Item 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following review of our results of operations and financial condition should be read in conjunction with Items 1, 1A, and 2, “Business, Risk Factors, and Properties,” and Item 8, “Financial Statements and Supplementary Data,” included in this report.

CAUTIONARY STATEMENT FOR THE PURPOSE OF SAFE HARBOR PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995

This report, including without limitation our disclosures below under the heading “OVERVIEW AND OUTLOOK,” includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. You can identify our forward-looking statements by the words “anticipate,” “believe,” “expect,” “plan,” “intend,” “estimate,” “project,” “projection,” “predict,” “budget,” “forecast,” “goal,” “guidance,” “target,” “could,” “should,” “may,” and similar expressions.

These forward-looking statements include, among other things, statements regarding:

•	future refining margins, including gasoline and distillate margins;

•	future ethanol margins;

•	expectations regarding feedstock costs, including crude oil differentials, and operating expenses;

•	anticipated levels of crude oil and refined product inventories;

•	our anticipated level of capital investments, including deferred refinery turnaround and catalyst costs and capital expenditures for environmental and other purposes, and the effect of these capital investments on our results of operations;

•	anticipated trends in the supply of and demand for crude oil and other feedstocks and refined products globally and in the regions where we operate;

•	expectations regarding environmental, tax, and other regulatory initiatives; and

•	the effect of general economic and other conditions on refining, and ethanol industry fundamentals.

We based our forward-looking statements on our current expectations, estimates, and projections about ourselves and our industry. We caution that these statements are not guarantees of future performance and involve risks, uncertainties, and assumptions that we cannot predict. In addition, we based many of these forward-looking statements on assumptions about future events that may prove to be inaccurate. Accordingly, our actual results may differ materially from the future performance that we have expressed or forecast in the forward-looking statements. Differences between actual results and any future performance suggested in these forward-looking statements could result from a variety of factors, including the following:

•	acts of terrorism aimed at either our facilities or other facilities that could impair our ability to produce or transport refined products or receive feedstocks;

•	political and economic conditions in nations that produce crude oil or consume refined products;

•	demand for, and supplies of, refined products such as gasoline, diesel fuel, jet fuel, petrochemicals, and ethanol;

•	demand for, and supplies of, crude oil and other feedstocks;

•	the ability of the members of the Organization of Petroleum Exporting Countries to agree on and to maintain crude oil price and production controls;

•	the level of consumer demand, including seasonal fluctuations;

•	refinery overcapacity or undercapacity;

•	our ability to successfully integrate any acquired businesses into our operations;

•	the actions taken by competitors, including both pricing and adjustments to refining capacity in response to market conditions;

•	the level of competitors’ imports into markets that we supply;

•	accidents, unscheduled shutdowns, or other catastrophes affecting our refineries, machinery, pipelines, equipment, and information systems, or those of our suppliers or customers;

•	changes in the cost or availability of transportation for feedstocks and refined products;

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

•	the levels of government subsidies for ethanol and other alternative fuels;

•	delay of, cancellation of, or failure to implement planned capital projects and realize the various assumptions and benefits projected for such projects or cost overruns in constructing such planned capital projects;

•	earthquakes, hurricanes, tornadoes, and irregular weather, which can unforeseeably affect the price or availability of natural gas, crude oil, grain and other feedstocks, and refined products and ethanol;

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

•	legislative or regulatory action, including the introduction or enactment of legislation or rulemakings by governmental authorities, including tax and environmental regulations, such as those to be implemented under the California Global Warming Solutions Act (also known as AB 32) and the EPA’s regulation of greenhouse gases, which may adversely affect our business or operations;

•	changes in the credit ratings assigned to our debt securities and trade credit;

•	changes in currency exchange rates, including the value of the Canadian dollar, the pound sterling, and the euro relative to the U.S. dollar;

•	overall economic conditions, including the stability and liquidity of financial markets; and

•	other factors generally described in the “Risk Factors” section included in Items 1, 1A, and 2, “Business, Risk Factors, and Properties” in this report.

Any one of these factors, or a combination of these factors, could materially affect our future results of operations and whether any forward-looking statements ultimately prove to be accurate. Our forward-looking statements are not guarantees of future performance, and actual results and future performance may differ materially from those suggested in any forward-looking statements. We do not intend to update these statements unless we are required by the securities laws to do so.

All subsequent written and oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by the foregoing. We undertake no obligation to publicly release any revisions to any such forward-looking statements that may be made to reflect events or circumstances after the date of this report or to reflect the occurrence of unanticipated events.

OVERVIEW AND OUTLOOK

Overview

For the year ended December 31, 2013, we reported net income attributable to Valero stockholders of $2.7 billion, or $4.97 per share (assuming dilution), compared to $2.1 billion, or $3.75 per share (assuming dilution), for the year ended December 31, 2012.

The increase in net income attributable to Valero stockholders of $637 million was primarily due to the effect of asset impairment losses of $1.0 billion recorded during the year ended December 31, 2012, which lowered net income for 2012, as compared to the year ended December 31, 2013. In addition, during 2013, we recorded a $325 million nontaxable gain related to the disposition of our retained interest in CST Brands, Inc. (CST), which is more fully described in Notes 3 and 11 of Notes to Consolidated Financial Statements. Excluding these significant items, net income attributable to Valero stockholders for 2013 declined by $702 million due primarily to lower refining segment operating income as discussed below.

Our operating income decreased $47 million from 2012 to 2013 as outlined by business segment in the following table (in millions):

		Year Ended December 31,
		2013				2012				Change
Operating income (loss) by business segment:
Refining		$	4,217			$	4,450			$	(233	)
Retail		81				348				(267		)
Ethanol		491				(47		)		538
Corporate		(826		)		(741		)		(85		)
Total		$	3,963			$	4,010			$	(47	)

Operating income for 2012 was negatively impacted by asset impairment losses of $1.0 billion, of which $928 million related to our Aruba refinery (as further discussed in Note 4 of Notes to Consolidated Financial Statements), and severance expense of $41 million, which was also related to our Aruba Refinery (as further discussed in Note 10 of Notes to Consolidated Financial Statements). Excluding these significant items, total operating income and refining segment operating income for 2012 would have been $5.1 billion and $5.5 billion, respectively, resulting in a $1.1 billion decrease in total operating income and a $1.3 billion decrease in refining segment operating income from 2012 to 2013.

The $1.3 billion decrease in refining segment operating income for 2013 compared to 2012 was primarily due to lower refining margins in each of our regions. The decrease in refining margins was the result of lower gasoline margins, lower discounts on light sweet crude oils, and higher costs of biofuel credits (primarily Renewable Identification Numbers (RINs) needed to comply with the U.S. federal Renewable Fuel Standard (RFS)), which were partially offset by higher distillate margins and higher discounts on sour crude oils between the years.

On May 1, 2013, we completed the separation of our retail business by spinning off 80 percent of CST as an independent public company. As a result, we no longer operate a retail business and had no retail segment operating results after April 30, 2013, resulting in the $267 million decrease in retail segment operating income for 2013 compared to 2012. The separation of our retail business is more fully discussed in Note 3 of Notes to Consolidated Financial Statements.

Our ethanol segment operating income in 2013 increased $538 million compared to 2012 due to higher gross margin per gallon of ethanol and higher production volumes. Lower corn prices and higher ethanol prices contributed to the improved gross margin. We increased our production of ethanol following the first quarter of 2013 to capture the improved economics of higher gross margins per gallon during 2013.

On December 16, 2013, Valero Energy Partners LP (VLP) completed its initial public offering of 17,250,000 common units at a price of $23.00 per unit, which included a 2,250,000 common unit over-allotment option that was fully exercised by the underwriters. VLP received $369 million in net proceeds from the sale of the units, after deducting underwriting fees, structuring fees and other offering costs. VLP’s initial assets include crude oil and refined petroleum products pipeline and terminal systems in the U.S. Gulf Coast and U.S. Mid-Continent regions that are integral to the operations of our Port Arthur, McKee, and Memphis Refineries. See Note 5 of Notes to Consolidated Financial Statements for additional information.

Outlook

Our refining segment benefits from processing sour crude oils (such as Maya crude oil) in our U.S. Gulf Coast region and light sweet crude oils (such as WTI crude oil) in our U.S. Mid-Continent region due to the favorable discounts between the prices of these types of crude oil and the price of Brent crude oil. Because the market for refined products generally tracks the price of Brent crude oil, which is a benchmark sweet crude oil, we benefit when we process crude oils that are priced at a discount to Brent crude oil. The discounts in the prices of light sweet and sour crude oils compared to the price of Brent crude oil widened significantly during the fourth quarter of 2013. For the first quarter of 2014, discounts on light sweet and sour crude oils narrowed slightly compared to the fourth quarter and we expect these discounts to remain volatile for the remainder of the first quarter.

In addition, gasoline margins across all regions were seasonally weak during the fourth quarter of 2013 and remain seasonally weak thus far in the first quarter of 2014. Distillate margins across all regions, thus far in 2014, have remained consistent with those realized during the fourth quarter of 2013. We are exposed to the volatility in the market prices of crude oil and refined products, and we expect such prices to continue to be volatile in the near to mid-term.

We are also exposed to the volatility in the market price of biofuel credits (primarily RINs in the U.S.), which we purchase in the open market to meet our obligation to blend biofuels into the products we produce. To date during the first quarter of 2014, the market price of RINs has increased compared to year end levels, but the price remains lower than prices experienced during 2013. Therefore, we estimate that the cost of meeting our obligation for the full year of 2014 will be between $250 million and $350 million. Because the market price of RINs is volatile and is significantly impacted by biofuel blending rates that are established by the EPA, it is difficult for us to predict reliably the market price of RINs.

RESULTS OF OPERATIONS

The following tables highlight our results of operations, our operating performance, and market prices that directly impact our operations. The narrative following these tables provides an analysis of our results of operations.

2013 Compared to 2012

Financial Highlights

(millions of dollars, except per share amounts)

	Year Ended December 31,
	2013 (a)				2012				Change
Operating revenues	$	138,074			$	139,250			$	(1,176	)
Costs and expenses:
Cost of sales	127,316				127,268				48
Operating expenses:
Refining (b)	3,704				3,668				36
Retail	226				686				(460		)
Ethanol	387				332				55
General and administrative expenses	758				698				60
Depreciation and amortization expense:
Refining	1,566				1,370				196
Retail	41				119				(78		)
Ethanol	45				42				3
Corporate	68				43				25
Asset impairment losses (c)	—				1,014				(1,014		)
Total costs and expenses	134,111				135,240				(1,129		)
Operating income	3,963				4,010				(47		)
Gain on disposition of retained interest in CST Brands, Inc. (a)	325				—				325
Other income, net	59				9				50
Interest and debt expense, net of capitalized interest	(365		)		(313		)		(52		)
Income before income tax expense	3,982				3,706				276
Income tax expense	1,254				1,626				(372		)
Net income	2,728				2,080				648
Less: Net income (loss) attributable to noncontrolling interests	8				(3		)		11
Net income attributable to Valero stockholders	$	2,720			$	2,083			$	637
Earnings per common share – assuming dilution	$	4.97			$	3.75			$	1.22

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See note references on page 32.

Refining Operating Highlights

(millions of dollars, except per barrel amounts)

	Year Ended December 31,
	2013				2012				Change
Refining (b) (c):
Operating income	$	4,217			$	4,450			$	(233	)
Throughput margin per barrel (e)	$	9.69			$	10.96			$	(1.27	)
Operating costs per barrel:
Operating expenses	3.78				3.79				(0.01		)
Depreciation and amortization expense	1.60				1.44				0.16
Total operating costs per barrel	5.38				5.23				0.15
Operating income per barrel	$	4.31			$	5.73			$	(1.42	)
Throughput volumes (thousand BPD):
Feedstocks:
Heavy sour crude	486				453				33
Medium/light sour crude	466				547				(81		)
Sweet crude	1,039				991				48
Residuals	282				200				82
Other feedstocks	106				120				(14		)
Total feedstocks	2,379				2,311				68
Blendstocks and other	303				302				1
Total throughput volumes	2,682				2,613				69
Yields (thousand BPD):
Gasolines and blendstocks	1,287				1,251				36
Distillates	984				918				66
Other products (f)	440				467				(27		)
Total yields	2,711				2,636				75

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See note references on page 32.

Refining Operating Highlights by Region (g)

(millions of dollars, except per barrel amounts)

	Year Ended December 31,
	2013				2012				Change
U.S. Gulf Coast (b) (c):
Operating income	$	2,381			$	2,541			$	(160	)
Throughput volumes (thousand BPD)	1,523				1,488				35
Throughput margin per barrel (e)	$	9.57			$	9.65			$	(0.08	)
Operating costs per barrel:
Operating expenses	3.66				3.55				0.11
Depreciation and amortization expense	1.63				1.44				0.19
Total operating costs per barrel	5.29				4.99				0.30
Operating income per barrel	$	4.28			$	4.66			$	(0.38	)
U.S. Mid-Continent:
Operating income	$	1,293			$	2,044			$	(751	)
Throughput volumes (thousand BPD)	435				430				5
Throughput margin per barrel (e)	$	13.37			$	18.49			$	(5.12	)
Operating costs per barrel:
Operating expenses	3.58				4.02				(0.44		)
Depreciation and amortization expense	1.64				1.48				0.16
Total operating costs per barrel	5.22				5.50				(0.28		)
Operating income per barrel	$	8.15			$	12.99			$	(4.84	)
North Atlantic:
Operating income	$	570			$	752			$	(182	)
Throughput volumes (thousand BPD)	459				428				31
Throughput margin per barrel (e)	$	7.93			$	9.24			$	(1.31	)
Operating costs per barrel:
Operating expenses	3.50				3.59				(0.09		)
Depreciation and amortization expense	1.03				0.85				0.18
Total operating costs per barrel	4.53				4.44				0.09
Operating income per barrel	$	3.40			$	4.80			$	(1.40	)
U.S. West Coast:
Operating income (loss)	$	(27	)		$	147			$	(174	)
Throughput volumes (thousand BPD)	265				267				(2		)
Throughput margin per barrel (e)	$	7.43			$	8.84			$	(1.41	)
Operating costs per barrel:
Operating expenses	5.35				5.09				0.26
Depreciation and amortization expense	2.35				2.25				0.10
Total operating costs per barrel	7.70				7.34				0.36
Operating income (loss) per barrel	$	(0.27	)		$	1.50			$	(1.77	)
Operating income for regions above	$	4,217			$	5,484			$	(1,267	)
Severance expense (b)	—				(41		)		41
Asset impairment losses (c)	—				(993		)		993
Total refining operating income	$	4,217			$	4,450			$	(233	)

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See note references on page 32.

Average Market Reference Prices and Differentials

(dollars per barrel, except as noted)

	Year Ended December 31,
	2013				2012				Change
Feedstocks:
Brent crude oil	$	108.74			$	111.70			(2.96	)
Brent less West Texas Intermediate (WTI) crude oil	10.80				17.55				(6.75	)
Brent less Alaska North Slope (ANS) crude oil	1.00				1.08				(0.08	)
Brent less Louisiana Light Sweet (LLS) crude oil	0.41				(0.91		)		1.32
Brent less Mars crude oil	5.52				3.97				1.55
Brent less Maya crude oil	11.31				12.06				(0.75	)
LLS crude oil	108.33				112.61				(4.28	)
LLS less Mars crude oil	5.11				4.88				0.23
LLS less Maya crude oil	10.90				12.97				(2.07	)
WTI crude oil	97.94				94.15				3.79
Natural gas (dollars per million British thermal units)	3.69				2.71				0.98
Products:
U.S. Gulf Coast:
CBOB gasoline less Brent	2.69				4.89				(2.20	)
Ultra-low-sulfur diesel less Brent	15.95				16.48				(0.53	)
Propylene less Brent	(2.72		)		(22.38		)		19.66
CBOB gasoline less LLS	3.10				3.98				(0.88	)
Ultra-low-sulfur diesel less LLS	16.36				15.57				0.79
Propylene less LLS	(2.31		)		(23.29		)		20.98
U.S. Mid-Continent:
CBOB gasoline less WTI (d)	16.77				25.40				(8.63	)
Ultra-low-sulfur diesel less WTI	28.33				34.96				(6.63	)
North Atlantic:
CBOB gasoline less Brent	8.50				10.66				(2.16	)
Ultra-low-sulfur diesel less Brent	17.84				19.06				(1.22	)
U.S. West Coast:
CARBOB 87 gasoline less ANS	12.69				15.39				(2.70	)
CARB diesel less ANS	18.83				19.93				(1.10	)
CARBOB 87 gasoline less WTI	22.49				31.86				(9.37	)
CARB diesel less WTI	28.63				36.40				(7.77	)
New York Harbor corn crush (dollars per gallon)	0.42				(0.15		)		0.57

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See note references on page 32.

Retail and Ethanol Operating Highlights

(millions of dollars, except per gallon amounts)

	Year Ended December 31,
	2013				2012				Change
Retail:
Operating income (a) (c)	$	81			$	348			$	(267	)
Ethanol:
Operating income (loss)	$	491			$	(47	)		$	538
Ethanol production (thousand gallons per day)	3,294				2,967				327
Gross margin per gallon of production (e)	$	0.77			$	0.30			$	0.47
Operating costs per gallon of production:
Operating expenses	0.32				0.30				0.02
Depreciation and amortization expense	0.04				0.04				—
Total operating costs per gallon of production	0.36				0.34				0.02
Operating income (loss) per gallon of production	$	0.41			$	(0.04	)		$	0.45

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See note references on page 32.

The following notes relate to references on pages 27 through 31.

(a)

On May 1, 2013, we completed the separation of our retail business by spinning off 80 percent of CST. This transaction is more fully discussed in Note 3 of Notes to Consolidated Financial Statements. As a result and effective May 1, 2013, our results of operations no longer include those of CST, except for our share of CST’s results of operations associated with the equity interest in CST retained by us through November 14, 2013, which is reflected in “other income, net” for the year ended December 31, 2013. The nature and significance of our post-separation participation in the supply of motor fuel to CST represents a continuation of activities with CST for accounting purposes. As such, the historical results of operations related to CST have not been reported as discontinued operations in the statements of income. In October 2013, we borrowed $525 million under a short-term debt agreement with a third-party financial institution in anticipation of liquidating our retained interest in CST. This liquidation was completed on November 14, 2013 by transferring all remaining shares of CST common stock owned by us to the financial institution in exchange for $467 million of our short-term debt, and we paid the remaining $58 million of short-term debt in cash. After paying $19 million of fees, we recognized a $325 million nontaxable gain.

(b)

In September 2012, we decided to reorganize our Aruba Refinery into a crude oil and refined products terminal. The reorganization resulted in the termination of the majority of our employees in Aruba, and we recognized severance expense of $41 million in September 2012. This expense is reflected in refining segment operating income for the year ended December 31, 2012, but it is excluded from operating costs per barrel for the refining segment and the U.S. Gulf Coast region. No income tax benefits were recognized related to this severance expense.

(c)

Asset impairment losses for the year ended December 31, 2012 include a $928 million loss on the write-down of the Aruba Refinery. In addition, we recorded asset impairment losses of $65 million ($42 million after taxes) related to equipment associated with permanently cancelled capital projects at several of our refineries and $21 million ($13 million after taxes) related to certain retail stores in 2012 that we owned prior to the separation of our retail business. The total asset impairment losses of $1.0 billion are reflected in the operating income of the respective segments for the year ended December 31, 2012, but the asset impairment losses associated with the Aruba Refinery and the cancelled capital projects are excluded from the operating costs per barrel and operating income per barrel for the refining segment and the U.S. Gulf Coast region.

(d)	U.S. Mid-Continent product specifications for gasoline changed on September 16, 2013 from Conventional 87 gasoline to CBOB gasoline. Therefore, average market reference prices for comparable products meeting the new specifications required in this region are now being provided for all periods presented.

(e)	Throughput margin per barrel represents operating revenues less cost of sales of our refining segment divided by throughput volumes. Gross margin per gallon of production represents operating revenues less cost of sales of our ethanol segment divided by production volumes.

(f)	Other products primarily include petrochemicals, gas oils, No. 6 fuel oil, petroleum coke, sulfur, and asphalt.

(g)

The regions reflected herein contain the following refineries: the U.S. Gulf Coast region includes the Aruba, Corpus Christi East, Corpus Christi West, Houston, Meraux, Port Arthur, St. Charles, Texas City, and Three Rivers Refineries; the U.S. Mid-Continent region includes the Ardmore, McKee, and Memphis Refineries; the North Atlantic region includes the Pembroke and Quebec City Refineries; and the U.S. West Coast region includes the Benicia and Wilmington Refineries.

General

Operating revenues decreased $1.2 billion (or 1 percent) for the year ended December 31, 2013 compared to the year ended December 31, 2012 primarily as a result of lower average refined product prices between the two years related to our refining segment operations. In addition, operating income decreased $47 million for the year ended December 31, 2013 compared to the year ended December 31, 2012 primarily due to a $233 million decrease in refining segment operating income, a $267 million decrease in retail segment operating income, and a $60 million increase in general and administrative expenses, partially offset by a $538 million increase in ethanol segment operating income. The reasons for these changes in the operating results of our segments and general and administrative expenses, as well as other items that affected our income, are discussed below.

Refining

Refining segment operating income decreased $233 million from $4.5 billion for the year ended December 31, 2012 to $4.2 billion for the year ended December 31, 2013. Excluding asset impairment losses and severance expenses of $993 million and $41 million in 2012 primarily related to our Aruba Refinery, which are more fully described in Notes 4 and 10 of Notes to Consolidated Financial Statements, respectively, refining segment operating income decreased $1.3 billion from 2012 to 2013. The decrease in refining segment operating income was primarily due to a $994 million decrease in refining margin, a $196 million increase in depreciation and amortization expense, and a $36 million increase in operating expenses.

Refining margin decreased $994 million (a $1.27 per barrel decrease) in 2013 compared to 2012, primarily due to the following:

•

Decrease in gasoline margins - We experienced a decline in gasoline margins throughout all of our regions during 2013 compared to 2012. For example, the WTI-based benchmark reference margin for U.S. Mid-Continent CBOB gasoline was $16.77 per barrel during 2013 compared to $25.40 per barrel during 2012, representing an unfavorable decrease of $8.63 per barrel. We estimate that the decline in gasoline margins per barrel during 2013 compared to 2012 had a negative impact to our refining margin of approximately $790 million for all refining regions.

•

Lower discounts on WTI-type crude oils in the U.S. Mid-Continent region - Because the market for refined products generally tracks the price of Brent crude oil, which is a benchmark sweet crude oil, we benefit when we process crude oils that are priced at a discount to Brent crude oil. In 2013, the discount in the price of WTI compared to the price of Brent crude oil narrowed compared to 2012. WTI crude oil sold at a discount of $10.80 per barrel to Brent crude oil in 2013 compared to a discount of $17.55 per barrel in 2012, representing an unfavorable decrease of $6.75 per barrel. Therefore, the lower discount on WTI-type crude oils that we processed negatively impacted our refining margin. We estimate that the decrease in the discounts for WTI-type crude oils that we processed during 2013 reduced our refining margin by approximately $640 million.

•

Higher costs of biofuel credits - As more fully described in Note 21 of Notes to Consolidated Financial Statements, we must purchase biofuel credits in order to meet our biofuel blending obligation under various government and regulatory compliance programs, and the cost of these credits (primarily RINs in the U.S.) increased by $267 million from $250 million in 2012 to $517 million in 2013. This increase was due to an increase in the market price of RINs caused by an expectation in the market of a shortage in available RINs.

•	Increase in distillate margins - Despite lower distillate prices throughout all of our regions during 2013 compared to 2012, we experienced an increase in distillate margins during 2013 compared to 2012 as a

result of increased production volumes of distillate between the years. This production volume increase of 66,000 barrels per day was primarily due to the start up of our new hydrocracker units at our Port Arthur and St. Charles Refineries, resulting in a $370 million increase in our refining margin in 2013.

•

Higher discounts on medium sour crude oils - In 2013, the discount in the price of medium sour crude oils compared to the price of Brent crude oil widened. For example, Mars crude oil, which is a medium sour crude oil, sold at a discount of $5.52 per barrel to Brent crude oil in 2013 compared to a discount of $3.97 per barrel during 2012, representing a favorable increase of $1.55 per barrel.Therefore, the higher discounts on the medium sour crude oils we processed favorably impacted our refining margin. We estimate that the increase in the discounts for medium sour crude oils that we processed during 2013 had a favorable impact to our refining margin of approximately $260 million.

The increase of $36 million in operating expenses was primarily due to a $185 million increase in energy costs related to higher natural gas costs and higher use of natural gas associated with our new hydrocracker units at our Port Arthur and St. Charles Refineries. This increase was partially offset by a $124 million decrease in operating expenses incurred by the Aruba Refinery, whose operations were suspended in March 2012.

The increase of $196 million in depreciation and amortization expense was due to additional depreciation expense primarily associated with our new hydrocracker units at our Port Arthur and St. Charles Refineries that began operating in late 2012 and the third quarter of 2013, respectively, and an increase in refinery turnaround and catalyst amortization.

Retail

Retail segment operating income was $81 million for the year ended December 31, 2013 compared to $348 million for the year December 31, 2012. The $267 million decrease was primarily due to the separation of our retail business on May 1, 2013, which is more fully described in Note 3 of Notes to Consolidated Financial Statements. As a result of the separation, retail segment operating income for 2013 reflects the operations of our former retail business for only the first four months of 2013.

Ethanol

Ethanol segment operating income was $491 million for the year ended December 31, 2013 compared to an operating loss of $47 million for the year ended December 31, 2012. The $538 million increase in operating income was primarily due to a $596 million increase in gross margin, partially offset by a $55 million increase in operating expenses.

Ethanol gross margin per gallon increased $0.47 per gallon from $0.30 per gallon in 2012 to $0.77 per gallon in 2013 due to the following:

•

Lower corn prices - Corn prices decreased year over year as many of the corn-producing regions of the U.S. Mid-Continent recovered from a drought that began in the second quarter of 2012. For example, the Chicago Board of Trade corn price was $5.80 per bushel in 2013 compared to $6.94 per bushel in 2012. The decrease in the price of corn that we processed during 2013 favorably impacted our ethanol margin by approximately $290 million.

•	Higher ethanol prices - Ethanol prices increased year over year due to a decrease in the supply of ethanol in the market. The decrease in supply resulted from reduced production in 2012 and early 2013 as the industry responded to a narrowing of ethanol gross margin per gallon, which were due to higher corn prices primarily caused by the drought in the corn-producing regions of the U.S. Mid-

Continent described above. By mid-2013, ethanol inventory levels in the U.S. had declined to their lowest level in over three years and as a result, prices increased significantly beginning late in the first quarter of 2013. For example, the New York Harbor ethanol price was $2.53 per gallon in 2013 compared to $2.37 per gallon in 2012. The increase in the price of ethanol per gallon during 2013 had a favorable impact to our ethanol margin of approximately $160 million.

•	Increased production volumes - Ethanol margin also improved due to increased production volumes between the years of 327,000 gallons per day in 2013 compared to 2012 in response to the improved ethanol gross margin per gallon. The increase in production volumes during 2013 had a favorable impact to our ethanol gross margin of approximately $85 million.

The $55 million increase in operating expenses during 2013 compared to 2012 was primarily due to a $40 million increase in energy costs compared to 2012 resulting from higher natural gas prices during 2013 and a $12 million year over year increase in chemical costs due to higher production.

Corporate Expenses and Other

General and administrative expenses increased $60 million from the year ended December 31, 2012 to the year ended December 31, 2013 primarily due to $52 million of environmental and legal reserve adjustments that were recorded during 2013 and $30 million for transaction costs related to the separation of our retail business on May 1, 2013. These increases were partially offset by an $11 million reduction in insurance reserves during 2013. The increase in corporate depreciation and amortization expense was primarily due to $20 million of losses incurred on the sale of certain corporate property.

During the year ended December 31, 2013, we recognized a nontaxable gain of $325 million, or $0.60 per share, related to the disposition of our retained interest in CST, which is more fully described in Note 11 of Notes to Consolidated Financial Statements.

“Interest and debt expense, net of capitalized interest” for year ended December 31, 2013 increased $52 million from the year ended December 31, 2012. This increase was primarily due to a $103 million decrease in capitalized interest due to completion of several large capital projects, including the new hydrocrackers at our Port Arthur and St. Charles Refineries, offset by a $44 million favorable impact from the decrease in average borrowings and a $12 million write-off of unamortized debt discounts related to the early redemption of certain industrial revenue bonds in the first quarter of 2012.

Income tax expense decreased $372 million from the year ended December 31, 2012 to the year ended December 31, 2013. The variation in the customary relationship between income tax expense and income from continuing operations before income tax expense for the year ended December 31, 2013 was primarily due to the nontaxable gain on the disposition of our retained interest in CST. The variation in the customary relationship between income tax expense and income before income tax expense for 2012 was primarily due to not recognizing the tax benefits associated with the asset impairment loss of $928 million and the severance expense of $41 million related to the Aruba Refinery as we did not expect to realize a tax benefit from these losses.

2012 Compared to 2011

Financial Highlights (a) (b)

(millions of dollars, except per share amounts)

	Year Ended December 31,
	2012				2011				Change
Operating revenues	$	139,250			$	125,987			$	13,263
Costs and expenses:
Cost of sales (c)	127,268				115,719				11,549
Operating expenses:
Refining (d)	3,668				3,406				262
Retail	686				678				8
Ethanol	332				399				(67		)
General and administrative expenses	698				571				127
Depreciation and amortization expense:
Refining	1,370				1,338				32
Retail	119				115				4
Ethanol	42				39				3
Corporate	43				42				1
Asset impairment loss (e)	1,014				—				1,014
Total costs and expenses	135,240				122,307				12,933
Operating income	4,010				3,680				330
Other income, net	9				43				(34		)
Interest and debt expense, net of capitalized interest	(313		)		(401		)		88
Income from continuing operations before income tax expense	3,706				3,322				384
Income tax expense	1,626				1,226				400
Income from continuing operations	2,080				2,096				(16		)
Loss from discontinued operations, net of income taxes	—				(7		)		7
Net income	2,080				2,089				(9		)
Less: Net loss attributable to noncontrolling interest	(3		)		(1		)		(2		)
Net income attributable to Valero stockholders	$	2,083			$	2,090			$	(7	)
Net income attributable to Valero stockholders:
Continuing operations	$	2,083			$	2,097			$	(14	)
Discontinued operations	—				(7		)		7
Total	$	2,083			$	2,090			$	(7	)
Earnings per common share – assuming dilution:
Continuing operations	$	3.75			$	3.69			$	0.06
Discontinued operations	—				(0.01		)		0.01
Total	$	3.75			$	3.68			$	0.07

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See note references on page 41.

Refining Operating Highlights

(millions of dollars, except per barrel amounts)

	Year Ended December 31,
	2012				2011				Change
Refining (a) (b):
Operating income (c) (d) (e)	$	4,450			$	3,516			$	934
Throughput margin per barrel (c) (f)	$	10.96			$	9.91			$	1.05
Operating costs per barrel:
Operating expenses (d)	3.79				3.83				(0.04		)
Depreciation and amortization expense	1.44				1.51				(0.07		)
Total operating costs per barrel (e)	5.23				5.34				(0.11		)
Operating income per barrel	$	5.73			$	4.57			$	1.16
Throughput volumes (thousand BPD):
Feedstocks:
Heavy sour crude	453				454				(1		)
Medium/light sour crude	547				442				105
Sweet crude	991				861				130
Residuals	200				282				(82		)
Other feedstocks	120				122				(2		)
Total feedstocks	2,311				2,161				150
Blendstocks and other	302				273				29
Total throughput volumes	2,613				2,434				179
Yields (thousand BPD):
Gasolines and blendstocks	1,251				1,120				131
Distillates	918				834				84
Other products (g)	467				494				(27		)
Total yields	2,636				2,448				188

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See note references on page 41.

Refining Operating Highlights by Region (h)

(millions of dollars, except per barrel amounts)

	Year Ended December 31,
	2012				2011				Change
U.S. Gulf Coast (a):
Operating income (c) (d) (e)	$	2,541			$	2,205			$	336
Throughput volumes (thousand BPD)	1,488				1,450				38
Throughput margin per barrel (c) (f)	$	9.65			$	9.33			$	0.32
Operating costs per barrel:
Operating expenses (d)	3.55				3.66				(0.11		)
Depreciation and amortization expense	1.44				1.50				(0.06		)
Total operating costs per barrel (d) (e)	4.99				5.16				(0.17		)
Operating income per barrel	$	4.66			$	4.17			$	0.49
U.S. Mid-Continent:
Operating income (c)	$	2,044			$	1,535			$	509
Throughput volumes (thousand BPD)	430				411				19
Throughput margin per barrel (c) (f)	$	18.49			$	15.91			$	2.58
Operating costs per barrel:
Operating expenses	4.02				4.15				(0.13		)
Depreciation and amortization expense	1.48				1.52				(0.04		)
Total operating costs per barrel	5.50				5.67				(0.17		)
Operating income per barrel	$	12.99			$	10.24			$	2.75
North Atlantic (b):
Operating income	$	752			$	171			$	581
Throughput volumes (thousand BPD)	428				317				111
Throughput margin per barrel (f)	$	9.24			$	5.43			$	3.81
Operating costs per barrel:
Operating expenses	3.59				3.08				0.51
Depreciation and amortization expense	0.85				0.87				(0.02		)
Total operating costs per barrel	4.44				3.95				0.49
Operating income per barrel	$	4.80			$	1.48			$	3.32
U.S. West Coast:
Operating income (c)	$	147			$	147			$	—
Throughput volumes (thousand BPD)	267				256				11
Throughput margin per barrel (c) (f)	$	8.84			$	9.11			$	(0.27	)
Operating costs per barrel:
Operating expenses	5.09				5.25				(0.16		)
Depreciation and amortization expense	2.25				2.29				(0.04		)
Total operating costs per barrel	7.34				7.54				(0.20		)
Operating income per barrel	$	1.50			$	1.57			$	(0.07	)
Operating income for regions above	$	5,484			$	4,058			$	1,426
Loss on derivative contracts related to the forward sales of refined product (c)	—				(542		)		542
Severance expense (d)	(41		)		—				(41		)
Asset impairment loss applicable to refining (e)	(993		)		—				(993		)
Total refining operating income	$	4,450			$	3,516			$	934

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See note references on page 41.

Average Market Reference Prices and Differentials

(dollars per barrel, except as noted)

	Year Ended December 31,
	2012				2011				Change
Feedstocks:
Brent crude oil	$	111.70			$	110.93			$	0.77
Brent less WTI crude oil	17.55				15.88				1.67
Brent less ANS crude oil	1.08				1.39				(0.31		)
Brent less LLS crude oil	(0.91		)		(0.54		)		(0.37		)
Brent less Mars crude oil	3.97				3.46				0.51
Brent less Maya crude oil	12.06				12.18				(0.12		)
LLS crude oil	112.61				111.47				1.14
LLS less Mars crude oil	4.88				4.00				0.88
LLS less Maya crude oil	12.97				12.72				0.25
WTI crude oil	94.15				95.05				(0.90		)
Natural gas (dollars per million British thermal units)	2.71				3.96				(1.25		)
Products:
U.S. Gulf Coast:
CBOB gasoline less Brent	4.89				5.17				(0.28		)
Ultra-low-sulfur diesel less Brent	16.48				13.78				2.70
Propylene less Brent	(22.38		)		8.23				(30.61		)
CBOB gasoline less LLS	3.98				4.63				(0.65		)
Ultra-low-sulfur diesel less LLS	15.57				13.24				2.33
Propylene less LLS	(23.29		)		7.69				(30.98		)
U.S. Mid-Continent:
CBOB gasoline less WTI (i)	25.40				22.37				3.03
Ultra-low-sulfur diesel less WTI	34.96				31.06				3.90
North Atlantic:
CBOB gasoline less Brent	10.66				5.95				4.71
Ultra-low-sulfur diesel less Brent	19.06				15.64				3.42
U.S. West Coast:
CARBOB 87 gasoline less ANS	15.39				11.48				3.91
CARB diesel less ANS	19.93				18.47				1.46
CARBOB 87 gasoline less WTI	31.86				25.97				5.89
CARB diesel less WTI	36.40				32.96				3.44
New York Harbor corn crush (dollars per gallon)	(0.15		)		0.25				(0.40		)

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See note references on page 41.

Retail and Ethanol Operating Highlights

(millions of dollars, except per gallon amounts)

	Year Ended December 31,
	2012				2011				Change
Retail–U.S.:
Operating income (e)	$	240			$	213			$	27
Company-operated fuel sites (average)	1,013				994				19
Fuel volumes (gallons per day per site)	5,083				5,060				23
Fuel margin per gallon	$	0.162			$	0.144			$	0.018
Merchandise sales	$	1,239			$	1,223			$	16
Merchandise margin (percentage of sales)	29.7		%		28.7		%		1.0		%
Margin on miscellaneous sales	$	89			$	88			$	1
Operating expenses	$	434			$	416			$	18
Depreciation and amortization expense	$	77			$	77			$	—
Asset impairment loss (e)	$	12			$	—			$	12
Retail–Canada:
Operating income (e)	$	108			$	168			$	(60	)
Fuel volumes (thousand gallons per day)	3,096				3,195				(99		)
Fuel margin per gallon	$	0.258			$	0.299			$	(0.041	)
Merchandise sales	$	257			$	261			$	(4	)
Merchandise margin (percentage of sales)	29.0		%		29.4		%		(0.4		)%
Margin on miscellaneous sales	$	44			$	43			$	1
Operating expenses	$	252			$	262			$	(10	)
Depreciation and amortization expense	$	42			$	38			$	4
Asset impairment loss (e)	$	9			$	—			$	9
Ethanol:
Operating income (loss)	$	(47	)		$	396			$	(443	)
Ethanol production (thousand gallons per day)	2,967				3,352				(385		)
Gross margin per gallon of production (f)	$	0.30			$	0.68			$	(0.38	)
Operating costs per gallon of production:
Operating expenses	0.30				0.33				(0.03		)
Depreciation and amortization expense	0.04				0.03				0.01
Total operating costs per gallon of production	0.34				0.36				(0.02		)
Operating income (loss) per gallon of production	$	(0.04	)		$	0.32			$	(0.36	)

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See note references on page 41.

The following notes relate to references on pages 36 through 40.

(a)	The financial highlights and operating highlights for the refining segment and U.S. Gulf Coast region reflect the results of operations of our Meraux Refinery, including related logistics assets, from the date of its acquisition on October 1, 2011.

(b)	The financial highlights and operating highlights for the refining segment and North Atlantic region reflect the results of operations of our Pembroke Refinery, including the related market and logistics business, from the date of its acquisition on August 1, 2011.

(c)

Cost of sales for the year ended December 31, 2011 includes a loss of $542 million ($352 million after taxes) on commodity derivative contracts related to the forward sales of refined product. These contracts were closed and realized during the first quarter of 2011. This loss is reflected in refining segment operating income for the year ended December 31, 2011, but throughput margin per barrel for the refining segment excludes this $542 million loss ($0.61 per barrel). In addition, operating income and throughput margin per barrel for the U.S. Gulf Coast, the U.S. Mid-Continent, and the U.S. West Coast regions for the year ended December 31, 2011 exclude the portion of this loss that had been allocated to them of $372 million ($0.70 per barrel), $122 million ($0.81 per barrel), and $48 million ($0.51 per barrel), respectively.

(d)

In September 2012, we decided to reorganize our Aruba Refinery into a crude oil and refined products terminal. The reorganization resulted in the termination of the majority of our employees in Aruba, and we recognized severance expense of $41 million in September 2012. This expense is reflected in refining segment operating income for the year ended December 31, 2012, but it is excluded from operating costs per barrel for the refining segment and the U.S. Gulf Coast region. No income tax benefits were recognized related to this severance expense.

(e)

Asset impairment losses for the year ended December 31, 2012 include a $928 million loss on the write-down of the Aruba Refinery. In addition, we recorded asset impairment losses of $65 million ($42 million after taxes) related to equipment associated with a permanently cancelled capital project at another refinery and $21 million ($13 million after taxes) related to certain retail stores in 2012. The total asset impairment losses of $1.0 billion are reflected in the operating income of the respective segments for the year ended December 31, 2012, but the asset impairment losses associated with the Aruba Refinery and the cancelled capital projects are excluded from the operating costs per barrel and operating income per barrel for the refining segment and the U.S. Gulf Coast region.

(f)	Throughput margin per barrel represents operating revenues less cost of sales of our refining segment divided by throughput volumes. Gross margin per gallon of production represents operating revenues less cost of sales of our ethanol segment divided by production volumes.

(g)	Other products primarily include petrochemicals, gas oils, No. 6 fuel oil, petroleum coke, and asphalt.

(h)

The regions reflected herein contain the following refineries: the U.S. Gulf Coast region includes Aruba, Corpus Christi East, Corpus Christi West, Houston, Meraux, Port Arthur, St. Charles, Texas City, and Three Rivers Refineries; the U.S. Mid-Continent region includes the Ardmore, McKee, and Memphis Refineries; the North Atlantic region includes the Pembroke and Quebec City Refineries; and the U.S.West Coast region includes the Benicia and Wilmington Refineries.

(i)	U.S. Mid-Continent product specifications for gasoline changed on September 16, 2013 to CBOB gasoline. Therefore, average market reference prices for comparable products meeting the new specifications required in this region are now being provided for all periods presented.

General

Operating revenues increased 11 percent (or $13.3 billion) for the year ended December 31, 2012 compared to the year ended December 31, 2011 primarily as a result of higher average refined product prices for most of the products we produce and higher throughput volumes between the two years related to our refining segment operations. Refined product prices are most significantly influenced by the price of crude oil, which is a worldwide commodity whose price is influenced by many factors, including, but not limited to, worldwide supply and demand characteristics, worldwide political conditions, and worldwide economic conditions. However, regional factors also impact the price of refined product prices in those geographic regions. Regional factors can be similar to those that affect the worldwide price of crude oil, but they can also be significantly influenced by weather conditions that disrupt the supply of and demand for refined products in the region. For example, in October 2012, Hurricane Sandy struck the U.S. East Coast and disrupted the supply of

refined products in that region for some time, which contributed to the increase of $5.99 per barrel in the North Atlantic benchmark reference price of CBOB gasoline in 2012 compared to 2011. The higher throughput volumes in 2012 resulted primarily from the incremental throughput of 75,000 BPD from the Meraux Refinery, which was acquired on October 1, 2011, and incremental throughput of 95,000 BPD from the Pembroke Refinery, which was acquired on August 1, 2011.

Operating income increased $330 million and income from continuing operations before income tax expense increased $384 million for the year ended December 31, 2012 compared to the amounts reported for the year ended December 31, 2011 due to a $934 million increase in refining segment operating income, a $33 million decrease in retail segment operating income, a $443 million decrease in ethanol segment operating income, and a $128 million increase in corporate expenses. The reasons for these changes are described below.

Refining

Refining segment operating income increased from $3.5 billion for the year ended December 31, 2011 to $4.5 billion for the year ended December 31, 2012. This increase was impacted by asset impairment losses of $928 million related to the Aruba Refinery and $65 million related to cancelled capital projects in 2012, $41 million of severance expense related to the Aruba Refinery, and a $542 million loss on derivative contracts in 2011. (See Notes 4 and 10 of Notes to Consolidated Financial Statements for further discussions of the asset impairment losses and the severance expense, respectively). Excluding these amounts, our refining segment operating income increased $1.4 billion from $4.1 billion for the year ended December 31, 2011 to $5.5 billion for the year ended December 31, 2012. This $1.4 billion improvement in operating income was primarily due to a $1.7 billion increase in refining margin, partially offset by a $262 million increase in operating expenses.

The $1.7 billion increase in refining margin (a $1.05 per barrel, or 11 percent, increase between 2012 and 2011) was primarily the result of improvements in the margin generated in our U.S. Mid-Continent and North Atlantic regions, which experienced increases in refining margin of $526 million (a $2.58 per barrel increase), and $821 million (a $3.81 per barrel increase), respectively.

The $526 million increase in refining margin in the U.S. Mid-Continent region was largely due to improved gasoline and distillate margins in that region in 2012 compared to 2011. For example, the U.S. Mid-Continent benchmark reference margins for CBOB gasoline (conventional 87 gasoline prior to September 16, 2013) and ultra-low-sulfur diesel, a type of distillate, increased year over year by $3.03 per barrel and $3.90 per barrel, respectively, and these increases were primarily the result of a $1.67 per barrel increase in the discount between the price of WTI crude oil versus Brent crude oil. Brent crude oil is the type of crude oil used by the market to set the price of refined products, but our refineries in the U.S. Mid-Continent region primarily process WTI-type crude oil; therefore, the increase in the price discount between WTI crude oil versus Brent crude oil had a positive impact to our refining margin in this region of approximately $300 million. WTI crude oil priced at a significant discount to Brent crude oil during 2012 because of increases in crude oil reserves within the U.S. Mid-Continent region and increased deliveries of crude oil from Canada into that region, coupled with the inability to transport significant quantities of that crude oil to refineries in other regions of the country.

The $821 million increase in refining margin in the North Atlantic region was also due to improved gasoline and distillate margins in that region in 2012 compared to 2011. For example, the North Atlantic benchmark reference margins for CBOB gasoline and ultra-low-sulfur diesel increased year over year by $4.71 per barrel and $3.42 per barrel, respectively, and these increases were due largely to a reduction in the supply of refined products, which resulted from the continued shutdown of refineries in the U.S. East Coast, Caribbean, and

Western Europe during 2012, and supply disruptions caused by Hurricane Sandy, which struck the U.S. East Coast in October 2012.

The increase of $262 million in operating expenses discussed above was primarily due to an increase of $123 million in operating expenses of the Meraux Refinery, an increase of $214 million in operating expenses incurred by the Pembroke Refinery, and a decrease of $123 million in operating expenses incurred by the Aruba Refinery. We acquired the Pembroke Refinery on August 1, 2011 and the Meraux Refinery on October 1, 2011; therefore, operating expenses for 2011 only reflected five months of operating expenses of the Pembroke Refinery and three months of operating expenses of the Meraux Refinery. In addition, in March 2012, we suspended the operations of the Aruba Refinery, which resulted in a significant decrease in operating expenses related to that refinery in 2012. The remaining increase in operating expenses of $48 million was primarily due to an increase of $31 million in employee-related expenses due to higher compensation expense related to merit increases and promotions and higher expenses for employee benefit costs, an increase of $9 million in catalyst and chemical costs due to higher prices of rare earth metals used in our fluid catalytic cracking units, an increase of $61 million in ad valorem taxes and insurance expense due to increased insurance reserves in 2012 combined with a nonrecurring favorable ad valorem tax adjustment in 2011, and a decrease of $63 million in energy costs due to lower natural gas prices. Even though operating expenses increased year over year, operating expenses per barrel in 2012 were comparable to 2011 due to the incremental throughput of 179,000 BPD, which primarily resulted from the incremental throughput of the Pembroke and Meraux Refineries discussed above.

Retail

Retail operating income was $348 million for the year ended December 31, 2012 compared to $381 million for the year ended December 31, 2011. This 9 percent (or $33 million) decrease was primarily due to a $21 million noncash asset impairment loss related to certain convenience stores (see Note 4 of Notes to Consolidated Financial Statements), a $56 million decrease in fuel margin from our Canadian retail operations, and a $41 million increase in fuel margin in our U.S. retail operations.

The Canadian retail fuel margin for 2012 was impacted by a decline in fuel volumes sold as a result of fewer retail sites combined with a decline in the fuel margin per gallon, which was due to pricing pressure from our competitors and changes in wholesale motor fuel prices during the year. Our U.S. retail fuel margin improved during 2012 due to increased fuel volumes sold as a result of more retail sites combined with improved fuel margin per gallon as wholesale motor fuel prices peaked in March 2012 and declined throughout the remainder of the year.

Ethanol

Ethanol segment operating loss was $47 million for the year ended December 31, 2012 compared to operating income of $396 million for the year ended December 31, 2011. This decrease of $443 million was primarily due to a $507 million decrease in gross margin, partially offset by a $67 million decrease in operating expenses.

The decrease in gross margin was due to a 56 percent decrease in the gross margin per gallon of ethanol production (a $0.38 per gallon decrease between the comparable periods) primarily due to lower ethanol prices in 2012 versus 2011. Ethanol prices during 2012 were pressured by a surplus of ethanol supply due to reduced demand for ethanol associated with the decline in gasoline demand in the U.S., lower exports of ethanol to Europe, and increased imports of ethanol from Brazil. In addition, ethanol production decreased 385,000 gallons per day between the comparable periods due to lower utilization rates at our ethanol plants during 2012. The reduction in operating expenses was due primarily to a $57 million decrease in energy

costs resulting from decreased consumption because of the lower utilization rates previously discussed, combined with lower natural gas prices versus the comparable period of 2011.

Corporate Expenses and Other

General and administrative expenses increased $127 million for the year ended December 31, 2012 compared to the year ended December 31, 2011 due to $58 million in administrative costs related to our European operations, which we acquired on August 1, 2011, a $23 million increase in employee benefits expense (primarily related to increased costs for medical and retirement benefits), and favorable legal settlements of $47 million in 2011, which did not recur in 2012.

“Other income, net” for the year ended December 31, 2012 decreased $34 million from the year ended December 31, 2011 due to an increase of $15 million of foreign currency transaction losses, an $11 million reduction in interest income due to the collection of a note receivable from PBF Holdings LLC in February 2012, and a $7 million reduction in bank interest income due to lower levels of temporary cash investments during 2012 as compared to the prior year.

“Interest and debt expense, net of capitalized interest” for the year ended December 31, 2012 decreased $88 million from the year ended December 31, 2011. This decrease is primarily due to an increase of $69 million in capitalized interest related to an increase in capital expenditures between the years and a $33 million favorable impact from the decrease in average borrowings, partially offset by a $12 million write-off of unamortized debt discounts related to the early redemption of certain industrial revenue bonds in the first quarter of 2012.

Income tax expense for the year ended December 31, 2012 increased $400 million from the year ended December 31, 2011 partially as a result of higher operating income in 2012. The variation in the customary relationship between income tax expense and income from continuing operations before income tax expense for the year ended December 31, 2012 was primarily due to not recognizing the tax benefits associated with the asset impairment loss of $928 million and the severance expense of $41 million related to the Aruba Refinery as we do not expect to realize a tax benefit from these losses.

LIQUIDITY AND CAPITAL RESOURCES

Cash Flows for the Year Ended December 31, 2013

Net cash provided by operating activities for the year ended December 31, 2013 was $5.6 billion compared to $5.3 billion for the year ended December 31, 2012. Changes in cash provided by or used for working capital during the years ended December 31, 2013 and 2012 are shown in Note 19 of Notes to Consolidated Financial Statements.

The net cash generated from operating activities during the year ended December 31, 2013 combined with $735 million of net cash received in connection with the separation of our retail business (consisting of $550 million of proceeds on short-term debt, a $500 million cash distribution from CST less $315 million of cash retained by CST), and $525 million of proceeds on short-term debt related to the disposition of our retained interest in CST were used mainly to:

•	fund $2.8 billion of capital expenditures and deferred turnaround and catalyst costs;

•	make scheduled long-term note repayments of $480 million;

•	make a short-term debt repayment of $58 million;

•	purchase common stock for treasury of $928 million;

•	pay common stock dividends of $462 million; and

•	increase available cash on hand by $2.2 billion.

In addition, VLP completed its initial public offering of common units for net proceeds of $369 million. Because we consolidate VLP’s financial statements, the total cash reported by us also increased by these net proceeds; however, such proceeds can only be used by VLP for its purposes.

Cash Flows for the Year Ended December 31, 2012

Net cash provided by operating activities for the year ended December 31, 2012 was $5.3 billion compared to $4.0 billion for the year ended December 31, 2011. The increase in cash generated from operating activities was primarily due to the increase in operating income discussed above under “RESULTS OF OPERATIONS,” after excluding the effect of the asset impairment loss included in the 2012 operating income that had no effect on cash. Changes in cash provided by or used for working capital during the years ended December 31, 2012 and 2011 are shown in Note 19 of Notes to Consolidated Financial Statements.

The net cash generated from operating activities during the year ended December 31, 2012 combined with $300 million of proceeds from the remarketing of the 4.0% Gulf Opportunity Zone Revenue Bonds Series 2010 (GO Zone Bonds), $1.1 billion of borrowings under our revolving credit facility, and $1.5 billion of proceeds from the sale of receivables under our accounts receivable sales facility were used mainly to:

•	fund $3.4 billion of capital expenditures and deferred turnaround and catalyst costs;

•	redeem our Series 1997 5.6%, Series 1998 5.6%, Series 1999 5.7%, Series 2001 6.65%, and Series 1997A 5.45% industrial revenue bonds for $108 million;

•	make scheduled long-term note repayments of $754 million;

•	repay borrowings under our revolving credit facility of $1.1 billion;

•	make repayments under our accounts receivable sales facility of $1.7 billion;

•	purchase common stock for treasury of $281 million;

•	pay common stock dividends of $360 million; and

•	increase available cash on hand by $699 million.

Capital Investments

Our operations, especially those of our refining segment, are highly capital intensive. Each of our refineries comprises a large base of property assets, consisting of a series of interconnected, highly integrated and

interdependent crude oil processing facilities and supporting logistical infrastructure (Units), and these Units are improved continuously. The cost of improvements, which consist of the addition of new Units and betterments of existing Units, can be significant. We have historically acquired our refineries at amounts significantly below their replacement costs, whereas our improvements are made at full replacement value. As such, the costs for improving our refinery assets increase over time and are significant in relation to the amounts we paid to acquire our refineries. We plan for these improvements by developing a multi-year capital program that is updated and revised based on changing internal and external factors.

We make improvements to our refineries in order to maintain and enhance their operating reliability, to meet environmental obligations with respect to reducing emissions and removing prohibited elements from the products we produce, or to enhance their profitability. Reliability and environmental improvements generally do not increase the throughput capacities of our refineries. Improvements that enhance refinery profitability may increase throughput capacity, but many of these improvements allow our refineries to process different types of crude oil and refine crude oil into products with higher market values. Therefore, many of our improvements do not increase throughput capacity significantly.

For 2014, we expect to incur approximately $2.3 billion for capital expenditures and approximately $700 million for deferred turnaround and catalyst costs. The capital expenditure estimate excludes expenditures related to potential strategic acquisitions. We continuously evaluate our capital budget and make changes as conditions warrant.

Contractual Obligations

Our contractual obligations as of December 31, 2013 are summarized below (in millions).

	Payments Due by Period
	2014				2015				2016				2017				2018				Thereafter				Total
Debt and capital lease obligations (including interest on capital lease obligations)	$	308			$	483			$	7			$	957			$	6			$	4,851			$	6,612
Operating lease obligations	305				230				162				111				95				321				1,224
Purchase obligations	33,159				3,501				994				453				279				1,126				39,512
Other long-term liabilities	—				138				113				112				103				863				1,329
Total	$	33,772			$	4,352			$	1,276			$	1,633			$	483			$	7,161			$	48,677

Debt and Capital Lease Obligations

During 2013, we made scheduled long-term note repayments of $480 million as described in Note 11 of Notes to Consolidated Financial Statements.

We have an accounts receivable sales facility with a group of third-party entities and financial institutions to sell eligible trade receivables on a revolving basis up to $1.5 billion. As of December 31, 2013, the amount of eligible receivables sold was $100 million. All amounts outstanding under this facility are reflected as debt.

Our debt and financing agreements do not have rating agency triggers that would automatically require us to post additional collateral. However, in the event of certain downgrades of our senior unsecured debt by the ratings agencies, the cost of borrowings under some of our bank credit facilities and other arrangements

would increase. As of December 31, 2013, all of our ratings on our senior unsecured debt are at or above investment grade level as follows:

Rating Agency		Rating
Moody’s Investors Service		Baa2 (stable outlook)
Standard & Poor’s Ratings Services		BBB (negative outlook)
Fitch Ratings		BBB (stable outlook)

We cannot provide assurance that these ratings will remain in effect for any given period of time or that one or more of these ratings will not be lowered or withdrawn entirely by a rating agency. We note that these credit ratings are not recommendations to buy, sell, or hold our securities and may be revised or withdrawn at any time by the rating agency. Each rating should be evaluated independently of any other rating. Any future reduction below investment grade or withdrawal of one or more of our credit ratings could have a material adverse impact on our ability to obtain short- and long-term financing and the cost of such financings.

Operating Lease Obligations

Our operating lease obligations include leases for land, office facilities and equipment, transportation equipment, time charters for ocean-going tankers and coastal vessels, dock facilities, and various facilities and equipment used in the storage, transportation, production, and sale of refinery feedstocks, refined product, and corn inventories. Operating lease obligations include all operating leases that have initial or remaining noncancelable terms in excess of one year, and are not reduced by minimum rentals to be received by us under subleases.

Purchase Obligations

A purchase obligation is an enforceable and legally binding agreement to purchase goods or services that specifies significant terms, including (i) fixed or minimum quantities to be purchased, (ii) fixed, minimum, or variable price provisions, and (iii) the approximate timing of the transaction. We have various purchase obligations including industrial gas and chemical supply arrangements (such as hydrogen supply arrangements), crude oil and other feedstock supply arrangements, and various throughput and terminalling agreements. We enter into these contracts to ensure an adequate supply of utilities and feedstock and adequate storage capacity to operate our refineries. Substantially all of our purchase obligations are based on market prices or adjustments based on market indices. Certain of these purchase obligations include fixed or minimum volume requirements, while others are based on our usage requirements. The purchase obligation amounts shown in the table above include both short- and long-term obligations and are based on (a) fixed or minimum quantities to be purchased and (b) fixed or estimated prices to be paid based on current market conditions. As of December 31, 2013, there was no significant change in the amount of our short- and long-term purchase obligations as compared to December 31, 2012.

Other Long-term Liabilities

Our other long-term liabilities are described in Note 10 of Notes to Consolidated Financial Statements. For purposes of reflecting amounts for other long-term liabilities in the table above, we made our best estimate of expected payments for each type of liability based on information available as of December 31, 2013.

Other Commercial Commitments

As of December 31, 2013, our outstanding letters of credit under our committed lines of credit were as follows (in millions):

		Borrowing Capacity				Expiration		Outstanding Letters of Credit
Letter of credit facilities		$	550			June 2014		$	278
U.S. revolving credit facility		$	3,000			November 2018		$	59
Canadian revolving credit facility		C$	50			November 2014		C$	10

As of December 31, 2013, we had no amounts borrowed under our revolving credit facilities. The letters of credit outstanding as of December 31, 2013 expire during 2014 and 2015.

Off-Balance Sheet Arrangements

We have not entered into any transactions, agreements, or other contractual arrangements that would result in off-balance sheet liabilities.

Other Matters Impacting Liquidity and Capital Resources

Stock Purchase Programs

As of December 31, 2013, we have approvals under common stock purchase programs to purchase approximately $2.6 billion of our common stock. In January 2014, we purchased 4 million shares for $208 million.

Pension Plan Funding

We plan to contribute approximately $38 million to our pension plans and $19 million to our postretirement plans during 2014.

On February 15, 2013, we announced changes to certain of our pension plans that reduced our pension obligations. In addition, we expect that these changes will also reduce our benefit costs for future years, as further discussed in Note 14 of Notes to Consolidated Financial Statements.

Environmental Matters

Our operations are subject to extensive environmental regulations by governmental authorities relating to the discharge of materials into the environment, waste management, pollution prevention measures, greenhouse gas emissions, and characteristics and composition of gasolines and distillates. Because environmental laws and regulations are becoming more complex and stringent and new environmental laws and regulations are continuously being enacted or proposed, the level of future expenditures required for environmental matters could increase in the future. In addition, any major upgrades in any of our operating facilities could require material additional expenditures to comply with environmental laws and regulations. See Notes 10 and 12 of Notes to Consolidated Financial Statements for a further discussion of our environmental matters.

Tax Matters

During the first quarter of 2014, we expect to pay approximately $400 million in tax payments that relate to 2013 and that were recorded in income taxes payable as of December 31, 2013. In addition, we currently believe the cash we will pay for income taxes for 2014 will increase and that such amount may exceed the total income tax expense that will be reflected on our statement of income. This belief is primarily due to an expected decrease in deductions that we will claim on our U.S. federal income tax return for depreciation

on our property, plant, and equipment. In prior years, the U.S. federal government enacted certain legislation that provided for the deduction of depreciation on an accelerated basis on newly built equipment as a means of encouraging capital investment by businesses. This legislation, however, generally does not extend beyond 2013. Although we expect the amount of cash required to pay our 2014 income taxes to increase compared to recent prior years, we believe that we will generate sufficient cash from operations and have sufficient cash on hand to make our tax payments as they become due.

As of December 31, 2013, the IRS has ongoing tax audits related to our U.S. federal tax returns from 2002 through 2011. We have received Revenue Agent Reports in connection with the 2002 through 2009 audits, and we are vigorously contesting certain tax positions and assertions from the IRS. We made significant progress during 2013 in resolving certain of these matters, and in January 2014, we settled the audit related to the 2004 and 2005 tax years for a group of our subsidiaries for an amount consistent with the recorded amount of unrecognized tax benefits associated with that audit. We are continuing to work with the IRS to resolve the remaining matters and expect to settle other audits within the next 12 months for amounts consistent with the recorded amounts of unrecognized tax benefits associated with those audits. Because these settlements are expected to occur in 2014, we classified certain of our long-term uncertain tax position liabilities to current liabilities as of December 31, 2013. The total amount of uncertain tax position liabilities was $443 million as of December 31, 2013, with $238 million reflected in “income taxes payable” and $205 million reflected in “other long-term liabilities”, and this total amount did not change significantly during the year ended December 31, 2013. Should we ultimately settle for amounts consistent with our estimates, we believe that we will have sufficient cash on hand at that time to make such payments.

Cash Held by Our International Subsidiaries

We operate in countries outside the U.S. through subsidiaries incorporated in these countries, and the earnings of these subsidiaries are taxed by the countries in which they are incorporated. We intend to reinvest these earnings indefinitely in our international operations even though we are not restricted from repatriating such earnings to the U.S. in the form of cash dividends. Should we decide to repatriate such earnings, we would incur and pay taxes on the amounts repatriated. In addition, such repatriation could cause us to record deferred tax expense that could significantly impact our results of operations, as further discussed in Note 16 of Notes to Consolidated Financial Statements. We believe, however, that a substantial portion of our international cash can be returned to the U.S. without significant tax consequences through means other than a repatriation of earnings. As of December 31, 2013, $1.1 billion of our cash and temporary cash investments was held by our international subsidiaries.

Financial Regulatory Reform

In July 2010, President Obama signed into law the Dodd-Frank Wall Street Reform and Consumer Protection Act (Wall Street Reform Act). Key provisions of the Wall Street Reform Act create new statutory requirements that require most derivative instruments to be traded on exchanges and routed through clearinghouses, as well as impose new recordkeeping and reporting responsibilities on market participants. While certain final rules implementing the Wall Street Reform Act became effective in the fourth quarter of 2012, others continue to become effective in 2013 and 2014. Although we cannot predict the ultimate impact of these rules, which may result in higher clearing costs and more reporting requirements with respect to our derivative activities, we believe they will not have a material impact on our financial position, results of operations, or liquidity.

Concentration of Customers

Our refining and marketing operations have a concentration of customers in the refining industry and customers who are refined product wholesalers and retailers. These concentrations of customers may impact our overall exposure to credit risk, either positively or negatively, in that these customers may be similarly affected by changes in economic or other conditions. However, we believe that our portfolio of accounts

receivable is sufficiently diversified to the extent necessary to minimize potential credit risk. Historically, we have not had any significant problems collecting our accounts receivable.

Sources of Liquidity

We believe that we have sufficient funds from operations and, to the extent necessary, from borrowings under our credit facilities, to fund our ongoing operating requirements. We expect that, to the extent necessary, we can raise additional funds from time to time through equity or debt financings in the public and private capital markets or the arrangement of additional credit facilities. However, there can be no assurances regarding the availability of any future financings or additional credit facilities or whether such financings or additional credit facilities can be made available on terms that are acceptable to us.

NEW ACCOUNTING PRONOUNCEMENTS

As discussed in Note 1 of Notes to Consolidated Financial Statements, certain new financial accounting pronouncements will become effective for our financial statements in the future. The adoption of these pronouncements is not expected to have a material effect on our financial statements.

CRITICAL ACCOUNTING POLICIES INVOLVING CRITICAL ACCOUNTING ESTIMATES

The preparation of financial statements in accordance with U.S. generally accepted accounting principles requires us to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Actual results could differ from those estimates. The following summary provides further information about our critical accounting policies that involve critical accounting estimates, and should be read in conjunction with Note 1 of Notes to Consolidated Financial Statements, which summarizes our significant accounting policies. The following accounting policies involve estimates that are considered critical due to the level of subjectivity and judgment involved, as well as the impact on our financial position and results of operations. We believe that all of our estimates are reasonable.

Property, Plant, and Equipment

Depreciation of property assets used in our refining segment is recorded on a straight-line basis over the estimated useful lives of these assets primarily using the composite method of depreciation. We maintain a separate composite group of property assets for each of our refineries. We estimate the useful life of each group based on an evaluation of the property assets comprising the group, and such evaluations consist of, but are not limited to, the physical inspection of the assets to determine their condition, consideration of the manner in which the assets are maintained, assessment of the need to replace assets, and evaluation of the manner in which improvements impact the useful life of the group. The estimated useful lives of our composite groups range primarily from 25 to 30 years.

Under the composite method of depreciation, the cost of an improvement is added to the composite group to which it relates and is depreciated over that group’s estimated useful life. We design improvements to our refineries in accordance with engineering specifications, design standards and practices accepted in our industry, and these improvements have design lives consistent with our estimated useful lives. Therefore, we believe the use of the group life to depreciate the cost of improvements made to the group is reasonable because the estimated useful life of each improvement is consistent with that of the group. It should be noted, however, that factors such as competition, regulation, or environmental matters could cause us to change our estimates, thus impacting depreciation expense in the future.

Impairment of Assets

Long-lived assets (which include property, plant, and equipment, intangible assets, and refinery turnaround and catalyst costs) and equity method investments are tested for recoverability whenever events or changes in circumstances indicate that the carrying amount of the asset may not be recoverable. An impairment loss should be recognized if the carrying amount of the asset exceeds its fair value.

In order to test for recoverability, we must make estimates of projected cash flows related to the asset being evaluated, which include, but are not limited to, assumptions about the use or disposition of the asset, its estimated remaining life, and future expenditures necessary to maintain its existing service potential. In order to determine fair value, management must make certain estimates and assumptions including, among other things, an assessment of market conditions, projected cash flows, investment rates, interest/equity rates, and growth rates, that could significantly impact the fair value of the asset being tested for impairment. Our impairment evaluations are based on assumptions that we deem to be reasonable. Providing sensitivity analyses if other assumptions were used in performing the impairment evaluations is not practicable due to the significant number of assumptions involved in the estimates. See Note 4 of Notes to Consolidated Financial Statements for a further discussion of our asset impairment analysis and certain losses resulting from those analyses.

Environmental Matters

Our operations are subject to extensive environmental regulations by governmental authorities relating primarily to the discharge of materials into the environment, waste management, and pollution prevention measures. Future legislative action and regulatory initiatives, as discussed in Note 12 of Notes to Consolidated Financial Statements could result in changes to required operating permits, additional remedial actions, or increased capital expenditures and operating costs that cannot be assessed with certainty at this time.

Accruals for environmental liabilities are based on best estimates of probable undiscounted future costs over a 20-year time period using currently available technology and applying current regulations, as well as our own internal environmental policies. However, environmental liabilities are difficult to assess and estimate due to uncertainties related to the magnitude of possible remediation, the timing of such remediation, and the determination of our obligation in proportion to other parties. Such estimates are subject to change due to many factors, including the identification of new sites requiring remediation, changes in environmental laws and regulations and their interpretation, additional information related to the extent and nature of remediation efforts, and potential improvements in remediation technologies. An estimate of the sensitivity to earnings for changes in those factors is not practicable due to the number of contingencies that must be assessed, the number of underlying assumptions, and the wide range of possible outcomes.

The amount of and changes in our accruals for environmental matters as of and for the years ended December 31, 2013, 2012, and 2011 is included in Note 10 of Notes to Consolidated Financial Statements.

Pension and Other Postretirement Benefit Obligations

We have significant pension and other postretirement benefit liabilities and costs that are developed from actuarial valuations. Inherent in these valuations are key assumptions including discount rates, expected return on plan assets, future compensation increases, and health care cost trend rates, and these assumptions are disclosed and described in Note 14 of Notes to Consolidated Financial Statements. Changes in these assumptions are primarily influenced by factors outside our control. For example, the discount rate assumption represents a yield curve comprised of various long-term bonds that have an average rating of double-A when averaging all available ratings by the recognized rating agencies, while the expected return on plan assets is based on a compounded return calculated assuming an asset allocation that is representative of the asset mix in our pension plans. To determine the expected return on plan assets, we utilized a forward-

looking model of asset returns. The historical geometric average return over the 10 years prior to December 31, 2013 was 8.86 percent. The actual return on assets for the years ended December 31, 2013, 2012 and 2011 was 19.38 percent, 11.84 percent, and 0.10 percent, respectively. These assumptions can have a significant effect on the amounts reported in our financial statements. For example, a 0.25 percent decrease in the assumptions related to the discount rate or expected return on plan assets or a 0.25 percent increase in the assumptions related to the health care cost trend rate or rate of compensation increase would have the following effects on the projected benefit obligation as of December 31, 2013 and net periodic benefit cost for the year ending December 31, 2014 (in millions):

	Pension Benefits				Other Postretirement Benefits
Increase in projected benefit obligation resulting from:
Discount rate decrease	$	83			$	10
Compensation rate increase	6				n/a
Health care cost trend rate increase	n/a				1
Increase in expense resulting from:
Discount rate decrease	8				—
Expected return on plan assets decrease	4				n/a
Compensation rate increase	2				n/a
Health care cost trend rate increase	n/a				—

See Note 14 of Notes to Consolidated Financial Statements for a further discussion of our pension and other postretirement benefit obligations.

Tax Matters

We record tax liabilities based on our assessment of existing tax laws and regulations. A contingent loss related to an indirect tax claim is recorded if the loss is both probable and estimable. The recording of our tax liabilities requires significant judgments and estimates. Actual tax liabilities can vary from our estimates for a variety of reasons, including different interpretations of tax laws and regulations and different assessments of the amount of tax due. In addition, in determining our income tax provision, we must assess the likelihood that our deferred tax assets, primarily consisting of net operating loss and tax credit carryforwards, will be recovered through future taxable income. Significant judgment is required in estimating the amount of valuation allowance, if any, that should be recorded against those deferred income tax assets. If our actual results of operations differ from such estimates or our estimates of future taxable income change, the valuation allowance may need to be revised. However, an estimate of the sensitivity to earnings that would result from changes in the assumptions and estimates used in determining our tax liabilities is not practicable due to the number of assumptions and tax laws involved, the various potential interpretations of the tax laws, and the wide range of possible outcomes. See Notes 12 and 16 of Notes to Consolidated Financial Statements for a further discussion of our tax liabilities.

Legal Matters

A variety of claims have been made against us in various lawsuits. We record a liability related to a loss contingency attributable to such legal matters if we determine that it is probable that a loss has been incurred and that the loss is reasonably estimable. The recording of such liabilities requires judgments and estimates, the results of which can vary significantly from actual litigation results due to differing interpretations of

relevant law and differing opinions regarding the degree of potential liability and the assessment of reasonable damages. However, an estimate of the sensitivity to earnings if other assumptions were used in recording our legal liabilities is not practicable due to the number of contingencies that must be assessed and the wide range of reasonably possible outcomes, both in terms of the probability of loss and the estimates of such loss.