand for crude oil, gasoline and other refined products; changes in domestic and foreign economies; weather conditions; domestic and foreign political affairs; crude

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oil and refined petroleum product production levels; logistics constraints; availability of imports; marketing of competitive fuels; price differentials between heavy and sour crude oils and light sweet crude oils and government regulation.

We engage in hedging activity primarily to fix the margin on a portion of our future gasoline and distillate production and to protect the value of certain crude oil, refined product and blendstock inventories.

Excise and other taxes collected from customers and remitted to governmental authorities are not included in revenues or cost of products sold. In addition to the crude oil that we purchase to supply our refinery production, we also purchase crude oil quantities that are transported to different locations and sold to third parties. We record these sales on a gross basis with the sales price recorded as revenues and the related costs within cost of products sold. Consolidated cost of products sold for the six months ended June 30, 2015, includes $16.9 million of realized and non-cash unrealized net losses from our economic hedging activities including refining segment losses of $15.8 million and NTI losses of $1.1 million. The non-cash unrealized net losses included in this total for the six months ended June 30, 2015, were $42.3 million, including $44.0 million related to refining segment losses offset by $1.7 million in NTI gains.

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 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.

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


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


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


•	adjustments to reflect the lower of cost or market value of crude oil, finished product and retail last-in, first-out ("LIFO") inventory values;


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


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


•	seasonal fluctuations in demand for refined products; and


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

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

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

Earnings and cash flows from WNRL's wholesale business are primarily affected by the sales volumes and margins of gasoline, diesel fuel and lubricants sold and transportation revenues from crude oil trucking and delivery. These margins are equal to the sales price, net of discounts, less total cost of sales and are measured on a cents per gallon ("cpg") basis. Factors that influence margins include local supply, demand and competition.

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Retail. Earnings and cash flows from our retail business are primarily affected by the sales volumes and margins of gasoline and diesel fuel and by the sales and margins of merchandise sold at our retail stores. Margins for gasoline and diesel fuel sales are equal to the sales price less the delivered cost of the fuel and motor fuel taxes and are measured on a cpg basis. Fuel margins are impacted by competition and local and regional supply and demand. Margins for retail merchandise sold are equal to retail merchandise sales less the delivered cost of the merchandise, net of supplier discounts and inventory shrinkage and are measured as a percentage of merchandise sales. Merchandise sales are impacted by convenience or location, branding and competition. Our retail sales reflect seasonal trends such that operating results for the first and fourth calendar quarters are generally lower than those for the second and third calendar quarters of each year primarily driven by lower volumes of fuel being sold. Earnings and cash flows from our cardlock business are primarily affected by the sales volumes and margins of gasoline and diesel fuel sold. These margins are equal to the sales price, net of discounts less the delivered cost of the fuel and motor fuel taxes and are measured on a cpg basis. Factors that influence margins include local supply, demand and competition.

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 2014 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 believe that recently issued accounting pronouncements and other authoritative guidance for which the effective date is in the future will either have no significant impact on our accounting or reporting or that such impact will not be material to our financial position, results of operations and cash flows when implemented. For further discussion on the impact of recent accounting pronouncements, see Note 2, Basis of Presentation and Significant Accounting Policies.

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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 six months ended June 30, 2015 and 2014, respectively. 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 June 30, 2015, Compared to the Three Months Ended June 30, 2014



	Three Months Ended
	June 30,
	2015			2014			Change
	(In thousands, except per share data)
Statements of Operations Data
Net sales (1)	$	2,828,892		$	4,351,290		$	(1,522,398	)
Operating costs and expenses:
Cost of products sold (exclusive of depreciation and amortization) (1)	2,177,887			3,731,169			(1,553,282		)
Direct operating expenses (exclusive of depreciation and amortization) (1)	224,723			203,463			21,260
Selling, general and administrative expenses	59,540			54,640			4,900
Affiliate severance costs	—			3,479			(3,479		)
Loss (gain) on disposal of assets, net	(387		)	119			(506		)
Maintenance turnaround expense	593			—			593
Depreciation and amortization	51,143			47,848			3,295
Total operating costs and expenses	2,513,499			4,040,718			(1,527,219		)
Operating income	315,393			310,572			4,821
Other income (expense):
Interest income	201			221			(20		)
Interest expense and other financing costs	(27,316		)	(27,801		)	485
Loss on extinguishment of debt	—			(1		)	1
Other, net	4,024			983			3,041
Income before income taxes	292,302			283,974			8,328
Provision for income taxes	(78,435		)	(93,407		)	14,972
Net income	213,867			190,567			23,300
Less net income attributable to non-controlling interests (2)	79,948			33,871			46,077
Net income attributable to Western Refining, Inc.	$	133,919		$	156,696		$	(22,777	)

Basic earnings per share	$	1.40		$	1.88		$	(0.48	)
Diluted earnings per share	$	1.40		$	1.56		$	(0.16	)
Dividends declared per common share	$	0.34		$	0.26		$	0.08
Weighted average basic shares outstanding	95,539			83,556			11,983
Weighted average dilutive shares outstanding	95,626			102,657			(7,031		)


(1)	Excludes $895.5 million and $1,236.7 million of intercompany sales and $895.5 million and $1,232.2 million of intercompany cost of products sold for the three months ended June 30, 2015 and June 30, 2014, respectively, and $4.5 million of intercompany direct operating expenses for the three months ended June 30, 2014 with no comparable activity for three months ended June 30, 2015.


(2)	Net income attributable to non-controlling interests for the three months ended June 30, 2015, consisted of income from NTI and WNRL in the amount of $74.6 million and $5.4 million, respectively. Net income attributable to non-controlling interests for the three months ended June 30, 2014, consisted of income from NTI and WNRL in the amount of $30.1 million and $3.8 million, respectively.

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	Three Months Ended
	June 30,
	2015			2014			Change
	(In thousands)
Economic Hedging Activities Recognized within Cost of Products Sold
Realized hedging gain, net	$	7,823		$	1,812		$	6,011
Unrealized hedging gain (loss), net	(22,287		)	45,379			(67,666		)
Total hedging gain (loss), net	$	(14,464	)	$	47,191		$	(61,655	)

Cash Flow Data
Net cash provided by (used in):
Operating activities	$	187,066		$	214,355		$	(27,289	)
Investing activities	(4,962		)	(38,000		)	33,038
Financing activities	(101,242		)	(76,179		)	(25,063		)
Capital expenditures	66,350			40,021			26,329

Gross Margin. Gross margin is calculated as net sales less cost of products sold (exclusive of depreciation and amortization). Our consolidated gross margin increased by 5.0% from the three months ended June 30, 2014 to the three months ended June 30, 2015. This increase was primarily due to refining margins, economic hedging activities and a lower of cost or market (LCM) inventory recovery. We discuss refining margins and economic hedging activities under our refining and NTI segments.

Direct Operating Expenses (exclusive of depreciation and amortization). The increase in direct operating expenses was primarily due to an increase of $9.8 million, $4.8 million, $3.7 million and $3.1 million in our NTI, WNRL, retail and refining segments, respectively.

Selling, General and Administrative Expenses. The increase in selling, general and administrative expenses resulted from an increase of $3.5 million $0.7 million, $0.6 million and $0.4 million in our corporate overhead, NTI, WNRL and retail segments, respectively, partially offset by a decrease of $0.2 million in our refining segment. The increase in corporate overhead was due to higher employee expenses based primarily on higher incentive compensation accruals in the current period.

Affiliate Severance Costs. The severance costs incurred during the three months ended June 30, 2014, relate to severance payments resulting from Western's acquisition of NTI's general partner.

Maintenance Turnaround Expense. We reported minimal turnaround expenses during the three months ended June 30, 2015.

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

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Six Months Ended June 30, 2015, Compared to the Six Months Ended June 30, 2014



	Six Months Ended
	June 30,
	2015			2014			Change
	(In thousands, except per share data)
Statements of Operations Data
Net sales (1)	$	5,147,622		$	8,076,433		$	(2,928,811	)
Operating costs and expenses:
Cost of products sold (exclusive of depreciation and amortization) (1)	3,919,197			6,891,906			(2,972,709		)
Direct operating expenses (exclusive of depreciation and amortization) (1)	440,034			401,812			38,222
Selling, general and administrative expenses	115,343			113,372			1,971
Affiliate severance costs	—			12,878			(12,878		)
Loss (gain) on disposal of assets, net	(105		)	1,005			(1,110		)
Maintenance turnaround expense	698			46,446			(45,748		)
Depreciation and amortization	101,069			94,258			6,811
Total operating costs and expenses	4,576,236			7,561,677			(2,985,441		)
Operating income	571,386			514,756			56,630
Other income (expense):
Interest income	364			416			(52		)
Interest expense and other financing costs	(52,273		)	(56,758		)	4,485
Loss on extinguishment of debt	—			(9		)	9
Other, net	7,230			2,465			4,765
Income before income taxes	526,707			460,870			65,837
Provision for income taxes	(137,872		)	(142,606		)	4,734
Net income	388,835			318,264			70,571
Less net income attributable to non-controlling interests (2)	148,927			76,022			72,905
Net income attributable to Western Refining, Inc.	$	239,908		$	242,242		$	(2,334	)

Basic earnings per share	$	2.51		$	2.97		$	(0.46	)
Diluted earnings per share	$	2.51		$	2.44		$	0.07
Dividends declared per common share	$	0.64		$	0.52		$	0.12
Weighted average basic shares outstanding	95,553			81,653			13,900
Weighted average dilutive shares outstanding	95,654			102,655			(7,001		)


(1)	Excludes $1,632.0 million and $2,294.8 million of intercompany sales and $1,632.0 million and $2,286.5 million of intercompany cost of products sold for the six months ended June 30, 2015 and June 30, 2014, respectively, and $8.3 million of intercompany direct operating expenses for the six months ended June 30, 2014 with no comparable activity for six months ended June 30, 2015.


(2)	Net income attributable to non-controlling interests for the six months ended June 30, 2015, consisted of income from NTI and WNRL in the amount of $138.4 million and $10.6 million, respectively. Net income attributable to non-controlling interests for the six months ended June 30, 2014, consisted of income from NTI and WNRL in the amount of $68.4 million and $7.6 million, respectively.

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	Six Months Ended
	June 30,
	2015			2014			Change
	(In thousands)
Economic Hedging Activities Recognized within Cost of Products Sold
Realized hedging gain, net	$	25,376		$	17,556		$	7,820
Unrealized hedging gain (loss), net	(42,344		)	119,350			(161,694		)
Total hedging gain (loss), net	$	(16,968	)	$	136,906		$	(153,874	)

Cash Flow Data
Net cash provided by (used in):
Operating activities	$	292,044		$	278,387		$	13,657
Investing activities	(14,133		)	(88,449		)	74,316
Financing activities	(165,134		)	(126,195		)	(38,939		)
Capital expenditures	119,545			90,619			28,926

Gross Margin. Gross margin is calculated as net sales less cost of products sold (exclusive of depreciation and amortization). Our consolidated gross margin increased by 3.7% from the six months ended June 30, 2014 to the six months ended June 30, 2015. This increase was primarily due to refining margins and economic hedging activities. We discuss refining margins and economic hedging activities under our refining and NTI segments.

Direct Operating Expenses (exclusive of depreciation and amortization). The increase in direct operating expenses was primarily due to an increase of $12.4 million, $10.6 million, $7.6 million and $7.9 million in our NTI, WNRL, retail and refining segments, respectively.

Selling, General and Administrative Expenses. The increase in selling, general and administrative expenses resulted from an increase of $3.5 million, $2.2 million, $1.3 million and $1.1 million in our corporate overhead and our refining, WNRL and retail segments, respectively, partially offset by a decrease of $6.1 million in our NTI segment. The increase in corporate overhead was due to higher employee expenses based primarily on higher incentive compensation accruals in the current period.

Affiliate Severance Costs. The severance costs incurred during the six months ended June 30, 2014, relate to severance payments resulting from Western's acquisition of NTI's general partner.

Maintenance Turnaround Expense. We reported minimal turnaround expenses during the six months ended June 30, 2015. During the six months ended June 30, 2014, we reported turnaround expenses in connection with the 2014 turnaround of the south side units of the El Paso refinery.

Depreciation and Amortization. The increase between periods is primarily due to additional depreciation at our El Paso refinery primarily resulting from assets capitalized during the first quarter of 2014 in El Paso and additional depreciation associated with our logistics assets related to the ongoing expansion of our Delaware Basin logistics system.

Interest Expense and Other Financing Costs. The decrease in interest expense from prior periods was attributable to the retirement of the 5.75% Convertible Senior Unsecured Notes during the second quarter of 2014. This decrease was partially offset during the current year by interest incurred through WNRL's issuance of $300.0 million in aggregate principal amount of 7.5% Senior Notes due 2023 (the "WNRL 2023 Senior Notes").

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Results by Segment

The following tables set forth our historical financial data by segment for the periods presented. During the fourth quarter of 2014, we changed our reportable segments due to changes in our organization. Our operations are organized into four operating segments based on manufacturing and marketing criteria and the nature of our products and services, our production processes and our types of customers. These segments are refining, NTI, WNRL and retail. See Note 3, Segment Information, in the notes to the condensed consolidated financial statements included in this quarterly report for more information. The historical financial data was retrospectively adjusted for the periods presented to conform to the current presentation.



	Three Months Ended
	June 30,
	2015		2014		Change
	(In thousands)
Gross Margin by Segment (excluding intersegment transactions)
Refining	$	291,080	$	350,479	$	(59,399	)
NTI	244,021		170,497		73,524
WNRL	70,475		60,158		10,317
Retail	45,429		38,851		6,578
Other	—		136		(136		)
Consolidated gross margin	$	651,005	$	620,121	$	30,884
Direct Operating Expenses by Segment (excluding intersegment transactions)
Refining	$	77,379	$	74,286	$	3,093
NTI	76,348		66,507		9,841
WNRL	37,355		32,521		4,834
Retail	33,641		29,950		3,691
Other	—		199		(199		)
Consolidated direct operating expenses	$	224,723	$	203,463	$	21,260
Depreciation and Amortization by Segment
Refining	$	21,884	$	20,397	$	1,487
NTI	19,515		19,362		153
WNRL	4,737		4,454		283
Retail	4,031		2,817		1,214
Other	976		818		158
Consolidated depreciation and amortization	$	51,143	$	47,848	$	3,295

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

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	Six Months Ended
	June 30,
	2015		2014		Change
	(In thousands)
Gross Margin by Segment (excluding intersegment transactions)
Refining	$	547,065	$	635,768	$	(88,703	)
NTI	461,334		360,423		100,911
WNRL	136,170		116,096		20,074
Retail	83,856		72,010		11,846
Other	—		230		(230		)
Consolidated gross margin	$	1,228,425	$	1,184,527	$	43,898
Direct Operating Expenses by Segment (excluding intersegment transactions)
Refining	$	154,911	$	147,040	$	7,871
NTI	146,053		133,626		12,427
WNRL	72,992		62,349		10,643
Retail	65,995		58,405		7,590
Other	83		392		(309		)
Consolidated direct operating expenses	$	440,034	$	401,812	$	38,222
Depreciation and Amortization by Segment
Refining	$	43,522	$	39,865	$	3,657
NTI	38,880		38,347		533
WNRL	9,475		8,606		869
Retail	7,317		5,752		1,565
Other	1,875		1,688		187
Consolidated depreciation and amortization	$	101,069	$	94,258	$	6,811

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

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Adjusted EBITDA

Adjusted EBITDA represents earnings before interest expense and other financing costs, 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. 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 June 30, 2015, Compared to the Three Months Ended June 30, 2014



	Three Months Ended
	June 30,
	2015			2014			Change
	(In thousands)
Net income attributable to Western Refining, Inc.	$	133,919		$	156,696		$	(22,777	)
Net income attributable to non-controlling interests	79,948			33,871			46,077
Interest expense and other financing costs	27,316			27,801			(485		)
Provision for income taxes	78,435			93,407			(14,972		)
Loss (gain) on disposal of assets, net	(387		)	119			(506		)
Depreciation and amortization	51,143			47,848			3,295
Maintenance turnaround expense	593			—			593
Loss on extinguishment of debt	—			1			(1		)
Net change in lower of cost or market inventory reserve	(38,204		)	—			(38,204		)
Unrealized loss (gain) on commodity hedging transactions	22,287			(45,379		)	67,666
Adjusted EBITDA	$	355,050		$	314,364		$	40,686

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Six Months Ended June 30, 2015, Compared to the Six Months Ended June 30, 2014



	Six Months Ended
	June 30,
	2015			2014			Change
	(In thousands)
Net income attributable to Western Refining, Inc.	$	239,908		$	242,242		$	(2,334	)
Net income attributable to non-controlling interests	148,927			76,022			72,905
Interest expense and other financing costs	52,273			56,758			(4,485		)
Provision for income taxes	137,872			142,606			(4,734		)
Loss (gain) on disposal of assets, net	(105		)	1,005			(1,110		)
Depreciation and amortization	101,069			94,258			6,811
Maintenance turnaround expense	698			46,446			(45,748		)
Loss on extinguishment of debt	—			9			(9		)
Net change in lower of cost or market inventory reserve	(53,926		)	—			(53,926		)
Unrealized loss (gain) on commodity hedging transactions	42,344			(119,350		)	161,694
Adjusted EBITDA	$	669,060		$	539,996		$	129,064

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Refining Segment

Three Months Ended June 30, 2015, Compared to the Three Months Ended June 30, 2014



	Three Months Ended
	June 30,
	2015		2014			Change
	(In thousands, except per barrel data)
Statement of Operations Data:
Net sales (including intersegment sales) (1)	$	1,819,032	$	2,742,701		$	(923,669	)
Operating costs and expenses:
Cost of products sold (exclusive of depreciation and amortization) (2)	1,527,952		2,392,222			(864,270		)
Direct operating expenses (exclusive of depreciation and amortization)	77,379		74,286			3,093
Selling, general and administrative expenses	7,133		7,354			(221		)
Loss on disposal of assets, net	78		188			(110		)
Maintenance turnaround expense	593		—			593
Depreciation and amortization	21,884		20,397			1,487
Total operating costs and expenses	1,635,019		2,494,447			(859,428		)
Operating income	$	184,013	$	248,254		$	(64,241	)
Key Operating Statistics
Total sales volume (bpd) (1) (3)	233,653		227,313			6,340
Total production (bpd)	160,266		163,567			(3,301		)
Total throughput (bpd)	162,001		165,641			(3,640		)
Per barrel of throughput:
Refinery gross margin (2) (4)	$	19.71	$	23.42		$	(3.71	)
Direct operating expenses (5)	5.25		4.93			0.32
Mid-Atlantic sales volume (bbls)	2,513		2,496			17
Mid-Atlantic margin per barrel	$	0.32	$	(1.03	)	$	1.35

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

El Paso and Gallup Refineries



	Three Months Ended
	June 30,
	2015	2014	Change
Key Operating Statistics
Product yields (bpd):
Gasoline	86,034	84,773	1,261
Diesel and jet fuel	63,188	69,080	(5,892	)
Residuum	5,140	5,792	(652	)
Other	5,904	3,922	1,982
Total production (bpd)	160,266	163,567	(3,301	)
Throughput (bpd):
Sweet crude oil	132,230	126,797	5,433
Sour crude oil	22,068	29,019	(6,951	)
Other feedstocks and blendstocks	7,703	9,825	(2,122	)
Total throughput (bpd)	162,001	165,641	(3,640	)

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El Paso Refinery



	Three Months Ended
	June 30,
	2015		2014		Change
Key Operating Statistics
Product yields (bpd):
Gasoline	68,289		68,566		(277		)
Diesel and jet fuel	55,032		60,693		(5,661		)
Residuum	5,140		5,792		(652		)
Other	4,504		2,462		2,042
Total production (bpd)	132,965		137,513		(4,548		)
Throughput (bpd):
Sweet crude oil	106,601		102,162		4,439
Sour crude oil	22,068		29,019		(6,951		)
Other feedstocks and blendstocks	5,646		8,060		(2,414		)
Total throughput (bpd)	134,315		139,241		(4,926		)
Total sales volume (bpd) (3)	149,561		150,728		(1,167		)
Per barrel of throughput:
Refinery gross margin (2) (4)	$	20.01	$	20.95	$	(0.94	)
Direct operating expenses (5)	4.17		3.86		0.31

Gallup Refinery



	Three Months Ended
	June 30,
	2015		2014		Change
Key Operating Statistics
Product yields (bpd):
Gasoline	17,745		16,207		1,538
Diesel and jet fuel	8,156		8,387		(231		)
Other	1,400		1,460		(60		)
Total production (bpd)	27,301		26,054		1,247
Throughput (bpd):
Sweet crude oil	25,629		24,635		994
Other feedstocks and blendstocks	2,057		1,765		292
Total throughput (bpd)	27,686		26,400		1,286
Total sales volume (bpd) (3)	33,637		33,839		(202		)
Per barrel of throughput:
Refinery gross margin (2) (4)	$	22.64	$	15.34	$	7.30
Direct operating expenses (5)	7.81		9.03		(1.22		)


(1)	Refining net sales for the three months ended June 30, 2015 and 2014, includes $259.0 million and $399.0 million, respectively, representing a period average of 50,455 bpd and 42,747 bpd, respectively, in crude oil sales to third parties.

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



	Three Months Ended
	June 30,
	2015			2014		Change
	(In thousands)
Realized hedging gain, net	$	10,686		$	4,177	$	6,509
Unrealized hedging gain (loss), net	(22,795		)	44,918		(67,713		)
Total hedging gain (loss), net	$	(12,109	)	$	49,095	$	(61,204	)

(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 10.7% and 9.4% of our total consolidated sales volumes for the three months ended June 30, 2015 and 2014, respectively. The majority of the purchased refined products are distributed through our refined product sales activities in the Mid-Atlantic region where we satisfy our refined product customer sales requirements through a third-party supply agreement.

(4)

Refinery gross margin for the respective periods presented is a per barrel measurement calculated by subtracting cost of products sold from net sales and dividing that difference by our refineries’ total throughput volumes. 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. Refinery gross margin is a non-GAAP performance measure that we believe is useful for evaluating our refinery performance as a general indication of the excess of the refined product sales amount over the related cost of products sold. 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
	June 30,
	2015		2014		Change
	(In thousands)
Refinery net sales (including intersegment sales)	$	1,612,976	$	2,430,001	$	(817,025	)
Mid-Atlantic sales	206,056		312,700		(106,644		)
Net sales (including intersegment sales)	$	1,819,032	$	2,742,701	$	(923,669	)

Refinery cost of products sold (exclusive of depreciation and amortization)	$	1,322,364	$	2,076,946	$	(754,582	)
Mid-Atlantic cost of products sold	205,588		315,276		(109,688		)
Cost of products sold (exclusive of depreciation and amortization)	$	1,527,952	$	2,392,222	$	(864,270	)

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Our calculation of refinery gross margin may differ from similar calculations of other companies in our industry, thereby limiting its usefulness as a comparative measure. The following table reconciles combined gross profit for our refineries to combined gross margin for our refineries for the periods presented:



	Three Months Ended
	June 30,
	2015		2014		Change
	(In thousands, except per barrel data)
Refinery net sales (including intersegment sales)	$	1,612,976	$	2,430,001	$	(817,025	)
Refinery cost of products sold (exclusive of depreciation and amortization)	1,322,364		2,076,946		(754,582		)
Depreciation and amortization	21,884		20,397		1,487
Gross profit	268,728		332,658		(63,930		)
Plus depreciation and amortization	21,884		20,397		1,487
Refinery gross margin	$	290,612	$	353,055	$	(62,443	)
Refinery gross margin per throughput barrel	$	19.71	$	23.42	$	(3.71	)
Gross profit per throughput barrel	$	18.23	$	22.07	$	(3.84	)


(5)	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 calculated as net sales (including intersegment sales) less cost of products sold (exclusive of depreciation and amortization). Excluding the impact of hedging activities, refinery gross margin per throughput barrel increased in a manner consistent with the increase in industry benchmarks. The Gulf Coast benchmark 3:2:1 crack spread rose to $22.76 in the second quarter of 2015 from $19.14 in the second quarter of 2014. Our crude oil purchases are based on pricing tied to WTI that, in recent quarters, has experienced price volatility relative to Brent crude oil. During the second quarter of 2015, this differential decreased to an average of $4.00 per barrel from an average of $6.62 per barrel for the second quarter of 2014. During 2014 and through the first six months of 2015, our El Paso refinery margins reflected the positive impact of the WTI Midland/Cushing discount. This positive impact has declined in the current period as the WTI Midland/Cushing discount has decreased to an average $0.60 per barrel during the second quarter of 2015, compared to $8.40 for the second quarter of 2014.

Refinery gross margin was also affected by second quarter 2015 net realized and unrealized economic hedging losses of $12.1 million compared to net realized and unrealized economic hedging gains of $49.1 million during the second quarter of 2014. 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 Renewable Identification Numbers ("RIN"), which was $6.5 million for the three months ended June 30, 2015, compared to $1.3 million for the three months ended June 30, 2014. Total refinery throughput decreased by 0.3 million barrels quarter over quarter. Our refined product sales volume increased to 21.3 million barrels during the second quarter of 2015 from 20.7 million barrels during the second quarter of 2014.

Direct Operating Expenses (exclusive of depreciation and amortization). Direct operating expenses increased quarter over quarter primarily due to higher maintenance of $2.9 million due to maintenance projects in the El Paso refinery, higher employee expense of $1.8 million due to increased headcount and higher railcar lease expense of $0.9 million due to new short term leases in 2015, partially offset by lower energy expense of $3.0 million due to decreased natural gas prices.

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

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Six Months Ended June 30, 2015, Compared to the Six Months Ended June 30, 2014



	Six Months Ended
	June 30,
	2015		2014		Change
	(In thousands, except per barrel data)
Statement of Operations Data:
Net sales (including intersegment sales) (1)	$	3,310,473	$	5,068,515	$	(1,758,042	)
Operating costs and expenses:
Cost of products sold (exclusive of depreciation and amortization) (2)	2,763,408		4,432,747		(1,669,339		)
Direct operating expenses (exclusive of depreciation and amortization)	154,911		147,040		7,871
Selling, general and administrative expenses	16,702		14,484		2,218
Loss on disposal of assets, net	495		672		(177		)
Maintenance turnaround expense	698		46,446		(45,748		)
Depreciation and amortization	43,522		39,865		3,657
Total operating costs and expenses	2,979,736		4,681,254		(1,701,518		)
Operating income	$	330,737	$	387,261	$	(56,524	)
Key Operating Statistics
Total sales volume (bpd) (1) (3)	233,564		214,105		19,459
Total production (bpd)	162,539		149,362		13,177
Total throughput (bpd)	164,635		151,642		12,993
Per barrel of throughput:
Refinery gross margin (2) (4)	$	18.26	$	23.14	$	(4.88	)
Direct operating expenses (5)	5.20		5.36		(0.16		)
Mid-Atlantic sales volume (bbls)	4,453		4,878		(425		)
Mid-Atlantic margin per barrel	$	0.75	$	0.15	$	0.60

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

El Paso and Gallup Refineries



	Six Months Ended
	June 30,
	2015	2014	Change
Key Operating Statistics
Product yields (bpd):
Gasoline	87,607	75,894	11,713
Diesel and jet fuel	64,143	62,626	1,517
Residuum	5,039	5,075	(36	)
Other	5,750	5,767	(17	)
Total production (bpd)	162,539	149,362	13,177
Throughput (bpd):
Sweet crude oil	131,709	120,157	11,552
Sour crude oil	22,649	24,090	(1,441	)
Other feedstocks and blendstocks	10,277	7,395	2,882
Total throughput (bpd)	164,635	151,642	12,993

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El Paso Refinery



	Six Months Ended
	June 30,
	2015		2014		Change
Key Operating Statistics
Product yields (bpd):
Gasoline	69,981		59,018		10,963
Diesel and jet fuel	55,874		54,215		1,659
Residuum	5,039		5,075		(36		)
Other	4,244		4,132		112
Total production (bpd)	135,138		122,440		12,698
Throughput (bpd):
Sweet crude oil	106,481		95,052		11,429
Sour crude oil	22,649		24,090		(1,441		)
Other feedstocks and blendstocks	7,665		5,132		2,533
Total throughput (bpd)	136,795		124,274		12,521
Total sales volume (bpd) (3)	150,680		139,176		11,504
Per barrel of throughput:
Refinery gross margin (2) (4)	$	18.72	$	18.70	$	0.02
Direct operating expenses (5)	4.13		4.31		(0.18		)

Gallup Refinery



	Six Months Ended
	June 30,
	2015		2014		Change
Key Operating Statistics
Product yields (bpd):
Gasoline	17,626		16,876		750
Diesel and jet fuel	8,269		8,411		(142		)
Other	1,506		1,635		(129		)
Total production (bpd)	27,401		26,922		479
Throughput (bpd):
Sweet crude oil	25,228		25,105		123
Other feedstocks and blendstocks	2,612		2,263		349
Total throughput (bpd)	27,840		27,368		472
Total sales volume (bpd) (3)	33,263		33,520		(257		)
Per barrel of throughput:
Refinery gross margin (2) (4)	$	18.34	$	14.42	$	3.92
Direct operating expenses (5)	7.93		8.73		(0.80		)


(1)	Refining net sales for the six months ended June 30, 2015 and 2014, includes $474.5 million and $753.4 million, respectively, representing a period average of 49,621 bpd and 41,409 bpd, respectively, in crude oil sales to third parties.

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



	Six Months Ended
	June 30,
	2015			2014		Change
	(In thousands)
Realized hedging gain, net	$	28,141		$	20,661	$	7,480
Unrealized hedging gain (loss), net	(43,977		)	119,056		(163,033		)
Total hedging gain (loss), net	$	(15,836	)	$	139,717	$	(155,553	)

(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 10.0% and 11.1% of our total consolidated sales volumes for the six months ended June 30, 2015 and 2014, respectively. The majority of the purchased refined products are distributed through our refined product sales activities in the Mid-Atlantic region where we satisfy our refined product customer sales requirements through a third-party supply agreement.

(4)



	Six Months Ended
	June 30,
	2015		2014		Change
	(In thousands)
Refinery net sales (including intersegment sales)	$	2,968,495	$	4,471,200	$	(1,502,705	)
Mid-Atlantic sales	341,978		597,315		(255,337		)
Net sales (including intersegment sales)	$	3,310,473	$	5,068,515	$	(1,758,042	)

Refinery cost of products sold (exclusive of depreciation and amortization)	$	2,424,458	$	3,836,144	$	(1,411,686	)
Mid-Atlantic cost of products sold	338,950		596,603		(257,653		)
Cost of products sold (exclusive of depreciation and amortization)	$	2,763,408	$	4,432,747	$	(1,669,339	)

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	Six Months Ended
	June 30,
	2015		2014		Change
	(In thousands, except per barrel data)
Refinery net sales (including intersegment sales)	$	2,968,495	$	4,471,200	$	(1,502,705	)
Refinery cost of products sold (exclusive of depreciation and amortization)	2,424,458		3,836,144		(1,411,686		)
Depreciation and amortization	43,522		39,865		3,657
Gross profit	500,515		595,191		(94,676		)
Plus depreciation and amortization	43,522		39,865		3,657
Refinery gross margin	$	544,037	$	635,056	$	(91,019	)
Refinery gross margin per throughput barrel	$	18.26	$	23.14	$	(4.88	)
Gross profit per throughput barrel	$	16.80	$	21.69	$	(4.89	)


(5)	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 calculated as net sales (including intersegment sales) less cost of products sold (exclusive of depreciation and amortization). Excluding the impact of hedging activities, refinery gross margin per throughput barrel increased in a manner consistent with the increase in industry benchmarks. The Gulf Coast benchmark 3:2:1 crack spread rose to $20.40 in the first six months of 2015 from $17.89 in the first six months of 2014. Our crude oil purchases are based on pricing tied to WTI that, in recent quarters, has experienced price volatility relative to Brent crude oil. During the first six months of 2015, this differential decreased to an average of $4.60 per barrel from an average of $8.02 per barrel for the first six months of 2014. During 2014 and through the first six months of 2015, our El Paso refinery margins have reflected the positive impact of the WTI Midland/Cushing discount. This positive impact has declined in the current period as the WTI Midland/Cushing discount has decreased to an average of $1.25 per barrel during the first six months of 2015, compared to $5.95 for the first six months of 2014.

Refinery gross margin was also affected by net realized and unrealized economic hedging losses of $15.8 million for the first six months of 2015, compared to net realized and unrealized economic hedging gains of $139.7 million for the first six months of 2014. 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 $12.7 million for the first six months of 2015, compared to $11.3 million for the first six months of 2014. Total refinery throughput increased by 2.4 million barrels. Our refined product sales volume increased to 42.3 million barrels during the first six months of 2015 from 38.8 million barrels during the first six months of 2014. The increase in refinery throughput and refined product sales volume was primarily due to a turnaround for the south side units of the El Paso refinery during the first quarter of 2014, with no similar activity in 2015.

Direct Operating Expenses (exclusive of depreciation and amortization). Direct operating expenses increased primarily due to higher maintenance expenses of $5.0 million due to maintenance projects in the El Paso refinery, higher employee expense of $3.6 million due to increased headcount and higher railcar lease expense of $2.1 million due to new short term leases in 2015, partially offset by lower energy expense of $4.0 million due to decreased natural gas prices.

Maintenance Turnaround Expense. During the six months ended June 30, 2014, we reported turnaround expenses in connection with a turnaround of the south side units of the El Paso refinery.

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

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NTI

Three Months Ended June 30, 2015, Compared to the Three Months Ended June 30, 2014



	Three Months Ended
	June 30,
	2015			2014			Change
	(In thousands, except per barrel data)
Statement of Operations Data:
Net sales	$	852,820		$	1,499,321		$	(646,501	)
Operating costs and expenses:
Cost of products sold (exclusive of depreciation and amortization) (1)	608,799			1,328,824			(720,025		)
Direct operating expenses (exclusive of depreciation and amortization)	76,348			66,507			9,841
Selling, general and administrative expenses	23,319			22,632			687
Affiliate severance costs	—			3,479			(3,479		)
Gain on disposal of assets, net	(296		)	(89		)	(207		)
Depreciation and amortization	19,515			19,362			153
Total operating costs and expenses	727,685			1,440,715			(713,030		)
Operating income	$	125,135		$	58,606		$	66,529
Key Operating Statistics
Total sales volume (bpd)	103,778			102,409			1,369
Total refinery production (bpd)	98,722			93,342			5,380
Total refinery throughput (bpd) (2)	98,954			93,022			5,932
Per barrel of throughput:
Refinery gross margin (1) (3)	$	21.98		$	15.03		$	6.95
Direct operating expenses (4)	4.80			4.17			0.63

Retail fuel gallons sold (in thousands)	77,398			76,740			658
Retail fuel margin per gallon (5)	$	0.22		$	0.19		$	0.03
Merchandise sales	95,799			89,895			5,904
Merchandise margin (6)	25.9		%	26.5		%	(0.6		)%


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



	Three Months Ended
	June 30,
	2015			2014			Change
	(In thousands)
Realized hedging loss, net	$	(2,863	)	$	(2,365	)	$	(498	)
Unrealized hedging gain, net	508			461			47
Total hedging loss, net	$	(2,355	)	$	(1,904	)	$	(451	)


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

(3)

Refinery gross margin is a per barrel measurement calculated by dividing the difference between net sales and cost of products sold by the refinery's total throughput volumes for the respective periods presented. Refinery net sales include $37.2 million and $314.5 million related to crude oil sales during the second quarter of 2015 and 2014, respectively. Refinery gross margin is a non-GAAP performance measure that we believe is useful in evaluating refinery performance as a general indication of the excess of the refined product sales amount over the related cost of products sold. Each of the components used in this calculation (net sales and cost of products sold) can be reconciled to corresponding amounts included in the 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. Cost of products sold for the

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second quarter of 2015 includes a non-cash adjustment of $38.2 million in order to state the inventory value at market prices that were lower than cost.

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



	Three Months Ended
	June 30,
	2015		2014		Change
	(In thousands, except per barrel data)
Net refinery sales (including intersegment sales)	$	839,876	$	1,486,741	$	(646,865	)
Refinery cost of products sold (exclusive of depreciation and amortization)	641,872		1,359,500		(717,628		)
Refinery depreciation and amortization	17,255		17,398		(143		)
Gross profit	180,749		109,843		70,906
Plus depreciation and amortization	17,255		17,398		(143		)
Refinery gross margin	$	198,004	$	127,241	$	70,763
Refinery gross margin per refinery throughput barrel	$	21.98	$	15.03	$	6.95
Gross profit per refinery throughput barrel	$	20.07	$	12.98	$	7.09


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


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


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

Gross Margin. Refinery gross margin is calculated as net sales (including intersegment sales) less cost of products sold (exclusive of depreciation and amortization). NTI gross margin increased primarily due to increased gross margin per barrel sold and a volume increase in barrels sold of 1.3% due to higher throughput in the three months ended June 30, 2015. Gross margin for the three months ended June 30, 2015, includes a non-cash adjustment of $38.2 million to state NTI's LIFO inventory at market prices, which were lower than LIFO cost.

Direct Operating Expenses (exclusive of depreciation and amortization). Direct operating expenses increased quarter over quarter due to an increase in higher personnel costs due to higher throughput levels in 2015 and higher contractor costs and material costs related to NTI's flare emission reduction plan. These increases were partially offset by lower natural gas costs during the three months ended June 30, 2015.

Selling, General and Administrative Expenses. The increase relates primarily to higher personnel costs including equity-based compensation expense partially offset by lower insurance costs.

Affiliate Severance Costs. The severance costs incurred during the three months ended June 30, 2014, relate to severance payments resulting from Western's acquisition of NTI's general partner.

Depreciation and Amortization. Depreciation and amortization increased due primarily to increased refining assets placed in service since March 31, 2014, the most significant of which was NTI's waste water treatment plant.

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Six Months Ended June 30, 2015, Compared to the Six Months Ended June 30, 2014



	Six Months Ended
	June 30,
	2015			2014			Change
	(In thousands, except per barrel data)
Statement of Operations Data:
Net sales	$	1,550,596		$	2,756,699		$	(1,206,103	)
Operating costs and expenses:
Cost of products sold (exclusive of depreciation and amortization) (1)	1,089,262			2,396,214			(1,306,952		)
Direct operating expenses (exclusive of depreciation and amortization)	146,053			133,688			12,365
Selling, general and administrative expenses	43,590			49,737			(6,147		)
Affiliate severance costs	—			12,878			(12,878		)
Gain on disposal of assets, net	(311		)	(101		)	(210		)
Depreciation and amortization	38,880			38,347			533
Total operating costs and expenses	1,317,474			2,630,763			(1,313,289		)
Operating income	$	233,122		$	125,936		$	107,186
Key Operating Statistics
Total sales volume (bpd)	101,144			95,822			5,322
Total refinery production (bpd)	96,529			93,139			3,390
Total refinery throughput (bpd) (2)	96,544			92,826			3,718
Per barrel of throughput:
Refinery gross margin (1) (3)	$	21.39		$	16.54		$	4.85
Direct operating expenses (4)	4.70			4.33			0.37

Retail fuel gallons sold (in thousands)	149,259			149,779			(520		)
Retail fuel margin per gallon (5)	$	0.21		$	0.19		$	0.02
Merchandise sales	178,413			168,443			9,970
Merchandise margin (6)	25.9		%	26.2		%	(0.3		)%
Company-operated retail outlets at period end	165			164			1
Franchised retail outlets at period end	99			81			18


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



	Six Months Ended
	June 30,
	2015			2014			Change
	(In thousands)
Realized hedging loss, net	$	(2,765	)	$	(3,105	)	$	340
Unrealized hedging gain, net	1,633			294			1,339
Total hedging loss, net	$	(1,132	)	$	(2,811	)	$	1,679


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

(3)

Refinery gross margin is a per barrel measurement calculated by dividing the difference between net sales and cost of products sold by the refinery's total throughput volumes for the respective periods presented. Refinery net sales include $59.0 million and $569.2 million related to crude oil sales during the first six months of 2015 and 2014, respectively. Refinery gross margin is a non-GAAP performance measure that we believe is useful in evaluating refinery performance as a general indication of the excess of the refined product sales amount over the related cost of products sold. Each of the components used in this calculation (net sales and cost of products sold) can be reconciled to corresponding amounts included in the 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. Cost of products sold for the

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first six months of 2015 includes a non-cash recovery of $49.0 million in order to state the inventory value at market prices that were lower than cost.

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



	Six Months Ended
	June 30,
	2015		2014		Change
	(In thousands, except per barrel data)
Net refinery sales (including intersegment sales)	$	1,529,406	$	2,730,336	$	(1,200,930	)
Refinery cost of products sold (exclusive of depreciation and amortization)	1,155,618		2,452,431		(1,296,813		)
Refinery depreciation and amortization	34,368		34,488		(120		)
Gross profit	339,420		243,417		96,003
Plus depreciation and amortization	34,368		34,488		(120		)
Refinery gross margin	$	373,788	$	277,905	$	95,883
Refinery gross margin per refinery throughput barrel	$	21.39	$	16.54	$	4.85
Gross profit per refinery throughput barrel	$	19.42	$	14.49	$	4.93


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


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


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

per barrel sold. Additionally, gross margin increased due to 5.6% higher sales volumes due to higher throughput in the six months ended June 30, 2015. Gross margin for the six months ended June 30, 2015, includes a non-cash recovery of $49.0 million to state NTI's LIFO inventory at market prices, which were lower than LIFO cost.

Direct Operating Expenses (exclusive of depreciation and amortization). Direct operating expenses increased quarter over quarter as a result of higher personnel costs and chemical costs resulting from higher throughput levels in 2015 and higher material costs and contractor labor costs in 2015 due primarily to NTI's flare emissions reduction plan. These increases were partially offset by lower natural gas costs during the six months ended June 30, 2015.

Selling, General and Administrative Expenses. This decrease relates primarily to lower incentive compensation expense, insurance costs and professional service costs.

Affiliate Severance Costs. The severance costs incurred during the six months ended June 30, 2014, relate to severance payments resulting from Western's acquisition of NTI's general partner.

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WNRL

The WNRL financial and operational data presented includes the historical results of all assets acquired from Western in the Wholesale Acquisition. This acquisition from Western was a transfer 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 WRW into WNRL.

Three Months Ended June 30, 2015, Compared to the Three Months Ended June 30, 2014



	Three Months Ended
	June 30,
	2015			2014		Change
	(In thousands)
Statement of Operations Data:
Net sales	$	734,501		$	970,337	$	(235,836	)
Operating costs and expenses:
Cost of products sold	664,026			905,726		(241,700		)
Direct operating expenses	37,355			36,974		381
Selling, general and administrative expenses	6,250			5,691		559
Loss (gain) on disposal of assets, net	(160		)	18		(178		)
Depreciation and amortization	4,737			4,454		283
Total operating costs and expenses	712,208			952,863		(240,655		)
Operating income	$	22,293		$	17,474	$	4,819



	Three Months Ended
	June 30,
	2015		2014		Change
Key Operating Statistics
Pipeline and gathering (bpd):
Mainline movements:
Permian/Delaware Basin system	43,873		24,196		19,677
Four Corners system (1)	51,486		35,837		15,649
Gathering (truck offloading):
Permian/Delaware Basin system	24,019		26,178		(2,159		)
Four Corners system	12,950		11,188		1,762
Terminalling, transportation and storage (bpd):
Shipments into and out of storage (includes asphalt)	389,220		406,881		(17,661		)
Wholesale:
Fuel gallons sold (in thousands)	310,811		293,204		17,607
Fuel gallons sold to retail (included in fuel gallons sold above) (in thousands)	79,023		65,095		13,928
Fuel margin per gallon (2)	$	0.037	$	0.020	$	0.017
Lubricant gallons sold (in thousands)	3,014		3,068		(54		)
Lubricant margin per gallon (3)	$	0.78	$	0.85	$	(0.07	)
Crude oil trucking volume (bpd)	48,992		37,251		11,741
Average crude oil revenue per barrel	$	2.51	$	2.99	$	(0.48	)


(1)	Some barrels of crude oil in route to Western's Gallup refinery and Permian/Delaware Basin are transported on more than one of our mainlines. 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 WNRL's 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.

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(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 calculated as net sales (including intersegment sales) less cost of products sold (exclusive of depreciation and amortization). WNRL's gross margin increased by 9.1% primarily due to truck freight revenue from increased crude oil gathering activity in the Permian Basin area.

Direct Operating Expenses (exclusive of depreciation and amortization). Direct operating expenses increased quarter over quarter due to an increase in employee expenses resulting from increased headcount primarily to our staff of drivers due to additions to our truck fleet of $1.5 million, partially offset by a decrease in fuel expense for our transportation department of $0.9 million and maintenance expenses of $0.6 million that was primarily due to differences in the timing of the scheduled maintenance during the second quarter of 2015 versus the second quarter of 2014.

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

General and Administrative Expenses. General and administrative expenses increased quarter over quarter due to an increase in professional and legal services ($0.4 million).

Depreciation and Amortization. Depreciation and amortization increased due to the expansion of WNRL's Delaware Basin logistics system and the addition of crude oil tanker trailers during 2014.

Six Months Ended June 30, 2015, Compared to the Six Months Ended June 30, 2014



	Six Months Ended
	June 30,
	2015			2014		Change
	(In thousands)
Statement of Operations Data:
Net sales	$	1,341,897		$	1,834,947	$	(493,050	)
Operating costs and expenses:
Cost of products sold	1,205,727			1,710,543		(504,816		)
Direct operating expenses	72,992			70,657		2,335
Selling, general and administrative expenses	12,181			10,888		1,293
Loss (gain) on disposal of assets, net	(244		)	18		(262		)
Depreciation and amortization	9,475			8,606		869
Total operating costs and expenses	1,300,131			1,800,712		(500,581		)
Operating income	$	41,766		$	34,235	$	7,531

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	Six Months Ended
	June 30,
	2015		2014		Change
Key Operating Statistics
Pipeline and gathering (bpd):
Mainline movements:
Permian/Delaware Basin system	40,213		19,794		20,419
Four Corners system (1)	48,679		38,412		10,267
Gathering (truck offloading):
Permian/Delaware Basin system	23,316		24,182		(866		)
Four Corners system	11,812		11,293		519
Terminalling, transportation and storage (bpd):
Shipments into and out of storage (includes asphalt)	390,263		373,918		16,345
Wholesale:
Fuel gallons sold (in thousands)	614,242		561,018		53,224
Fuel gallons sold to retail (included in fuel gallons sold above) (in thousands)	154,286		126,689		27,597
Fuel margin per gallon (2)	$	0.032	$	0.022	$	0.010
Lubricant gallons sold (in thousands)	5,971		6,092		(121		)
Lubricant margin per gallon (3)	$	0.72	$	0.80	$	(0.08	)
Crude oil trucking volume (bpd)	46,037		32,138		13,899
Average crude oil revenue per barrel	$	2.63	$	3.03	$	(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 of our mainlines. 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 WNRL's 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 calculated as net sales (including intersegment sales) less cost of products sold (exclusive of depreciation and amortization). WNRL's gross margin increased by 9.5% primarily due to truck freight revenue from increased crude oil gathering activity in the Permian Basin area.

Direct Operating Expenses (exclusive of depreciation and amortization). Direct operating expenses increased primarily based on higher employee expenses of $3.2 million resulting from an increase in the number of drivers in our truck fleet. Partially offsetting this increase was a decrease in fuel expense for our transportation department of $1.7 million.

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

General and Administrative Expenses. General and administrative expenses increased primarily due to an increase in professional and legal services ($0.9 million).

Depreciation and Amortization. Depreciation and amortization increased due to the expansion of WNRL's Delaware Basin logistics system and the addition of crude oil tanker trailers during 2014.

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Retail Segment

Three Months Ended June 30, 2015, Compared to the Three Months Ended June 30, 2014



	Three Months Ended
	June 30,
	2015			2014			Change
	(In thousands, except per gallon data)
Statement of Operations Data
Net sales (including intersegment sales)	$	318,072		$	375,232		$	(57,160	)
Operating costs and expenses:
Cost of products sold (exclusive of depreciation and amortization)	272,643			336,381			(63,738		)
Direct operating expenses (exclusive of depreciation and amortization)	33,641			29,950			3,691
Selling, general and administrative expenses	3,109			2,709			400
Gain on disposal of assets, net	(9		)	—			(9		)
Depreciation and amortization	4,031			2,817			1,214
Total operating costs and expenses	313,415			371,857			(58,442		)
Operating income	$	4,657		$	3,375		$	1,282
Key Operating Statistics
Retail fuel gallons sold	90,339			78,143			12,196
Average retail fuel sales price per gallon (net of excise taxes)	$	2.20		$	3.13		$	(0.93	)
Average retail fuel cost per gallon (net of excise taxes)	2.03			2.96			(0.93		)
Fuel margin per gallon (1)	0.17			0.17			—
Merchandise sales	$	79,981		$	68,314		$	11,667
Merchandise margin (2)	29.9		%	28.7		%	1.2		%
Cardlock fuel gallons sold	16,903			17,444			(541		)
Cardlock fuel margin per gallon	$	0.160		$	0.181		$	(0.021	)

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



	Three Months Ended
	June 30,
	2015		2014		Change
	(In thousands, except per gallon data)
Net Sales
Retail fuel sales (net of excise taxes)	$	199,166	$	244,842	$	(45,676	)
Merchandise sales	79,981		68,314		11,667
Cardlock sales	35,782		59,217		(23,435		)
Other sales	3,143		2,859		284
Net sales	$	318,072	$	375,232	$	(57,160	)
Cost of Products Sold
Retail fuel cost of products sold (net of excise taxes)	$	183,471	$	231,385	$	(47,914	)
Merchandise cost of products sold	56,104		48,728		7,376
Cardlock cost of products sold	33,004		56,043		(23,039		)
Other cost of products sold	64		225		(161		)
Cost of products sold	$	272,643	$	336,381	$	(63,738	)
Retail fuel margin per gallon (1)	$	0.17	$	0.17	$	—


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

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

Gross Margin. Gross margin is calculated as net sales (including intersegment sales) less cost of products sold (exclusive of depreciation and amortization). The increase in retail gross margin quarter over quarter was primarily the result of increased same store fuel margins coupled with higher fuel sales volumes and increased merchandise gross margin. The effect of the 32 new retail outlets added during the first half of 2015 and two retail outlets added in the third and fourth quarters of 2014 was an increase in retail gross margin of $5.1 million. The store closed during the fourth quarter of 2014 had a negligible effect on gross margin.

Direct Operating Expenses (exclusive of depreciation and amortization). The increase in direct operating expenses quarter over quarter was primarily due to the addition of the new outlets which generated an additional $4.5 million in current quarter's expenses. This increase was partially offset by decreased same store credit card processing fees ($0.6 million), maintenance expense ($0.3 million) and utilities ($0.1 million).

Selling, general and administrative expenses. The increase in selling, general and administrative expenses was primarily due to increased cardlock employee expenses ($0.5 million) partially offset by decreased same store outside support services ($0.2 million).

Depreciation and Amortization. The increase in depreciation and amortization expense quarter over quarter was primarily due to accelerated depreciation of four closed outlets, accelerated depreciation of retail's point of sale system and additional depreciation incurred from major remodels at three locations. The addition of 32 new retail outlets added during the first half of 2015 and two retail outlets added in the third and fourth quarters of 2014 resulted in an additional $0.4 million in the current quarter's depreciation expense.

Six Months Ended June 30, 2015, Compared to the Six Months Ended June 30, 2014



	Six Months Ended
	June 30,
	2015			2014			Change
	(In thousands, except per gallon data)
Statement of Operations Data
Net sales (including intersegment sales)	$	576,674		$	710,516		$	(133,842	)
Operating costs and expenses:
Cost of products sold (exclusive of depreciation and amortization)	492,818			638,506			(145,688		)
Direct operating expenses (exclusive of depreciation and amortization)	65,995			58,405			7,590
Selling, general and administrative expenses	6,373			5,308			1,065
Gain on disposal of assets, net	(45		)	—			(45		)
Depreciation and amortization	7,317			5,752			1,565
Total operating costs and expenses	572,458			707,971			(135,513		)
Operating income	$	4,216		$	2,545		$	1,671
Key Operating Statistics
Retail fuel gallons sold	174,163			151,530			22,633
Average retail fuel sales price per gallon (net of excise taxes)	$	2.02		$	3.05		$	(1.03	)
Average retail fuel cost per gallon (net of excise taxes)	1.86			2.89			(1.03		)
Fuel margin per gallon (1)	0.16			0.16			—
Merchandise sales	$	150,868		$	128,784		$	22,084
Merchandise margin (2)	29.6		%	28.8		%	0.8		%
Operating retail outlets at period end	262			229			33
Cardlock fuel gallons sold	33,023			34,329			(1,306		)
Cardlock fuel margin per gallon	$	0.173		$	0.172		$	0.001
Operating cardlocks at period end	52			52			—

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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:



	Six Months Ended
	June 30,
	2015		2014		Change
	(In thousands, except per gallon data)
Net Sales
Retail fuel sales (net of excise taxes)	$	351,711	$	461,130	$	(109,419	)
Merchandise sales	150,868		128,784		22,084
Cardlock sales	67,776		114,924		(47,148		)
Other sales	6,319		5,678		641
Net sales	$	576,674	$	710,516	$	(133,842	)
Cost of Products Sold
Retail fuel cost of products sold (net of excise taxes)	$	324,593	$	437,499	$	(112,906	)
Merchandise cost of products sold	106,169		91,704		14,465
Cardlock cost of products sold	61,936		108,985		(47,049		)
Other cost of products sold	120		318		(198		)
Cost of products sold	$	492,818	$	638,506	$	(145,688	)
Retail fuel margin per gallon (1)	$	0.16	$	0.16	$	—


(1)	Retail fuel margin per gallon is a measurement calculated by dividing the difference between retail fuel sales and cost of retail fuel sales 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. Gross margin is calculated as net sales (including intersegment sales) less cost of products sold (exclusive of depreciation and amortization). The increase in retail gross margin was primarily the result of same store higher fuel sales volumes and increased same store merchandise gross margin. The effect of the 32 new retail outlets added during the first half of 2015 and two retail outlets added in the third and fourth quarters of 2014 was an increase in retail gross margin of $8.8 million which was partially offset by a store closure during the fourth quarter of 2014 of $0.1 million.

Direct Operating Expenses (exclusive of depreciation and amortization). The increase in direct operating expenses was primarily due to the addition of the new outlets which generated an additional $8.5 million in expenses. This increase was partially offset by decreased same store credit card processing fees ($1.5 million), maintenance expense ($0.6 million) and utilities ($0.2 million).

Selling, general and administrative expenses. The increase in selling, general and administrative expenses was primarily due to increased cardlock employee expenses ($1.1 million) partially offset by decreased cardlock bad debt expense ($0.2 million).

Depreciation and Amortization. The increase in depreciation and amortization expense was primarily due to accelerated depreciation of four closed outlets, accelerated depreciation of retail's point of sale system and additional depreciation incurred from major remodels at three locations. The addition of 32 new retail outlets added during the first half of 2015 and two retail outlets added in the third and fourth quarters of 2014 resulted in an additional $0.7 million in depreciation expense.

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Outlook

Our refining margins, excluding hedging activities, were stronger in the second quarter of 2015 compared to the second quarter of 2014. The Gulf Coast benchmark 3:2:1 crack spread improved from an average of $17.89 for the six months ended June 30, 2014, to an average of $20.40 for the six months ended June 30, 2015.

Western's and NTI's refining margins in recent years have benefited from the price relationship between WTI crude oil and Brent crude oil. Western and NTI both base their crude oil purchases on pricing tied to WTI. During the second quarter of 2015, the discount of WTI crude oil to Brent crude oil averaged $4.00 per barrel for the quarter compared to an average of $6.62 per barrel for the second quarter of 2014. However, the WTI/Brent discount has been volatile recently due to continued growth of inland crude oil production and new crude oil pipeline capacity additions in the Permian Basin and in Cushing, Oklahoma. The Gulf Coast benchmark 3:2:1 crack spread and the WTI/Brent discount for July 2015 averaged $27.13 and $5.70 per barrel, respectively. Additionally, the WTI Midland/Cushing trade-month discount of $0.60 per barrel for the second quarter of 2015 benefited our El Paso refining margins in the quarter, although it was much lower than the $8.40 Midland/Cushing trade-month discount that we realized in the second quarter of 2014. This differential has continued to narrow and averaged around $0.13 in July 2015. NTI’s location also allows them direct access, via pipeline, to cost-advantaged crude oil from the Bakken Shale in North Dakota and other Canadian crude oils that may price at substantial discounts to WTI. Although crude oil differentials narrowed in the second quarter of 2015, our gasoline and asphalt margins improved during the quarter and contributed to our stronger refining margins. We expect continued volatility in crude oil pricing differentials and crack spreads given the recent drop in Brent and WTI crude oil prices.

During 2014 and the first six months of 2015, we experienced volatility in the pricing of ethanol RINs as refiners essentially achieved full utilization of ethanol in gasoline blends. We expect continued volatility as the industry strives to meet Renewable Fuel Standard obligations.

Liquidity and Capital Resources

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

As of June 30, 2015, we had cash and cash equivalents of $543.9 million, including NTI cash of $127.9 million and WNRL cash of $78.6 million, and had no direct borrowings under the Western, NTI or WNRL revolving credit facilities. WNR, NTI and WNRL had net availability under our revolving credit facilities of $419.5 million, $253.5 million and $299.3 million, respectively. We held restricted cash of $68.3 million remaining from the proceeds generated by the sale of WRW. As a result, Western had $825.2 million in total liquidity as of June 30, 2015, defined as Western’s cash and cash equivalents plus restricted cash and net availability under Western's revolving credit facility.

From time to time, our board of directors has approved share repurchase programs authorizing us to repurchase specified dollar amounts of our outstanding common stock. Our board of directors approved our current $200 million share repurchase program in November of 2014 (the "November 2014 Program") that will expire at the earlier of the exhaustion of the authorized amount or November of 2015. We have repurchased 2.2 million shares of our common stock at a cost of $84.2 million under the November 2014 Program. As of June 30, 2015, we had $115.8 million remaining in authorized expenditures under the November 2014 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.

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Cash Flows

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



	Six Months Ended
	June 30,
	2015			2014			Change
	(In thousands)
Net cash provided by operating activities	$	292,044		$	278,387		$	13,657
Net cash used in investing activities	(14,133		)	(88,449		)	74,316
Net cash used in financing activities	(165,134		)	(126,195		)	(38,939		)
Net increase in cash and cash equivalents	$	112,777		$	63,743		$	49,034

The increase in net cash from operating activities period over period was primarily the result of the increase in net income and the results of our commodity hedging activity as discussed above, offset by changes in our working capital as disclosed in our Condensed Consolidated Statements of Cash Flows for the six months ended June 30, 2015 and 2014.

Cash flows from operating activities for the six months ended June 30, 2015, combined with $300.0 million from the issuance of long-term debt were primarily used for the following investing and financing activities:

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

•Fund capital expenditures ($119.5 million) including the use of $98.7 million of restricted cash;

•Payment of distributions to non-controlling interest holders ($100.3 million);

•Payment of cash dividends ($61.1 million);

•Purchase of treasury stock ($25.0 million); and

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

Cash flows used in operating activities for the six months ended June 30, 2014, were primarily used for the following investing and financing activities:

•Fund capital expenditures ($90.6 million);

•Payments of distributions to non-controlling interest holders ($76.0 million); and

•Payment of cash dividends ($41.5 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 2015 forecasted spending allocation between sustaining, discretionary and regulatory projects for 2015:



	Western (1)		NTI		WNRL		Totals
	(In thousands)
Sustaining	$	45,874	$	26,100	$	11,010	$	82,984
Discretionary	162,129		34,000		31,769		227,898
Regulatory	42,152		9,900		1,387		53,439
Total	$	250,155	$	70,000	$	44,166	$	364,321


(1)	Western's capital expenditure forecast for the full year 2015 is $250.2 million, of which $230.3 million is for our refining segment, $16.5 million for our retail segment and $3.4 million for other general projects.

Our discretionary projects include crude oil logistics projects, such as the new 70 mile pipeline project in the Permian Basin of Southeast New Mexico that was completed in the first quarter of 2015, as well as improvements on existing pipeline in the San Juan Basin in Northwest New Mexico also completed in the first quarter of 2015. WNRL’s discretionary projects include improvement projects of the on-site refined product distribution terminals at the El Paso and Gallup refineries and further expansion of the Mason Station pipeline system.

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Capital Structure

Our capital structure at June 30, 2015 and 2014 was as follows:



	June 30, 2015		June 30, 2014
	(In thousands)
Debt, including current maturities:
Western obligations:
Revolving Credit Facility due 2019	$	—	$	—
Term Loan Credit Facility due 2020	541,750		547,250
6.25% Senior Unsecured Notes due 2021	350,000		350,000
5.50% promissory note due 2015	—		206
Total Western obligations	891,750		897,456
NTI obligations:
Revolving Credit Facility due 2018	—		—
7.125% Senior Secured Notes due 2020	356,490		278,125
Total NTI obligations	356,490		278,125
WNRL obligations:
Revolving Credit Facility due 2018	—		—
7.5% Senior Notes due 2023	300,000		—
Total WNRL obligations	300,000		—
Long-term debt	1,548,240		1,175,581
Equity	2,997,586		2,981,640
Total capitalization	$	4,545,826	$	4,157,221

See Note 9, Long-Term Debt and Note 10, Equity, for further information.

Contractual Obligations and Commercial Commitments

In January 2015, our retail segment entered into leases for 31 additional retail store locations under a master lease agreement. Total average annual commitments for these additional retail store leases are approximately $4.5 million for 20 years. We include a complete summary of our future contractual obligations and commercial commitments as of December 31, 2014 in our 2014 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 2015 cash dividend declarations, payments and scheduled payments through July 31, 2015:

Declaration Date

Record Date

Payment Date

Dividend per Common Share

Total Payment (In thousands)

First quarter

February 6

February 20

March 6

0.30

28,638

Second quarter

April 21

May 5

May 20

0.34

32,476

Third quarter (1)

July 17

July 27

August 12

0.34

—

Total

61,114


(1)	The third quarter 2015 cash dividend of $0.34 per common share will result in an estimated aggregate payment of $32.5 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 June 30, 2015, we held approximately 9.4 million barrels of crude oil, refined product and other inventories valued under the LIFO valuation method with an average cost of $67.53 per barrel. At June 30, 2015, the excess of the current cost of our crude oil, refined products and other feedstocks and blendstocks inventories over aggregated LIFO costs was $52.4 million.

All commodity futures contracts, price swaps and options are recorded at fair value and any changes in fair value between periods are recorded under cost of products sold in our 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 six months ended June 30, 2015 and 2014 and open commodity hedging positions as of June 30, 2015 and December 31, 2014:



	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2015			2014		2015			2014
	(In thousands)
Economic hedging results
Realized hedging gain, net	$	7,823		$	1,812	$	25,376		$	17,556
Unrealized hedging gain (loss), net	(22,287		)	45,379		(42,344		)	119,350
Total hedging gain (loss), net	$	(14,464	)	$	47,191	$	(16,968	)	$	136,906

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	June 30, 2015			December 31, 2014
	(In thousands)
Open commodity hedging instruments (barrels)
Crude oil and refined product futures, net long (short) positions	2,907			(864		)
Refined product crack spread swaps, net short positions	(10,827		)	(8,781		)
Total open barrels commodity hedging instruments, net short positions	(7,920		)	(9,645		)

Fair value of outstanding contracts, net
Other current assets	$	63,258		$	79,722
Other assets	28,031			56,533
Accrued liabilities	(2,620		)	(4,889		)
Other long-term liabilities	(1,047		)	(1,400		)
Fair value of outstanding contracts - unrealized gain, net	$	87,622		$	129,966

During the three and six months ended June 30, 2015 and 2014, we did not have any commodity derivative instruments that were designated or accounted for as hedges.


Item 4.	Controls and Procedures

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 June 30, 2015. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of June 30, 2015.

There were no changes in our internal control over financial reporting during the quarter ended June 30, 2015, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Part II

Other Information

Item 1A. Risk Factors

There have been no material changes from the risk factors disclosed in the section entitled "Risk Factors" in our 2014 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 four separate share repurchase programs authorizing us to repurchase up to $200 million, per program, of our outstanding common stock. Our board of directors approved our current share repurchase program in November 2014 (the "November 2014 Program") that will expire in November 2015. We did not purchase any shares of our common stock during the three months ended June 30, 2015.

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 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 Revolving Credit Agreement and our 2021 Notes, and depends, in part, on our ability to satisfy certain financial covenants.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

None.

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Item 5. Other Information

None.

Item 6. Exhibits

Exhibit Index***



Number		Exhibit Title



31.1*		Certification Statement of Chief Executive Officer of the Company pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

31.2*		Certification Statement of Chief Financial Officer of the Company pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

32.1**		Certification Statement of Chief Executive Officer of the Company pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

32.2**		Certification Statement of Chief Financial Officer of the Company pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

101		Interactive Data Files



*		Filed herewith.

**		Furnished herewith.

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

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SIGNATURES

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.

WESTERN REFINING, INC.




Signature	Title	Date

/s/ Gary R. Dalke	Chief Financial Officer	August 5, 2015
Gary R. Dalke	(Principal Financial Officer)

Attached files

Western Refining, Inc. Reports

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