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 costs for refinery turnarounds and catalyst, capital expenditures for environmental and other purposes, and joint venture investments, and the effect of those 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, 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) and GHG emission credits needed to comply with the requirements of various GHG emission programs;

•	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 GHGs, 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, 2015, we reported net income attributable to Valero stockholders from continuing operations of $4.0 billion, or $7.99 per share (assuming dilution), compared to $3.7 billion, or $6.97 per share (assuming dilution), for the year ended December 31, 2014. Included in our 2015 results was a noncash charge for a lower of cost or market inventory valuation adjustment recorded in December 2015 of $790 million ($624 million after taxes, or $1.25 per share (assuming dilution)), of which $740 million was attributable to our refining segment and $50 million was attributable to our ethanol segment. This matter is more fully described in Note 6 of Notes to Consolidated Financial Statements. Included in our 2014 results was a last-in, first-out (LIFO) inventory gain of $233 million ($151 million after taxes, or $0.29 per share (assuming dilution)) primarily related to our refining segment.

Our operating income increased $456 million from 2014 to 2015 as outlined by business segment in the following table (in millions):

		Year Ended December 31,
		2015				2014				Change
Operating income (loss) by business segment:
Refining		$	6,973			$	5,884			$	1,089
Ethanol		142				786				(644		)
Corporate		(757		)		(768		)		11
Total		$	6,358			$	5,902			$	456

However, excluding the effect of the lower of cost or market inventory valuation adjustment and the LIFO gain discussed above, total operating income for 2015 and 2014 was $7.1 billion and $5.7 billion, respectively, reflecting a $1.4 billion favorable increase between the years, with refining segment operating income of $7.7 billion and $5.6 billion, respectively, (a favorable increase of $2.1 billion) and ethanol segment operating income of $192 million and $782 million, (an unfavorable decrease of $590 million).

The $2.1 billion increase in refining segment operating income in 2015 compared to 2014 was due to higher margins on gasoline and other refined products (e.g., petroleum coke, propane, sulfur, and lubes), partially offset by lower discounts for most sweet and sour crude oils relative to Brent crude oil and lower distillate margins. Our ethanol segment operating income decreased $590 million in 2015 compared to 2014 due to lower ethanol margins that resulted from lower ethanol and co-product prices, partially offset by lower corn feedstock costs.

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.”

In March 2015, we issued $600 million of 3.65 percent senior notes due March 15, 2025 and $650 million of 4.9 percent senior notes due March 15, 2045, and our consolidated subsidiary, VLP, borrowed $200 million under its revolving credit facility (the VLP Revolver), as further described in Note 10 of Notes to Consolidated Financial Statements. On July 1, 2015, VLP repaid $25 million of the amount borrowed under the VLP Revolver.

On July 13, 2015, our board of directors authorized us to purchase an additional $2.5 billion of our outstanding common stock, with no expiration date to such authorization, and we had $1.3 billion remaining available under that authorization as of December 31, 2015.

Effective November 24, 2015, VLP completed a public offering of 4,250,000 common units at a price of $46.25 per unit and received net proceeds from the offering of $189 million after deducting the underwriting discount and other offering costs. This transaction is further described in Note 4 of Notes to Consolidated Financial Statements.

Outlook

Energy markets and margins were volatile during 2015, and we expect them to continue to be volatile in the 2016. Below is a summary of factors that have impacted or may impact our results of operations during the first quarter of 2016:

•	Gasoline margins have been volatile, but are expected to recover from seasonal lows in the near term as domestic and export demand is expected to increase. Distillate margins have been negatively impacted by mild winter temperatures and are also expected to recover from their seasonal lows.

•	Medium and heavy sour crude oil discounts are expected to remain wide as sour crude oil remains oversupplied. Fuel oil price weakness has also put pressure on heavy sour crude oil discounts. Sweet crude oil discounts are expected to remain weak on lower domestic sweet crude oil production and higher foreign sweet and sour crude oil imports.

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

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

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.

2015 Compared to 2014

Financial Highlights

(millions of dollars, except per share amounts)

	Year Ended December 31,
	2015				2014				Change
Operating revenues	$	87,804			$	130,844			$	(43,040	)
Costs and expenses:
Cost of sales (excluding the lower of cost or market inventory valuation adjustment) (a)	73,861				118,141				(44,280		)
Lower of cost or market inventory valuation adjustment (b)	790				—				790
Operating expenses:
Refining	3,795				3,900				(105		)
Ethanol	448				487				(39		)
General and administrative expenses	710				724				(14		)
Depreciation and amortization expense:
Refining	1,745				1,597				148
Ethanol	50				49				1
Corporate	47				44				3
Total costs and expenses	81,446				124,942				(43,496		)
Operating income	6,358				5,902				456
Other income, net	46				47				(1		)
Interest and debt expense, net of capitalized interest	(433		)		(397		)		(36		)
Income from continuing operations before income tax expense	5,971				5,552				419
Income tax expense	1,870				1,777				93
Income from continuing operations	4,101				3,775				326
Loss from discontinued operations	—				(64		)		64
Net income	4,101				3,711				390
Less: Net income attributable to noncontrolling interests	111				81				30
Net income attributable to Valero Energy Corporation stockholders	$	3,990			$	3,630			$	360
Net income attributable to Valero Energy Corporation stockholders:
Continuing operations	$	3,990			$	3,694			$	296
Discontinued operations	—				(64		)		64
Total	$	3,990			$	3,630			$	360
Earnings per common share – assuming dilution:
Continuing operations	$	7.99			$	6.97			$	1.02
Discontinued operations	—				(0.12		)		0.12
Total	$	7.99			$	6.85			$	1.14

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See note references on page 32.

Refining Operating Highlights

(millions of dollars, except per barrel amounts)

	Year Ended December 31,
	2015				2014				Change
Refining (c):
Operating income	$	6,973			$	5,884			$	1,089
Throughput margin per barrel (a) (b) (d)	$	12.97			$	11.05			$	1.92
Operating costs per barrel:
Operating expenses	3.71				3.87				(0.16		)
Depreciation and amortization expense	1.71				1.58				0.13
Total operating costs per barrel	5.42				5.45				(0.03		)
Operating income per barrel	$	7.55			$	5.60			$	1.95
Throughput volumes (thousand BPD):
Feedstocks:
Heavy sour crude oil	438				457				(19		)
Medium/light sour crude oil	428				466				(38		)
Sweet crude oil	1,208				1,149				59
Residuals	274				230				44
Other feedstocks	140				134				6
Total feedstocks	2,488				2,436				52
Blendstocks and other	311				329				(18		)
Total throughput volumes	2,799				2,765				34
Yields (thousand BPD):
Gasolines and blendstocks	1,364				1,329				35
Distillates	1,066				1,047				19
Other products (e)	408				423				(15		)
Total yields	2,838				2,799				39

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See note references on page 32.

Refining Operating Highlights by Region (a) (b) (f)

(millions of dollars, except per barrel amounts)

	Year Ended December 31,
	2015				2014				Change
U.S. Gulf Coast:
Operating income	$	3,978			$	3,368			$	610
Throughput volumes (thousand BPD)	1,592				1,600				(8		)
Throughput margin per barrel (d)	$	12.27			$	11.03			$	1.24
Operating costs per barrel:
Operating expenses	3.64				3.66				(0.02		)
Depreciation and amortization expense	1.78				1.60				0.18
Total operating costs per barrel	5.42				5.26				0.16
Operating income per barrel	$	6.85			$	5.77			$	1.08
U.S. Mid-Continent:
Operating income	$	1,434			$	1,323			$	111
Throughput volumes (thousand BPD)	447				446				1
Throughput margin per barrel (d)	$	14.09			$	13.63			$	0.46
Operating costs per barrel:
Operating expenses	3.59				3.90				(0.31		)
Depreciation and amortization expense	1.71				1.61				0.10
Total operating costs per barrel	5.30				5.51				(0.21		)
Operating income per barrel	$	8.79			$	8.12			$	0.67
North Atlantic:
Operating income	$	1,446			$	911			$	535
Throughput volumes (thousand BPD)	494				457				37
Throughput margin per barrel (d)	$	12.06			$	10.02			$	2.04
Operating costs per barrel:
Operating expenses	2.88				3.40				(0.52		)
Depreciation and amortization expense	1.17				1.16				0.01
Total operating costs per barrel	4.05				4.56				(0.51		)
Operating income per barrel	$	8.01			$	5.46			$	2.55
U.S. West Coast:
Operating income	$	855			$	53			$	802
Throughput volumes (thousand BPD)	266				262				4
Throughput margin per barrel (d)	$	17.00			$	8.60			$	8.40
Operating costs per barrel:
Operating expenses	5.92				5.91				0.01
Depreciation and amortization expense	2.26				2.14				0.12
Total operating costs per barrel	8.18				8.05				0.13
Operating income per barrel	$	8.82			$	0.55			$	8.27
Operating income for regions above	$	7,713			$	5,655			$	2,058
Lower of cost or market inventory valuation adjustment (b)	(740		)		—				(740		)
LIFO gain (a)	—				229				(229		)
Total refining operating income	$	6,973			$	5,884			$	1,089

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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,
	2015				2014				Change
Feedstocks:
Brent crude oil	$	53.62			$	99.57			$	(45.95	)
Brent less West Texas Intermediate (WTI) crude oil	4.91				6.40				(1.49		)
Brent less Alaska North Slope (ANS) crude oil	0.67				1.73				(1.06		)
Brent less LLS crude oil	2.37				2.79				(0.42		)
Brent less Mars crude oil	6.54				6.75				(0.21		)
Brent less Maya crude oil	9.54				13.73				(4.19		)
LLS crude oil	51.25				96.78				(45.53		)
LLS less Mars crude oil	4.17				3.96				0.21
LLS less Maya crude oil	7.17				10.94				(3.77		)
WTI crude oil	48.71				93.17				(44.46		)
Natural gas (dollars per million British thermal units (MMBtu))	2.58				4.36				(1.78		)
Products:
U.S. Gulf Coast:
CBOB gasoline less Brent	9.83				3.54				6.29
Ultra-low-sulfur diesel less Brent	12.64				14.28				(1.64		)
Propylene less Brent	(5.94		)		5.57				(11.51		)
CBOB gasoline less LLS	12.20				6.33				5.87
Ultra-low-sulfur diesel less LLS	15.01				17.07				(2.06		)
Propylene less LLS	(3.57		)		8.36				(11.93		)
U.S. Mid-Continent:
CBOB gasoline less WTI	17.59				12.28				5.31
Ultra-low-sulfur diesel less WTI	19.02				24.05				(5.03		)
North Atlantic:
CBOB gasoline less Brent	12.85				9.07				3.78
Ultra-low-sulfur diesel less Brent	16.05				18.25				(2.20		)
U.S. West Coast:
CARBOB 87 gasoline less ANS	25.56				13.40				12.16
CARB diesel less ANS	16.90				19.14				(2.24		)
CARBOB 87 gasoline less WTI	29.80				18.07				11.73
CARB diesel less WTI	21.14				23.81				(2.67		)
New York Harbor corn crush (dollars per gallon)	0.22				0.85				(0.63		)

Ethanol Operating Highlights (a) (b)

(millions of dollars, except per gallon amounts)

	Year Ended December 31,
	2015				2014				Change
Ethanol (c):
Operating income	$	192			$	782			$	(590	)
Production (thousand gallons per day)	3,827				3,422				405
Gross margin per gallon of production (d)	$	0.49			$	1.06			$	(0.57	)
Operating costs per gallon of production:
Operating expenses	0.32				0.39				(0.07		)
Depreciation and amortization expense	0.03				0.04				(0.01		)
Total operating costs per gallon of production	0.35				0.43				(0.08		)
Operating income per gallon of production	$	0.14			$	0.63			$	(0.49	)
Operating income from above	$	192			$	782			$	(590	)
Lower of cost or market inventory valuation adjustment (b)	(50		)		—				(50		)
LIFO gain (a)	—				4				(4		)
Total ethanol operating income	$	142			$	786			$	(644	)

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See note references below.

The following notes relate to references on pages 28 through 32.

(a)

Cost of sales for the year ended December 31, 2014 reflects a LIFO gain of $233 million ($151 million after taxes), of which $229 million is attributable to our refining segment and $4 million is attributable to our ethanol segment. These amounts have been excluded from (1) the segment and regional throughput margins per barrel and the regional operating income amounts for the refining segment, and (2) the operating income and gross margin per gallon of production amounts for the ethanol segment.

(b)

In December 2015, we recorded a lower of cost or market inventory valuation adjustment of $790 million ($624 million after taxes), of which $740 million is attributable to our refining segment and $50 million is attributable to our ethanol segment. In accordance with U.S. generally accepted accounting principles (GAAP), we are required to state our inventories at the lower of cost or market. Cost is primarily determined using the LIFO inventory valuation methodology, whereby the most recently incurred costs are charged to cost of sales in the statement of income and inventories are valued at base layer acquisition costs in the balance sheet. Market is determined based on an assessment of the net realizable value of our inventory. In periods where the market price of our inventory falls below cost, we record an inventory valuation adjustment to write down the value to market in accordance with U.S. GAAP. The lower of cost or market inventory valuation adjustment for the year ended December 31, 2015 has been excluded from (1) the segment and regional throughput margins per barrel and the regional operating income amounts for the refining segment, and (2) the gross operating income and the gross margin per gallon of production amounts for the ethanol segment. This adjustment is further discussed in Note 6 of Notes to Consolidated Financial Statements.

(c)

The LIFO gain of $233 million recorded in 2014 (see note (a)) and the lower of cost or market inventory valuation adjustment of $790 million recorded in 2015 (see note (b)) are reflected in refining operating income and ethanol operating income for the years ended December 31, 2015 and 2014, but are excluded from throughput margin per barrel and operating income per barrel for the refining segment, and from gross margin per gallon and operating income per gallon for the ethanol segment, respectively, as also described in notes (a) and (b).

(d)	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.

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

(f)

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 $43.0 billion (or 33 percent) and cost of sales decreased $44.3 billion (or 37 percent) for the year ended December 31, 2015 compared to the year ended December 31, 2014 primarily due to a decrease in refined product prices and crude oil feedstock costs, respectively. Despite the decrease in operating revenues, cost of sales decreased to a greater extent resulting in an increase in operating income of $456 million in 2015, with refining segment operating income increasing by $1.1 billion and ethanol segment operating income decreasing by $644 million. The reasons for these changes in the operating results of our segments and corporate expenses, as well as other items that affected our income, are discussed below.

Refining

Refining segment operating income increased $1.1 billion from $5.9 billion in 2014 to $7.0 billion in 2015. Excluding the effect of the lower of cost or market inventory valuation adjustment of $740 million in 2015 and the LIFO gain of $229 million in 2014, our refining segment operating income increased $2.1 billion. This increase was primarily due to a $2.1 billion (or $1.92 per barrel) increase in refining margin and a $105 million decrease in operating expenses, partially offset by a $148 million increase in depreciation and amortization expense.

The increase in refining margin of $2.1 billion was due primarily to the following:

•

Increase in gasoline margins - We experienced an increase in gasoline margins throughout all our regions during 2015. For example, the Brent-based benchmark reference margin for U.S. Gulf Coast CBOB gasoline was $9.83 per barrel in 2015 compared to $3.54 per barrel in 2014, a favorable increase of $6.29 per barrel. Another example is the ANS-based reference margin for U.S. West Coast CARBOB gasoline that was $25.56 per barrel in 2015 compared to $13.40 per barrel in 2014, a favorable increase of $12.16 per barrel. We estimate that the increase in gasoline margins per barrel in 2015 compared to 2014 had a positive impact to our refining margin of approximately $2.9 billion.

•

Increase in other refined products margins - We experienced an increase in the margins of other refined products such as petroleum coke, propane, sulfur, and lubes in 2015 compared to 2014. Margins for other refined products were higher during 2015 due to the lower cost of crude oils in 2015 compared to 2014. Because the market prices for our other refined products remain relatively stable, we benefit when the cost of crude oils that we process declines. For example, the benchmark price of Brent crude oil was $53.62 per barrel in 2015 compared to $99.57 per barrel in 2014. We estimate that the increase in margins for other refined products in 2015 compared to 2014 had a positive impact to our refining margin of approximately $1.6 billion.

•

Lower discounts on light sweet 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 2015, the discount in the price of light sweet and sour crude oils compared to the price of Brent crude oil narrowed. Therefore, while we benefitted from processing crude oils priced at a discount to Brent crude oil, that benefit declined in 2015 compared to 2014. For example, we processed LLS crude oil (a type of light sweet crude oil) in our U.S. Gulf Coast region that sold at a discount of $2.37 per barrel to Brent crude oil in 2015 compared

to $2.79 per barrel in 2014, representing an unfavorable decrease of $0.42 per barrel. Another example is Maya crude oil (a type of sour crude oil) that sold at a discount of $9.54 per barrel to Brent crude oil in 2015 compared to a discount of $13.73 per barrel in 2014, representing an unfavorable decrease of $4.19 per barrel. We estimate that the narrowing of the discounts for sweet crude oils and sour crude oils that we processed during 2015 had an unfavorable impact to our refining margin of approximately $260 million and $770 million, respectively.

•

Lower benefit from processing other feedstocks - In addition to crude oil, we use other feedstocks and blendstocks in our refining processes, such as natural gas. When combined with steam, natural gas produces hydrogen that is used in our hydrotreater and hydrocracker processing units to produce refined products. Although natural gas costs declined from 2014 to 2015, the decline was not as significant as the decline in the cost of Brent crude oil; therefore, the benefit we normally derive by using natural gas as a feedstock declined. We estimate that the decline in the benefit we derived from processing other feedstocks had an unfavorable impact to our refining margin of approximately $980 million in 2015 compared to 2014.

•

Decrease in distillate margins - We experienced a decrease in distillate margins throughout all our regions during 2015. For example, the WTI-based benchmark reference margin for U.S. Mid-Continent ultra-low-sulfur diesel (a type of distillate) was $19.02 per barrel in 2015 compared to $24.05 per barrel in 2014, an unfavorable decrease of $5.03 per barrel. Another example is the Brent-based benchmark reference margin for U.S. Gulf Coast ultra-low-sulfur diesel that was $12.64 per barrel in 2015 compared to $14.28 per barrel in 2014, an unfavorable decrease of $1.64 per barrel. We estimate that the decrease in distillate margins per barrel in 2015 compared to 2014 had an unfavorable impact to our refining margin of approximately $650 million.

•	Higher throughput volumes - Refining throughput volumes increased by 34,000 BPD in 2015. We estimate that the increase in refining throughput volumes had a positive impact to our refining margin of approximately $160 million in 2015.

The decrease of $105 million in operating expenses was primarily due to a $196 million decrease in energy costs driven by lower natural gas prices ($2.58 per MMBtu in 2015 compared to $4.36 per MMBtu in 2014). This decrease in energy costs was partially offset by a $47 million increase in employee-related expenses primarily due to higher employee benefit costs and incentive compensation expenses, and a $26 million increase in costs associated with higher levels of maintenance activities in 2015.

The increase of $148 million in depreciation and amortization expense was primarily associated with the impact of new capital projects that began operating in 2015 and higher refinery turnaround and catalyst amortization.

Ethanol

Ethanol segment operating income was $142 million in 2015 compared to $786 million in 2014. Excluding the effect of the lower of cost or market inventory valuation adjustment of $50 million in 2015 and the LIFO gain of $4 million in 2014, our ethanol segment operating income decreased $590 million. This decrease was primarily due to a $628 million (or $0.57 per gallon) decrease in gross margin, partially offset by a $39 million decrease in operating expenses.

The decrease in ethanol gross margin of $628 million was due primarily to the following:

•	Lower ethanol prices - Ethanol prices were lower in 2015 primarily due to the decrease in crude oil and gasoline prices in 2015 compared to 2014. For example, the New York Harbor ethanol price was $1.59 per

gallon in 2015 compared to $2.37 per gallon in 2014. We estimate that the decrease in the price of ethanol per gallon during 2015 had an unfavorable impact to our ethanol margin of approximately $800 million.

•

Lower corn prices - Corn prices were lower in 2015 compared to 2014 due to a higher domestic corn yield realized during the 2014 fall harvest (most of which is processed in the following year). For example, the Chicago Board of Trade (CBOT) corn price was $3.77 per bushel in 2015 compared to $4.16 per bushel in 2014. We estimate that the decrease in the price of corn that we processed during 2015 had a favorable impact to our ethanol margin of approximately $160 million.

•	Lower co-product prices - The decrease in corn prices in 2015 compared to 2014 had a negative effect on the prices we received for corn-related ethanol co-products, such as distillers grains and corn oil. We estimate that the decrease in co-product prices had an unfavorable impact to our ethanol margin of approximately $40 million.

•

Increased production volumes - Ethanol margin was favorably impacted by increased production volumes of 405,000 gallons per day in 2015. Production volumes in 2014 were negatively impacted by weather-related rail disruptions. In addition, production volumes in 2015 were positively impacted by production volumes from our Mount Vernon plant, which began operations in August 2014. We estimate that the increase in production volumes had a favorable impact to our ethanol margin of approximately $50 million.

The $39 million decrease in operating expenses was primarily due to a $40 million decrease in energy costs related to lower natural gas prices ($2.58 per MMBtu in 2015 compared to $4.36 per MMBtu in 2014).

Other

“Interest and debt expense, net of capitalized interest” increased by $36 million in 2015. This increase was primarily due to the impact from $1.25 billion of debt issued by Valero and $200 million borrowed by VLP under the VLP Revolver in 2015.

Income tax expense increased $93 million in 2015. This increase was lower than expected given the increase in income from continuing operations of $419 million and was due primarily to earnings from our international operations that are taxed at statutory tax rates that are lower than in the U.S. In addition, in 2015, the U.K. statutory rate was lowered and we favorably settled various U.S. income tax audits.

The loss from discontinued operations in 2014 includes expenses of $64 million primarily related to an asset retirement obligation associated with our decision in May 2014 to abandon the Aruba Refinery, as further described in Note 2 of Notes to Consolidated Financial Statements.

2014 Compared to 2013

Financial Highlights (a)

(millions of dollars, except per share amounts)

	Year Ended December 31,
	2014				2013 (c)				Change
Operating revenues	$	130,844			$	138,074			$	(7,230	)
Costs and expenses:
Cost of sales (b)	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. (c)	—				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 interest	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 40.

Refining Operating Highlights (a)

(millions of dollars, except per barrel amounts)

	Year Ended December 31,
	2014				2013				Change
Refining (d):
Operating income	$	5,884			$	4,211			$	1,673
Throughput margin per barrel (b) (e)	$	11.05			$	9.69			$	1.36
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	$	5.60			$	4.30			$	1.30
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 (f)	423				440				(17		)
Total yields	2,799				2,711				88

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See note references on page 40.

Refining Operating Highlights by Region (b) (g)

(millions of dollars, except per barrel amounts)

	Year Ended December 31,
	2014				2013				Change
U.S. Gulf Coast (a):
Operating income	$	3,368			$	2,375			$	993
Throughput volumes (thousand BPD)	1,600				1,523				77
Throughput margin per barrel (e)	$	11.03			$	9.57			$	1.46
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	$	5.77			$	4.27			$	1.50
U.S. Mid-Continent:
Operating income	$	1,323			$	1,293			$	30
Throughput volumes (thousand BPD)	446				435				11
Throughput margin per barrel (e)	$	13.63			$	13.37			$	0.26
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	$	8.12			$	8.15			$	(0.03	)
North Atlantic:
Operating income	$	911			$	570			$	341
Throughput volumes (thousand BPD)	457				459				(2		)
Throughput margin per barrel (e)	$	10.02			$	7.93			$	2.09
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	$	5.46			$	3.40			$	2.06
U.S. West Coast:
Operating income (loss)	$	53			$	(27	)		$	80
Throughput volumes (thousand BPD)	262				265				(3		)
Throughput margin per barrel (e)	$	8.60			$	7.43			$	1.17
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	$	0.55			$	(0.27	)		$	0.82
Operating income for regions above	$	5,655			$	4,211			$	1,444
LIFO gain (b)	229				—				229
Total refining operating income	$	5,884			$	4,211			$	1,673

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See note references on page 40.

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 WTI crude oil	6.40				10.80				(4.40		)
Brent less ANS crude oil	1.73				1.00				0.73
Brent less 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 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

Ethanol and Retail Operating Highlights

(millions of dollars, except per gallon amounts)

	Year Ended December 31,
	2014				2013				Change
Ethanol (d):
Operating income	$	782			$	491			$	291
Production (thousand gallons per day)	3,422				3,294				128
Gross margin per gallon of production (e)	$	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
Operating income from above	$	782			$	491			$	291
LIFO gain (b)	4				—				4
Total ethanol operating income	$	786			$	491			$	295
Retail:
Operating income	$	—			$	81			$	(81	)

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See note references below.

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

(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)

Cost of sales for the year ended December 31, 2014 reflects a LIFO gain of $233 million ($151 million after taxes), of which $229 million is attributable to our refining segment and $4 million is attributable to our ethanol segment. These amounts have been excluded from (1) the segment and regional throughput margins per barrel and the regional operating income amounts for the refining segment, and (2) the operating income and gross margin per gallon of production amounts for the ethanol segment.

(c)

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.

(d)

The LIFO gain of $233 million recorded in 2014 (see note (b)) is reflected in refining operating income and ethanol operating income for the year ended December 31, 2014, but is excluded from throughput margin per barrel and operating income per barrel for the refining segment, and from gross margin per gallon and operating income per gallon for the ethanol segment, respectively, as also described in note (b).

(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 $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 in 2014 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 in 2013 to $5.9 billion in 2014. Excluding the LIFO gain of $229 million in 2014 related to our refining segment, our refining segment operating income increased by $1.4 billion. This increase was primarily due to a $1.7 billion (or $1.36 per barrel) increase in refining margin, partially offset by a $190 million increase in operating expenses and a $31 million increase in depreciation and amortization expense.

The increase in refining margin of $1.7 billion was 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 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 in 2014 compared to $0.41 per barrel in 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 in 2014 compared to a discount of $11.31 per barrel in 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 in 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 in 2014. 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 20 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 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 in 2014 compared to $108.74 in 2013. We estimate that the increase in other refinery products margins in 2014 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 in 2014 compared to $15.95 per barrel in 2013, representing an unfavorable decrease of $1.67 per barrel. We estimate that the decline in distillate margins in 2014 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 in 2014 compared to $3.69 per MMBtu in 2013) and a $22 million increase in maintenance expense primarily related to higher levels of routine maintenance activities in 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 in 2014 compared to $491 million in 2013. The $295 million increase in operating income was due primarily to a $399 million (or $0.29 per gallon) increase in gross margin, partially offset by a $100 million increase in operating expenses.

The increase in ethanol gross margin of $399 million was 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 CBOT 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 in 2014 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 in 2014 primarily due to $30 million of transaction costs in 2013 related to the separation of our retail business on May 1, 2013.

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” increased $32 million in 2014. 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 in 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 in 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.

LIQUIDITY AND CAPITAL RESOURCES

Cash Flows for the Year Ended December 31, 2015

Our operations generated $5.6 billion of cash in 2015, driven primarily by net income of $4.1 billion and excluding $2.6 billion of noncash charges to income ($1.8 billion for depreciation and amortization expense and $790 million for a lower of cost or market inventory valuation adjustment). See “RESULTS OF OPERATIONS” for further discussion of our operations. However, the change in working capital during the year had a negative impact to cash generated by our operations of $1.3 billion. This use of cash was composed primarily of (i) a decrease in accounts payable, net of a decrease in receivables, of $493 million, (ii) an increase in income taxes receivable and a decrease in income taxes payable totaling $432 million, and (iii) an increase in inventories of $222 million as shown in Note 18 of Notes to Consolidated Financial Statements. The unfavorable effect of accounts payable, net of accounts receivable, was mainly due to a decrease in commodity prices from December 2014 to December 2015. The unfavorable effect in income taxes was due to tax payments associated with the settlement of several IRS audits and an overpayment of taxes in 2015. This overpayment resulted from a change in the U.S. Federal tax laws late in the year that reinstated the bonus depreciation deduction, which lowered our current income tax expense. The unfavorable effect in inventories was mainly due to the build in inventory volumes in 2015 as we purchased crude oil at prices we deemed favorable during the fourth quarter of 2015.

The $5.6 billion of cash generated by our operations in 2015, along with (i) $1.45 billion in proceeds from the issuance of debt and (ii) net proceeds of $189 million from VLP’s public offering of 4,250,000 common units as discussed in Note 4 of Notes to Consolidated Financial Statements, were used mainly to:

•	fund $2.5 billion of investing activities, including $2.4 billion in capital investments. Capital investments are comprised of capital expenditures, deferred turnaround and catalyst costs, and joint venture investments;

•	make payments on debt and capital lease obligations of $513 million, of which $400 million related to our 4.5 percent senior notes, $75 million related to our 8.75 percent debentures, $25 million related to the VLP Revolver, $10 million related to capital lease obligations, and $3 million related to other non-bank debt;

•	purchase common stock for treasury of $2.8 billion;

•	pay common stock dividends of $848 million; and

•	increase available cash on hand by $425 million.

Cash Flows for the Year Ended December 31, 2014

Our operations generated $4.2 billion of cash in 2014, driven primarily by net income of $3.7 billion and excluding $1.7 billion of noncash charges to income (primarily depreciation and amortization expense). See “RESULTS OF OPERATIONS” for further discussion of our operations. However, the change in our working capital during the year had a negative impact to cash generated by our operations of $1.8 billion. This use of cash was composed primarily of a decrease in accounts receivable of $2.8 billion, which was offset by a decrease in accounts payable of $3.1 billion, a decrease in income taxes payable of $319 million, and an increase in inventories of $1.0 billion as shown in Note 18 of Notes to Consolidated Financial Statements. The favorable effect in accounts receivable and the unfavorable effect in accounts payable were mainly due to a decrease in commodity prices from December 2013 to December 2014. The unfavorable effect associated with income taxes payable resulted from income tax payments exceeding income tax liabilities incurred in 2014 due to the payment of liabilities associated with prior period earnings. The unfavorable effect in inventories was mainly due to the build in inventory volumes from 2013 to 2014 as we purchased crude oil at prices we deemed favorable during the fourth quarter of 2014.

The $4.2 billion of cash provided by our operations in 2014, along with $603 million from available cash on hand, was used mainly to:

•	fund $2.8 billion of capital investments, which included capital expenditures and deferred turnaround and catalyst costs;

•	make debt and capital lease obligations repayments of $204 million, of which $200 million related to our 4.75 percent senior notes, and $4 million related to capital lease obligations;

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

•	pay common stock dividends of $554 million.

Capital Investments

We define capital investments as capital expenditures for additions to and improvements of our refining and ethanol segment assets (including turnaround and catalyst costs) and investments in joint ventures.

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 to refine crude oil into products with higher market values. Therefore, many of our improvements do not increase throughput capacity significantly.

We hold investments in joint ventures and we invest in these joint ventures or enter into new joint venture arrangements to enhance our operations. In December 2015, we exercised our option to purchase a 50 percent interest in Diamond Pipeline LLC (Diamond Pipeline), which was formed by Plains Pipeline, L.P. (Plains) to construct and operate a 440-mile, 20-inch crude oil pipeline expected to provide capacity of up to 200,000 BPD of domestic sweet crude oil from the Plains Cushing, Oklahoma terminal to our Memphis Refinery, with the ability to connect into the Capline Pipeline. The pipeline is expected to be completed in 2017 for an estimated $925 million, pending receipt of necessary regulatory approvals. We contributed $136 million upon exercise of our option and expect to invest an additional $170 million in 2016.

For 2016, we expect to incur approximately $2.6 billion for capital investments, including capital expenditures, deferred turnaround and catalyst costs, and joint venture investments. This consists of approximately $1.6 billion for stay-in-business capital and $1.0 billion for growth strategies, including our continued investment in Diamond Pipeline. This capital investment estimate excludes potential strategic acquisitions. We continuously evaluate our capital budget and make changes as conditions warrant.

Contractual Obligations

Our contractual obligations as of December 31, 2015 are summarized below (in millions).

	Payments Due by Period
	2016				2017				2018				2019				2020				Thereafter				Total
Debt and capital lease obligations (a)	$	134			$	966			$	16			$	766			$	1,039			$	4,517			$	7,438
Operating lease obligations	430				283				200				143				100				311				1,467
Purchase obligations	14,975				3,204				2,458				1,197				985				4,535				27,354
Other long-term liabilities	—				172				134				131				125				1,049				1,611
Total	$	15,539			$	4,625			$	2,808			$	2,237			$	2,249			$	10,412			$	37,870

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(a)	Debt obligations exclude amounts related to unamortized discount and fair value adjustments. Capital lease obligations include related interest expense. These items are further described in Note 10 of Notes to Consolidated Financial Statements.

Debt and Capital Lease Obligations

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. In July 2015, we amended our agreement to decrease the facility from $1.5 billion to $1.4 billion and extended the maturity date to July 2016. As of December 31, 2015, the actual availability under the facility fell below the facility borrowing capacity to $1.1 billion primarily due to a decrease in eligible trade receivables as a result of the ongoing decline in the market prices of the finished products that we produce. As of December 31, 2015, 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.

Other Long-term Liabilities

Our other long-term liabilities are described in Note 9 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, 2015.

Summary of Credit Facilities

As of December 31, 2015, we had outstanding borrowings and letters of credit issued under our credit facilities as follows (in millions):

								December 31, 2015
		Facility Amount				Maturity Date		Borrowings				Letters of Credit				Available
Committed facilities:
Revolver		$	3,000			November 2020		$	—			$	57			$	2,943
VLP Revolver		$	750			November 2020		$	175			$	—			$	575
Canadian Revolver		C$	50			November 2016		C$	—			C$	10			C$	40
Accounts receivable sales facility		$	1,400			July 2016		$	100			$	—			$	992
Letter of credit facilities		$	275			June 2016 and November 2016		$	—			$	9			$	266
Uncommitted facilities:
Letter of credit facilities		$	775			N/A		$	—			$	87			$	688

Letters of credit issued as of December 31, 2015 expire in 2016 through 2018.

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

On July 13, 2015, our board of directors authorized us to purchase an additional $2.5 billion of our outstanding common stock with no expiration date to such authorization. This authorization was in addition to the remaining amount available under a $3 billion program previously authorized. During the third quarter of 2015, we completed our purchases under the $3 billion program. As of December 31, 2015, we had approximately $1.3 billion remaining available under the $2.5 billion program, but we have no obligation to make purchases under this program.

Pension Plan Funding

We plan to contribute approximately $36 million to our pension plans and $20 million to our other postretirement benefit plans during 2016.

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, GHG 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 9 and 11 of Notes to Consolidated Financial Statements for a further discussion of our environmental matters.

Tax Matters

The IRS has ongoing tax audits related to our U.S. federal tax returns from 2008 through 2011, and we have received Revenue Agent Reports (RARs) in connection with the audits for tax years 2008 and 2009. We are contesting certain tax positions and assertions included in the RARs and continue to make progress in resolving certain of these matters with the IRS. During 2015, we settled the audits related to our 2004 through 2007 tax years consistent with the recorded amounts of uncertain tax position liabilities associated with those audits. In addition, we expect to settle our audit for tax years 2008 and 2009 within the next 12 months and we believe it will be settled for amounts consistent with the recorded amounts of uncertain tax position liabilities associated with that audit. As a result, we have classified a portion of our uncertain tax position liabilities as a current liability. Our net uncertain tax position liabilities, including related penalties and interest, was $391 million as of December 31, 2015. 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 15 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, 2015, $1.7 billion 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 are significant; however, we are recovering the majority of these costs from our customers. If we are unable to recover these costs from our customers in the future, we believe that we will have sufficient cash on hand to cover these costs.

Concentration of Customers

Our 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. GAAP 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. Unless otherwise noted, estimates of the sensitivity to earnings that would result from changes in the assumptions used in determining our estimates is not practicable due to the number of assumptions and contingencies involved, and the wide range of possible outcomes.

Lower of Cost or Market Inventory Valuation

Inventories are carried at the lower of cost or market. Cost is principally determined under the LIFO method using the dollar-value LIFO approach. Market value is determined based on the net realizable value of the inventories.

We compare the market value of inventories to their cost on an aggregate basis, excluding materials and supplies. In determining the market value of our inventories, we assume our refinery and ethanol feedstocks

are converted into refined products, which requires us to make estimates regarding the refined products expected to be produced from those feedstocks and the conversion costs required to convert those feedstocks into refined products. We also estimate the usual and customary transportation costs required to move the inventory from our refineries and ethanol plants to the appropriate points of sale. We then apply an estimated selling price to our inventories. If the aggregate market value is less than cost, we record a lower of cost or market inventory valuation adjustment to reflect our inventories at market value.

The lower of cost or market inventory valuation adjustment for the year ended December 31, 2015 is discussed in Note 6 of Notes to Consolidated Financial Statements.

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 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.

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 11 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.

The amount of our accruals for environmental matters as of December 31, 2015 and 2014 are included in Note 9 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. These assumptions are disclosed and described in Note 13 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, 2015 was 5.69 percent. The actual return on assets for the years ended December 31, 2015, 2014, and 2013 was 1.46 percent, 7.33 percent, and 19.38 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, 2015 and net periodic benefit cost for the year ending December 31, 2016 (in millions):

	Pension Benefits				Other Postretirement Benefits
Increase in projected benefit obligation resulting from:
Discount rate decrease	$	101			$	11
Compensation rate increase	10				n/a
Health care cost trend rate increase	n/a				1
Increase in expense resulting from:
Discount rate decrease	9				—
Expected return on plan assets decrease	5				n/a
Compensation rate increase	3				n/a
Health care cost trend rate increase	n/a				—

Beginning in 2016, our net periodic benefit cost will be determined using the spot-rate approach. Under this approach, our net periodic benefit cost will be impacted by the spot rates of the corporate bond yield curve used to calculate our liability discount rate. If the yield curve were to flatten entirely and our liability discount rate remained unchanged, our net periodic benefit cost would increase by $19 million for pension benefits and $3 million for other postretirement benefits in 2016.

See Note 13 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. Judgment is required in estimating the amount of a 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. See Notes 11 and 15 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.