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 Item 1A, “Risk Factors,” 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 in the regions where we operate, as well as globally;

•	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 alternative fuels;

•	the volatility in the market price of biofuel credits (primarily Renewable Identification Numbers (RINs) needed to comply with the U.S. federal Renewable Fuel Standard);

•	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 implemented under the California Global Warming Solutions Act (also known as AB 32), Quebec’s Regulation respecting the cap-and-trade system for greenhouse gas emission allowances (the Quebec cap-and-trade system), and the U.S. 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 Item 1A, “Risk Factors” 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, 2014, we reported net income attributable to Valero stockholders from continuing operations of $3.7 billion, or $6.97 per share (assuming dilution), compared to $2.7 billion, or $4.96 per share (assuming dilution), for the year ended December 31, 2013. The increase of $980 million was due primarily to the increase of $1.9 billion in our operating income as shown in the table below. The increase in our operating income was partially offset by a $325 million nontaxable gain recorded in 2013 related to the disposition of our retained interest in CST, which is more fully described in Notes 3 and 11 of Notes to Consolidated Financial Statements.

Our operating income increased $1.9 billion from 2013 to 2014 as outlined by business segment in the following table (in millions):

		Year Ended December 31,
		2014				2013				Change
Operating income (loss) by business segment:
Refining		$	5,884			$	4,211			$	1,673
Ethanol		786				491				295
Retail		—				81				(81		)
Corporate		(768		)		(826		)		58
Total		$	5,902			$	3,957			$	1,945

The $1.7 billion increase in refining segment operating income for 2014 compared to 2013 was due to wider discounts for sweet and sour crude oils relative to Brent crude oil, higher throughput volumes in our U.S. Gulf Coast region, and higher margins on other refined products (e.g., petroleum coke and sulfur), partially offset by weaker distillate margins. Higher energy costs and depreciation expense between the periods also impacted our refining segment income. Our ethanol segment operating income increased $295 million in 2014 compared to 2013 due to lower corn feedstock costs and higher production volumes, partially offset by lower co-product prices and lower ethanol prices.

On May 1, 2013, we completed the separation of our retail business, by spinning off CST as an independent public company. Therefore, we did not have any retail segment operations in 2014, resulting in the $81 million decrease in retail segment operating income in 2014 compared to 2013.

Additional details and analysis of the changes in the operating income of our business segments and other components of net income attributable to Valero stockholders are provided below under “RESULTS OF OPERATIONS.”

Outlook

Energy markets and margins were volatile during 2014, especially in the latter part of the year, and we expect them to continue to be volatile in the near to mid-term. Below is a summary of factors that have impacted or may impact our results of operations during the first quarter of 2015:

•	Discounts in the price of medium sour and heavy sour crude oils as compared to the price of Brent crude oil have widened since year end as producers of those crude oils have attempted to maintain market share in an oversupplied crude oil market.

•

Discounts in the price of North American sweet crude oils as compared to the price of Brent crude oil are expected to increase due to a build in U.S. crude oil inventories, driven primarily by (i) increasing imports of medium sour and heavy sour crude oils, (ii) seasonal planned refinery maintenance, and (iii) a crude oil market structure where the future price is higher than the current price of crude oil, which indicates that the crude oil market is oversupplied.

•	Refined product margins are expected to strengthen due to an increase in the demand for refined products and the impact on product inventories from refinery maintenance thus far in the first quarter of 2015.

•	Ethanol margins are expected to remain relatively low as long as gasoline prices remain low.

•	The market price of biofuel credits (primarily RINs) is expected to remain volatile during 2015.

•	The cost to implement certain provisions of the AB 32 cap-and-trade system and low carbon fuel standard in California and the Quebec cap-and-trade system may be significant; however, we expect to recover the majority of these costs from our customers.

•	A further decline in market prices of crude oil and refined products may negatively impact the carrying value of our inventories.

•

The United Steelworkers union and the U.S. refining industry are currently in the process of collective bargaining and strikes have been called at 12 U.S. refineries. We have four refineries that could be targeted for a strike but none has been targeted at this time. Also note our disclosures in Item 1A, “Risk Factors” — Our business may be negatively affected by work stoppages, slowdowns or strikes by our employees, as well as new labor legislation issued by regulators.

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.

2014 Compared to 2013

Financial Highlights (a)

(millions of dollars, except per share amounts)

	Year Ended December 31,
	2014				2013 (b)				Change
Operating revenues	$	130,844			$	138,074			$	(7,230	)
Costs and expenses:
Cost of sales	118,141				127,316				(9,175		)
Operating expenses:
Refining	3,900				3,710				190
Retail	—				226				(226		)
Ethanol	487				387				100
General and administrative expenses	724				758				(34		)
Depreciation and amortization expense:
Refining	1,597				1,566				31
Retail	—				41				(41		)
Ethanol	49				45				4
Corporate	44				68				(24		)
Total costs and expenses	124,942				134,117				(9,175		)
Operating income	5,902				3,957				1,945
Gain on disposition of retained interest in CST Brands, Inc. (b)	—				325				(325		)
Other income, net	47				59				(12		)
Interest and debt expense, net of capitalized interest	(397		)		(365		)		(32		)
Income from continuing operations before income tax expense	5,552				3,976				1,576
Income tax expense	1,777				1,254				523
Income from continuing operations	3,775				2,722				1,053
Income (loss) from discontinued operations	(64		)		6				(70		)
Net income	3,711				2,728				983
Less: Net income attributable to noncontrolling interests	81				8				73
Net income attributable to Valero Energy Corporation stockholders	$	3,630			$	2,720			$	910
Net income attributable to Valero Energy Corporation stockholders:
Continuing operations	$	3,694			$	2,714			$	980
Discontinued operations	(64		)		6				(70		)
Total	$	3,630			$	2,720			$	910
Earnings per common share – assuming dilution:
Continuing operations	$	6.97			$	4.96			$	2.01
Discontinued operations	(0.12		)		0.01				(0.13		)
Total	$	6.85			$	4.97			$	1.88

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See note references on page 31.

Refining Operating Highlights (a)

(millions of dollars, except per barrel amounts)

	Year Ended December 31,
	2014				2013				Change
Refining:
Operating income	$	5,884			$	4,211			$	1,673
Throughput margin per barrel (c)	$	11.28			$	9.69			$	1.59
Operating costs per barrel:
Operating expenses	3.87				3.79				0.08
Depreciation and amortization expense	1.58				1.60				(0.02		)
Total operating costs per barrel	5.45				5.39				0.06
Operating income per barrel	$	5.83			$	4.30			$	1.53
Throughput volumes (thousand BPD):
Feedstocks:
Heavy sour crude oil	457				486				(29		)
Medium/light sour crude oil	466				466				—
Sweet crude oil	1,149				1,039				110
Residuals	230				282				(52		)
Other feedstocks	134				106				28
Total feedstocks	2,436				2,379				57
Blendstocks and other	329				303				26
Total throughput volumes	2,765				2,682				83
Yields (thousand BPD):
Gasolines and blendstocks	1,329				1,287				42
Distillates	1,047				984				63
Other products (d)	423				440				(17		)
Total yields	2,799				2,711				88

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See note references on page 31.

Refining Operating Highlights by Region (e)

(millions of dollars, except per barrel amounts)

	Year Ended December 31,
	2014				2013				Change
U.S. Gulf Coast (a):
Operating income	$	3,484			$	2,375			$	1,109
Throughput volumes (thousand BPD)	1,600				1,523				77
Throughput margin per barrel (c)	$	11.23			$	9.57			$	1.66
Operating costs per barrel:
Operating expenses	3.66				3.67				(0.01		)
Depreciation and amortization expense	1.60				1.63				(0.03		)
Total operating costs per barrel	5.26				5.30				(0.04		)
Operating income per barrel	$	5.97			$	4.27			$	1.70
U.S. Mid-Continent:
Operating income	$	1,358			$	1,293			$	65
Throughput volumes (thousand BPD)	446				435				11
Throughput margin per barrel (c)	$	13.85			$	13.37			$	0.48
Operating costs per barrel:
Operating expenses	3.90				3.58				0.32
Depreciation and amortization expense	1.61				1.64				(0.03		)
Total operating costs per barrel	5.51				5.22				0.29
Operating income per barrel	$	8.34			$	8.15			$	0.19
North Atlantic:
Operating income	$	971			$	570			$	401
Throughput volumes (thousand BPD)	457				459				(2		)
Throughput margin per barrel (c)	$	10.38			$	7.93			$	2.45
Operating costs per barrel:
Operating expenses	3.40				3.50				(0.10		)
Depreciation and amortization expense	1.16				1.03				0.13
Total operating costs per barrel	4.56				4.53				0.03
Operating income per barrel	$	5.82			$	3.40			$	2.42
U.S. West Coast:
Operating income (loss)	$	71			$	(27	)		$	98
Throughput volumes (thousand BPD)	262				265				(3		)
Throughput margin per barrel (c)	$	8.79			$	7.43			$	1.36
Operating costs per barrel:
Operating expenses	5.91				5.35				0.56
Depreciation and amortization expense	2.14				2.35				(0.21		)
Total operating costs per barrel	8.05				7.70				0.35
Operating income (loss) per barrel	$	0.74			$	(0.27	)		$	1.01
Total refining operating income	$	5,884			$	4,211			$	1,673

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See note references on page 31.

Average Market Reference Prices and Differentials

(dollars per barrel, except as noted)

	Year Ended December 31,
	2014				2013				Change
Feedstocks:
Brent crude oil	$	99.57			$	108.74			(9.17	)
Brent less West Texas Intermediate (WTI) crude oil	6.40				10.80				(4.40	)
Brent less Alaska North Slope (ANS) crude oil	1.73				1.00				0.73
Brent less Louisiana Light Sweet (LLS) crude oil	2.79				0.41				2.38
Brent less Mars crude oil	6.75				5.52				1.23
Brent less Maya crude oil	13.73				11.31				2.42
LLS crude oil	96.78				108.33				(11.55	)
LLS less Mars crude oil	3.96				5.11				(1.15	)
LLS less Maya crude oil	10.94				10.90				0.04
WTI crude oil	93.17				97.94				(4.77	)
Natural gas (dollars per million British thermal units (MMBtu))	4.36				3.69				0.67
Products:
U.S. Gulf Coast:
CBOB gasoline less Brent	3.54				2.69				0.85
Ultra-low-sulfur diesel less Brent	14.28				15.95				(1.67	)
Propylene less Brent	5.57				(2.72		)		8.29
CBOB gasoline less LLS	6.33				3.10				3.23
Ultra-low-sulfur diesel less LLS	17.07				16.36				0.71
Propylene less LLS	8.36				(2.31		)		10.67
U.S. Mid-Continent:
CBOB gasoline less WTI	12.28				16.77				(4.49	)
Ultra-low-sulfur diesel less WTI	24.05				28.33				(4.28	)
North Atlantic:
CBOB gasoline less Brent	9.07				8.50				0.57
Ultra-low-sulfur diesel less Brent	18.25				17.84				0.41
U.S. West Coast:
CARBOB 87 gasoline less ANS	13.40				12.69				0.71
CARB diesel less ANS	19.14				18.83				0.31
CARBOB 87 gasoline less WTI	18.07				22.49				(4.42	)
CARB diesel less WTI	23.81				28.63				(4.82	)
New York Harbor corn crush (dollars per gallon)	0.85				0.42				0.43

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See note references on page 31.

Ethanol and Retail Operating Highlights

(millions of dollars, except per gallon amounts)

	Year Ended December 31,
	2014				2013				Change
Ethanol:
Operating income	$	786			$	491			$	295
Production (thousand gallons per day)	3,422				3,294				128
Gross margin per gallon of production (c)	$	1.06			$	0.77			$	0.29
Operating costs per gallon of production:
Operating expenses	0.39				0.32				0.07
Depreciation and amortization expense	0.04				0.04				—
Total operating costs per gallon of production	0.43				0.36				0.07
Operating income per gallon of production	$	0.63			$	0.41			$	0.22
Retail:
Operating income	$	—			$	81			$	(81	)

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See note references on page 31.

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

(a)

In May 2014, we abandoned our Aruba Refinery, except for the associated crude oil and refined products terminal assets that we continue to operate. As a result, the refinery’s results of operations have been presented as discontinued operations and the operating highlights for the refining segment and the U.S. Gulf Coast region exclude the Aruba Refinery for all years presented. This transaction is more fully described in Note 2 of Notes to Consolidated Financial Statements.

(b)

On May 1, 2013, we completed the separation of our retail business. As a result and effective May 1, 2013, our results of operations no longer include those of CST, our former retail business. 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. This transaction is more fully discussed in Note 3 of Notes to Consolidated Financial Statements.

(c)	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.

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

(e)

The regions reflected herein contain the following refineries: the U.S. Gulf Coast region includes the 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 $7.2 billion (or 5 percent) for the year ended December 31, 2014 compared to the year ended December 31, 2013. This decrease was primarily due to a decrease in refined product prices in all of our regions. Despite the decline in operating revenues, operating income increased $1.9 billion for the year ended December 31, 2014 compared to the year ended December 31, 2013 due primarily to a $1.7 billion increase in refining segment operating income, a $295 million increase in ethanol segment operating income, and a $34 million decrease in general and administrative expenses, partially offset by an $81 million decrease in retail segment operating income due to the spin-off of our retail business in 2013 as mentioned previously. 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 increased $1.7 billion from $4.2 billion for the year ended December 31, 2013 to $5.9 billion for the year ended December 31, 2014, due primarily to a $1.9 billion increase in refining margin, partially offset by a $190 million increase in operating expenses and a $31 million increase in depreciation and amortization expense.

Refining margin increased $1.9 billion (a $1.59 per barrel increase) in 2014 compared to 2013, due primarily to the following:

•

Higher discounts on light sweet crude oils and sour crude oils - Because the market prices for refined products generally track 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. For the year ended December 31, 2014, the discount in the price of some light sweet crude oils and sour crude oils compared to the price of Brent crude oil widened. For example, LLS crude oil processed in our U.S. Gulf Coast region, which is a light sweet crude oil, sold at a discount of $2.79 per barrel to Brent crude oil for the year ended December 31, 2014 compared to $0.41 per barrel for the year ended December 31, 2013, representing a favorable increase of $2.38 per barrel. Another example is Maya crude oil, a sour crude oil, which sold at a discount of $13.73 per barrel to Brent crude oil during the year ended December 31, 2014 compared to a discount of $11.31 per barrel during the year ended December 31, 2013, representing a favorable increase of $2.42 per barrel. We estimate that the discounts for light sweet crude oils and sour crude oils that we processed during the year ended December 31, 2014 had a positive impact to our refining margin of approximately $680 million and $800 million, respectively.

•	Higher throughput volumes - Refining throughput volumes increased 83,000 BPD for the year ended December 31, 2014 compared to the year ended December 31, 2013. We estimate that the increase in refining throughput volumes had a positive impact on our refining margin of approximately $340 million.

•

Lower costs of biofuel credits - As more fully described in Note 21 of Notes to Consolidated Financial Statements, we purchase biofuel credits in order to meet our biofuel blending obligations under various government and regulatory compliance programs, and the cost of these credits (primarily RINs in the U.S.) decreased by $145 million from $517 million in 2013 to $372 million in 2014. This decrease was due primarily to a reduction in the market price of RINs between the two years.

•

Increase in other refinery products margins - We experienced an increase in the margins of other refinery products relative to Brent crude oil, such as petroleum coke and sulfur during 2014 compared to 2013. Margins for other refinery products were higher during 2014 due to the decrease in the cost of crude oils during the year compared to 2013. For example, the benchmark price of Brent crude oil was $99.57 per barrel for the year ended December 31, 2014 compared to $108.74 for the year ended December 31,

2013. We estimate that the increase in other refinery products margins during the year ended December 31, 2014 compared to the year ended December 31, 2013 had a positive impact to our refining margin of approximately $430 million.

•

Decrease in distillate margins - We experienced a decrease in distillate margins in our U.S. Gulf Coast region primarily due to the decrease in refined product prices . For example, the Brent-based benchmark reference margin for U.S. Gulf Coast ultra-low sulfur diesel was $14.28 per barrel for the year ended December 31, 2014 compared to $15.95 per barrel for the year ended December 31, 2013, representing an unfavorable decrease of $1.67 per barrel. We estimate that the decline in distillate margins during the year ended December 31, 2014 compared to the year ended December 31, 2013 had a negative impact to our refining margin of approximately $400 million.

The increase of $190 million in operating expenses was primarily due to a $128 million increase in energy costs related to higher natural gas prices ($4.36 per MMBtu for the year ended December 31, 2014 compared to $3.69 per MMBtu for the year ended December 31, 2013) and a $22 million increase in maintenance expense primarily related to higher levels of routine maintenance activities during the year ended December 31, 2014.

The increase of $31 million in depreciation and amortization expense was primarily due to additional depreciation expense of $25 million associated with the new hydrocracker unit at our St. Charles Refinery that began operating in July 2013.

Ethanol

Ethanol segment operating income was $786 million for the year ended December 31, 2014 compared to $491 million for the year ended December 31, 2013. The $295 million increase in operating income was due primarily to a $399 million increase in gross margin (a $0.29 per gallon increase), partially offset by a $100 million increase in operating expenses.

Ethanol gross margin per gallon increased to $1.06 per gallon for the year ended December 31, 2014 from $0.77 per gallon for the year ended December 31, 2013 due primarily to the following:

•

Lower corn prices - Corn prices were lower in 2014 due to higher corn inventories in 2014 compared to 2013, which resulted from a higher yielding harvest in 2013 compared to the drought-stricken harvest of 2012. For example, the Chicago Board of Trade corn price was $4.16 per bushel in 2014 compared to $5.80 per bushel in 2013. The decrease in the price of corn that we processed during 2014 favorably impacted our ethanol margin by approximately $910 million.

•

Lower ethanol prices - Ethanol prices were lower in 2014 due to higher ethanol inventories resulting from higher industry run rates in 2014 as compared to 2013. The decrease in crude oil and gasoline prices in 2014 also contributed to the decrease in ethanol prices. For example, the New York Harbor ethanol price was $2.37 per gallon in 2014 compared to $2.53 per gallon in 2013. The decrease in the price of ethanol per gallon during 2014 had an unfavorable impact to our ethanol margin of approximately $260 million.

•	Lower co-product prices - The decrease in corn prices in 2014 had a negative effect on the prices we received for corn-related ethanol co-products, such as distillers grains and corn oil. The decrease in co-products prices had an unfavorable impact to our ethanol segment margin of approximately $250 million.

The $100 million increase in operating expenses during 2014 compared to 2013 was partially due to $22 million in operating expenses of the Mount Vernon plant acquired in March 2014. The remaining increase of $78 million was primarily due to increased energy costs and chemical costs. The increase in energy costs of $57 million was due primarily to the severe winter weather in the U.S. in the first quarter of 2014 that caused a significant increase in regional natural gas prices combined with higher use of natural gas due to the increase in production volumes. The increase in chemical costs of $16 million was due to higher production volumes.

Corporate Expenses and Other

General and administrative expenses decreased $34 million from the year ended December 31, 2013 to the year ended December 31, 2014 primarily due to $30 million of transaction costs related to the separation of our retail business on May 1, 2013 that were recorded in 2013 and did not recur.

Depreciation and amortization expense decreased $24 million primarily due to a $20 million loss on the sale of certain corporate property in 2013 that was reflected in depreciation and amortization expense.

“Interest and debt expense, net of capitalized interest” for the year ended December 31, 2014 increased $32 million from the year ended December 31, 2013. This increase was primarily due to a $48 million decrease in capitalized interest due to the completion of several large capital projects during 2013, including the new hydrocracker at our St. Charles Refinery, partially offset by a $20 million favorable impact from a decrease in average borrowings.

Income tax expense increased $523 million from the year ended December 31, 2013 to the year ended December 31, 2014 due to higher income from continuing operations before income tax expense. The effective rate for both years is lower than the U.S. statutory rate because income from continuing operations from our international operations was taxed at statutory rates that were lower than in the U.S. and due to a higher benefit from our U.S. manufacturing deduction.

Income (loss) from discontinued operations for the year ended December 31, 2014 includes expenses of $59 million for an asset retirement obligation and $4 million for certain contractual obligations associated with our decision in May 2014 to abandon the Aruba Refinery, as further described in Note 2 of Notes to Consolidated Financial Statements.

2013 Compared to 2012

Financial Highlights (a)

(millions of dollars, except per share amounts)

	Year Ended December 31,
	2013 (b)				2012				Change
Operating revenues	$	138,074			$	138,393			$	(319	)
Costs and expenses:
Cost of sales	127,316				126,485				831
Operating expenses:
Refining	3,710				3,513				197
Retail	226				686				(460		)
Ethanol	387				332				55
General and administrative expenses	758				698				60
Depreciation and amortization expense:
Refining	1,566				1,345				221
Retail	41				119				(78		)
Ethanol	45				42				3
Corporate	68				43				25
Asset impairment losses (c)	—				86				(86		)
Total costs and expenses	134,117				133,349				768
Operating income	3,957				5,044				(1,087		)
Gain on disposition of retained interest in CST Brands, Inc. (b)	325				—				325
Other income, net	59				10				49
Interest and debt expense, net of capitalized interest	(365		)		(314		)		(51		)
Income from continuing operations before income tax expense	3,976				4,740				(764		)
Income tax expense	1,254				1,626				(372		)
Income from continuing operations	2,722				3,114				(392		)
Income (loss) from discontinued operations	6				(1,034		)		1,040
Net income	2,728				2,080				648
Less: Net income (loss) attributable to noncontrolling interest	8				(3		)		11
Net income attributable to Valero Energy Corporation stockholders	$	2,720			$	2,083			$	637
Net income attributable to Valero Energy Corporation stockholders:
Continuing operations	$	2,714			$	3,117			$	(403	)
Discontinued operations	6				(1,034		)		1,040
Total	$	2,720			$	2,083			$	637
Earnings per common share – assuming dilution:
Continuing operations	$	4.96			$	5.61			$	(0.65	)
Discontinued operations	0.01				(1.86		)		1.87
Total	$	4.97			$	3.75			$	1.22

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See note references on page 39.

Refining Operating Highlights (a)

(millions of dollars, except per barrel amounts)

	Year Ended December 31,
	2013				2012				Change
Refining (c):
Operating income	$	4,211			$	5,484			$	(1,273	)
Throughput margin per barrel (e)	$	9.69			$	11.00			$	(1.31	)
Operating costs per barrel:
Operating expenses	3.79				3.71				0.08
Depreciation and amortization expense	1.60				1.42				0.18
Total operating costs per barrel	5.39				5.13				0.26
Operating income per barrel	$	4.30			$	5.87			$	(1.57	)
Throughput volumes (thousand BPD):
Feedstocks:
Heavy sour crude oil	486				431				55
Medium/light sour crude oil	466				546				(80		)
Sweet crude oil	1,039				991				48
Residuals	282				199				83
Other feedstocks	106				118				(12		)
Total feedstocks	2,379				2,285				94
Blendstocks and other	303				299				4
Total throughput volumes	2,682				2,584				98
Yields (thousand BPD):
Gasolines and blendstocks	1,287				1,249				38
Distillates	984				909				75
Other products (f)	440				451				(11		)
Total yields	2,711				2,609				102

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See note references on page 39.

Refining Operating Highlights by Region (g)

(millions of dollars, except per barrel amounts)

	Year Ended December 31,
	2013				2012				Change
U.S. Gulf Coast (a) (c):
Operating income	$	2,375			$	2,606			$	(231	)
Throughput volumes (thousand BPD)	1,523				1,459				64
Throughput margin per barrel (e)	$	9.57			$	9.71			$	(0.14	)
Operating costs per barrel:
Operating expenses	3.67				3.41				0.26
Depreciation and amortization expense	1.63				1.42				0.21
Total operating costs per barrel	5.30				4.83				0.47
Operating income per barrel	$	4.27			$	4.88			$	(0.61	)
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	$	4,211			$	5,549			$	(1,338	)
Asset impairment loss applicable to refining (c)	—				(65		)		65
Total refining operating income	$	4,211			$	5,484			$	(1,273	)

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See note references on page 39.

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 WTI crude oil	10.80				17.55				(6.75		)
Brent less ANS crude oil	1.00				1.08				(0.08		)
Brent less 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 (MMBtu))	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 39.

Ethanol and Retail Operating Highlights

(millions of dollars, except per gallon amounts)

	Year Ended December 31,
	2013				2012				Change
Ethanol:
Operating income (loss)	$	491			$	(47	)		$	538
Production (thousand gallons per day)	3,294				2,967				327
Gross margin per gallon of production (f)	$	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
Retail:
Operating income (b) (d)	$	81			$	348			$	(267	)

---

See note references on page 39.

The following notes relate to references on pages 35 through 39.

(a)

In May 2014, we abandoned our Aruba Refinery, except for the associated crude oil and refined products terminal assets that we continue to operate. As a result, the refinery’s results of operations have been presented as discontinued operations and the operating highlights for the refining segment and the U.S. Gulf Coast region exclude the Aruba Refinery for all years presented.This transaction is more fully described in Note 2 of Notes to Consolidated Financial Statements.

(b)

On May 1, 2013, we completed the separation of our retail business. As a result and effective May 1, 2013, our results of operations no longer include those of CST, our former retail business. 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. This transaction is more fully discussed in Note 3 of Notes to Consolidated Financial Statements.

(c)

Asset impairment losses for the year ended December 31, 2012 include asset impairment losses of $65 million ($42 million after taxes) related to equipment associated with permanently cancelled capital project 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 $86 million 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 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 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 years 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 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 $319 million 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 $1.1 billion for the year ended December 31, 2013 compared to the year ended December 31, 2012 primarily due to a $1.3 billion 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 $1.3 billion from $5.5 billion for the year ended December 31, 2012 to $4.2 billion for the year ended December 31, 2013. The decrease in refining segment operating income was primarily due to an $855 million decrease in refining margin, a $221 million increase in depreciation and amortization expense, and a $197 million increase in operating expenses.

Refining margin decreased $855 million (a $1.31 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 75,000 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 $197 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.

The increase of $221 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 were lower in 2013 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 were higher in 2013 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 was 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 Notes 3 and 11 of Notes to Consolidated Financial Statements.

“Interest and debt expense, net of capitalized interest” for the year ended December 31, 2013 increased $51 million from the year ended December 31, 2012. This increase was primarily due to a $102 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.

Loss from discontinued operations for the year ended December 31, 2012 represents the results of operations of the Aruba Refinery, which was abandoned in May 2014, including an asset impairment loss of $928 million as discussed in Note 2 of Notes to Consolidated Financial Statements.

LIQUIDITY AND CAPITAL RESOURCES

Cash Flows for the Year Ended December 31, 2014

Net cash provided by operating activities for the year ended December 31, 2014 was $4.2 billion compared to $5.6 billion for the year ended December 31, 2013. The decrease in net cash provided by operating activities was due primarily to a $2.7 billion unfavorable effect from changes in working capital between the periods partially offset by the increase in income from continuing operations discussed above under “RESULTS OF OPERATIONS.” The changes in cash provided by or used for working capital during the years ended December 31, 2014 and 2013 are shown in Note 19 of Notes to Consolidated Financial Statements.

The net cash provided by operating activities during the year ended December 31, 2014, along with$603 million from available cash on hand, was used mainly to:

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

•	make a scheduled long-term note repayment of $200 million;

•	purchase common stock for treasury of $1.3 billion; and

•	pay common stock dividends of $554 million.

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.

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 2015, we expect to incur approximately $1.95 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 and joint venture arrangements. We continuously evaluate our capital budget and make changes as conditions warrant.

We hold an option until January 2016 to purchase a 50 percent interest in the Diamond Pipeline project, a 440-mile, 20-inch crude oil pipeline that is projected to provide capacity of up to 200,000 BPD of domestic sweet crude oil from the Plains Cushing, Oklahoma terminal to our Memphis Refinery. The Diamond Pipeline project is currently being constructed by a third party for an estimated $900 million and is expected to be completed in 2017.

Contractual Obligations

Our contractual obligations as of December 31, 2014 are summarized below (in millions).

	Payments Due by Period
	2015				2016				2017				2018				2019				Thereafter				Total
Debt and capital lease obligations (including interest on capital lease obligations)	$	609			$	8			$	956			$	6			$	756			$	4,092			$	6,427
Operating lease obligations	314				229				159				131				75				275				1,183
Purchase obligations	17,929				2,475				1,205				769				366				4,269				27,013
Other long-term liabilities	—				159				144				145				139				1,352				1,939
Total	$	18,852			$	2,871			$	2,464			$	1,051			$	1,336			$	9,988			$	36,562

Debt and Capital Lease Obligations

In February 2015, we made a scheduled debt repayment of $400 million related to our 4.5% senior notes.

As of December 31, 2014, we had 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. In December 2014, the actual availability under the facility fell below the facility borrowing capacity to $1.4 billion primarily due to a decline in eligible trade receivables as a result of a decrease in the latter part of 2014 in the market prices of the finished products that we produce. As of December 31, 2014, 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. 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 (stable 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 products, 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. Purchase obligations decreased from 2013 to 2014 primarily because of a decline in crude oil and refined product prices.

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, 2014.

Other Commercial Commitments

As of December 31, 2014, we had outstanding letters of credit under our committed lines of credit as follows (in millions):

		Borrowing Capacity				Expiration		Outstanding Letters of Credit
Letter of credit facilities		$	550			June 2015		$	56
Revolver		$	3,000			November 2018		$	54
VLP Revolver		$	300			December 2018		$	—
Canadian Revolver		C$	50			November 2015		C$	10

As of December 31, 2014, we had no amounts borrowed under our revolving credit facilities. The letters of credit outstanding as of December 31, 2014 expire in 2015 through 2017.

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, 2014, we have approvals under our $3 billion common stock purchase program to purchase approximately $1.5 billion of our common stock, but we have no obligation to make purchases under this program. Year to date through February 20, 2015, we have purchased one million shares for $57 million under this stock purchase program.

Pension Plan Funding

We plan to contribute approximately $47 million to our pension plans and $20 million to our other postretirement benefit plans during 2015.

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 as previously discussed above in “OUTLOOK.” 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 year ended December 31, 2014, we paid $1.6 billion in income taxes, of which $400 million related to 2013 that was recorded in income taxes payable as of December 31, 2013. The payments made for the year ended December 31, 2014 exceeded income taxes paid for 2013 by $800 million. The increase in income taxes paid in 2014 is due in part to higher income from continuing operations before income tax expense. Although the amount of cash required to pay our 2014 income taxes increased compared to recent years, we generated and expect to continue generating sufficient cash from operations to make our tax payments as they become due.

The Internal Revenue Service (IRS) has ongoing tax audits related to our U.S. federal tax returns from 2004 through 2011, and we have received Revenue Agent Reports (RARs) in connection with the audits for tax years 2004 through 2009. We are vigorously contesting certain tax positions and assertions included in the RARs and continue to make significant progress in resolving certain of these matters with the IRS. During the year ended December 31, 2014, we settled the audit related to our 2002 and 2003 tax years and the audit related to a group of our subsidiaries for their 2004 and 2005 tax years consistent with the recorded amounts of uncertain tax position liabilities associated with those audits. In addition, we expect to settle our audits for tax years 2004 through 2007 within the next 12 months and we believe they will be settled for amounts that do not exceed the recorded amounts of uncertain tax position liabilities associated with those audits. As a result, we have classified a portion of our uncertain tax position liabilities as a current liability. As of December 31, 2014, the total amount of uncertain tax position liabilities, including related penalties and interest, was $484 million, with $168 million reflected as a current liability in income taxes payable and $316 million reflected in other long-term liabilities. 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, 2014, $738 million of our cash and temporary cash investments was held by our international subsidiaries.

Emissions Allowances and Cap-and-Trade

The cost to implement certain provisions of the AB 32 cap-and-trade system and low carbon fuel standard in California and the Quebec cap-and-trade system may be significant; however, we expect to recover the majority of these costs from our customers.

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, except as otherwise disclosed.

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 deferred 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 Notes 2 and 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, 2014, 2013, and 2012 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 of 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, 2014 was 7.71 percent. The actual return on assets for the years ended December 31, 2014, 2013 and 2012 was 7.33 percent, 19.38 percent, and 11.84 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, 2014 and net periodic benefit cost for the year ending December 31, 2015 (in millions):

	Pension Benefits				Other Postretirement Benefits
Increase in projected benefit obligation resulting from:
Discount rate decrease	$	105			$	12
Compensation rate increase	7				n/a
Health care cost trend rate increase	n/a				1
Increase in expense resulting from:
Discount rate decrease	10				—
Expected return on plan assets decrease	5				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 (excise/duty, sales/use, gross receipts, and/or value-added 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.