Western Refining 10-Q 2013 Q2 Quarterly report

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, 2013

OR

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 26, 2013, there were 80,388,178 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	1
Condensed Consolidated Balance Sheets as of June 30, 2013 and December 31, 2012	1
Condensed Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2013 and 2012	2
Condensed Consolidated Statements of Comprehensive Income for the Three and Six Months Ended June 30, 2013 and 2012	3
Condensed Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2013 and 2012	4
Notes to Condensed Consolidated Financial Statements	5
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	32
Item 3. Quantitative and Qualitative Disclosure About Market Risk	62
Item 4. Controls and Procedures	63
Part II. Other Information	63
Item 1A. Risk Factors	63
Item 2. Unregistered Sale of Equity Securities	63
Item 6. Exhibits	65
Signatures	66
EX-10.2
EX-31.1
EX-31.2
EX-32.1
EX-32.2
EX-101 INSTANCE DOCUMENT
EX-101 SCHEMA DOCUMENT
EX-101 CALCULATION LINKBASE DOCUMENT
EX-101 LABELS LINKBASE DOCUMENT
EX-101 PRESENTATION LINKBASE DOCUMENT

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 sections 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 are forward-looking statements that represent management’s beliefs and assumptions based on currently available information. These forward-looking statements relate to matters such as our industry, 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, additions to pipeline capacity in the Permian Basin and at Cushing, Oklahoma, crude oil production in the Permian Basin, a crude oil expansion project in El Paso, expected share repurchases, volatility in pricing of Renewal Identification Numbers ("RINs"), taxes, capital expenditures, liquidity and capital resources, our evaluation of the bank and capital markets for opportunities to deliver additional value to our shareholders, our working capital requirements, our planned share repurchases, and other financial and operating information. Forward-looking statements also include those regarding the timing of completion of certain operational improvements we are making at our refineries, future operational and refinery efficiencies and cost savings, timing of future maintenance turnarounds, the amount or sufficiency of future cash flows and earnings growth, future expenditures, future contributions related to pension and postretirement obligations, our ability to manage our inventory price exposure through commodity hedging instruments, the impact on our business of existing and future state and federal regulatory requirements, environmental loss contingency accruals, projected remediation costs or requirements, and the expected outcomes of legal proceedings in which we are involved. We have used the words “anticipate,” “assume,” “believe,” “budget,” “continue,” “could,” “estimate,” “expect,” “intend,” “may,” “plan,” “potential,” “predict,” “project,” “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. In addition, our business and operations involve numerous risks and uncertainties, many of which 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.

Actual events, results, and outcomes may differ materially from our expectations due to a variety of factors. Although it is not possible to identify all of these factors, they include, among others, the following:

• changes in the underlying demand for our refined products;

• changes in crack spreads;

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

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

• 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;

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

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

• 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 debt instruments;

• actions of customers and competitors;

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

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

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

i

• 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 accrued or insurance coverage;

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

• 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 II — Item 1A. Risk Factors in this Form 10-Q and under Part I — Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2012 ("2012 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 on these forward-looking statements.

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

ii

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, 2013			December 31, 2012
ASSETS
Current assets:
Cash and cash equivalents	$	372,335		$	453,967
Accounts receivable, trade, net of a reserve for doubtful accounts of $1,186 and $1,166 for 2013 and 2012, respectively	351,923			273,087
Inventories	334,571			409,970
Prepaid expenses	123,546			74,041
Other current assets	84,611			81,338
Total current assets	1,266,986			1,292,403
Property, plant, and equipment, net	1,162,897			1,112,484
Intangible assets, net	41,101			41,624
Other assets, net	39,907			33,896
Total assets	$	2,510,891		$	2,480,407
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	511,453		$	439,168
Accrued liabilities	148,587			266,106
Deferred income tax liability, net	46,261			27,710
Current portion of long-term debt	200,626			206
Total current liabilities	906,927			733,190
Long-term liabilities:
Long-term debt, less current portion	350,206			499,657
Deferred income tax liability, net	294,094			282,339
Other liabilities	55,291			56,151
Total long-term liabilities	699,591			838,147
Commitments and contingencies (Note 20)
Shareholders’ equity:
Common stock, par value $0.01, 240,000,000 shares authorized; 91,799,353 and 90,960,640 shares issued, respectively	918			910
Preferred stock, par value $0.01, 10,000,000 shares authorized; no shares issued or outstanding	—			—
Additional paid-in capital	623,455			612,339
Retained earnings	613,207			400,708
Accumulated other comprehensive loss, net of tax	(1,024		)	(1,174		)
Treasury stock, 11,235,524 and 4,022,141 shares, respectively at cost	(332,183		)	(103,713		)
Total shareholders’ equity	904,373			909,070
Total liabilities and shareholders’ equity	$	2,510,891		$	2,480,407

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

1

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,
	2013			2012			2013			2012
Net sales	$	2,429,962		$	2,469,348		$	4,616,179		$	4,808,560
Operating costs and expenses:
Cost of products sold (exclusive of depreciation and amortization)	1,986,883			1,899,684			3,784,067			4,136,186
Direct operating expenses (exclusive of depreciation and amortization)	113,861			116,792			235,721			232,373
Selling, general, and administrative expenses	29,450			27,316			56,002			53,097
Gain on disposal of assets, net	—			—			—			(1,891		)
Maintenance turnaround expense	35			1,862			43,203			2,312
Depreciation and amortization	27,143			22,767			51,475			45,531
Total operating costs and expenses	2,157,372			2,068,421			4,170,468			4,467,608
Operating income	272,590			400,927			445,711			340,952
Other income (expense):
Interest income	235			202			386			395
Interest expense and other financing costs	(14,681		)	(21,808		)	(32,669		)	(45,930		)
Amortization of loan fees	(1,515		)	(1,771		)	(3,119		)	(3,578		)
Loss on extinguishment of debt	(24,719		)	(7,654		)	(46,766		)	(7,654		)
Other, net	101			(279		)	298			1,283
Income before income taxes	232,011			369,617			363,841			285,468
Provision for income taxes	(82,752		)	(131,113		)	(130,863		)	(100,468		)
Net income	$	149,259		$	238,504		$	232,978		$	185,000
Net earnings per share:
Basic	$	1.81		$	2.63		$	2.74		$	2.04
Diluted	1.46			2.19			2.26			1.75
Weighted average common shares outstanding:
Basic	82,390			90,024			84,546			89,684
Diluted	104,729			110,535			106,942			110,163
Cash dividends declared per common share	$	0.12		$	—		$	0.24		$	0.08

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

2

WESTERN REFINING, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

(In thousands)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2013			2012			2013			2012
Net income	$	149,259		$	238,504		$	232,978		$	185,000
Other comprehensive income before tax:
Defined benefit plans:
Pension plan termination adjustment	217			—			217			—
Reclassification of loss to income	13			17			25			35
Other comprehensive income before tax	230			17			242			35
Income tax	(87		)	(6		)	(92		)	(13		)
Other comprehensive income, net of tax	143			11			150			22
Comprehensive income	$	149,402		$	238,515		$	233,128		$	185,022

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

3

WESTERN REFINING, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(In thousands)

	Six Months Ended
	June 30,
	2013			2012
Cash flows from operating activities:
Net income	$	232,978		$	185,000
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	51,475			45,531
Changes in fair value - commodity hedging instruments	(57,968		)	158,407
Reserve for doubtful accounts	77			58
Amortization of loan fees and original issue discount	11,014			11,443
Loss on extinguishment of debt	46,766			7,654
Stock-based compensation expense	3,102			4,154
Deferred income taxes	30,306			(50,723		)
Excess tax benefit from stock-based compensation	8,146			3,387
Loss on disposal of assets, net	55			275
Changes in operating assets and liabilities:
Accounts receivable	(78,913		)	(76,277		)
Inventories	75,399			33,230
Prepaid expenses	(49,505		)	19,772
Other assets	18,209			(4,270		)
Accounts payable and accrued liabilities	(30,868		)	9,293
Other long-term liabilities	(949		)	1,923
Net cash provided by operating activities	259,324			348,857
Cash flows from investing activities:
Capital expenditures	(101,854		)	(59,397		)
Proceeds from the sale of assets	434			291
Decrease in restricted cash	—			220,355
Net cash provided by (used in) investing activities	(101,420		)	161,249
Cash flows from financing activities:
Additions to long-term debt	350,000			—
Payments on long-term debt	(325,157		)	(322,770		)
Debt retirement fees	(24,396		)	(1,415		)
Deferred financing costs	(12,445		)	—
Purchase of treasury stock	(198,789		)	—
Dividends paid	(20,479		)	(7,266		)
Convertible debt redemption	(124		)	—
Excess tax benefit from stock-based compensation	(8,146		)	(3,387		)
Net cash used in financing activities	(239,536		)	(334,838		)
Net increase (decrease) in cash and cash equivalents	(81,632		)	175,268
Cash and cash equivalents at beginning of period	453,967			170,829
Cash and cash equivalents at end of period	$	372,335		$	346,097

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

4

WESTERN REFINING, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. Organization

“Western,” “we,” “us,” “our,” and the "Company" are used to refer to Western Refining, Inc. and, unless the context otherwise requires, our subsidiaries.

We are an independent crude oil refiner and marketer of refined products and also operate retail convenience stores that sell various grades of gasoline, diesel fuel, and convenience store merchandise. We own and operate two refineries: one in El Paso, Texas and one near Gallup in the Four Corners region of northern New Mexico. Primarily, we operate in Arizona, Colorado, the Mid-Atlantic region, New Mexico, and west Texas. In addition to the refineries, we also own and operate stand-alone refined product distribution terminals in Bloomfield and Albuquerque, New Mexico, as well as asphalt terminals in Phoenix and Tucson, Arizona; Albuquerque; and El Paso. As of June 30, 2013, we also operated 222 retail convenience stores in Arizona, Colorado, New Mexico, and Texas; a fleet of crude oil and refined product truck transports; and a wholesale petroleum products distributor that operates in Arizona, California, Colorado, Georgia, Maryland, Nevada, New Mexico, Texas, and Virginia.

Our operations include three business segments: the refining group, the wholesale group, and the retail group. See Note 3, Segment Information for further discussion of our business segments.

2. Basis of Presentation, Significant Accounting Policies, and Recent Accounting Pronouncements

The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with U.S. generally accepted accounting principles (“GAAP”) for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by GAAP for complete financial statements. In the opinion of management, all adjustments (consisting of normal recurring accruals) considered necessary for a fair presentation have been included. Operating results for the three and six months ended June 30, 2013 are not necessarily indicative of the results that may be expected for the year ending December 31, 2013, or for any other period.

The Condensed Consolidated Balance Sheet at December 31, 2012 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, 2012 (“2012 Form 10-K”).

The condensed consolidated financial statements include the accounts of Western Refining, Inc. and our wholly-owned subsidiaries. All intercompany accounts and transactions have been eliminated for all periods presented.

Revenue Recognition

Revenues for products sold are recorded upon delivery and title transfer of the products to customers, when the customer has the assumed risk of loss, and when payment has been received or collection is reasonably assured. Transportation, shipping, and handling costs incurred are included in cost of products sold. Excise and other taxes collected from customers and remitted to governmental authorities are not included in revenues.

Cost Classifications

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

Refining direct operating expenses include direct costs of labor, maintenance materials and services, chemicals and catalysts, natural gas, utilities, and other direct operating expenses. Wholesale direct operating expenses include direct costs of labor, transportation expense, maintenance materials and services, utilities, and other direct operating expenses. Retail direct operating expenses include direct costs of labor, maintenance materials and services, outside services, bank charges, rent expense, utilities, and other direct operating expenses. Direct operating expenses also include insurance expense and property taxes.

5

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Maintenance Turnaround Expense

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

Use of Estimates

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

Recent Accounting Pronouncements

The accounting provisions covering items reclassified from comprehensive income were amended to require disclosure about the nature of the reclassification. These provisions are effective beginning January 1, 2013. The adoption of this guidance did not affect our financial position, results of operations, or cash flows because these requirements only affected disclosures.

The accounting provisions covering balance sheet offsetting related to certain derivative items were amended to require an entity to disclose information about offsetting and related arrangements to enable users of its financial statements to understand the effect of those arrangements on its financial position. These provisions are effective beginning January 1, 2013. The revised provisions did not affect our financial position, results of operations, or cash flows.

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

3. Segment Information

Our operations are organized into three 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 the refining group, the wholesale group, and the retail group. A description of each segment and the principal products follows:

Refining Group. Our refining group currently operates two refineries: one in El Paso, Texas (the “El Paso refinery”) and one near Gallup, New Mexico (the “Gallup refinery”). The refining group also operates a crude oil transportation and pipeline gathering system in New Mexico, an asphalt plant in El Paso, two stand-alone refined product distribution terminals, and four asphalt terminals. Our refineries make various grades of gasoline, diesel fuel, and other products from crude oil, other feedstocks, and blending components. We purchase crude oil, other feedstocks, and blending components from various third-party suppliers. We also acquire refined products through exchange agreements and from various third-party suppliers to supplement supply to our customers. We sell these products through our wholesale group, our retail convenience stores, other independent wholesalers and retailers, commercial accounts, and sales and exchanges with major oil companies. Net sales for the three and six months ended June 30, 2013 includes $6.9 million in business interruption insurance recoveries related to a weather related outage at the El Paso refinery during the first quarter of 2011.

On July 25, 2013, Western Refining Logistics, LP (the “Partnership”), our wholly owned subsidiary, filed a registration statement (see Note 22, Subsequent Event for further discussion). The information contained in this report is neither an offer to sell nor a solicitation of an offer to buy any of the common units offered in the registration statement. Through June 30, 2013, we have made no changes in the manner in which we evaluate the performance of our refining group. However, a successful offering by the Partnership could result in management changing the manner in which the refining group is evaluated in the future.

Wholesale Group. Our wholesale group includes several lubricant and bulk petroleum distribution plants, unmanned fleet fueling operations, and a fleet of refined product and lubricant delivery trucks. Our wholesale group distributes commercial wholesale petroleum products primarily in Arizona, California, Colorado, Georgia, Maryland, Nevada, New Mexico, Texas, and Virginia. The wholesale group purchases petroleum fuels and lubricants from our refining group and from third-party suppliers.

Prior to September 2012, the refined products sold by our wholesale group in the Mid-Atlantic region were purchased from various third parties. On August 31, 2012, we transferred all of our Northeast wholesale inventories to a third party and

6

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

entered into an exclusive supply and marketing agreement with the third party covering activities related to our refined product supply, hedging, and sales in the Mid-Atlantic region. Under the supply agreement, we purchase all of our refined products for sale in the Mid‑Atlantic region from the supplier. We will receive monthly distribution amounts from the supplier equal to one-half of the amount by which our refined product sales price exceeds the supplier's costs of acquiring, transporting, and hedging (including net realized and unrealized hedging gains and losses) the refined product. To the extent our refined product sales do not exceed the refined product costs during any month, we will pay one-half of that amount to the supplier, limited to an aggregate annual amount of $2.0 million.

Retail Group. Our retail convenience stores sell various grades of gasoline, diesel fuel, general merchandise, and beverage and food products to the general public. Our wholesale group supplies the majority of gasoline and diesel fuel that our retail group sells. We purchase general merchandise and beverage and food products from various third-party suppliers. At June 30, 2013 and 2012, the retail group operated 222 service stations and convenience stores or kiosks located in Arizona, Colorado, New Mexico, and Texas.

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

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

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

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. The effects of seasonal demand for gasoline are partially offset by increased demand during the winter months for diesel fuel in the Southwest.

Disclosures regarding our reportable segments with reconciliations to consolidated totals for the three and six months ended June 30, 2013 and 2012 are presented below:

	For the Three Months Ended June 30, 2013
	Refining Group		Wholesale Group		Retail Group		Other			Consolidated
	(In thousands)
Net sales to external customers	$	1,095,146	$	1,023,208	$	311,608	$	—		$	2,429,962
Intersegment sales (1)	906,336		219,123		5,312		—
Operating income (loss) (2)	$	275,512	$	9,161	$	5,872	$	(17,955	)	$	272,590
Other income (expense), net										(40,579		)
Income before income taxes										$	232,011
Depreciation and amortization	$	22,511	$	1,000	$	2,685	$	947		$	27,143
Capital expenditures	30,682		2,171		2,517		859			36,229

(1) Intersegment sales of $1,130.8 million have been eliminated in consolidation.

(2) The effect of our economic hedging activity is included within operating income of our refining group as a component of cost of products sold. Refining cost of products sold includes $78.0 million in net realized and unrealized economic hedging gains.

7

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

	For the Six Months Ended June 30, 2013
	Refining Group		Wholesale Group		Retail Group		Other			Consolidated
	(In thousands)
Net sales to external customers	$	2,073,828	$	1,950,202	$	592,149	$	—		$	4,616,179
Intersegment sales (1)	1,703,740		425,846		10,324		—
Operating income (loss) (2)	$	457,395	$	17,920	$	3,718	$	(33,322	)	$	445,711
Other income (expense), net										(81,870		)
Income before income taxes										$	363,841
Depreciation and amortization	$	42,765	$	1,965	$	5,357	$	1,388		$	51,475
Capital expenditures	91,720		3,835		3,375		2,924			101,854
Total assets at June 30, 2013	1,657,222		265,052		193,058		395,559			2,510,891

(1) Intersegment sales of $2,139.9 million have been eliminated in consolidation.

(2) The effect of our economic hedging activity is included within operating income of our refining group as a component of cost of products sold. Refining cost of products sold includes $47.5 million in net realized and unrealized economic hedging gains.

	For the Three Months Ended June 30, 2012
	Refining Group		Wholesale Group		Retail Group		Other			Consolidated
	(In thousands)
Net sales to external customers	$	1,134,719	$	1,030,518	$	304,111	$	—		$	2,469,348
Intersegment sales (1)	1,036,855		213,504		6,315		—
Operating income (loss) (2)	$	393,445	$	16,134	$	7,900	$	(16,552	)	$	400,927
Other income (expense), net										(31,310		)
Loss before income taxes										$	369,617
Depreciation and amortization	$	18,652	$	950	$	2,605	$	560		$	22,767
Capital expenditures	33,357		1,032		2,509		261			37,159

8

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

(1) Intersegment sales of $1,256.7 million have been eliminated in consolidation.

(2) The effect of our economic hedging activity is included within operating income of our refining and wholesale groups as a component of cost of products sold. Refining cost of products sold includes $36.8 million in net realized and unrealized economic hedging gains and wholesale cost of products sold includes $23.2 million in net realized and unrealized economic hedging gains for the three months ended June 30, 2012.

	For the Six Months Ended June 30, 2012
	Refining Group		Wholesale Group		Retail Group		Other			Consolidated
	(In thousands)
Net sales to external customers	$	2,208,799	$	2,026,018	$	573,743	$	—		$	4,808,560
Intersegment sales (1)	2,106,412		410,068		12,596		—
Operating income (loss) (2)	$	344,151	$	20,585	$	8,378	$	(32,162	)	$	340,952
Other income (expense), net										(55,484		)
Loss before income taxes										$	285,468
Depreciation and amortization	$	37,351	$	1,904	$	5,122	$	1,154		$	45,531
Capital expenditures	54,317		1,623		2,878		579			59,397
Total assets at June 30, 2012	1,521,825		325,353		184,431		378,926			2,410,535

(1) Intersegment sales of $2,529.1 million have been eliminated in consolidation.

(2) The effect of our economic hedging activity is included within operating income of our refining and wholesale groups as a component of cost of products sold. Refining cost of products sold includes $196.2 million in net realized and unrealized economic hedging losses and wholesale cost of products sold includes $2.4 million in net realized and unrealized economic hedging gains for the six months ended June 30, 2012.

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 equivalents, accounts receivable, accounts payable, and accrued liabilities approximated their fair values at June 30, 2013 and December 31, 2012 due to their short-term maturities.

We have posted cash margin with various counterparties to support hedging and trading activities. The cash margin posted is required by counterparties as collateral deposits and cannot be offset against the fair value of open contracts except in the event of default. Certain of our commodity derivative contracts under master netting agreements 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" in the following tables. Fair value amounts by hierarchy level are presented on a gross basis in the tables below.

9

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

The following tables represent our assets and liabilities measured at fair value on a recurring basis as of June 30, 2013 and December 31, 2012, and the basis for that measurement:

	Carrying Value at June 30, 2013			Fair Value Measurement at June 30, 2013 Using								Netting Adjustments			Net Fair Value at June 30, 2013
				Level 1		Level 2			Level 3
	(In thousands)
Gross financial assets:
Current assets - commodity hedging contracts	$	29,261		$	—	$	27,560		$	1,701		$	(2,966	)	$	26,295
Other assets - commodity hedging contracts	1,650			—		314			1,336			(1,650		)	—
Gross financial liabilities:
Accrued liabilities - commodity hedging contracts	(2,966		)	—		(2,966		)	—			2,966			—
Other long-term liabilities - commodity hedging contracts	(17,537		)	—		(16,946		)	(591		)	1,650			(15,887		)
	$	10,408		$	—	$	7,962		$	2,446		$	—		$	10,408

	Carrying Value at December 31, 2012			Fair Value Measurement at December 31, 2012 Using								Netting Adjustments			Net Fair Value at December 31, 2012
				Level 1		Level 2			Level 3
	(In thousands)
Gross financial assets:
Current assets - commodity hedging contracts	$	5,369		$	—	$	5,369		$	—		$	(1,451	)	$	3,918
Other assets - commodity hedging contracts	1,375			—		1,360			15			(1,147		)	228
Gross financial liabilities:
Accrued liabilities - commodity hedging contracts	(37,352		)	—		(37,352		)	—			1,451			(35,901		)
Other long-term liabilities - commodity hedging contracts	(16,951		)	—		(15,289		)	(1,662		)	1,147			(15,804		)
	$	(47,559	)	$	—	$	(45,912	)	$	(1,647	)	$	—		$	(47,559	)

Commodity hedging contracts designated as Level 3 financial assets are jet fuel crack spread swaps for contracts that mature after March 2014 and throughout 2015. Ultra-low sulfur diesel ("ULSD") pricing has had a strong historical correlation to jet fuel crack spread swaps. We estimate the fair value of our Level 3 instruments based on the differential between quoted market settlement prices on ULSD futures and quoted market settlement prices on jet fuel futures for settlement dates corresponding to each of our outstanding Level 3 jet fuel crack spread swaps. As quoted prices for similar assets or liabilities in an active market are available, we reclassify the underlying financial asset or liability and designate as Level 2 prior to final settlement.

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

10

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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, 2013 and 2012.

	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2013			2012		2013			2012
	(In thousands)
Asset (liability) balance at beginning of period	$	(2,536	)	$	1,019	$	(1,647	)	$	2,631
Change in fair value	4,982			68		4,093			(1,544		)
Fair value of trades entered into during the period	—			19		—			19
Fair value reclassification from Level 3 to Level 2	—			—		—			—
Asset balance at end of period	$	2,446		$	1,106	$	2,446		$	1,106

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, 2013 and December 31, 2012, the carrying amount and estimated fair value of our debt was as follows:

	June 30, 2013		December 31, 2012
	(In thousands)
Carrying amount	$	550,832	$	499,863
Fair value	968,666		984,831

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, 2013		December 31, 2012
	(In thousands)
Refined products (1)	$	120,337	$	190,147
Crude oil and other raw materials	180,661		189,249
Lubricants	16,929		13,379
Convenience store merchandise	16,644		17,195
Inventories	$	334,571	$	409,970

(1) Includes $14.9 million and $15.1 million of inventory valued using the first-in, first-out (“FIFO”) valuation method at June 30, 2013 and December 31, 2012, 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 our wholesale and retail groups, refined products inventories are valued under the LIFO valuation method. Lubricants and retail store merchandise are valued under the FIFO valuation method.

As of June 30, 2013 and December 31, 2012, refined products valued under the LIFO method and crude oil and other raw materials totaled 5.0 million barrels and 5.8 million barrels, respectively. At June 30, 2013 and December 31, 2012, the excess of the current cost of these crude oil, refined product, and other feedstock and blendstock inventories over LIFO cost was $207.5 million and $148.3 million, respectively.

11

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

During the three months ended June 30, 2013 and 2012, cost of products sold included net non-cash charges of $18.5 million and credits of $100.7 million, respectively, from changes in our LIFO reserves. During the six months ended June 30, 2013 and 2012, cost of products sold included net non-cash charges of $59.2 million and net non-cash credits of $77.7 million, respectively, from changes in our LIFO reserves.

Average LIFO cost per barrel of our refined products and crude oil and other raw materials inventories as of June 30, 2013 and December 31, 2012 was as follows:

	June 30, 2013					December 31, 2012
	Barrels	LIFO Cost		Average LIFO Cost Per Barrel		Barrels	LIFO Cost		Average LIFO Cost Per Barrel
	(In thousands, except cost per barrel)
Refined products	1,643	$	105,414	$	64.16	2,404	$	175,097	$	72.84
Crude oil and other	3,332	180,662		54.22		3,419	189,249		55.35
	4,975	$	286,076	57.50		5,823	$	364,346	62.57

6. Prepaid Expenses

Prepaid expenses were as follows:

	June 30, 2013		December 31, 2012
	(In thousands)
Prepaid crude oil and other raw materials inventories	$	91,362	$	47,858
Prepaid insurance and other	32,184		26,183
Prepaid expenses	$	123,546	$	74,041

7. Other Current Assets

Other current assets were as follows:

	June 30, 2013		December 31, 2012
	(In thousands)
Material and chemical inventories	$	28,496	$	27,533
Unrealized hedging gains	26,295		3,918
Excise and other taxes receivable	17,873		14,955
Margin account deposits	4,897		29,669
Exchange and other receivables	7,050		5,263
Other current assets	$	84,611	$	81,338

12

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

8. Property, Plant, and Equipment, Net

Property, plant, and equipment, net was as follows:

	June 30, 2013			December 31, 2012
	(In thousands)
Refinery facilities and related equipment	$	1,222,889		$	1,179,418
Pipelines, terminals, and transportation equipment	87,080			76,037
Wholesale and retail facilities and related equipment	223,350			221,674
Other	27,010			23,238
	1,560,329			1,500,367
Accumulated depreciation	(495,938		)	(451,490		)
	1,064,391			1,048,877
Construction in progress	98,506			63,607
Property, plant, and equipment, net	$	1,162,897		$	1,112,484

Depreciation expense was $26.4 million and $49.9 million for the three and six months ended June 30, 2013, respectively, and $21.9 million and $43.8 million for the three and six months ended June 30, 2012, respectively.

9. Intangible Assets, Net

Intangible assets, net were as follows:

	June 30, 2013							December 31, 2012							Weighted Average Amortization Period (Years)
	Gross Carrying Value		Accumulated Amortization			Net Carrying Value		Gross Carrying Value		Accumulated Amortization			Net Carrying Value
	(In thousands)
Amortizable assets:
Licenses and permits	$	20,427	$	(9,765	)	$	10,662	$	20,427	$	(8,971	)	$	11,456	6.8
Customer relationships	7,300		(2,538		)	4,762		7,300		(2,278		)	5,022		9.2
Rights-of-way and other	7,310		(4,015		)	3,295		7,120		(3,401		)	3,719		4.4
	35,037		(16,318		)	18,719		34,847		(14,650		)	20,197
Unamortizable assets:
Trademarks	4,800		—			4,800		4,800		—			4,800
Liquor licenses	17,582		—			17,582		16,627		—			16,627
Intangible assets, net	$	57,419	$	(16,318	)	$	41,101	$	56,274	$	(14,650	)	$	41,624

Intangible asset amortization expense for the three and six months ended June 30, 2013 was $0.7 million and $1.4 million, respectively, based on estimated useful lives ranging from 2 to 23 years. Intangible asset amortization expense for the three and six months ended June 30, 2012 was $0.7 million and $1.5 million, respectively, based on estimated useful lives ranging from 3 to 15 years.

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

Remainder of 2013	$	1,502
2014	2,849
2015	2,371
2016	2,200
2017	2,259
2018	2,258

13

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

10. Other Assets, Net

Other assets, net of amortization, were as follows:

	June 30, 2013		December 31, 2012
	(In thousands)
Unamortized loan fees	$	27,888	$	22,701
Unrealized hedging gains	—		228
Other	12,019		10,967
Other assets, net of amortization	$	39,907	$	33,896

11. Accrued and Other Long-Term Liabilities

Accrued liabilities were as follows:

	June 30, 2013		December 31, 2012
	(In thousands)
Income taxes	$	35,871	$	72,900
Excise taxes	35,028		54,727
Payroll and related costs	34,703		45,989
Professional and other	20,825		21,126
Property taxes	9,674		25,819
Interest	6,325		2,176
Environmental reserves	4,180		3,932
Banking fees and other financing	1,981		2,841
Fair value of open commodity hedging positions, net	—		35,901
Short-term pension obligation	—		695
Accrued liabilities	$	148,587	$	266,106

During the latter half of 2012, we increased our annual property tax accrual estimate by $11.6 million resulting from an increased appraisal from the El Paso Central Appraisal District for 2012. Believing the appraised property values to be in error, we filed a lawsuit in state district court to appeal this appraised value. We were successful in having the appraised property values revised and for the three and six months ended June 30, 2013 have recorded $10.6 million, net of legal fees, as a reduction of our property tax expense.

Other long-term liabilities were as follows:

	June 30, 2013		December 31, 2012
	(In thousands)
Fair value of open commodity hedging positions, net	$	15,887	$	15,804
Capital lease obligations	10,079		10,158
Unrecognized tax benefits	9,952		9,572
Retiree plan obligations	6,315		6,228
Asset retirement obligations	5,196		5,088
Environmental reserves	3,914		3,904
Other	3,948		5,397
Other long-term liabilities	$	55,291	$	56,151

As of June 30, 2013, we had environmental liability accruals of $8.1 million, of which $4.2 million was in accrued liabilities. A portion of these liabilities have been recorded using an inflation factor of 2.7% and a discount rate of 7.1%.

14

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Environmental liabilities of $6.8 million accrued at June 30, 2013 have not been discounted. As of June 30, 2013, the unescalated, undiscounted environmental reserve related to discounted liabilities totaled $1.5 million, leaving $0.2 million to be accreted over time.

The table below summarizes our environmental liability accruals:

	December 31, 2012		Increase		Payments			June 30, 2013
	(In thousands)
Discounted liabilities	$	1,292	$	10	$	(50	)	$	1,252
Undiscounted liabilities	6,544		725		(427		)	6,842
Total environmental liabilities	$	7,836	$	735	$	(477	)	$	8,094

12. Long-Term Debt

Long-term debt was as follows:

	June 30, 2013			December 31, 2012
	(In thousands)
6.25% Senior Unsecured Notes, due 2021	$	350,000		$	—
11.25% Senior Secured Notes, due 2017, net of unamortized discount of $19,001 for 2012	—			305,999
5.75% Convertible Senior Unsecured Notes, due 2014, net of conversion feature of $14,980 and $22,105 for 2013 and 2012, respectively	200,414			193,345
5.50% promissory note, due 2015	418			519
Revolving Credit Agreement	—			—
Long-term debt	550,832			499,863
Current portion of long-term debt (1)	(200,626		)	(206		)
Long-term debt, net of current portion	$	350,206		$	499,657

(1) During the second quarter of 2013 we reclassified the balance of our 5.75% Convertible Senior Unsecured Notes, maturing June 15, 2014, to current portion of long-term debt.

Outstanding amounts under the Revolving Credit Agreement, if any, are included in the current portion of long-term debt.

15

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Interest expense and other financing costs were as follows:

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2013			2012			2013			2012
	(In thousands)
Contractual interest:
6.25% Senior Unsecured Notes	$	5,469		$	—		$	5,773		$	—
11.25% Senior Secured Notes	1,207			9,141			10,115			18,282
5.75% Convertible Senior Unsecured Notes	3,097			3,097			6,194			6,194
Term Loan	—			3,537			—			9,458
Revolving Credit Agreement	—			—			—			—
	9,773			15,775			22,082			33,934
Amortization of original issuance discount:
11.25% Senior Secured Notes	—			727			770			1,446
5.75% Convertible Senior Unsecured Notes	3,581			3,134			7,121			6,232
Term Loan	—			70			—			188
	3,581			3,931			7,891			7,866
Other interest expense	1,651			2,576			3,575			5,174
Capitalized interest	(324		)	(474		)	(879		)	(1,044		)
Interest expense and other financing costs	$	14,681		$	21,808		$	32,669		$	45,930

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

11.25% Senior Secured Notes

On March 11, 2013, we announced the commencement of a cash tender offer and consent solicitation for any and all of our outstanding 11.25% Senior Secured Notes due 2017 (the “2017 Notes”), pursuant to our Offer to Purchase and Consent Solicitation Statement (the “Offer to Purchase”). Holders who validly tendered their 2017 Notes on or before March 22, 2013 (the "Early Tender Deadline") were eligible to receive total consideration of $1,079.60 per $1,000 principal amount of 2017 Notes, which included a consent payment of $20.00 per $1,000 principal amount of 2017 Notes tendered. On March 25, 2013, we announced that the holders of $148.8 million of the 2017 Notes had tendered their 2017 Notes in the tender offer. We used the funds from the 2021 Note offering, detailed below, to fund the Offer to Purchase.

On March 25, 2013, we issued a notice of redemption (with a redemption date of April 24, 2013), to the remaining holders of our 2017 Notes that were not accepted for payment and that remained outstanding on April 24, 2013 (the “Redemption Date” and such 2017 Notes to be redeemed, the “Outstanding 2017 Notes”). The maximum amount of Outstanding 2017 Notes that were subject to redemption was $176.2 million.

The Offer to Purchase expired on April 5, 2013 and an additional $2.5 million of the 2017 Notes were validly tendered and not validly withdrawn, resulting in a total amount of $151.3 million of 2017 Notes that were validly tendered and not validly withdrawn. As a result of the Offer to Purchase, we recorded a loss on extinguishment of debt of $22.0 million including a write-off of $1.9 million of unamortized loan fees during the first quarter of 2013.

On April 24, 2013, we redeemed the remaining Outstanding 2017 Notes at 100.0% of the principal amount of such Outstanding 2017 Notes, plus the Fixed Rate Notes Applicable Premium (as such term is defined in the indenture governing the 2017 Notes) as of the Redemption Date plus accrued and unpaid interest from December 15, 2012 to, but excluding, the Redemption Date. This redemption resulted in a loss on extinguishment of debt of $24.7 million including a write-off of $2.3 million of unamortized loan fees that we have reported in the second quarter of 2013 results of operations.

6.25% Senior Unsecured Notes

Separately on March 25, 2013, we entered into an indenture (the "2021 Indenture") for the issuance of $350.0 million in aggregate principal amount of 6.25% Senior Unsecured Notes due 2021 (the “2021 Notes”). The 2021 Notes are guaranteed on a senior unsecured several and joint basis by each of our 100% owned domestic restricted subsidiaries that guarantee any of our indebtedness under our (a) Revolving Credit Agreement or (b) any other Credit Facilities (as each such term is defined in the 2021 Indenture), or any capital markets debt, in the case of clause (b), in a principal amount of at least $150.0 million. The

16

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

2021 Notes and the guarantees are our and each Guarantor's general obligations and will rank equally and ratably with all of our existing and future senior indebtedness and senior to our and the Guarantors’ subordinated indebtedness. The 2021 Notes will be effectively subordinated in right of payment to all secured indebtedness (including secured indebtedness under the Revolving Credit Agreement) to the extent of the value of the collateral securing such indebtedness. We will pay interest on the 2021 Notes semi-annually in cash in arrears on April 1 and October 1 of each year, beginning on October 1, 2013. The 2021 Notes will mature on April 1, 2021. We used the proceeds from the offering primarily to redeem the 2017 Notes. We incurred transaction and other financing fees of $7.5 million related to the issuance of the 2021 Notes.

The 2021 Indenture contains covenants that limit our ability to, among other things: pay dividends or make other distributions in respect of our capital stock or make other restricted payments; make certain investments; sell certain assets; incur additional debt or issue certain preferred shares; create liens on certain assets to secure debt; consolidate, merge, sell or otherwise dispose of all or substantially all of our assets; restrict dividends or other payments from restricted subsidiaries; and enter into certain transactions with our affiliates. The 2021 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 2021 Notes to be due and payable immediately.

In connection with the sale of the 2021 Notes, we entered into a registration rights agreement, dated March 25, 2013 (the “Registration Rights Agreement”), with the initial purchasers. Under the Registration Rights Agreement, we agreed to register notes having substantially identical terms as the 2021 Notes with the U.S. Securities and Exchange Commission as part of an offer to exchange freely tradable exchange notes for the 2021 Notes. We filed a related Form S-4 on June 14, 2013 that was declared effective by the SEC on June 27, 2013. The exchange offer expired on July 26, 2013. On July 27, 2013, we exchanged all of the previously issued 2021 notes for new notes due 2021 that are registered under the U.S. Securities Act.

5.25% Convertible Senior Unsecured Notes

The Convertible Senior Unsecured Notes (the "2014 Notes") are presently convertible at the option of the holder. The conversion rate as of June 30, 2013 was 103.1929 for each $1,000 of principal amount of the 2014 Notes. The 2014 Notes will also be convertible in any future calendar quarter (prior to maturity) whenever the last reported sale price of our common stock exceeds 130% of the applicable conversion price in effect for the 2014 Notes on the last trading day of the immediately preceding calendar quarter for twenty days in the thirty consecutive trading day period ending on the last trading day of the immediately preceding calendar quarter. If any 2014 Notes are surrendered for conversion, we may elect to satisfy our obligations upon conversion through the delivery of shares of our common stock, in cash, or a combination thereof.

During the second quarter of 2013, $0.1 million in 2014 Notes at par value were presented for conversion. These conversions were settled in cash and resulted in a loss on extinguishment of debt of $4.5 thousand. As of June 30, 2013, the if-converted value of the 2014 Notes exceeded its principal amount by $408.5 million.

Term Loan

In addition to our scheduled Term Loan Credit Agreement ("Term Loan") payment of $0.8 million made during the first quarter of 2012, we made non-mandatory prepayments of $30.0 million and $291.8 million during the first and second quarters of 2012, respectively. As a result of the retirement of our Term Loan in the second quarter of 2012, we recorded a loss on extinguishment of debt of $7.7 million. 

Revolving Credit Agreement

On April 11, 2013, we entered into the Second Amended and Restated Revolving Credit Agreement. Lenders under the Revolving Credit Agreement extended $900.0 million in commitments that mature on April 11, 2018, and incorporate a borrowing base tied to eligible accounts receivable and inventory. The Revolving Credit Agreement also provides for letters of credit and swing line loans and provides for a quarterly commitment fee ranging from 0.25% to 0.50% per annum subject to adjustment based upon the average utilization ratio and letter of credit fees ranging from 1.75% to 2.25% per annum, payable quarterly, subject to adjustment based upon the average excess availability. Borrowings can be either base rate loans plus a margin ranging from 0.75% to 1.25% or LIBOR loans plus a margin ranging from 1.75% to 2.25% subject to adjustment based upon the average excess availability under the Revolving Credit Agreement. Prior to April 11, 2013, the Revolving Credit Agreement included commitments of $1.0 billion maturing on September 22, 2016. Interest rates ranged from 2.50% to 3.25% over LIBOR. Our subsidiaries guarantee the Revolving Credit Agreement on a joint and several basis. The Revolving Credit Agreement is secured by our cash and cash equivalents, accounts receivable, and inventory. We paid $4.5 million in amendment and other financing fees related to the Revolving Credit Agreement that are being amortized over the term of the Revolving Credit Agreement.

17

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

The Revolving Credit Agreement 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. If an event of default under the Revolving Credit Agreement occurs and is continuing, the Administrative Agent at the request of lenders holding a specified percentage of commitments, shall, or with such lenders' consent, may terminate the obligations of the lenders to make loans and the obligations of the issuing banks to issue letters of credit, declare the obligations outstanding under the Revolving Credit Agreement to be immediately due and payable, and/or exercise legal and contractual rights and remedies.

As of June 30, 2013, we had no direct borrowings under the Revolving Credit Agreement, with gross availability of $691.4 million, of which $252.7 million was used for outstanding letters of credit.

13. Shareholders' Equity

Changes to shareholders' equity during the six months ended June 30, 2013 were as follows:

	Shareholders' Equity
	(In thousands)
Balance at December 31, 2012	$	909,070
Net income	232,978
Convertible debt redemption	(124		)
Other comprehensive income, net of tax	150
Dividends	(20,479		)
Stock-based compensation	3,102
Excess tax benefit from stock-based compensation	8,146
Purchase of treasury stock	(228,470		)
Balance at June 30, 2013	$	904,373

Our board of directors have authorized two separate share repurchase programs of up to $200 million under each program(the "July 2012 Program" and the "April 2013 Program"). Through July 26, 2013, we have utilized the entire $200 million authorized under the July 2012 Program and $116.0 million under the April 2013 Program.

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

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

	July 2012 Program			April 2013 Program
	Number of shares purchased	Cost of share purchases (In thousands)		Number of shares purchased	Cost of share purchases (In thousands)
Shares purchased at December 31, 2012	3,324,135	$	82,270	—	$	—
Shares purchased during Q1, 2013	2,071,882	72,768		—	—
Shares purchased at March 31, 2013	5,396,017	155,038		—	—
Shares purchased during Q2, 2013	1,390,348	44,962		3,751,153	110,740
Shares purchased at June 30, 2013	6,786,365	$	200,000	3,751,153	$	110,740

As of June 30, 2013, we had $89.3 million remaining in authorized expenditures under the April 2013 Program. As of July 26, 2013, we have purchased an additional 199,340 shares at a cost of $5.3 million.

18

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

14. Income Taxes

Compared to the federal statutory rate of 35%, our effective tax rate for the three and six months ended June 30, 2013 was 35.7% and 36.0%, respectively. The effective tax rate for both the three and six months ended June 30, 2013 was higher than the statutory rate primarily due to state obligations offset by the Domestic Production Activity Deduction. Compared to the federal statutory rate of 35%, our effective tax rate for both the three and six months ended June 30, 2012 was 35.5% and 35.2%, respectively, primarily due to state tax obligations offset by the Domestic Production Activity Deduction and the generation of new federal tax credits.

The Internal Revenue Service (the “IRS”) is presently conducting an examination of our tax years ending December 31, 2010 and 2009. That examination is in progress and no material adjustments have been proposed. The IRS has completed an examination of our tax years ending December 31, 2008 and 2007. For the 2008 and 2007 years, we have agreed to all IRS adjustments. Due to statutory requirements, all adjustments will be reviewed by the U.S. Joint Committee of Taxation prior to finalizing the audits. For our tax year ending December 31, 2006, we have concluded the IRS audit and filed final Decision Documents in Tax Court. We do not believe the results of any of these examinations or appeals will have a material adverse effect on our financial position, results of operations, or cash flows, but the timing and the results of final determinations on these matters remains uncertain.

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 $26.5 million was provided against the deferred tax assets relating to these NOL carryforwards at June 30, 2013. There was no change in the valuation allowance for the Yorktown NOL carryforwards from December 31, 2012.

As of June 30, 2013, we have recorded a liability of $10.0 million for unrecognized tax benefits of which $0.4 million would affect our effective tax rate if recognized. We recognized $0.3 million and $0.4 million in interest and penalties for the three and six months ended June 30, 2013, respectively.

15. Retirement Plans

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

Pensions

Through December 31, 2012, we distributed $25.8 million from plan assets to plan participants as a result of the temporary idling of Yorktown refining operations in 2010 and resultant termination of all participants of the Yorktown cash balance plan. Since the idling of the Yorktown facility through June 30, 2013, we have contributed $7.2 million to the Yorktown pension plan, including $1.3 million during the current year. We received regulatory approval to terminate the defined benefit plan covering certain previous Yorktown refinery employees and did so during the second quarter of 2013. We have recorded a termination loss of $0.8 million, including $0.2 million reclassified from other comprehensive income during the three and six months ended June 30, 2013.

19

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

The components of the net periodic benefit cost associated with our pension plan for certain previous employees of the Yorktown refinery were as follows:

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2013			2012			2013			2012
	(In thousands)
Net periodic benefit cost includes:
Service cost	$	7		$	—		$	15		$	—
Interest cost	(1		)	55			(3		)	110
Amortization of net actuarial loss	1			8			3			15
Expected return on assets	—			(23		)	—			(45		)
Settlement expense	775			—			775			—
Net periodic benefit cost	$	782		$	40		$	790		$	80

Our benefit obligation at December 31, 2012 for the Yorktown benefit plan was $1.3 million and the benefit plan held $0.6 million in assets.

Postretirement Obligations

The components of the net periodic benefit cost associated with our postretirement medical benefit plans covering certain employees at our El Paso refinery and previous employees of the Yorktown refinery were as follows:

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2013		2012		2013		2012
	(In thousands)
Net periodic benefit cost includes:
Service cost	$	62	$	33	$	125	$	65
Interest cost	35		62		70		125
Amortization of net actuarial loss	12		10		23		20
Net periodic benefit cost	$	109	$	105	$	218	$	210

Our benefit obligation at December 31, 2012 for our postretirement medical benefit plans was $6.5 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,
	2013			2012			2013			2012
	(In thousands)
Beginning of period balance	$	(1,167	)	$	(1,801	)	$	(1,174	)	$	(1,812	)
Current period changes	143			11			150			22
End of period balance	$	(1,024	)	$	(1,790	)	$	(1,024	)	$	(1,790	)

20

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Defined Contribution Plan

We sponsor a 401(k) defined contribution plan under which participants may contribute a percentage of their eligible compensation to various investment choices offered by the plan. We make a safe harbor matching contribution to the account of each participant who is covered under the collective bargaining agreement with the International Union of Operating Engineers in El Paso and has completed 12 months of service equal to 250% of the first 4% of compensation beginning February 1, 2012. During January 2012, the safe harbor matching contribution was 200% of the first 4% of compensation. In addition, participants who were covered by the settlement agreement with the International Union of Operating Engineers in El Paso received a contribution equal to 3% of the compensation paid between January 1, 2012 and January 31, 2012. For all other employees, we matched 1.33% of eligible compensation for each 1% of eligible compensation contributed by the participant up to a maximum of 6% provided the participant had a minimum of one year of service with Western. For the three and six months ended June 30, 2013 and 2012, we expensed $2.3 million, $4.3 million, $1.2 million, and $2.5 million, respectively, in connection with this plan.

16. Crude Oil and Refined Product Risk Management

We enter into crude oil forward contracts to facilitate the supply of crude oil to the refineries. During the six months ended June 30, 2013, we entered into net forward, fixed-price contracts to physically receive and deliver crude oil that qualify as normal purchases and normal sales and are exempt from derivative reporting requirements.

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

The fair value of these contracts is reflected in the 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 to market the hedging instruments at each period end.

The following tables summarize our economic hedging activity for the three and six months ended June 30, 2013 and 2012 and open commodity hedging positions as of June 30, 2013 and December 31, 2012:

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2013		2012		2013			2012
	(In thousands)
Economic hedging activities recognized within cost of products sold
Realized hedging gain (loss), net	$	18,329	$	393	$	(10,489	)	$	(35,366	)
Unrealized hedging gain (loss), net	59,691		59,582		57,968			(158,407		)
Total hedging gain (loss), net	$	78,020	$	59,975	$	47,479		$	(193,773	)

21

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

	June 30, 2013			December 31, 2012
	(In thousands)
Open commodity hedging instruments (bbls)
Crude and refined product futures, net (short) long positions	993			(588		)
Refined product crack spread swaps, net (short) long positions	(23,327		)	(26,683		)
Total open barrels commodity hedging instruments, net (short) long positions	(22,334		)	(27,271		)
Fair value of outstanding contracts, net
Other current assets	$	26,295		$	3,918
Other assets	—			228
Accrued liabilities	—			(35,901		)
Other long-term liabilities	(15,887		)	(15,804		)
Fair value of outstanding contracts - unrealized gain (loss), net	$	10,408		$	(47,559	)

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 on its condensed consolidated balance sheets. We have posted cash margin with various counterparties to support hedging and trading activities. The cash margin posted is required by counterparties as collateral deposits and cannot be offset against the fair value of open contracts except in the event of default.

The following table presents offsetting information regarding Western's derivatives as of June 30, 2013 and December 31, 2012:

	Gross Amounts of Recognized Assets (Liabilities)			Gross Amounts Offset in the Statements of Financial Position			Net Amounts of Assets (Liabilities) Presented in the Statements of Financial Position
As of June 30, 2013
	(In thousands)
Gross financial assets:
Current assets - commodity hedging contracts	$	29,261		$	(2,966	)	$	26,295
Other assets - commodity hedging contracts	1,650			(1,650		)	—
Gross financial liabilities:
Accrued liabilities - commodity hedging contracts	(2,966		)	2,966			—
Other long-term liabilities - commodity hedging contracts	(17,537		)	1,650			(15,887		)
	$	10,408		$	—		$	10,408

22

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

	Gross Amounts of Recognized Assets (Liabilities)			Gross Amounts Offset in the Statements of Financial Position			Net Amounts of Assets (Liabilities) Presented in the Statements of Financial Position
As of December 31, 2012
	(In thousands)
Gross financial assets:
Current assets - commodity hedging contracts	$	5,369		$	(1,451	)	$	3,918
Other assets - commodity hedging contracts	1,375			(1,147		)	228
Gross financial liabilities:
Accrued liabilities - commodity hedging contracts	(37,352		)	1,451			(35,901		)
Other long-term liabilities - commodity hedging contracts	(16,951		)	1,147			(15,804		)
	$	(47,559	)	$	—		$	(47,559	)

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

As of June 30, 2013, we had the following outstanding crude oil and refined product hedging instruments that were entered into as economic hedges. Settlement prices for our unleaded gasoline crack spread swaps range from $13.08 to $26.73 per contract. Settlement prices for our distillate crack spread swaps range from $25.93 to $29.86 per contract. The information presents the notional volume of outstanding contracts by type of instrument and year of maturity (volumes in thousands of barrels):

	Notional Contract Volumes by Year of Maturity
	2013		2014		2015		2016
Inventory positions (futures and swaps):
Crude oil and refined products — net (short) positions	(309	)	—		—		—
Natural gas futures — net (short) long positions	(179	)	493		493		494
Refined product positions (crack spread swaps):
Distillate — net (short) positions	(3,827	)	(10,200	)	(6,525	)	(2,100	)
Unleaded gasoline — net (short) positions	(450	)	(225	)	—		—

17. Stock-Based Compensation

We have two share-based compensation plans, the Western Refining 2006 Long-Term Incentive Plan (the “2006 LTIP”) and the 2010 Incentive Plan of Western Refining (the “2010 Incentive Plan”) that allow for restricted share awards and restricted share unit awards. As of June 30, 2013, there were 14,311 and 3,004,229 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 either a one, three, or five year period and their market value at the date of the grant is amortized over the restricted period on a straight-line basis.

As of June 30, 2013, there were 23,689 and 451,418 restricted shares and restricted share units not vested, respectively, outstanding.

23

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

The components of stock compensation expense were as follows:

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2013		2012		2013		2012
	(In thousands)
Direct operating expenses	$	—	$	80	$	61	$	177
Selling, general, and administrative expenses	1,205		1,996		3,041		3,977
Total stock compensation expense	$	1,205	$	2,076	$	3,102	$	4,154

The computation of the excess tax benefit related to vested restricted shares and restricted share units is presented as follows:

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2013			2012			2013			2012
	(In thousands)
Restricted shares:
Aggregate intrinsic value of vested shares	$	1,194		$	745		$	23,095		$	13,951
Aggregate fair value at grant date of vested shares	226			313			3,918			4,929
	968			432			19,177			9,022
Statutory blended rate	37.80		%	37.54		%	37.80		%	37.54		%
Excess tax benefit	$	366		$	162		$	7,249		$	3,387
Restricted share units:
Aggregate intrinsic value of vested shares	$	4,053		$	1,495		$	5,347		$	1,495
Aggregate fair value at grant date of vested shares	2,334			1,266			2,975			1,266
	1,719			229			2,372			229
Statutory blended rate	37.80		%	37.54		%	37.80		%	37.54		%
Excess tax benefit	$	650		$	86		$	897		$	86

As of June 30, 2013, the aggregate fair value at grant date of outstanding restricted shares and restricted share units was $0.2 million and $11.2 million, respectively. The aggregate intrinsic value of outstanding restricted shares and restricted share units was $0.7 million and $12.7 million, respectively. The unrecognized compensation cost of restricted shares and restricted share units not vested was $0.1 million and $9.6 million, respectively. Unrecognized compensation costs for restricted shares and restricted share units will be recognized over a weighted average period of approximately 0.57 years and 3.17 years, respectively.

24

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

The following table summarizes our restricted share unit and restricted share activity for the three and six months ended June 30, 2013:

	Restricted Share Units				Restricted Shares
	Number of Units		Weighted Average Grant Date Fair Value		Number of Shares		Weighted Average Grant Date Fair Value
Not vested at December 31, 2012	440,860		$	18.24	694,622		$	5.93
Awards granted	150,114		34.84		—		—
Awards vested	(37,136	)	17.25		(628,622	)	5.87
Awards forfeited	—		—		—		—
Not vested at March 31, 2013	553,838		22.83		66,000		6.41
Awards granted	28,224		31.89		—		—
Awards vested	(130,644	)	17.87		(42,311	)	5.33
Awards forfeited	—		—		—		—
Not vested at June 30, 2013	451,418		24.83		23,689		8.35

18. Earnings Per Share

We follow the provisions related to the accounting treatment of certain participating securities for the purpose of determining earnings per share. These provisions address share-based payment awards that have not vested and that contain nonforfeitable rights to dividends or dividend equivalents and states that they are participating securities and should be included in the computation of earnings per share pursuant to the two-class method. As discussed in Note 17, Stock-Based Compensation, we granted shares of restricted stock to certain employees and outside directors. Although ownership of these shares does not transfer to the recipients until the shares have vested, recipients have voting and nonforfeitable dividend rights on these shares from the date of grant. Accordingly, we utilize the two-class method to determine our earnings per share.

25

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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,
	2013			2012			2013			2012
	(In thousands, except per share data)
Basic earnings per common share:
Allocation of earnings:
Net income	$	149,259		$	238,504		$	232,978		$	185,000
Distributed earnings	(9,963		)	—			(20,479		)	(7,265		)
Income allocated to participating securities	(360		)	(2,128		)	(1,092		)	(2,233		)
Distributed earnings allocated to participating securities	26			—			105			91
Undistributed income available to common shareholders	$	138,962		$	236,376		$	211,512		$	175,593
Weighted average number of common shares outstanding (1)	82,390			90,024			84,546			89,684
Basic earnings per common share:
Distributed earnings per share	$	0.12		$	—		$	0.24		$	0.08
Undistributed earnings per share	1.69			2.63			2.50			1.96
Basic earnings per common share	$	1.81		$	2.63		$	2.74		$	2.04

(1) Excludes the weighted average number of common shares outstanding associated with participating securities of 213,324; 436,783; 810,567; and 1,141,289 shares for the three and six months ended June 30, 2013 and 2012, respectively.

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2013		2012		2013		2012
	(In thousands, except per share data)
Diluted earnings per common share:
Net income	$	149,259	$	238,504	$	232,978	$	185,000
Tax effected interest related to convertible debt	4,154		3,892		8,282		7,762
Net income available to common shareholders, assuming dilution	$	153,413	$	242,396	$	241,260	$	192,762
Weighted average diluted common shares outstanding:	104,729		110,535		106,942		110,163
Diluted earnings per common share:	$	1.46	$	2.19	$	2.26	$	1.75

26

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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

	Three Months Ended		Six Months Ended
	June 30,		June 30,
	2013	2012	2013	2012
	(In thousands)
Weighted average number of common shares outstanding	82,390	90,024	84,546	89,684
Common equivalent shares from Convertible Senior Unsecured Notes	22,227	20,047	22,227	20,047
Restricted shares	112	464	169	432
Weighted average number of diluted shares outstanding	104,729	110,535	106,942	110,163

A shareholder's interest in our common stock could become diluted as a result of vestings of restricted shares and restricted share units and the conversion of our Convertible Senior Unsecured Notes into actual shares of our common stock. In calculating our fully diluted earnings per common share, we consider the impact of restricted shares and restricted share units that have not vested and common equivalent shares related to our Convertible Senior Unsecured Notes. We include restricted shares and restricted share units that have not vested in our diluted earnings calculation when the trading price of our common stock equals or exceeds the per share or per share unit grant price. Common equivalent shares from our Convertible Senior Unsecured Notes are generally included in our diluted earnings calculation when net income exceeds certain thresholds above which the effect of the shares becomes dilutive. We calculate the volume of these shares by applying the current conversion rate of 103.1929 to each $1,000 of principal amount of Convertible Senior Unsecured Notes. At June 30, 2012, the conversion rate was 93.0470.

The table below summarizes our 2013 cash dividend declarations, payments, and scheduled payments through July 26, 2013:

	2013
	Declaration Date	Record Date	Payment Date	Dividend per Common Share		Total Payment (In thousands)
First quarter	January 4	January 19	February 13	$	0.12	$	10,516
Second quarter	April 8	April 23	May 8	0.12		9,963
Third quarter (1)	July 17	July 31	August 15	0.18
Total						$	20,479

(1) The third quarter 2013 cash dividend of $0.18 per common share will result in an aggregate payment of $14.5 million.

19. Cash Flows

Cash Equivalents

Cash equivalents totaling $20.0 million consisting of short-term money market deposits were included in the Condensed Consolidated Balance Sheets as of June 30, 2013 and December 31, 2012, respectively.

27

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Supplemental Cash Flow Information

Supplemental disclosures of cash flow information were as follows:

	Six Months Ended
	June 30,
	2013		2012
	(In thousands)
Income taxes paid	$	128,636	$	93,762
Interest paid, excluding amounts capitalized	22,176		39,708

Non-cash investing and financing activities were as follows:

	Six Months Ended
	June 30,
	2013		2012
	(In thousands)
Treasury stock purchased, not yet settled	$	29,681	$	—
Assets acquired through capital lease obligations	—		3,691

20. Contingencies

Environmental Matters

Like 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.

El Paso Refinery

Prior spills, releases, and discharges of petroleum or hazardous substances have impacted the groundwater and certain solid waste management units and other areas at and adjacent to the El Paso refinery. We are currently in the remediation process, in conjunction with Chevron U.S.A., Inc. (“Chevron”), for these areas pursuant to certain agreed administrative orders with the Texas Commission on Environmental Quality (the “TCEQ”; previously known as the Texas Natural Resources Conservation Commission). 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, which Chevron has fulfilled. Chevron also retained control of and liability for certain groundwater remediation responsibilities that are ongoing.

In May 2000, we entered into an Agreed Order with the TCEQ for remediation of the south side of the El Paso refinery property. We purchased a non-cancelable Pollution and Legal Liability and Clean-Up Cost Cap Insurance policy that covers environmental clean-up costs related to contamination that occurred prior to December 31, 1999, including the costs of the Agreed Order activities. The insurance provider assumed responsibility for all environmental clean-up costs related to the Agreed Order up to $20.0 million. 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. Under the policy, environmental costs outside the scope of the Agreed Order are covered up to $20.0 million and require that we pay a deductible of $0.1 million per incident as well as any costs that exceed the covered limits of the insurance policy.

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

28

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

(“EPA Initiative”). On September 2, 2011, the court entered the Consent Decree. Under the EPA Initiative, the EPA is investigating industry-wide noncompliance 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.

Based on the terms of the Consent Decree and current information, we estimate the total capital expenditures necessary to address the Consent Decree issues would be approximately $51.0 million, of which we have already expended $48.3 million, including $15.2 million for the installation of a flare gas recovery system completed in 2007 and $33.1 million for nitrogen oxides (“NOx”) emission controls on heaters and boilers through June 2013. We estimate remaining expenditures of approximately $2.7 million for the NOx emission controls on heaters and boilers during 2013. This amount is included in our estimated capital expenditures for regulatory projects. Under the terms of the Consent Decree, we paid a civil penalty of $1.5 million in September 2011.

In 2004 and 2005, the El Paso refinery applied for and was issued a Texas Flexible Permit by the TCEQ, under which the refinery continues to operate. However, there is an ongoing dispute between the EPA and the Texas Attorney General as to the validity of the state-issued permits. Although we believe our Texas Flexible Permit was federally enforceable, we applied with the TCEQ for, and received in December 2012, a permit amendment obtaining a State Implementation Plan ("SIP"), approved state air quality permit to address concerns raised by the EPA about all flexible permits. No additional capital expenditures are required by the permit amendment.

In November 2012, we proposed to TCEQ that we settle unresolved air enforcement issued to our El Paso refinery between October 2004 and April 2008 and in July 2013 the TCEQ proposed two Agreed Orders with penalties totaling $0.2 million to settle the enforcement. We anticipate settling on or before September 2013. The proposed orders do not require any soil or groundwater remediation or clean-up. Based on current information, we do not believe the requirements of the orders will have a material effect on our business, financial condition, or results of operations.

Four Corners Refineries

Four Corners 2005 Consent Agreements. In July 2005, as part of the EPA Initiative, Giant 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 (the “2005 NMED Agreement”). In January 2009, we and the NMED agreed to an amendment of the 2005 administrative settlement with the NMED (the “2009 NMED Amendment”), which altered certain deadlines and allowed for alternative air pollution controls.

In November 2009, we indefinitely suspended refining operations at the Bloomfield refinery. We currently operate the site, including certain remaining tanks and equipment, as a stand-alone products distribution terminal and crude storage facility for our Gallup refinery. An amendment to the 2009 NMED Amendment, which became effective June 25, 2012, reflects the indefinite suspension as of 2009.

Based on current information and the 2009 NMED Amendment as amended in June 2012 to reflect the indefinite suspension of refining operations at our Bloomfield facility and to delay NOx controls on heaters, boilers, and a Fluid Catalytic Cracking Unit (the "FCCU") at our Gallup refinery, we estimated $51.0 million in total capital expenditures after January 2009. We expended $11.3 million through 2011 and $37.6 million during 2012. During the first six months of 2013, we spent an additional $1.8 million to complete the project. These capital expenditures were primarily for installation of emission controls on the heaters, boilers, and FCCU, and for reducing sulfur in fuel gas to reduce emissions of sulfur dioxide, NOx, and particulate matter from our Gallup refinery. We will incur additional capital expenditures to implement one or more FCCU off‑set projects. One FCCU off-set project is to be completed by the end of 2014 and the others are to be completed by the end of 2017. The 2009 NMED Amendment also provided for a $2.3 million penalty. We completed payment of the penalty between November 2009 and September 2010 to fund Supplemental Environmental Projects. We paid an additional penalty of $0.4 million in July 2012 associated with the June 2012 amendment. Implementation of the requirements in the 2009 NMED Amendment, as amended in June 2012, will not result in any soil or groundwater remediation or clean-up costs.

Bloomfield 2007 NMED Remediation Order. In July 2007, we received a final administrative compliance order from the NMED alleging that releases of contaminants and hazardous substances that have occurred at the Bloomfield refinery over the course of its operation prior to June 1, 2007 have resulted in soil and groundwater contamination. Among other things, the order requires that we investigate the extent of such releases, perform interim remediation measures, and implement corrective measures. Prior to July 2007, with the approval of the NMED and the New Mexico Oil Conservation Division, we placed into operation certain remediation measures which remain operational. As of June 30, 2013, we have expended $3.3 million and

29

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

have accrued the remaining estimated costs of $3.9 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 (the "Gallup 2007 RCRA Inspection”) 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 have paid penalties totaling $0.2 million pursuant to the settlement. We do not expect implementation of the requirements in the final settlement will result in any additional soil or groundwater remediation or clean-up costs not otherwise required. We estimated capital expenditures of approximately $38.8 million to upgrade the wastewater treatment plant at the Gallup refinery pursuant to the requirements of the final settlement. We expended $20.8 million through 2011, $17.1 million during 2012 on the upgrade of the wastewater treatment plant, $0.4 million during the first six months of 2013, and expect to spend the remaining $0.5 million during 2013. The final settlement deadline was modified in September 2010 to establish May 31, 2012 as the deadline for completing startup of the upgraded plant. After negotiating an extension of this deadline with the EPA, we completed startup on August 12, 2012.

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. The settlement will not result in any groundwater remediation or clean-up costs.

Yorktown Refinery

Yorktown 1991 and 2006 Orders. In December 2011, our subsidiaries sold the Yorktown refinery, an adjacent parcel of land, and all other related real estate and assets. As part of this transaction, the purchaser agreed to assume all obligations and remaining work required by the EPA. The purchaser agreed to indemnify us for costs associated with the EPA order, following the sale, with the exception of the completion and related liability for construction of the second phase of the Corrective Action Measures Unit (the "CAMU"). We have completed construction of this phase of the CAMU and have incurred substantially all costs anticipated to complete this work. We and the purchaser agreed that the purchaser would replace Giant as the respondent under the EPA order. The replacement is pending the EPA's agreement.

Legal Matters

Over the last several years, lawsuits have been filed in numerous states alleging that methyl tertiary butyl ether (“MTBE”), a high octane blendstock used by many refiners in producing specially formulated gasoline, has contaminated water supplies and/or damaged natural resources. Our subsidiary, Western Refining Yorktown, Inc., is currently a defendant in a lawsuit brought by the State of New Jersey alleging damage to the State of New Jersey’s natural resources.

Owners of a small hotel in Aztec, New Mexico filed a lawsuit in San Juan County, New Mexico alleging migration of underground gasoline onto their property from underground storage tanks located on a retail store property across the street, which is owned by our subsidiary. Plaintiffs claim a component of the gasoline, MTBE, has contaminated their property as a result of this release. The Trial Court granted summary judgment against Plaintiffs and dismissed all claims related to the alleged 1992 release. On appeal by Plaintiffs to the New Mexico Court of Appeals, the Court reversed and reinstated certain of its claims but only to the extent they relate to releases that occurred after January 1, 1999.

A lawsuit has been filed in the Federal District Court for the District of New Mexico by certain Plaintiffs who allege the Bureau of Indian Affairs (the “BIA”) acted improperly in approving certain rights-of-way on land allotted to the individual Plaintiffs (each, an "Allottee") by the Navajo Nation, Arizona, New Mexico, and Utah (the “Navajo Nation”). The lawsuit names us and numerous other defendants (“Rights-of-Way Defendants”) and seeks imposition of a constructive trust and asserts these Rights-of-Way Defendants are in trespass on the Allottee’s lands. The Court dismissed Plaintiffs’ claims in this matter. Plaintiffs then attempted to re-file these claims with the Department of Interior, which also dismissed Plaintiffs claims. Plaintiffs are now attempting to appeal this dismissal within the Department of Interior.

Regarding the claims asserted against us referenced above, potentially applicable factual and legal issues have not been resolved; and we have yet to determine if a liability is probable. We do not believe the potential settlement of any of the asserted claims discussed above would have a material effect on our financial condition, results of operations, or cash flows; however, we cannot reasonably estimate the range of any loss associated with these matters. Accordingly, we have not recorded a liability for these pending lawsuits.

30

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Other Matters

The EPA has issued Renewable Fuels Standards ("RFS"), implementing mandates to blend renewable fuels into the petroleum fuels produced at our refineries. Annually, the EPA establishes a volume of renewable fuels that refineries must blend into their refined petroleum fuels. To the extent we are unable to blend at the applicable rate, we must purchase Renewable Identification Numbers ("RIN"). Although we anticipate that we will internally generate most of the RINs required to meet our obligations, including a carryover of 2012 RINs, the volatility of the RIN market is such that the impact of the RINs that we do purchase on our cost of products sold thus far in 2013 is greater than in 2012. The net cost of meeting our obligations through RIN purchases was $8.3 million and $12.8 million for the three and six months ended June 30, 2013, respectively, and $2.1 million and $3.3 million for the three and six months ended June 30, 2012, respectively.

In late 2011, the EPA initiated enforcement proceedings against companies it believes produced invalid RINs. We purchased RINs to satisfy a portion of our obligations under the Renewable Fuels Standard program for calendar year 2010 and had purchased some RINs the EPA considered invalid. In April 2012, we entered into an administrative settlement with the EPA that required us to pay a penalty of less than $0.1 million. We continue to purchase RINs to satisfy our obligations under the RFS program, and we understand the EPA continues to investigate invalid RINs. While we do not know if the EPA will identify other RINs we have purchased as being invalid or what actions the EPA would take, at this time we do not expect any such action would have a material effect on our financial condition, results of operations, or cash flows.

On July 2, 2013, the Office of the Navajo Tax Commission (the “Commission”) informed Giant Four Corners, Inc. (“Four Corners”) that it was seeking to impose penalties in the total amount of $1.5 million for allegedly operating 15 retail convenience stores on the Navajo Nation without a Fuel Retailer's License for the week of January 1-7, 2013. Four Corners believes these penalties are inappropriate and is challenging the proposed imposition of any penalties under the facts and circumstances related to the renewal of this License. No amounts have been accrued for this matter as of June 30, 2013.

On July 24, 2013, the Commission informed Western Refining Wholesale, Inc. (“Western Wholesale”) that it was seeking to impose penalties in the total amount of $4.1 million for allegedly transporting and distributing fuel on the Navajo Nation without a Fuel Distributor's License or a Fuel Carrier's License for the week of January 1-7, 2013. Western Wholesale believes these penalties are inappropriate and is challenging the proposed imposition of any penalties under the facts and circumstances related to the renewal of these Licenses. No amounts have been accrued for this matter as of June 30, 2013.

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.

21. Related Party Transactions

Effective November 30, 2012, an entity controlled by one of our officers purchased the building and related lease agreement of certain office space that we and other commercial tenants occupy in El Paso, Texas. The lease agreement expires in May 2017. Under the terms of the lease, we make annual payments of $0.2 million. For the three and six months ended June 30, 2013, we made rental payments under this lease to the related party of $0.06 million and $0.11 million, respectively. We have no amounts due as of June 30, 2013 related to this lease agreement.

22. Subsequent Event

On July 25, 2013, Western Refining Logistics, LP (the “Partnership”), our wholly owned subsidiary, filed a registration statement on Form S-1 with the U.S. Securities and Exchange Commission in connection with a proposed initial public offering of its common units representing limited partner interests. The number of common units to be offered and the price range for the offering have not yet been determined. The Partnership was formed by Western to own, operate, develop, and acquire crude oil and refined products logistics assets. Headquartered in El Paso, Texas, the Partnership expects its initial assets will include pipeline and gathering assets and terminalling, transportation, and storage assets in the Southwestern portion of the U.S. At the date of this report, the registration statement is not effective. The completion of the offering is subject to numerous conditions, including market conditions, and we can provide no assurance that it will be successfully completed. The information contained in this report is neither an offer to sell nor a solicitation of an offer to buy any of the common units in the initial public offering.

31

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 management’s current expectations, estimates, and projections about our business and operations. The cautionary statements made in this report should be read as applying to all related forward-looking statements wherever they appear in this report. Our actual results may differ materially from those currently anticipated and expressed in such forward-looking statements as a result of a number of factors, including those we discuss under Part I, Item 1A. “Risk Factors” included in our Annual Report onForm 10-Kfor the year ended December 31, 2012, or 2012 Form 10-K, and elsewhere in this report. You should read such “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., or WNR, and its subsidiaries, unless the context otherwise requires or where otherwise indicated.

Company Overview

We are an independent crude oil refiner and marketer of refined products and also operate retail convenience stores that sell various grades of gasoline, diesel fuel, and convenience store merchandise. We own and operate two refineries with a total crude oil throughput capacity of 153,000 barrels per day ("bpd"). In addition to our 128,000 bpd refinery in El Paso, Texas, we own and operate a refinery near Gallup, New Mexico, with a throughput capacity of 25,000 bpd. Our primary operating areas encompass Arizona, Colorado, the Mid-Atlantic region, New Mexico, and west Texas. In addition to the refineries, we also own and operate stand-alone refined product distribution terminals in Albuquerque and Bloomfield, New Mexico, as well as asphalt terminals in Phoenix and Tucson, Arizona; Albuquerque; and El Paso. As of June 30, 2013, we also operated 222 retail convenience stores in Arizona, Colorado, New Mexico, and Texas; a fleet of crude oil and refined product truck transports; and a wholesale petroleum products distributor that operates in Arizona, California, Colorado, Georgia, Maryland, Nevada, New Mexico, Texas, and Virginia.

We report our operating results in three business segments: the refining group, the wholesale group, and the retail group. Our refining group currently operates the two refineries and related refined product distribution terminals and asphalt terminals. At the refineries, we refine crude oil and other feedstocks into refined products such as gasoline, diesel fuel, jet fuel, and asphalt. We market refined products to a diverse customer base including wholesale distributors and retail chains. Our wholesale group distributes gasoline, diesel fuel, and lubricant products. Our retail group operates retail convenience stores and sells gasoline, diesel fuel, and merchandise. See Note 3, Segment Information, in the Notes to Condensed Consolidated Financial Statements included elsewhere in this quarterly report for detailed information on our operating results by segment.

On July 25, 2013, Western Refining Logistics, LP (the “Partnership”), our wholly owned subsidiary, filed a registration statement on Form S-1 with the U.S. Securities and Exchange Commission in connection with a proposed initial public offering of its common units representing limited partner interests. The number of common units to be offered and the price range for the offering have not yet been determined. Western formed the Partnership to own, operate, develop and acquire crude oil and refined product logistics assets. Headquartered in El Paso, Texas, the Partnership expects its initial assets will include pipeline and gathering assets and terminalling, transportation, and storage assets in the Southwestern portion of the U.S. At the date of this report, the registration statement is not effective. The completion of the offering is subject to numerous conditions, including market conditions, and we can provide no assurance that it will be successfully completed. The information contained in this report is neither an offer to sell nor a solicitation of an offer to buy any of the common units in the initial public offering.

Major Influences on Results of Operations

Refining. Our net sales fluctuate significantly with movements in refined product prices and the cost of crude oil and other feedstocks. The spread between our cost of crude oil and our sales prices for refined products is the primary factor affecting our earnings and cash flows from operations. Factors driving the movement in petroleum based commodities pricing includes supply and demand for crude oil, gasoline, and other refined products. Supply and demand for these products depend on changes in domestic and foreign economies; weather conditions; domestic and foreign political affairs; production levels; logistics constraints; availability of imports; marketing of competitive fuels; price differentials between various types of crude oils; and Renewable Fuel Standards and other government regulations.

Other impacts to our overall refinery gross margins include the sale of lower value products such as residuum and propane as well as refinery production loss. Higher crude costs tend to have a negative effect on the margin for lower value product sales. Our refinery product yield volume is less than our total refinery throughput volume; a higher yield loss negatively impacts our gross margin. Also affecting refining margins within refinery cost of products sold is the impact of our economic hedging activity entered into 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. Consolidated cost of products sold for the six months ended June 30, 2013 includes $47.5 million of realized and non-cash unrealized net gains from our economic

32

hedging activities, which is recorded in refining cost of products sold. The non-cash unrealized net gains included in this total were $58.0 million for the period. Our results of operations are also significantly affected by our refineries’ direct operating expenses, including the cost of natural gas used for fuel and the cost of electricity. Natural gas prices have historically been volatile. Typically, electricity prices fluctuate with natural gas prices.

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. The effects of seasonal demand for gasoline are partially offset by increased demand during the winter months for diesel fuel in the Southwest. Refining margins remain volatile and our results of operations may not reflect these historical seasonal trends.

Safety, reliability, and the environmental performance of our refineries’ operations are critical to our financial performance. Unplanned downtime of our refineries generally results in lost refinery gross margin opportunity, increased maintenance costs, and a temporary increase in working capital investment and inventory. We attempt to mitigate the financial impact of planned downtime, such as a turnaround or other major maintenance project, through a planning process that considers product availability, the margin environment, and the availability of resources to perform the required maintenance.

Periodically we have planned maintenance turnarounds at our refineries that are expensed as incurred. We completed a refinery maintenance turnaround at our Gallup refinery during October 2012. In the first quarter of 2013, we completed a scheduled maintenance turnaround for the north side units of the El Paso refinery. In addition to planned outages, we occasionally experience unplanned downtime due to circumstances outside of our control. Certain of these outages qualify for reimbursement under our business interruption insurance coverage, and we record these reimbursements as revenues. Net sales for the three and six months ended June 30, 2013 includes $6.9 million in business interruption insurance recoveries for a weather related claim from the first quarter of 2011.

The nature of our business requires us to maintain substantial quantities of crude oil and refined product inventories. We have no control over the changing market value of our crude oil and refined products inventories. Our inventory of crude oil and the majority of our refined products are valued at the lower of cost or market under the last-in, first-out, or LIFO, inventory valuation methodology. If the market value of our inventories decline below our cost basis, we would record a write-down of our inventories resulting in a non-cash charge to our cost of products sold. Under the LIFO inventory valuation method, this write-down is subject to recovery in future periods to the extent the market values of our inventories equal our cost basis relative to any LIFO inventory valuation write-downs previously recorded. See Note 5, Inventories, in the Notes to Condensed Consolidated Financial Statements included in this quarterly report for more information on the impact of LIFO inventory accounting.

Wholesale. Earnings and cash flows from our wholesale business segment are primarily affected by the sales volumes and margins of gasoline, diesel fuel, and lubricants sold. 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.

Historically, we purchased refined products to sell through our wholesale group in the Mid-Atlantic region from various third parties. On August 31, 2012, we entered into an exclusive supply and marketing agreement with a third party covering activities related to our refined product supply, hedging, and sales in the Mid-Atlantic region. Under the supply agreement, we will receive monthly distribution amounts from the supplier equal to one-half of the amount by which our refined product sales exceeds the supplier's costs of acquiring, transporting, and hedging the refined product. To the extent our refined product sales do not exceed the refined product costs during any month, we will 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.

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

33

Critical Accounting Policies and Estimates

We prepare our financial statements in conformity with U.S. generally accepted accounting principles, or 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 2012 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 either will not have a significant impact on our accounting or reporting or that such impact will not be material to our financial position, results of operations, and cash flows when implemented.

34

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, 2013 and 2012. 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 EndedJune 30, 2013 Compared to the Three Months EndedJune 30, 2012

	Three Months Ended
	June 30,
	2013			2012			Change
	(In thousands, except per share data)
Statements of Operations Data
Net sales (1)	$	2,429,962		$	2,469,348		$	(39,386	)
Operating costs and expenses:
Cost of products sold (exclusive of depreciation and amortization) (1)	1,986,883			1,899,684			87,199
Direct operating expenses (exclusive of depreciation and amortization) (1)	113,861			116,792			(2,931		)
Selling, general, and administrative expenses	29,450			27,316			2,134
Maintenance turnaround expense	35			1,862			(1,827		)
Depreciation and amortization	27,143			22,767			4,376
Total operating costs and expenses	2,157,372			2,068,421			88,951
Operating income	272,590			400,927			(128,337		)
Other income (expense):
Interest income	235			202			33
Interest expense and other financing costs	(14,681		)	(21,808		)	7,127
Amortization of loan fees	(1,515		)	(1,771		)	256
Loss on extinguishment of debt	(24,719		)	(7,654		)	(17,065		)
Other, net	101			(279		)	380
Income before income taxes	232,011			369,617			(137,606		)
Provision for income taxes	(82,752		)	(131,113		)	48,361
Net income	$	149,259		$	238,504		$	(89,245	)
Basic earnings per share	$	1.81		$	2.63		$	(0.82	)
Diluted earnings per share	$	1.46		$	2.19		$	(0.73	)
Dividends declared per common share	$	0.12		$	—		$	0.12
Weighted average basic shares outstanding	82,390			90,024			(7,634		)
Weighted average dilutive shares outstanding	104,729			110,535			(5,806		)

(1) Excludes $1,130.8 million and $1,256.7 million of intercompany sales; $1,127.7 million and $1,254.9 million of intercompany cost of products sold; and $3.1 million and $1.8 million of intercompany direct operating expenses for the three months ended June 30, 2013 and 2012, respectively.

35

	Three Months Ended
	June 30,
	2013			2012			Change
	(In thousands)
Key Operating Statistics
Fuel sales volume (bbls) (including intersegment sales)
Refining	16,767			17,445			(678		)
Wholesale	9,588			9,194			394
Retail	1,825			1,689			136
Total fuel sales volume (1)	28,180			28,328			(148		)
Costs and expenses (net of intersegment costs)
Refining	$	789,729		$	714,214		$	75,515
Wholesale	1,009,927			1,010,624			(697		)
Retail	301,088			291,638			9,450
Total operating costs	$	2,100,744		$	2,016,476		$	84,268
Economic Hedging Activities Recognized Within Cost of Products Sold
Realized hedging gain, net	$	18,329		$	393		$	17,936
Unrealized hedging gain, net	59,691			59,582			109
Total hedging gain, net	$	78,020		$	59,975		$	18,045
Cash Flow Data
Net cash provided by (used in):
Operating activities	$	294,957		$	306,014		$	(11,057	)
Investing activities	160,003			116,135			43,868
Financing activities	(330,990		)	(297,047		)	(33,943		)
Other Data
Adjusted EBITDA (2)	$	240,413		$	365,897		$	(125,484	)
Capital expenditures	36,229			37,159			(930		)

(1) 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 13.1% of our total consolidated sales volumes for the three months ended June 30, 2013. We distribute the majority of the refined products that we purchase through our wholesale sales activities in the Mid-Atlantic region where we satisfy our refined product customer sales requirements through a third-party supply agreement.

(2) Adjusted EBITDA represents earnings before interest expense and other financing costs, amortization of loan fees, provision for income taxes, depreciation, amortization, maintenance turnaround expense, and certain other non-cash income and expense items. However, Adjusted EBITDA is not a recognized measurement under 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:

36

• 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. The following table reconciles net income to Adjusted EBITDA for the periods presented:

	Three Months Ended
	June 30,
	2013			2012			Change
	(In thousands)
Net income	$	149,259		$	238,504		$	(89,245	)
Interest expense and other financing costs	14,681			21,808			(7,127		)
Provision for income taxes	82,752			131,113			(48,361		)
Amortization of loan fees	1,515			1,771			(256		)
Depreciation and amortization	27,143			22,767			4,376
Maintenance turnaround expense	35			1,862			(1,827		)
Loss on extinguishment of debt	24,719			7,654			17,065
Unrealized gain on commodity hedging transactions	(59,691		)	(59,582		)	(109		)
Adjusted EBITDA	$	240,413		$	365,897		$	(125,484	)

Overview. The decrease in net income was primarily due to decreases in our refining and wholesale segment margins resulting in part from lower crude oil cost advantages relative to waterborne crude oil. Between periods, our commodity hedging activities resulted in a $17.9 million increase in our refining margins for 2013 over 2012. We discuss economic hedging gains and losses in detail within our Refining Segment analysis under Refinery Gross Margin. The net increase to non-product related operating costs in 2013 over 2012 resulted from greater selling, general, and administrative costs and depreciation expense offset by decreases in direct operating expenses and maintenance and turnaround costs.

We analyze segment margins as a function of net sales less cost of products sold (exclusive of depreciation and amortization). At a consolidated level, our margin decreased by $126.6 million due to decreases of $119.6 million, $6.7 million, and $0.3 million from our refining, wholesale, and retail groups, respectively, net of intercompany transactions that eliminate in consolidation.

Direct Operating Expenses (exclusive of depreciation and amortization). The decrease in direct operating expenses resulted from decreases of $4.6 million and $0.1 million from our refining and wholesale groups, respectively, partially offset by an increase from our retail group of $1.7 million, net of intercompany transactions that eliminate in consolidation.

Selling, General, and Administrative Expenses. The increase in selling, general, and administrative expenses resulted from increases of $1.0 million, $0.8 million, and $0.3 million in our corporate overhead, refining group, and wholesale group, respectively.

Maintenance Turnaround Expense. During the three months ended June 30, 2013, we incurred turnaround expenses in preparation for a planned 2014 turnaround at the El Paso refinery. During the three months ended June 30, 2012, we incurred turnaround expenses in connection with the third quarter 2012 turnaround at our Gallup refinery. The Gallup turnaround was completed in October 2012.

Depreciation and Amortization. The increase between periods is primarily due to additional depreciation at our Gallup refinery ($2.3 million) resulting from additional assets capitalized at Gallup during the third and forth quarters of 2012, and additional depreciation at our El Paso refinery ($1.4 million) resulting from additional assets capitalized during the first quarter of 2013.

37

Operating Income. The decrease was primarily the result of lower quarter over quarter refining margins, greater selling, general, and administrative expenses, and depreciation expense, partially offset by lower direct operating expenses and turnaround costs.

Interest Income. Interest income for the three months ended June 30, 2013 and 2012 remained relatively unchanged.

Interest Expense and Other Financing Costs. The decrease was attributable to lower debt levels and lower average cost of borrowing during the three months ended June 30, 2013 compared to the same period in 2012.

Amortization of Loan Fees. The decrease was due to the retirement of our Term Loan and Senior Secured Notes and resultant write-off of related loan fees.

Loss on Extinguishment of Debt. We recorded a loss on extinguishment of debt for the three months ended June 30, 2013 resulting from the tender offer for our Senior Secured Notes. The loss recorded for the three months ended June 30, 2012 was attributable to the prepayment of our Term Loan.

Other, Net. Other expense, net for 2012 includes a legal expense compared to rental revenues in the current period.

Provision for Income Taxes. We recorded income tax expense for the three months ended June 30, 2013 and 2012. The effective tax rates for the three months ended June 30, 2013 and 2012 were 35.7% and 35.5%, respectively, compared to the federal statutory rate of 35%. The effective tax rates for both periods were slightly higher primarily due to state obligations offset by the Domestic Production Activity Deduction.

See additional analysis under the Refining Segment, Wholesale Segment, and Retail Segment.

38

Six Months EndedJune 30, 2013 Compared to the Six Months EndedJune 30, 2012

	Six Months Ended
	June 30,
	2013			2012			Change
	(In thousands, except per share data)
Statements of Operations Data
Net sales (1)	$	4,616,179		$	4,808,560		$	(192,381	)
Operating costs and expenses:
Cost of products sold (exclusive of depreciation and amortization) (1)	3,784,067			4,136,186			(352,119		)
Direct operating expenses (exclusive of depreciation and amortization) (1)	235,721			232,373			3,348
Selling, general, and administrative expenses	56,002			53,097			2,905
Gain on disposal of assets, net	—			(1,891		)	1,891
Maintenance turnaround expense	43,203			2,312			40,891
Depreciation and amortization	51,475			45,531			5,944
Total operating costs and expenses	4,170,468			4,467,608			(297,140		)
Operating income	445,711			340,952			104,759
Other income (expense):
Interest income	386			395			(9		)
Interest expense and other financing costs	(32,669		)	(45,930		)	13,261
Amortization of loan fees	(3,119		)	(3,578		)	459
Loss on extinguishment of debt	(46,766		)	(7,654		)	(39,112		)
Other, net	298			1,283			(985		)
Income before income taxes	363,841			285,468			78,373
Provision for income taxes	(130,863		)	(100,468		)	(30,395		)
Net income	$	232,978		$	185,000		$	47,978
Basic earnings per share	$	2.74		$	2.04		$	0.70
Diluted earnings per share	$	2.26		$	1.75		$	0.51
Dividends declared per common share	$	0.24		$	0.08		$	0.16
Weighted average basic shares outstanding	84,546			89,684			(5,138		)
Weighted average dilutive shares outstanding	106,942			110,163			(3,221		)

(1) Excludes $2,139.9 million and $2,529.1 million of intercompany sales; $2,134.7 million and $2,525.8 million of intercompany cost of products sold; and $5.2 million and $3.3 million of intercompany direct operating expenses for the six months ended June 30, 2013 and 2012, respectively.

39

	Six Months Ended
	June 30,
	2013			2012			Change
	(In thousands)
Key Operating Statistics
Fuel sales volume (bbls) (including intersegment sales)
Refining	31,224			34,392			(3,168		)
Wholesale	18,055			17,937			118
Retail	3,561			3,298			263
Total fuel sales volume (1)	52,840			55,627			(2,787		)
Costs and expenses (net of intersegment costs)
Refining	$	1,516,353		$	1,813,310		$	(296,957	)
Wholesale	1,924,292			1,998,914			(74,622		)
Retail	579,143			556,335			22,808
Total operating costs	$	4,019,788		$	4,368,559		$	(348,771	)
Economic Hedging Activities Recognized Within Cost of Products Sold
Realized hedging loss, net	$	(10,489	)	$	(35,366	)	$	24,877
Unrealized hedging gain (loss), net	57,968			(158,407		)	216,375
Total hedging gain (loss), net	$	47,479		$	(193,773	)	$	241,252
Cash Flow Data
Net cash provided by (used in):
Operating activities	$	259,324		$	348,857		$	(89,533	)
Investing activities	(101,420		)	161,249			(262,669		)
Financing activities	(239,536		)	(334,838		)	95,302
Other Data
Adjusted EBITDA (2)	$	483,105		$	548,880		$	(65,775	)
Capital expenditures	101,854			59,397			42,457
Balance Sheet Data (at end of period)
Cash and cash equivalents	$	372,335		$	346,097		$	26,238
Working capital	360,059			685,819			(325,760		)
Total assets	2,510,891			2,410,535			100,356
Total debt	550,832			491,798			59,034
Shareholders’ equity	904,373			1,005,125			(100,752		)

(1) 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 15.3% of our total consolidated sales volumes for the six months ended June 30, 2013. The majority of the purchased refined products are distributed through our wholesale refined product sales activities in the Mid-Atlantic region where we satisfy our refined product customer sales requirements through a third-party supply agreement.

(2) Adjusted EBITDA represents earnings before interest expense and other financing costs, amortization of loan fees, provision for income taxes, depreciation, amortization, maintenance turnaround expense, and certain other non-cash income and expense items. However, Adjusted EBITDA is not a recognized measurement under GAAP. Our management believes that the presentation of Adjusted EBITDA is useful to investors because it is frequently used by securities

40

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. The following table reconciles net income to Adjusted EBITDA for the periods presented:

	Six Months Ended
	June 30,
	2013			2012		Change
	(In thousands)
Net income	$	232,978		$	185,000	$	47,978
Interest expense and other financing costs	32,669			45,930		(13,261		)
Provision for income taxes	130,863			100,468		30,395
Amortization of loan fees	3,119			3,578		(459		)
Depreciation and amortization	51,475			45,531		5,944
Maintenance turnaround expense	43,203			2,312		40,891
Loss on extinguishment of debt	46,766			7,654		39,112
Unrealized (gain) loss on commodity hedging transactions	(57,968		)	158,407		(216,375		)
Adjusted EBITDA	$	483,105		$	548,880	$	(65,775	)

Overview. The increase in net income was primarily due to the difference in results from our commodity hedging activities between periods coupled with a decrease in interest and other financing costs. We discuss economic hedging gains and losses in greater detail within our Refining Segment analysis under Refinery Gross Margin. Offsetting these positive impacts to net income were increases in maintenance turnaround expense, losses on extinguishment of debt, and a greater provision for income taxes.

We analyze segment margins as a function of net sales less cost of products sold (exclusive of depreciation and amortization). At a consolidated level, our margin increased by $159.7 million due largely to an increase in our refining margins of $163.6 million, which is a reflection of unrealized commodity hedging gains and losses recorded within cost of products sold. The wholesale and retail groups recognized a margin decrease of $3.5 million and $0.4 million, respectively, net of intercompany transactions that eliminate in consolidation.

Direct Operating Expenses (exclusive of depreciation and amortization). The increase in direct operating expenses resulted from increases of $4.0 million and $1.6 million from our retail and refining groups, respectively, partially offset by a decrease from our wholesale group of $2.3 million, net of intercompany transactions that eliminate in consolidation.

Selling, General, and Administrative Expenses. The increase in selling, general, and administrative expenses resulted from increases of $1.1 million, $0.9 million, and $0.9 million in our refining group, corporate overhead, and wholesale group, respectively.

41

Gain on Disposal of Assets, Net. The net gain during the six months ended June 30, 2012 was related to sales of assets from our refining and wholesale groups of $1.4 million and $0.5 million, respectively.

Maintenance Turnaround Expense. During the six months ended June 30, 2013, we incurred turnaround expenses primarily associated with the planned turnaround of the north side units of our El Paso Refinery that was completed in the first quarter of 2013 and the planned 2014 El Paso turnaround. During the six months ended June 30, 2012, we incurred turnaround expenses in connection with the planned turnaround at our Gallup refinery. The Gallup turnaround began during the third quarter of 2012 and was completed in October 2012.

Depreciation and Amortization. The increase between periods is primarily due to additional depreciation at our Gallup refinery ($4.1 million) resulting from additional assets capitalized during the third and fourth quarters of 2012 and at our El Paso refinery ($1.6 million) related to first quarter of 2013 capital additions. This increase was partially offset by a decrease in the depreciation and amortization associated with refining logistics ($0.3 million).

Operating Income. The increase was primarily the result of gains from commodity hedging activities compared to losses in the prior year, a total impact of $241.3 million. Partially offsetting the increase were higher maintenance turnaround expenses and depreciation and amortization expense.

Interest Income. Interest income for the six months ended June 30, 2013 and 2012 remained relatively unchanged.

Interest Expense and Other Financing Costs. The decrease was attributable to lower debt levels and lower average cost of borrowing during the six months ended June 30, 2013 compared to the same period in 2012.

Amortization of Loan Fees. The decrease was due to the retirement of our Term Loan and Senior Secured Notes and resultant write-off of related loan fees.

Loss on Extinguishment of Debt. We recorded a loss on extinguishment of debt for the six months ended June 30, 2013 resulting from the tender offer for our Senior Secured Notes. The loss recorded for the six months ended June 30, 2012 was attributable to the prepayment of our Term Loan.

Other, Net. Other expense, net for 2012 includes amounts primarily related to a distribution from a one-time transaction that occurred through a partnership investment we hold ($1.4 million).

Provision for Income Taxes. We recorded income tax expense for the six months ended June 30, 2013 and 2012. The effective tax rates for the six months ended June 30, 2013 and 2012 were 36.0% and 35.2%, respectively, compared to the federal statutory rate of 35%. The effective tax rates for both periods were slightly higher primarily due to state obligations offset by the Domestic Production Activity Deduction.

See additional analysis under the Refining Segment, Wholesale Segment, and Retail Segment.

42

Refining Segment

Three Months EndedJune 30, 2013 Compared to the Three Months EndedJune 30, 2012

	Three Months Ended
	June 30,
	2013		2012		Change
	(In thousands, except per barrel data)
Net sales (including intersegment sales)	$	2,001,482	$	2,171,574	$	(170,092	)
Operating costs and expenses:
Cost of products sold (exclusive of depreciation and amortization) (1)	1,622,728		1,674,490		(51,762		)
Direct operating expenses (exclusive of depreciation and amortization)	73,338		76,579		(3,241		)
Selling, general, and administrative expenses	7,358		6,546		812
Maintenance turnaround expense	35		1,862		(1,827		)
Depreciation and amortization	22,511		18,652		3,859
Total operating costs and expenses	1,725,970		1,778,129		(52,159		)
Operating income	$	275,512	$	393,445	$	(117,933	)
Key Operating Statistics
Total sales volume (bpd)	184,248		191,704		(7,456		)
Total refinery production (bpd)	158,650		155,487		3,163
Total refinery throughput (bpd) (2)	161,985		157,960		4,025
Per barrel of throughput:
Refinery gross margin (1) (3)	$	25.69	$	34.58	$	(8.89	)
Refinery gross margin excluding hedging activities (1) (3)	20.40		32.02		(11.62		)
Gross profit (1) (3)	24.17		33.28		(9.11		)
Direct operating expenses (4)	4.98		5.33		(0.35		)

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

All Refineries (El Paso and Gallup)

	Three Months Ended
	June 30,
	2013	2012	Change
Key Operating Statistics
Refinery product yields (bpd):
Gasoline	83,885	80,085	3,800
Diesel and jet fuel	65,096	64,699	397
Residuum	5,869	6,491	(622	)
Other	3,800	4,212	(412	)
Total refinery production (bpd)	158,650	155,487	3,163
Refinery throughput (bpd):
Sweet crude oil	118,336	120,862	(2,526	)
Sour crude oil	27,867	26,823	1,044
Other feedstocks and blendstocks	15,782	10,275	5,507
Total refinery throughput (bpd) (2)	161,985	157,960	4,025

43

El Paso Refinery

	Three Months Ended
	June 30,
	2013		2012		Change
Key Operating Statistics
Refinery product yields (bpd):
Gasoline	65,805		63,467		2,338
Diesel and jet fuel	58,263		57,137		1,126
Residuum	5,869		6,491		(622		)
Other	3,021		3,259		(238		)
Total refinery production (bpd)	132,958		130,354		2,604
Refinery throughput (bpd):
Sweet crude oil	93,992		97,862		(3,870		)
Sour crude oil	27,867		26,823		1,044
Other feedstocks and blendstocks	13,777		7,472		6,305
Total refinery throughput (bpd) (2)	135,636		132,157		3,479
Total sales volume (bpd)	148,271		156,792		(8,521		)
Per barrel of throughput:
Refinery gross margin (1) (3)	$	19.46	$	31.91	$	(12.45	)
Direct operating expenses (4)	3.30		3.91		(0.61		)

Gallup Refinery

	Three Months Ended
	June 30,
	2013		2012		Change
Key Operating Statistics
Refinery product yields (bpd):
Gasoline	18,080		16,618		1,462
Diesel and jet fuel	6,833		7,562		(729		)
Other	779		953		(174		)
Total refinery production (bpd)	25,692		25,133		559
Refinery throughput (bpd):
Sweet crude oil	24,344		23,000		1,344
Other feedstocks and blendstocks	2,005		2,803		(798		)
Total refinery throughput (bpd) (2)	26,349		25,803		546
Total sales volume (bpd)	35,977		34,911		1,066
Per barrel of throughput:
Refinery gross margin (1) (3)	$	24.26	$	31.95	$	(7.69	)
Direct operating expenses (4)	10.41		7.98		2.43

44

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

	Three Months Ended
	June 30,
	2013		2012			Change
	(In thousands)
Realized hedging gain (loss), net	$	18,329	$	(22,809	)	$	41,138
Unrealized hedging gain, net	59,691		59,582			109
Total hedging gain, net	$	78,020	$	36,773		$	41,247

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

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

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

	Three Months Ended
	June 30,
	2013		2012		Change
	(In thousands, except per barrel data)
Net sales (including intersegment sales)	$	2,001,482	$	2,171,574	$	(170,092	)
Cost of products sold (exclusive of depreciation and amortization)	1,622,728		1,674,490		(51,762		)
Depreciation and amortization	22,511		18,652		3,859
Gross profit	356,243		478,432		(122,189		)
Plus depreciation and amortization	22,511		18,652		3,859
Refinery gross margin	$	378,754	$	497,084	$	(118,330	)
Refinery gross margin per refinery throughput barrel	$	25.69	$	34.58	$	(8.89	)
Gross profit per refinery throughput barrel	$	24.17	$	33.28	$	(9.11	)

(4) 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.

Overview. The decrease in operating income, excluding commodity hedging activities, was primarily attributable to lower refining margins influenced by a weaker refining margin environment during the current quarter. During the quarter our margins saw the negative impact of the narrowing differential between WTI crude oil and Brent crude oil and the decline of the WTI Midland/Cushing discount at our El Paso refinery. While these commodity discounts were still positive for the majority of the quarter, the overall margin benefit was less in this quarter when compared to the prior year. We discuss these discounts further under Refinery Gross Margin below. Partially offsetting the overall decrease in operating income were lesser quarter over quarter direct operating expenses and turnaround expenses. The higher throughput volumes were the result of the expansion of our Gallup refinery that was completed in October 2012 and increased intermediate feedstock throughput volumes at our El Paso refinery partially offset by third-party pipeline supply issues during the quarter that reduced crude oil throughput at El Paso. These third-party pipeline supply issues were resolved during the quarter.

Refinery Gross Margin. Refinery gross margin is a function of net sales (including intersegment sales) less cost of products sold (exclusive of depreciation and amortization). Refinery gross margin decreased quarter over quarter due to decreases in our sales volumes and average selling price per barrel coupled with an increase in the average per barrel cost of crude oil and feedstocks. The increase in the cost of crude oil and feedstocks was partially offset by an increase in net realized

45

and unrealized economic hedging gains. We enter into hedge contracts to manage our exposure to commodity price risks or to fix sales margins on future gasoline and distillate production. Unrealized mark-to-market gains and losses related to our economic hedging instruments are the result of differences between forward crack spreads and the fixed margins from our hedge contracts. We incur unrealized commodity hedging gains when forward spreads are valued beneath our fixed contract margins. We record hedging gains or losses in cost of product sold which directly impacts our refining gross margin. Our current quarter refining gross margin included greater net realized and unrealized commodity hedging gains compared to the second quarter of 2012.

Excluding the impact of hedging activities, refining margin per throughput barrel decreased consistent with the decrease in industry benchmarks. The Gulf Coast benchmark 3:2:1 crack spread fell to $23.61 in the second quarter of 2013 from $29.07 in the second quarter of 2012. We base all of our crude oil purchases on pricing tied to WTI, which in recent quarters has traded at a large discount to Brent crude oil. During the second quarter this differential declined to an average of $8.36 per barrel and, while it positively impacted our margins, the extent of benefit was less than in the same period in 2012. During 2012 and in the first quarter of 2013 our refining margins reflected the increased price differential between WTI Cushing crude oil and WTI Midland crude oil. During the second quarter of 2013 at our El Paso refinery this differential averaged only $0.08 per barrel compared to $4.55 for the second quarter of 2012.

In addition to supply side impacts, our refining margins were affected by the higher cost of RINs. The net cost of RINs was $8.3 million for the three months ended June 30, 2013 compared to $2.1 million for the three months ended June 30, 2012. Total refinery throughput increased by 0.4 million barrels quarter over quarter primarily due to increased intermediate feedstock runs subsequent to the turnaround of the north side units of our El Paso refinery during the first quarter of 2013 partially offset by reduced crude oil throughput at El Paso. Our refined product sales volume decreased to 16.8 million barrels during the second quarter of 2013 from 17.4 million barrels during the second quarter of 2012.

Direct Operating Expenses (exclusive of depreciation and amortization). Direct operating expenses decreased quarter over quarter primarily due to lower property tax expense ($10.0 million) and environmental expenses ($1.9 million) associated with disposal of waste material at the Gallup refinery, partially offset by higher energy expenses ($3.2 million) due to an increase in cost for natural gas and employee expenses ($3.4 million). The decrease in property tax expense was the result of a revised property appraisal and resultant refund of property taxes paid for 2012.

Selling, General, and Administrative Expenses. Selling, general, and administrative expenses increased quarter over quarter primarily due to higher employee expenses ($0.7 million) related to higher incentive compensation.

Maintenance Turnaround Expense. During the three months ended June 30, 2013, we incurred turnaround expenses in preparation for a planned 2014 turnaround at the El Paso refinery. During the three months ended June 30, 2012, we incurred turnaround expenses in connection with the turnaround at our Gallup refinery. The Gallup turnaround began during the third quarter of 2012 and was completed in October 2012.

Depreciation and Amortization. Depreciation and amortization increased due to additional depreciation at our Gallup refinery ($2.3 million) and El Paso refinery ($1.4 million) primarily resulting from additional assets capitalized during the third and fourth quarters of 2012 for Gallup and the first quarter of 2013 for El Paso.

46

Six Months EndedJune 30, 2013 Compared to the Six Months EndedJune 30, 2012

	Six Months Ended
	June 30,
	2013		2012			Change
	(In thousands, except per barrel data)
Net sales (including intersegment sales)	$	3,777,568	$	4,315,211		$	(537,643	)
Operating costs and expenses:
Cost of products sold (exclusive of depreciation and amortization) (1)	3,064,880		3,768,035			(703,155		)
Direct operating expenses (exclusive of depreciation and amortization)	155,213		151,688			3,525
Selling, general, and administrative expenses	14,112		13,056			1,056
Gain on disposal of assets, net	—		(1,382		)	1,382
Maintenance turnaround expense	43,203		2,312			40,891
Depreciation and amortization	42,765		37,351			5,414
Total operating costs and expenses	3,320,173		3,971,060			(650,887		)
Operating income	$	457,395	$	344,151		$	113,244
Key Operating Statistics
Total sales volume (bpd)	172,506		188,998			(16,492		)
Total refinery production (bpd)	139,787		149,164			(9,377		)
Total refinery throughput (bpd) (2)	142,288		151,396			(9,108		)
Per barrel of throughput:
Refinery gross margin (1) (3)	$	27.67	$	19.86		$	7.81
Refinery gross margin excluding hedging activities (1) (3)	25.83		26.98			(1.15		)
Gross profit (1) (4)	26.01		18.50			7.51
Direct operating expenses (4)	6.03		5.51			0.52

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

All Refineries (El Paso and Gallup)

	Six Months Ended
	June 30,
	2013	2012	Change
Key Operating Statistics
Refinery product yields (bpd):
Gasoline	75,794	77,450	(1,656	)
Diesel and jet fuel	55,124	62,001	(6,877	)
Residuum	4,981	5,409	(428	)
Other	3,888	4,304	(416	)
Total refinery production (bpd)	139,787	149,164	(9,377	)
Refinery throughput (bpd):
Sweet crude oil	109,280	115,133	(5,853	)
Sour crude oil	24,635	24,683	(48	)
Other feedstocks and blendstocks	8,373	11,580	(3,207	)
Total refinery throughput (bpd) (2)	142,288	151,396	(9,108	)

47

El Paso Refinery

	Six Months Ended
	June 30,
	2013		2012		Change
Key Operating Statistics
Refinery product yields (bpd):
Gasoline	58,703		60,960		(2,257		)
Diesel and jet fuel	48,162		54,871		(6,709		)
Residuum	4,981		5,409		(428		)
Other	3,127		3,383		(256		)
Total refinery production (bpd)	114,973		124,623		(9,650		)
Refinery throughput (bpd):
Sweet crude oil	85,577		92,846		(7,269		)
Sour crude oil	24,635		24,683		(48		)
Other feedstocks and blendstocks	6,683		8,747		(2,064		)
Total refinery throughput (bpd) (2)	116,895		126,276		(9,381		)
Total sales volume (bpd)	138,437		155,837		(17,400		)
Per barrel of throughput:
Refinery gross margin (1) (3)	$	25.76	$	26.85	$	(1.09	)
Direct operating expenses (4)	4.47		4.23		0.24

Gallup Refinery

	Six Months Ended
	June 30,
	2013		2012		Change
Key Operating Statistics
Refinery product yields (bpd):
Gasoline	17,091		16,490		601
Diesel and jet fuel	6,962		7,130		(168		)
Other	761		921		(160		)
Total refinery production (bpd)	24,814		24,541		273
Refinery throughput (bpd):
Sweet crude oil	23,703		22,287		1,416
Other feedstocks and blendstocks	1,690		2,833		(1,143		)
Total refinery throughput (bpd) (2)	25,393		25,120		273
Total sales volume (bpd)	34,069		33,129		940
Per barrel of throughput:
Refinery gross margin (1) (3)	$	25.46	$	26.89	$	(1.43	)
Direct operating expenses (4)	10.25		8.27		1.98

48

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

	Six Months Ended
	June 30,
	2013			2012			Change
	(In thousands)
Realized hedging loss, net	$	(10,489	)	$	(37,771	)	$	27,282
Unrealized hedging gain (loss), net	57,968			(158,407		)	216,375
Total hedging gain (loss), net	$	47,479		$	(196,178	)	$	243,657

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

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

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

	Six Months Ended
	June 30,
	2013		2012		Change
	(In thousands, except per barrel data)
Net sales (including intersegment sales)	$	3,777,568	$	4,315,211	$	(537,643	)
Cost of products sold (exclusive of depreciation and amortization)	3,064,880		3,768,035		(703,155		)
Depreciation and amortization	42,765		37,351		5,414
Gross profit	669,923		509,825		160,098
Plus depreciation and amortization	42,765		37,351		5,414
Refinery gross margin	$	712,688	$	547,176	$	165,512
Refinery gross margin per refinery throughput barrel	$	27.67	$	19.86	$	7.81
Gross profit per refinery throughput barrel	$	26.01	$	18.50	$	7.51

(4) 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.

Overview. The increase in operating income was primarily attributable to an unrealized hedging gain of $58.0 million compared to an unrealized hedging loss of $158.4 million for the six months ended June 30, 2013 and 2012, respectively. Partially offsetting the overall increase in operating income were greater turnaround expenses and lower throughput volumes associated with the planned turnaround of the north side units of our El Paso refinery that was completed during the first quarter. The lower throughput volumes resulting from the planned north side shutdown reduced our overall refining margins.

Refinery Gross Margin. Refinery gross margin is a function of net sales (including intersegment sales) less cost of products sold (exclusive of depreciation and amortization). Refinery gross margin increased due to a gain from net realized and unrealized economic hedging activities versus a loss in the prior year. We enter into hedge contracts to manage our exposure to commodity price risks or to fix sales margins on future gasoline and distillate production. Unrealized mark-to-market gains and losses related to our economic hedging instruments are the result of differences between forward crack spreads and the fixed margins from our hedge contracts. We incur unrealized commodity hedging losses when forward spreads are in excess of our fixed contract margins. Hedging gains or losses are included within cost of product sold, directly impacting our refining gross margin.

49

Excluding the impact of hedging activities, refining margin per throughput barrel decreased. We continue to realize the positive impact from the discount of WTI crude oil to Brent crude oil, and more recently the WTI Midland/Cushing discount at our El Paso Refinery, however, less so in this period when compared to the prior year. The Gulf Coast benchmark 3:2:1 crack spread decreased from $27.19 in the first six months of 2012 to $25.90 in the first six months of 2013. We base all of our crude oil purchases on pricing tied to WTI, and our margins were positively impacted by the discount of WTI crude oil to Brent crude oil. The WTI/Brent discount has been volatile over the past two years due in part to new and proposed crude oil pipeline capacity additions in the Permian Basin and at Cushing, Oklahoma. The amount of this discount fluctuates and is difficult to predict. During 2012 and the first six months of 2013, the refining margin reflected the increased price differential between WTI Cushing crude oil and WTI Midland crude oil. For our El Paso refinery, this differential averaged $1.67 per barrel for the first six months of 2013 compared to $4.06 for the first six months of 2012. Permian Basin crude oil production continues to increase, providing additional cost-advantaged crude oil for our El Paso refinery and contributes to the discount we receive on WTI Midland crude oil.

In addition to supply side impacts, our refining margins were affected by the higher cost of RINs and by lower throughputs. The net cost of RINs was $12.8 million for the six months ended June 30, 2013 compared to $3.3 million for the six months ended June 30, 2012. Total refinery throughput decreased by 1.8 million barrels primarily due to the scheduled turnaround of the north side units of our El Paso refinery during the first quarter of 2013. Also, our refined product sales volume decreased to 31.2 million barrels during the first six months of 2013 from 34.4 million barrels during the first six months of 2012.

Direct Operating Expenses (exclusive of depreciation and amortization). Direct operating expenses increased period over period primarily due to higher employee expenses ($7.6 million) associated with incentive compensation and increased wages associated with a scheduled maintenance turnaround of the north side units of our El Paso refinery, energy expenses ($3.5 million) due to cost increases in natural gas, outside support services ($1.4 million) associated with equipment rentals, contract inspection, and consulting services, and insurance expense ($1.3 million) due to increased cost of business interruption insurance and revised insurance rates, partially offset by lower property tax expense ($9.5 million) related to a revised property appraisal and resultant refund of property taxes paid for 2012.

Selling, General, and Administrative Expenses. Selling, general, and administrative expenses increased primarily due to greater employee expenses ($1.0 million) associated with higher headcount in refining management.

Gain on Disposal of Assets, Net. The net gain during 2012 was primarily the result of transactions relating to the sale of catalyst from our refineries ($1.7 million) partially offset by losses from the disposal of various assets at our Bloomfield terminal ($0.3 million).

Maintenance Turnaround Expense. During the first six months of 2013, we incurred turnaround expenses associated with a planned turnaround of the north side units of our El Paso refinery completed during the first quarter of 2013 as well as expenses associated with a planned 2014 turnaround of the south side units. During the first six months of 2012, we incurred turnaround expenses in connection with the planned turnaround at our Gallup refinery. The Gallup turnaround began during the third quarter of 2012 and was completed in October 2012.

Depreciation and Amortization. Depreciation and amortization increased due to additional depreciation at our Gallup refinery ($4.1 million) and El Paso refinery ($1.6 million) primarily resulting from additional assets capitalized during the third and fourth quarters of 2012 in Gallup and the first quarter of 2013 in El Paso. This increase was partially offset by a decrease in the depreciation and amortization associated with refining logistics ($0.3 million).

50

Wholesale Segment

Three Months EndedJune 30, 2013 Compared to the Three Months EndedJune 30, 2012

	Three Months Ended
	June 30,
	2013			2012			Change
	(In thousands, except per gallon data)
Statement of Operations Data
Net sales (including intersegment sales)	$	1,242,331		$	1,244,022		$	(1,691	)
Operating costs and expenses:
Cost of products sold (exclusive of depreciation and amortization)	1,212,326			1,207,351			4,975
Direct operating expenses (exclusive of depreciation and amortization)	16,724			16,778			(54		)
Selling, general, and administrative expenses	3,120			2,809			311
Depreciation and amortization	1,000			950			50
Total operating costs and expenses	1,233,170			1,227,888			5,282
Operating income	$	9,161		$	16,134		$	(6,973	)
Key Operating Data
Fuel gallons sold	402,696			386,146			16,550
Fuel gallons sold to retail (included in fuel gallons sold)	64,330			59,673			4,657
Average fuel sales price per gallon	$	3.21		$	3.35		$	(0.14	)
Average fuel cost per gallon	3.15			3.27			(0.12		)
Fuel margin per gallon (1)	0.07			0.09			(0.02		)
Lubricant gallons sold	3,053			2,862			191
Average lubricant sales price per gallon	$	11.18		$	11.24		$	(0.06	)
Average lubricant cost per gallon	9.87			10.09			(0.22		)
Lubricant margin (2)	11.7		%	10.2		%	1.5		%
Realized hedging loss	$	—		$	23,202		$	(23,202	)
Unrealized hedging loss	—			—			—

51

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

	Three Months Ended
	June 30,
	2013			2012			Change
	(In thousands, except per gallon data)
Net Sales
Fuel sales	$	1,292,740		$	1,293,362		$	(622	)
Excise taxes included in fuel sales	(93,533		)	(89,830		)	(3,703		)
Lubricant sales	34,124			32,161			1,963
Other sales	9,000			8,329			671
Net sales	$	1,242,331		$	1,244,022		$	(1,691	)
Cost of Products Sold
Fuel cost of products sold	$	1,270,271		$	1,264,538		$	5,733
Excise taxes included in fuel cost of products sold	(93,533		)	(89,830		)	(3,703		)
Lubricant cost of products sold	30,118			28,881			1,237
Other cost of products sold	5,470			3,762			1,708
Cost of products sold	$	1,212,326		$	1,207,351		$	4,975
Fuel margin per gallon (1)	$	0.07		$	0.09		$	(0.02	)

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

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

Overview. The decrease in operating income was primarily due to decreased fuel margins from our wholesale operations in the Northeast. On August 31, 2012, our wholesale segment entered into a supply and marketing agreement with a third party covering activities related to refined product supply, hedging, and sales in the Mid-Atlantic region. Under the agreement we will receive one-half of the amount our refined product sales exceed the supplier's cost of acquiring, transporting, and hedging the refined products and we will pay one-half the amount our refined product sales do not exceed the refined product costs, with an annual limit of $2.0 million.

Wholesale Gross Margin. We analyze gross margin as a function of net sales (including intersegment sales) less cost of products sold (exclusive of depreciation and amortization). Wholesale gross margin decreased by $6.7 million primarily due to lower fuel margins from our wholesale operations in the Northeast region. This fuel margin decrease was partially offset by higher fuel sales volumes in the Southwest and Northeast regions. Additionally, we no longer hedge wholesale product internally in the Northeast region following the transfer of our Northeast inventories under our third party supply and marketing agreement. Prior to the agreement, we entered into hedge contracts to protect our refined product inventory values and recorded gains and losses on these hedge contracts within cost of products sold.

Direct Operating Expenses (exclusive of depreciation and amortization). Direct operating expenses remained relatively unchanged quarter over quarter.

Selling, General, and Administrative Expenses. Selling, general, and administrative expenses increased quarter over quarter due to an increase in employee expenses caused by an increase in compensation rates ($0.2 million) and corresponding benefit expenses ($0.1 million).

Depreciation and Amortization. Depreciation and amortization remained relatively unchanged quarter over quarter.

52

Six Months EndedJune 30, 2013 Compared to the Six Months EndedJune 30, 2012

	Six Months Ended
	June 30,
	2013			2012			Change
	(In thousands, except per gallon data)
Statement of Operations Data
Net sales (including intersegment sales)	$	2,376,048		$	2,436,086		$	(60,038	)
Operating costs and expenses:
Cost of products sold (exclusive of depreciation and amortization)	2,317,350			2,373,882			(56,532		)
Direct operating expenses (exclusive of depreciation and amortization)	32,788			35,100			(2,312		)
Selling, general, and administrative expenses	6,025			5,124			901
Gain on disposal of assets, net	—			(509		)	509
Depreciation and amortization	1,965			1,904			61
Total operating costs and expenses	2,358,128			2,415,501			(57,373		)
Operating income	$	17,920		$	20,585		$	(2,665	)
Key Operating Data
Fuel gallons sold	758,329			753,374			4,955
Fuel gallons sold to retail (included in fuel gallons sold)	125,758			116,377			9,381
Average fuel sales price per gallon	$	3.26		$	3.36		$	(0.10	)
Average fuel cost per gallon	3.20			3.30			(0.10		)
Fuel margin per gallon (1)	0.07			0.07			—
Lubricant gallons sold	5,953			5,716			237
Average lubricant sales price per gallon	$	11.09		$	11.18		$	(0.09	)
Average lubricant cost per gallon	9.89			10.06			(0.17		)
Lubricant margin (2)	10.8		%	10.0		%	0.8		%
Realized hedging loss	$	—		$	2,405		$	(2,405	)
Unrealized hedging loss	—			—			—

53

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

	Six Months Ended
	June 30,
	2013			2012			Change
	(In thousands, except per gallon data)
Net Sales
Fuel sales	$	2,468,777		$	2,531,752		$	(62,975	)
Excise taxes included in fuel sales	(176,770		)	(177,073		)	303
Lubricant sales	66,017			63,887			2,130
Other sales	18,024			17,520			504
Net sales	$	2,376,048		$	2,436,086		$	(60,038	)
Cost of Products Sold
Fuel cost of products sold	$	2,423,628		$	2,485,233		$	(61,605	)
Excise taxes included in fuel cost of products sold	(176,770		)	(177,073		)	303
Lubricant cost of products sold	58,861			57,480			1,381
Other cost of products sold	11,631			8,242			3,389
Cost of products sold	$	2,317,350		$	2,373,882		$	(56,532	)
Fuel margin per gallon (1)	$	0.07		$	0.07		$	—

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

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

Overview. The decrease in operating income was primarily due to decreased fuel margins and fuel sales volume from our wholesale operations in the Northeast. On August 31, 2012, our wholesale segment entered into a supply and marketing agreement with a third party covering activities related to refined product supply, hedging, and sales in the Mid-Atlantic region. Under the agreement we will receive one-half of the amount our refined product sales exceed the supplier's cost of acquiring, transporting, and hedging the refined products and we will pay one-half the amount our refined product sales do not exceed the refined product costs, with an annual limit of $2.0 million.

Wholesale Gross Margin. We analyze gross margin as a function of net sales (including intersegment sales) less cost of products sold (exclusive of depreciation and amortization). Wholesale gross margin decreased by $3.5 million primarily due to lower fuel margins and fuel sales volumes from our wholesale operations in the Northeast region. This decrease was partially offset by higher fuel sales volumes in the Southwest region. Additionally, we no longer hedge wholesale product internally in the Northeast region following the transfer of our Northeast inventories under our third party supply and marketing agreement. Prior to the agreement, we entered into hedge contracts to protect our refined product inventory values and recorded gains and losses on these hedge contracts within cost of products sold.

Direct Operating Expenses (exclusive of depreciation and amortization). Direct operating expenses decreased due to lower terminalling fees for our Northeast region operations ($4.8 million) partially offset by increased employee expense ($1.3 million), environmental remediation expense ($0.5 million), maintenance expense ($0.4 million), and insurance expense ($0.3 million).

Selling, General, and Administrative Expenses. Selling, general, and administrative expenses increased due to an increase in employee expenses caused by an increase in compensation rates ($0.7 million) and corresponding benefit expenses ($0.2 million).

Gain on Disposal of Assets, Net. Gain on disposal of assets for the six months ended June 30, 2012 was related primarily to gains on lease buy-outs and subsequent sale of 17 fuel tanker trucks with no corresponding activity in the current period.

Depreciation and Amortization. Depreciation and amortization remained relatively unchanged.

54

Retail Segment

Three Months EndedJune 30, 2013 Compared to the Three Months EndedJune 30, 2012

	Three Months Ended
	June 30,
	2013			2012			Change
	(In thousands, except per gallon data)
Statement of Operations Data
Net sales (including intersegment sales)	$	316,920		$	310,426		$	6,494
Operating costs and expenses:
Cost of products sold (exclusive of depreciation and amortization)	279,514			272,755			6,759
Direct operating expenses (exclusive of depreciation and amortization)	26,885			25,197			1,688
Selling, general, and administrative expenses	1,964			1,969			(5		)
Depreciation and amortization	2,685			2,605			80
Total operating costs and expenses	311,048			302,526			8,522
Operating income	$	5,872		$	7,900		$	(2,028	)
Key Operating Data
Fuel gallons sold	76,669			70,953			5,716
Average fuel sales price per gallon	$	3.51		$	3.74		$	(0.23	)
Average fuel cost per gallon	3.31			3.51			(0.20		)
Fuel margin per gallon (1)	0.20			0.23			(0.03		)
Merchandise sales	$	66,126		$	62,947		$	3,179
Merchandise margin (2)	28.9		%	30.3		%	(1.4		)%

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

	Three Months Ended
	June 30,
	2013			2012			Change
	(In thousands, except per gallon data)
Net Sales
Fuel sales	$	269,094		$	265,672		$	3,422
Excise taxes included in fuel sales	(29,789		)	(27,014		)	(2,775		)
Merchandise sales	66,126			62,947			3,179
Other sales	11,489			8,821			2,668
Net sales	$	316,920		$	310,426		$	6,494
Cost of Products Sold
Fuel cost of products sold	$	253,417		$	249,181		$	4,236
Excise taxes included in fuel cost of products sold	(29,789		)	(27,014		)	(2,775		)
Merchandise cost of products sold	47,046			43,851			3,195
Other cost of products sold	8,840			6,737			2,103
Cost of products sold	$	279,514		$	272,755		$	6,759
Fuel margin per gallon (1)	$	0.20		$	0.23		$	(0.03	)

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

55

(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.

Overview. During 2012, we added 13 stores to our retail network primarily in the second quarter. Our results of operations for the second quarter of 2013 reflect the activity generated by these additional stores. As such, we have segregated the same store activity from the new retail outlets within the following analysis of the results of operations. The decrease in operating income was primarily due to decreased same store operating margins partially offset by higher fuel sales volumes. The effect of the new retail outlets added during the second quarter of 2012 was an increase of operating income by $0.4 million.

Retail Gross Margin. Retail gross margin is a function of net sales (including intersegment sales) less cost of products sold (exclusive of depreciation and amortization). The decrease in retail gross margin quarter over quarter was primarily the result of an industry wide narrowing of per gallon fuel margins partially offset by increased merchandise sales. The effect of the new retail outlets added during the second quarter 2012 was an increase of retail gross margin of $1.3 million.

Direct Operating Expenses (exclusive of depreciation and amortization). The increase in direct operating expenses quarter over quarter was primarily due to $0.8 million of current quarter to date expenses generated by retail outlets added during the second quarter 2012. The addition of the new outlets resulted in increased employee expense ($0.5 million), credit card processing fees ($0.2 million), lease expense ($0.2 million), and utilities ($0.1 million).

Selling, General, and Administrative Expenses. Selling, general, and administrative expenses remained relatively unchanged quarter over quarter.

Depreciation and Amortization. Depreciation and amortization remained relatively unchanged quarter over quarter. The majority of retail outlets added during 2012 were through operating leases and are therefore not depreciated.

Six Months EndedJune 30, 2013 Compared to the Six Months EndedJune 30, 2012

	Six Months Ended
	June 30,
	2013			2012			Change
	(In thousands, except per gallon data)
Statement of Operations Data
Net sales (including intersegment sales)	$	602,473		$	586,339		$	16,134
Operating costs and expenses:
Cost of products sold (exclusive of depreciation and amortization)	536,528			520,007			16,521
Direct operating expenses (exclusive of depreciation and amortization)	52,939			48,923			4,016
Selling, general, and administrative expenses	3,931			3,909			22
Depreciation and amortization	5,357			5,122			235
Total operating costs and expenses	598,755			577,961			20,794
Operating income	$	3,718		$	8,378		$	(4,660	)
Key Operating Data
Fuel gallons sold	149,551			138,525			11,026
Average fuel sales price per gallon	$	3.44		$	3.62		$	(0.18	)
Average fuel cost per gallon	3.27			3.42			(0.15		)
Fuel margin per gallon (1)	0.17			0.20			(0.03		)
Merchandise sales	$	123,952		$	119,486		$	4,466
Merchandise margin (2)	28.6		%	29.4		%	(0.8		)%
Operating retail outlets at period end	222			222			—

56

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

	Six Months Ended
	June 30,
	2013			2012			Change
	(In thousands, except per gallon data)
Net Sales
Fuel sales	$	515,192		$	501,277		13,915
Excise taxes included in fuel sales	(58,412		)	(53,503		)	(4,909		)
Merchandise sales	123,952			119,486			4,466
Other sales	21,741			19,079			2,662
Net sales	$	602,473		$	586,339		$	16,134
Cost of Products Sold
Fuel cost of products sold	$	489,542		$	474,229		$	15,313
Excise taxes included in fuel cost of products sold	(58,412		)	(53,503		)	(4,909		)
Merchandise cost of products sold	88,503			84,335			4,168
Other cost of products sold	16,895			14,946			1,949
Cost of products sold	$	536,528		$	520,007		$	16,521
Fuel margin per gallon (1)	$	0.17		$	0.20		$	(0.03	)

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

Overview. During 2012, we added 13 stores to our retail network primarily in the second quarter. Our results of operations for the first six months of 2013 reflect the activity generated by these additional stores for the full six months as opposed to only a partial period in 2012. As such, we have segregated the same store activity from the new retail outlets within the following analysis of the results of operations. The decrease in operating income was primarily due to decreased same store operating margins partially offset by higher fuel sales volumes. The effect of the new retail outlets added during the first six months of 2012 was an increase of operating income by $0.2 million.

Retail Gross Margin. Retail gross margin is a function of net sales (including intersegment sales) less cost of products sold (exclusive of depreciation and amortization). The decrease in retail gross margin was primarily the result of an industry wide narrowing of per gallon fuel margins coupled with decreased same store merchandise sales. The effect of the new retail outlets added during the second quarter 2012 was an increase of retail gross margin of $2.7 million.

Direct Operating Expenses (exclusive of depreciation and amortization). The increase in direct operating expenses was primarily due to $2.3 million of current year to date expenses generated by retail outlets added during the second quarter 2012. The addition of the new outlets resulted in increased employee expense ($1.1 million), credit card processing fees ($0.4 million), maintenance expense ($0.1 million), lease expense ($0.5 million), and utilities ($0.3 million).

Selling, General, and Administrative Expenses. Selling, general, and administrative expenses remained relatively unchanged.

Depreciation and Amortization. Depreciation and amortization remained relatively unchanged. The majority of retail outlets added during 2012 were through operating leases and are therefore not depreciated.

57

Outlook

Our refining margins excluding net realized and net non-cash unrealized gain or loss on hedging activities were weaker in the second quarter of 2013 compared to the second quarter of 2012. The Gulf Coast benchmark 3:2:1 crack spread declined from an average of $29.07 to an average of $23.61 for the three months endedJune 30, 2012 compared to the same period for 2013. We base all of our crude oil purchases on pricing tied to WTI, and during the second quarter of 2013 the discount of WTI crude oil to Brent crude oil declined to an average of $8.36 for the quarter compared to $15.09 for the second quarter of 2012. However, the WTI/Brent discount has been volatile recently due to new and proposed crude oil pipeline capacity additions in the Permian Basin and in Cushing, Oklahoma. Despite the continued narrowing of the WTI/Brent discount in the third quarter of 2013 the Gulf Coast benchmark 3:2:1 crack spread for July 2013 was relatively strong at $19.68 through July 26. During the second quarter of 2013, we completed the first two phases of our Delaware Basin logistics system that includes truck offloading, storage, and pipeline assets. The addition of these assets will increase our capacity to deliver cost advantaged crude oil from the Delaware Basin to our El Paso refinery.

Beginning in the first quarter of 2013 and continuing into the second quarter, we experienced significant volatility in the pricing of ethanol RIN's as refiners essentially achieved full utilization of ethanol in gasoline blends. We expect this volatility to continue as the industry strives to meet Renewable Fuel Standards obligations.

Liquidity and Capital Resources

Our primary sources of liquidity are cash generated from our operating activities, existing cash balances, and borrowings under our Revolving Credit Agreement. We ended the quarter with $372.3 million of cash and cash equivalents and $691.4 million in gross availability under our Revolving Credit Agreement reduced by $252.7 million in outstanding letters of credit. As of June 30, 2013, we had no direct borrowings under the Revolving Credit Agreement. We continually evaluate the bank and capital markets for opportunities to further improve our capital structure and deliver additional value to our shareholders.

Our board of directors have authorized two separate share repurchase programs of up to $200 million under each program(the "July 2012 Program" and the "April 2013 Program"). Through June 30, 2013, we have utilized the entire $200 million authorized under the July 2012 Program and $110.7 million under the April 2013 Program. The total share repurchase amount during the first six months of 2013 between the July 2012 Program and the April 2013 Program was 7,213,383 shares at a cost of $228.5 million. Under both programs through June 30, 2013, we have repurchased 10,537,518 shares at a cost of $310.7 million. From June 30, 2013 to July 26, 2013, we purchased an additional 199,340 shares at a cost of $5.3 million. As of July 26, 2013, we had $84.0 million remaining in authorized expenditures under the April 2013 Program.

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

Cash Flows

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

	Six Months Ended
	June 30,
	2013			2012			Change
	(In thousands)
Net cash provided by operating activities	$	259,324		$	348,857		$	(89,533	)
Net cash provided by (used in) investing activities	(101,420		)	161,249			(262,669		)
Net cash used in financing activities	(239,536		)	(334,838		)	95,302
Net increase (decrease) in cash and cash equivalents	$	(81,632	)	$	175,268		$	(256,900	)

The decrease in net cash from operating activities period over period was primarily the result of the following net changes between years:

•Net unrealized commodity hedging activity ($216.4 milliondecrease);

•Prepaid expenses ($69.3 milliondecrease);

58

•Accounts receivable ($2.6 milliondecrease);

•Accounts payable and accrued liabilities ($40.2 milliondecrease);

•Deferred income taxes ($81.0 millionincrease);

•Net income ($48.0 millionincrease);

•Inventories ($42.2 millionincrease);

•Loss on extinguishment of debt ($39.1 millionincrease); and

•Other assets ($22.5 millionincrease).

The changes in components making up net income and results of our commodity hedging activity occurred for reasons discussed above. The decrease from prepaid expenses was primarily due to the timing of prepayments for crude oil to certain of our suppliers. The changes in deferred income taxes resulted primarily from the change in our net unrealized hedging activity between periods. The change in accounts payable and accrued liabilities was a matter of timing primarily driven by accruals related to the planned El Paso refinery turnaround during the first quarter of 2013.

Cash flows used in operating activities for the six months ended June 30, 2013 combined with $350.0 million from the issuance of long-term debt were primarily used for the following:

•Payments on long-term debt ($325.2 million);

•Purchase of treasury stock ($198.8 million);

•Fund capital expenditures ($101.9 million);

•Debt retirement fees ($24.4 million); and

•Payment of cash dividends ($20.5 million).

Future Capital Expenditures

Our 2013 budget included approximately $205.8 million (excluding capitalized interest) in capital expenditures for the year. The total estimate includes $49.5 million for sustaining capital, $122.4 million for discretionary capital, and $33.9 million for regulatory spending. Our discretionary projects include crude oil logistic projects, such as a gathering and storage project in the Permian Basin of southeast New Mexico that we completed in the second quarter of 2013 and preliminary work on a potential crude unit expansion at our El Paso refinery estimated to be completed in 2016.

Indebtedness

Our capital structure at June 30, 2013 and 2012 was as follows:

	June 30, 2013		June 30, 2012
	(In thousands)
Debt, including current maturities:
6.25% Senior Unsecured Notes, due 2021	$	350,000	$	—
11.25% Senior Secured Notes, due 2017, net of unamortized discount of $20,541 for 2012	—		304,459
5.75% Convertible Senior Unsecured Notes, due 2014, net of conversion feature of $14,980 and $28,767 for 2013 and 2012, respectively	200,414		186,683
5.50% promissory note, due 2015	418		656
Revolving Credit Agreement	—		—
Long-term debt	550,832		491,798
Shareholders’ equity	904,373		1,005,125
Total capitalization	$	1,455,205	$	1,496,923

11.25% Senior Secured Notes

On March 11, 2013, we announced the commencement of a cash tender offer and consent solicitation for any and all of our outstanding 11.25% Senior Secured Notes due 2017 (the “2017 Notes”), pursuant to our Offer to Purchase and Consent Solicitation Statement (the “Offer to Purchase”). Holders who validly tendered their 2017 Notes on or before March 22, 2013 (the "Early Tender Deadline") were eligible to receive total consideration of $1,079.60 per $1,000 principal amount of 2017

59

Notes, which included a consent payment of $20.00 per $1,000 principal amount of 2017 Notes tendered. On March 25, 2013, we announced that the holders of $148.8 million of the 2017 Notes had tendered their 2017 Notes in the tender offer. We used the funds from the 2021 Note offering, detailed below, to fund the Offer to Purchase.

On March 25, 2013, we issued a notice of redemption (with a redemption date of April 24, 2013), to the remaining holders of our 2017 Notes that were not accepted for payment and that remained outstanding on April 24, 2013 (the “Redemption Date” and such 2017 Notes to be redeemed, the “Outstanding 2017 Notes”). The maximum amount of Outstanding 2017 Notes that were subject to redemption was $176.2 million.

The Offer to Purchase expired on April 5, 2013 and an additional $2.5 million of the 2017 Notes were validly tendered and not validly withdrawn, resulting in a total amount of $151.3 million of 2017 Notes that were validly tendered and not validly withdrawn. As a result of the Offer to Purchase, we recorded a loss on extinguishment of debt of $22.0 million including a write-off of $1.9 million of unamortized loan fees during the first quarter of 2013.

On April 24, 2013, we redeemed the then Outstanding 2017 Notes at 100.0% of the principal amount of such Outstanding 2017 Notes, plus the Fixed Rate Notes Applicable Premium (as such term is defined in the indenture governing the 2017 Notes) as of the Redemption Date plus accrued and unpaid interest from December 15, 2012 to, but excluding, the Redemption Date. This redemption resulted in a loss on extinguishment of debt of $24.7 million including a write-off of $2.3 million of unamortized loan fees that has been included in the second quarter of 2013 results of operations.

6.25% Senior Unsecured Notes

Separately on March 25, 2013, we entered into an indenture (the "2021 Indenture") for the issuance of $350.0 million in aggregate principal amount of 6.25% Senior Unsecured Notes due 2021 (the “2021 Notes”). The 2021 Notes are guaranteed on a senior unsecured basis by each of our wholly-owned domestic restricted subsidiaries that guarantee any of our indebtedness under our (a) Revolving Credit Agreement or (b) any other Credit Facilities (as each such term is defined in the 2021 Indenture), or any capital markets debt, in the case of clause (b), in a principal amount of at least $150.0 million. The 2021 Notes and the guarantees are our and each Guarantor's general obligations and will rank equally and ratably with all of our existing and future senior indebtedness and senior to our and the Guarantors’ subordinated indebtedness. The 2021 Notes will be effectively subordinated in right of payment to all secured indebtedness (including secured indebtedness under the Revolving Credit Agreement) to the extent of the value of the collateral securing such indebtedness. We will pay interest on the 2021 Notes semi-annually in cash in arrears on April 1 and October 1 of each year, beginning on October 1, 2013. The 2021 Notes will mature on April 1, 2021. We used the proceeds from the offering primarily to redeem the 2017 Notes. We incurred transaction and other financing fees of $7.5 million related to the issuance of the 2021 Notes.

The 2021 Indenture contains covenants that limit our ability to, among other things: pay dividends or make other distributions in respect of our capital stock or make other restricted payments; make certain investments; sell certain assets; incur additional debt or issue certain preferred shares; create liens on certain assets to secure debt; consolidate, merge, sell or otherwise dispose of all or substantially all of our assets; restrict dividends or other payments from restricted subsidiaries; and enter into certain transactions with our affiliates. The 2021 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 2021 Notes to be due and payable immediately.

In connection with the sale of the 2021 Notes, we entered into a registration rights agreement, dated March 25, 2013 (the “Registration Rights Agreement”), with the initial purchasers. Under the Registration Rights Agreement, we agreed to register notes having substantially identical terms as the 2021 Notes with the U.S. Securities and Exchange Commission as part of an offer to exchange freely tradable exchange notes for the 2021 Notes. We filed a related Form S-4 on June 14, 2013. On July 27, 2013, we exchanged all of the previously issued 2021 notes for new notes due 2021 that are registered under the U.S. Securities Act.

5.25% Convertible Senior Unsecured Notes

The Convertible Senior Unsecured Notes (the "2014 Notes") are presently convertible at the option of the holder. The conversion rate as of June 30, 2013 was 103.1929 for each $1,000 of principal amount of the 2014 Notes. The 2014 Notes will also be convertible in any future calendar quarter (prior to maturity) whenever the last reported sale price of our common stock exceeds 130% of the applicable conversion price in effect for the 2014 Notes on the last trading day of the immediately preceding calendar quarter for twenty days in the thirty consecutive trading day period ending on the last trading day of the immediately preceding calendar quarter. If any 2014 Notes are surrendered for conversion, we may elect to satisfy our obligations upon conversion through the delivery of shares of our common stock, in cash, or a combination thereof. We intend to fund the retirement of the 2014 Notes in June of 2014 through a combination of cash generated from operations, existing cash balances, and the delivery of shares of our common stock.

During the second quarter of 2013, $0.1 million in 2014 Notes at par value were presented for conversion. These conversions were settled in cash and resulted in a loss on extinguishment of debt of $4.5 thousand.

60

As of June 30, 2013, the if-converted value of the 2014 Notes exceeded its principal amount by $408.5 million.

Term Loan

In addition to our scheduled Term Loan Credit Agreement ("Term Loan") payment of $0.8 million made during the first quarter of 2012, we made non-mandatory prepayments of $30.0 million and $291.8 million during the first and second quarters of 2012, respectively. As a result of the retirement of our Term Loan in the second quarter of 2012, we recorded a loss on extinguishment of debt of $7.7 million.

Revolving Credit Agreement

On April 11, 2013, we entered into the Second Amended and Restated Revolving Credit Agreement. Lenders under the Revolving Credit Agreement extended $900.0 million in commitments that mature on April 11, 2018, and incorporate a borrowing base tied to eligible accounts receivable and inventory. The Revolving Credit Agreement also provides for letters of credit and swing line loans and provides for a quarterly commitment fee ranging from 0.25% to 0.50% per annum subject to adjustment based upon the average utilization ratio and letter of credit fees ranging from 1.75% to 2.25% per annum, payable quarterly, subject to adjustment based upon the average excess availability. Borrowings can be either base rate loans plus a margin ranging from 0.75% to 1.25% or LIBOR loans plus a margin ranging from 1.75% to 2.25% subject to adjustment based upon the average excess availability under the Revolving Credit Agreement. Prior to April 11, 2013, the Revolving Credit Agreement included commitments of $1.0 billion maturing on September 22, 2016. Interest rates ranged from 2.50% to 3.25% over LIBOR. Our subsidiaries guarantee the Revolving Credit Agreement on a joint and several basis. The Revolving Credit Agreement is secured by our cash and cash equivalents, accounts receivable, and inventory. We paid $4.5 million in amendment and other financing fees related to the Revolving Credit Agreement that are being amortized over the term of the Revolving Credit Agreement.

The Revolving Credit Agreement 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. If an event of default under the Revolving Credit Agreement occurs and is continuing, the Administrative Agent at the request of lenders holding a specified percentage of commitments, shall, or with such lenders' consent, may terminate the obligations of the lenders to make loans and the obligations of the issuing banks to issue letters of credit, declare the obligations outstanding under the Revolving Credit Agreement to be immediately due and payable, and/or exercise legal and contractual rights and remedies.

As of June 30, 2013, we had no direct borrowings under the Revolving Credit Agreement, with gross availability of $691.4 million, of which $252.7 million was used for outstanding letters of credit.

Contractual Obligations and Commercial Commitments

On March 25, 2013, we entered into an indenture for the issuance of $350.0 million of 6.25% Senior Unsecured Notes due 2021. We used the proceeds from the 2021 Notes to fully retire our 2017 Notes. The issuance and retirement of the respective debt instruments resulted in additional debt service obligations of $39.1 million through 2021.

We include a complete summary of our future contractual obligations and commercial commitments as of December 31, 2012 in our 2012 Form 10-K under Part I, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations, Contractual Obligations and Commercial Commitments.

Dividends

On January 4, 2013, we declared a first quarter 2013 cash dividend of $0.12 per share on our common stock. We paid the aggregate dividend of $10.5 million on February 13, 2013 to stockholders of record as of January 19, 2013. On April 8, 2013, we declared a second quarter 2013 cash dividend of $0.12 per share on our common stock. We paid the aggregate dividend of $10.0 million on May 8, 2013 to stockholders of record at the close of business on April 23, 2013. On July 17, 2013, we declared a third quarter 2013 cash dividend of $0.18 per share on our common stock. We are scheduled to pay the aggregate dividend of $14.5 million on August 15, 2013 to stockholders of record at the close of business on July 31, 2013. We anticipate paying future quarterly dividends, subject to the Board of Directors' approval and compliance with our outstanding financing agreements.

Off-Balance Sheet Arrangements

We have no off-balance sheet arrangements.

61

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, the values of which are subject to wide fluctuations in market prices driven by worldwide economic conditions, regional and global inventory levels, and seasonal conditions.

At June 30, 2013, we held approximately 5.0 million barrels of crude oil, refined product, and other inventories valued under the LIFO valuation method with an average cost of $57.50 per barrel. At June 30, 2013, the excess of the current cost of our crude oil, refined products, and other feedstocks and blendstocks inventories over aggregated LIFO costs was $207.5 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. We elected not to pursue hedge accounting treatment for financial accounting purposes on instruments used to manage price exposure to inventory positions. The financial instruments used to fix margins on future sales volumes do not qualify for hedge accounting. Therefore, changes in the fair value of these hedging instruments are included in income in the period of change. Net gains or losses associated with these transactions are reflected within cost of products sold at the end of each period.

The following tables summarize our economic hedging activity for the three and six months ended June 30, 2013 and 2012 and open commodity hedging positions as of June 30, 2013 and December 31, 2012:

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2013		2012		2013			2012
	(In thousands)
Economic hedging activities recognized within cost of products sold
Realized hedging gain (loss), net	$	18,329	$	393	$	(10,489	)	$	(35,366	)
Unrealized hedging gain (loss), net	59,691		59,582		57,968			(158,407		)
Total hedging gain (loss), net	$	78,020	$	59,975	$	47,479		$	(193,773	)

62

	June 30, 2013			December 31, 2012
	(In thousands)
Open commodity hedging instruments (bbls)
Crude futures	993			(588		)
Refined product price and crack spread swaps	(23,327		)	(26,683		)
Total open commodity hedging instruments	(22,334		)	(27,271		)
Fair value of outstanding contracts, net
Other current assets	$	26,295		$	3,918
Other assets	—			228
Accrued liabilities	—			(35,901		)
Other long-term liabilities	(15,887		)	(15,804		)
Fair value of outstanding contracts - unrealized gain (loss), net	$	10,408		$	(47,559	)

During the three and six months ended June 30, 2013 and 2012, 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, 2013. 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, 2013.

There were no changes in our internal control over financial reporting during the quarter ended June 30, 2013 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Over the course of the next several months, we will implement an energy trading and risk management system in discreet phases that will require us to revise certain aspects of our financial reporting controls and processes. We do not believe that any individual phase of this implementation will result in significant changes to our internal control over financial reporting; however, when fully implemented, the cumulative effect of changes made during each phase may be significant.

Part II

Item 1A. Risk Factors

We discuss the risks we face in our 2012 annual report on Form 10-K under Part I, Item 1A. Risk Factors.

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

On July 18, 2012, our board of directors authorized a share repurchase program of up to $200 million (the "July 2012 Program"). Under the July 2012 Program, we completed, through April 5, 2013, the purchase of 6,786,365 shares of our common stock at a cost of $200.0 million. During April 2013, we completed the purchase of 1,390,348 shares of our common stock at a cost of $45.0 million under the July 2012 Program. On April 8, 2013, our board of directors authorized another $200 million share repurchase program (the "April 2013 Program") and, through July 26, 2013, we completed the purchase of 3,950,493 shares of our common stock at a cost of $116.0 million. The total share repurchase amount during the first six months of 2013 between the July 2012 Program and the April 2013 Program of 7,213,383 shares at a cost of $228.5 million. Share repurchases may be made from time-to-time through open market transactions, block trades, privately negotiated transactions, or otherwise and are subject to market conditions, as well as corporate, regulatory, and other considerations. The share repurchase programs may be discontinued at any time by our board of directors.

63

The following table presents shares repurchased, by month, during the second quarter of 2013.

	Total number of shares purchased	Average price paid per share (1)		Total number of shares purchased as part of publicly announced plans or programs	Maximum dollar value that may yet be purchased under the program (In thousands)
April 1 - April 30	2,855,660	$	31.15	2,855,660	$	155,955
May 1 - May 31	1,006,708	30.21		1,006,708	125,526
June 1 - June 30	1,279,133	28.33		1,279,133	89,260
	5,141,501	30.26		5,141,501

(1) Average price per share excludes commissions.

As of July 26, 2013, we have repurchased an additional 199,340 shares at a cost of $5.3 million.

Our payment of dividends is limited under the terms of our Revolving Credit Agreement and our 2021 Notes, and in part, depends on our ability to satisfy certain financial covenants.

64

Item 6. Exhibits

Exhibit Index***

Number	Exhibit Title
10.2	Second Amended and Restated Revolving Credit Agreement dated as of April 11, 2013 by and among Western Refining, Inc., the several lenders from time to time party thereto and Bank of America, N.A., as Administrative Agent, Swing Line Lender and L/C Issuer (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, filed with the SEC on April 15, 2013).
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.
†	Management contract or compensatory plan or arrangement.
**	As provided in Rule 406T of Regulation S-T, this information is furnished and not filed for purposes of Sections 11 and 12 of the Securities Act of 1933 and Section 18 of the Securities Exchange Act of 1934.
***	Reports filed under the Securities Exchange Act (Form 10-K, Form 10-Q, and Form 8-K) are under File No. 001-32721.

65

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 2, 2013
Gary R. Dalke	(Principal Financial Officer)

66