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 petroleum 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 petroleum 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 petroleum products or receive feedstocks;

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

•	demand for, and supplies of, refined petroleum 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 petroleum 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 RINs needed to comply with the RFS) 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 petroleum 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.

This report includes references to financial measures that are not defined under U.S. generally accepted accounting principles (GAAP). These non-GAAP financial measures include adjusted net income attributable to Valero stockholders, gross margin, and adjusted operating income. We have included these non-GAAP financial measures to help facilitate the comparison of operating results between periods. See the accompanying financial tables in “RESULTS OF OPERATIONS” for a reconciliation of these non-GAAP

financial measures to the most directly comparable U.S. GAAP financial measures. In note (d) to the accompanying tables, we disclose the reasons why we believe our use of the non-GAAP financial measures provides useful information.

OVERVIEW AND OUTLOOK

Overview

For the year ended December 31, 2016, we reported net income attributable to Valero stockholders from continuing operations of $2.3 billion and adjusted net income attributable to Valero stockholders from continuing operations of $1.7 billion. For the year ended December 31, 2015, we reported net income attributable to Valero stockholders from continuing operations of $4.0 billion and adjusted net income attributable to Valero stockholders from continuing operations of $4.6 billion. The decrease in net income attributable to Valero stockholders from continuing operations of $1.7 billion and the decrease in adjusted net income attributable to Valero stockholders from continuing operations of $2.9 billion are outlined in the following table (in millions).

		Year Ended December 31,
		2016				2015				Change
Net income attributable to Valero Energy Corporation stockholders from continuing operations		$	2,289			$	3,990			$	(1,701	)
Adjusted net income attributable to Valero Energy Corporation stockholders from continuing operations(1)		1,724				4,614				(2,890		)

The decrease in both net income and adjusted net income attributable to Valero stockholders from continuing operations was due to lower operating income in 2016 compared to 2015 (net of the resulting decrease of $1.1 billion in income tax expense between the years). Operating income decreased by $2.8 billion, while adjusted operating income decreased by $4.3 billion, as outlined by segment in the following table (in millions).

		Year Ended December 31,
		2016				2015				Change
Operating income (loss) by segment:
Refining		$	3,995			$	6,973			$	(2,978	)
Ethanol		340				142				198
Corporate		(763		)		(757		)		(6		)
Total		$	3,572			$	6,358			$	(2,786	)
Adjusted operating income (loss) by segment(1):
Refining		$	3,354			$	7,713			$	(4,359	)
Ethanol		290				192				98
Corporate		(763		)		(757		)		(6		)
Total		$	2,881			$	7,148			$	(4,267	)

---

(1)	Net income and operating income have been adjusted for certain items that we believe are not indicative of our core operating performance and that may obscure our underlying business results and trends. Each of these adjustments is reflected in the tables on pages 28 and 29. Adjusted amounts are non-GAAP measurements.

The $2.8 billion decrease in operating income was impacted by the net effect of noncash adjustments for a lower of cost or market inventory valuation adjustment and an asset impairment loss. We have excluded such effects from adjusted operating income because we believe that these adjustments are not indicative of our core operating performance and may obscure the underlying business results and trends. The resulting $4.3 billion decrease in adjusted operating income is primarily due to the following:

•	Refining segment - The $4.4 billion decrease in adjusted operating income was primarily due to lower margins on refined petroleum products and lower discounts on light sweet crude oils and sour crude oils relative to Brent crude oil, which also negatively impacted our refining margins. This is more fully described on pages 37 and 38.

•	Ethanol segment - The $98 million increase in adjusted operating income was primarily due to higher ethanol margins that resulted from lower corn prices combined with lower operating expenses, partially offset by lower margins on other co-products. This is more fully described on page 38.

Additional details and analysis of the changes in the operating income and adjusted operating income of our business segments and other components of net income and adjusted net income attributable to Valero stockholders from continuing operations, including a reconciliation of non-GAAP financial measures used in this Overview to their most comparable measures reported under U.S. GAAP, are provided below under “RESULTS OF OPERATIONS” beginning on page 27.

Outlook

For the year ended December 31, 2016, margins were unfavorable compared to 2015, and thus far in the first quarter of 2017 margins have been mixed. Below are several factors that have impacted or may impact our results of operations during the first quarter of 2017:

•	Refining and ethanol product margins are expected to remain near current levels.

•	Crude oil discounts are expected to remain weak due to lower demand resulting from industry-wide refinery maintenance.

RESULTS OF OPERATIONS

The following tables highlight our results of operations, our operating performance, and market prices that directly impact our operations. In addition, these tables include financial measures that are not defined under U.S. GAAP and represent non-GAAP financial measures. These non-GAAP financial measures are reconciled to their most comparable U.S. GAAP financial measures and include adjusted net income attributed to Valero stockholders, adjusted net income from continuing operations attributable to Valero stockholders, adjusted operating income, and gross margin. In note (d) to these tables, we disclose the reasons why we believe our use of non-GAAP financial measures provides useful information. The narrative following these tables provides an analysis of our results of operations.

2016 Compared to 2015

Financial Highlights

(millions of dollars, except share and per share amounts)

	Year Ended December 31,
	2016				2015				Change
Operating revenues	$	75,659			$	87,804			$	(12,145	)
Costs and expenses:
Cost of sales (excluding the lower of cost or market inventory valuation adjustment)	65,962				73,861				(7,899		)
Lower of cost or market inventory valuation adjustment (a)	(747		)		790				(1,537		)
Operating expenses:
Refining	3,792				3,795				(3		)
Ethanol	415				448				(33		)
General and administrative expenses	715				710				5
Depreciation and amortization expense:
Refining	1,780				1,745				35
Ethanol	66				50				16
Corporate	48				47				1
Asset impairment loss (b)	56				—				56
Total costs and expenses	72,087				81,446				(9,359		)
Operating income	3,572				6,358				(2,786		)
Other income, net	56				46				10
Interest and debt expense, net of capitalized interest	(446		)		(433		)		(13		)
Income before income tax expense	3,182				5,971				(2,789		)
Income tax expense (b) (c)	765				1,870				(1,105		)
Net income	2,417				4,101				(1,684		)
Less: Net income attributable to noncontrolling interests	128				111				17
Net income attributable to Valero Energy Corporation stockholders	$	2,289			$	3,990			$	(1,701	)
Earnings per common share – assuming dilution	$	4.94			$	7.99			$	(3.05	)
Weighted-average common shares outstanding – assuming dilution (in millions)	464				500				(36		)

---

See note references on pages 50 through 52.

Reconciliation of Non-GAAP Measures to Most Comparable Measures

Reported under U.S. GAAP (d)

(millions of dollars)

	Year Ended December 31,
	2016				2015
Reconciliation of net income attributable to Valero Energy Corporation stockholders to adjusted net income attributable to Valero Energy Corporation stockholders
Net income attributable to Valero Energy Corporation stockholders	$	2,289			$	3,990
Exclude adjustments:
Lower of cost or market inventory valuation adjustment (a)	747				(790		)
Income tax (expense) benefit related to the lower of cost or market inventory valuation adjustment	(168		)		166
Lower of cost or market inventory valuation adjustment, net of taxes	579				(624		)
Asset impairment loss (b)	(56		)		—
Income tax benefit on Aruba Disposition (b)	42				—
Total adjustments	565				(624		)
Adjusted net income attributable to Valero Energy Corporation stockholders	$	1,724			$	4,614

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See note references on pages 50 through 52.

Reconciliation of Non-GAAP Measures to Most Comparable Measures

Reported under U.S. GAAP (d)

(millions of dollars)

	Year Ended December 31,
	2016				2015
Reconciliation of operating income to gross margin and reconciliation of operating income to adjusted operating income by segment
Refining segment
Operating income	$	3,995			$	6,973
Add back:
Lower of cost or market inventory valuation adjustment (a)	(697		)		740
Operating expenses	3,792				3,795
Depreciation and amortization expense	1,780				1,745
Asset impairment loss (b)	56				—
Gross margin	$	8,926			$	13,253
Operating income	$	3,995			$	6,973
Exclude adjustments:
Lower of cost or market inventory valuation adjustment (a)	697				(740		)
Asset impairment loss (b)	(56		)		—
Adjusted operating income	$	3,354			$	7,713
Ethanol segment
Operating income	$	340			$	142
Add back:
Lower of cost or market inventory valuation adjustment (a)	(50		)		50
Operating expenses	415				448
Depreciation and amortization expense	66				50
Gross margin	$	771			$	690
Operating income	$	340			$	142
Exclude adjustment: Lower of cost or market inventory valuation adjustment (a)	50				(50		)
Adjusted operating income	$	290			$	192

---

See note references on pages 50 through 52.

Reconciliation of Non-GAAP Measures to Most Comparable Measures

Reported under U.S. GAAP (d)

(millions of dollars)

	Year Ended December 31,
	2016				2015
Reconciliation of operating income to gross margin and reconciliation of operating income to adjusted operating income by refining segment region (f)
U.S. Gulf Coast region
Operating income	$	1,959			$	3,945
Add back:
Lower of cost or market inventory valuation adjustment (a)	(37		)		33
Operating expenses	2,163				2,113
Depreciation and amortization expense	1,070				1,036
Asset impairment loss (b)	56				—
Gross margin	$	5,211			$	7,127
Operating income	$	1,959			$	3,945
Exclude adjustments:
Lower of cost or market inventory valuation adjustment (a)	37				(33		)
Asset impairment loss (b)	(56		)		—
Adjusted operating income	$	1,978			$	3,978
U.S. Mid-Continent region
Operating income	$	456			$	1,425
Add back:
Lower of cost or market inventory valuation adjustment (a)	(9		)		9
Operating expenses	588				586
Depreciation and amortization expense	268				278
Gross margin	$	1,303			$	2,298
Operating income	$	456			$	1,425
Exclude adjustment: Lower of cost or market inventory valuation adjustment (a)	9				(9		)
Adjusted operating income	$	447			$	1,434

---

See note references on pages 50 through 52.

Reconciliation of Non-GAAP Measures to Most Comparable Measures

Reported under U.S. GAAP (d)

(millions of dollars)

	Year Ended December 31,
	2016				2015
Reconciliation of operating income to gross margin and reconciliation of operating income to adjusted operating income by refining segment region (f) (continued)
North Atlantic region
Operating income	$	1,355			$	753
Add back:
Lower of cost or market inventory valuation adjustment (a)	(646		)		693
Operating expenses	501				521
Depreciation and amortization expense	195				211
Gross margin	$	1,405			$	2,178
Operating income	$	1,355			$	753
Exclude adjustment: Lower of cost or market inventory valuation adjustment (a)	646				(693		)
Adjusted operating income	$	709			$	1,446
U.S. West Coast region
Operating income	$	225			$	850
Add back:
Lower of cost or market inventory valuation adjustment (a)	(5		)		5
Operating expenses	540				575
Depreciation and amortization expense	247				220
Gross margin	$	1,007			$	1,650
Operating income	$	225			$	850
Exclude adjustment: Lower of cost or market inventory valuation adjustment (a)	5				(5		)
Adjusted operating income	$	220			$	855

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See note references on pages 50 through 52.

Refining Segment Operating Highlights

(millions of dollars, except per barrel amounts)

	Year Ended December 31,
	2016				2015				Change
Throughput volumes (thousand BPD)
Feedstocks:
Heavy sour crude oil	396				438				(42		)
Medium/light sour crude oil	526				428				98
Sweet crude oil	1,193				1,208				(15		)
Residuals	272				274				(2		)
Other feedstocks	152				140				12
Total feedstocks	2,539				2,488				51
Blendstocks and other	316				311				5
Total throughput volumes	2,855				2,799				56
Yields (thousand BPD)
Gasolines and blendstocks	1,404				1,364				40
Distillates	1,066				1,066				—
Other products (g)	421				408				13
Total yields	2,891				2,838				53
Refining segment operating statistics
Gross margin (d)	$	8,926			$	13,253			$	(4,327	)
Adjusted operating income (d)	$	3,354			$	7,713			$	(4,359	)
Throughput volumes (thousand BPD)	2,855				2,799				56
Throughput margin per barrel (h)	$	8.54			$	12.97			$	(4.43	)
Operating costs per barrel:
Operating expenses	3.63				3.71				(0.08		)
Depreciation and amortization expense	1.70				1.71				(0.01		)
Total operating costs per barrel	5.33				5.42				(0.09		)
Adjusted operating income per barrel (i)	$	3.21			$	7.55			$	(4.34	)

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See note references on pages 50 through 52.

Ethanol Segment Operating Highlights

(millions of dollars, except per gallon amounts)

	Year Ended December 31,
	2016				2015				Change
Ethanol segment operating statistics
Gross margin (d)	$	771			$	690			$	81
Adjusted operating income (d)	$	290			$	192			$	98
Production volumes (thousand gallons per day)	3,842				3,827				15
Gross margin per gallon of production (h)	$	0.55			$	0.49			$	0.06
Operating costs per gallon of production:
Operating expenses	0.30				0.32				(0.02		)
Depreciation and amortization expense	0.04				0.03				0.01
Total operating costs per gallon of production	0.34				0.35				(0.01		)
Adjusted operating income per gallon of production (i)	$	0.21			$	0.14			$	0.07

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See note references on pages 50 through 52.

Refining Segment Operating Highlights

(millions of dollars, except per barrel amounts)

	Year Ended December 31,
	2016				2015				Change
Refining segment operating statistics by region (f)
U.S. Gulf Coast region
Gross margin (d)	$	5,211			$	7,127			$	(1,916	)
Adjusted operating income (d)	$	1,978			$	3,978			$	(2,000	)
Throughput volumes (thousand BPD)	1,653				1,592				61
Throughput margin per barrel (h)	$	8.61			$	12.27			$	(3.66	)
Operating costs per barrel:
Operating expenses	3.57				3.64				(0.07		)
Depreciation and amortization expense	1.77				1.78				(0.01		)
Total operating costs per barrel	5.34				5.42				(0.08		)
Adjusted operating income per barrel (i)	$	3.27			$	6.85			$	(3.58	)
U.S. Mid-Continent region
Gross margin (d)	$	1,303			$	2,298			$	(995	)
Adjusted operating income (d)	$	447			$	1,434			$	(987	)
Throughput volumes (thousand BPD)	452				447				5
Throughput margin per barrel (h)	$	7.89			$	14.09			$	(6.20	)
Operating costs per barrel:
Operating expenses	3.56				3.59				(0.03		)
Depreciation and amortization expense	1.63				1.71				(0.08		)
Total operating costs per barrel	5.19				5.30				(0.11		)
Adjusted operating income per barrel (i)	$	2.70			$	8.79			$	(6.09	)

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See note references on pages 50 through 52.

Refining Segment Operating Highlights

(millions of dollars, except per barrel amounts)

	Year Ended December 31,
	2016				2015				Change
Refining segment operating statistics by region (f) (continued)
North Atlantic region
Gross margin (d)	$	1,405			$	2,178			$	(773	)
Adjusted operating income (d)	$	709			$	1,446			$	(737	)
Throughput volumes (thousand BPD)	483				494				(11		)
Throughput margin per barrel (h)	$	7.95			$	12.06			$	(4.11	)
Operating costs per barrel:
Operating expenses	2.84				2.88				(0.04		)
Depreciation and amortization expense	1.10				1.17				(0.07		)
Total operating costs per barrel	3.94				4.05				(0.11		)
Adjusted operating income per barrel (i)	$	4.01			$	8.01			$	(4.00	)
U.S. West Coast region
Gross margin (d)	$	1,007			$	1,650			$	(643	)
Adjusted operating income (d)	$	220			$	855			$	(635	)
Throughput volumes (thousand BPD)	267				266				1
Throughput margin per barrel (h)	$	10.30			$	17.00			$	(6.70	)
Operating costs per barrel:
Operating expenses	5.53				5.92				(0.39		)
Depreciation and amortization expense	2.52				2.26				0.26
Total operating costs per barrel	8.05				8.18				(0.13		)
Adjusted operating income per barrel (i)	$	2.25			$	8.82			$	(6.57	)

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See note references on pages 50 through 52.

Average Market Reference Prices and Differentials

(dollars per barrel, except as noted)

	Year Ended December 31,
	2016				2015				Change
Feedstocks
Brent crude oil	$	45.02			$	53.62			$	(8.60	)
Brent less West Texas Intermediate (WTI) crude oil	1.83				4.91				(3.08		)
Brent less Alaska North Slope (ANS) crude oil	1.25				0.67				0.58
Brent less LLS crude oil (j)	0.15				1.26				(1.11		)
Brent less Argus Sour Crude Index (ASCI) crude oil (k)	5.18				5.63				(0.45		)
Brent less Maya crude oil	8.63				9.54				(0.91		)
LLS crude oil (j)	44.87				52.36				(7.49		)
LLS less ASCI crude oil (j) (k)	5.03				4.37				0.66
LLS less Maya crude oil (j)	8.48				8.28				0.20
WTI crude oil	43.19				48.71				(5.52		)
Natural gas (dollars per million British thermal units (MMBtu))	2.46				2.58				(0.12		)
Products
U.S. Gulf Coast:
CBOB gasoline less Brent	9.17				9.83				(0.66		)
Ultra-low-sulfur diesel less Brent	10.21				12.64				(2.43		)
Propylene less Brent	(6.68		)		(5.94		)		(0.74		)
CBOB gasoline less LLS (j)	9.32				11.09				(1.77		)
Ultra-low-sulfur diesel less LLS (j)	10.36				13.90				(3.54		)
Propylene less LLS (j)	(6.53		)		(4.68		)		(1.85		)
U.S. Mid-Continent:
CBOB gasoline less WTI	11.82				17.59				(5.77		)
Ultra-low-sulfur diesel less WTI	13.03				19.02				(5.99		)
North Atlantic:
CBOB gasoline less Brent	11.99				12.85				(0.86		)
Ultra-low-sulfur diesel less Brent	11.57				16.05				(4.48		)
U.S. West Coast:
CARBOB 87 gasoline less ANS	17.04				25.56				(8.52		)
CARB diesel less ANS	14.52				16.90				(2.38		)
CARBOB 87 gasoline less WTI	17.62				29.80				(12.18		)
CARB diesel less WTI	15.10				21.14				(6.04		)
New York Harbor corn crush (dollars per gallon)	0.30				0.22				0.08

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See note references on pages 50 through 52.

General

Operating revenues decreased $12.1 billion (or 14 percent) and “cost of sales (excluding the lower of cost or market inventory valuation adjustment)” decreased $7.9 billion (or 11 percent) for 2016 compared to 2015 primarily due to a decrease in refined petroleum products prices and crude oil feedstock costs, respectively. Operating income decreased $2.8 billion for the year ended December 31, 2016 compared to the year ended December 31, 2015, primarily due to a decrease in refining segment operating income of $3.0 billion, partially offset by an increase in ethanol segment operating income of $198 million. Adjusted operating income decreased $4.3 billion for 2016 compared to 2015, primarily due to a decrease in refining segment adjusted operating income of $4.4 billion, partially offset by an increase in ethanol segment adjusted operating income of $98 million. The reasons for these changes in the operating results of our segments, as well as other items that affected our income, are discussed below.

Refining

Refining segment adjusted operating income decreased $4.4 billion for 2016 compared to 2015, primarily due to a $4.3 billion decrease in refining gross margin.

Refining gross margin decreased $4.3 billion (a $4.43 per barrel decrease) for 2016 compared to 2015, primarily due to the following:

•

Decrease in gasoline margins - We experienced a decrease in gasoline margins throughout all of our regions in 2016 compared to 2015. For example, WTI-based benchmark reference margin for U.S. Mid-Continent CBOB gasoline was $11.82 per barrel in 2016 compared to $17.59 per barrel in 2015, representing an unfavorable decrease of $5.77 per barrel. Another example is the ANS-based reference margin for U.S. West Coast CARBOB 87 gasoline was $17.04 per barrel in 2016 compared to $25.56 per barrel in 2015, representing an unfavorable decrease of $8.52 per barrel. We estimate that the decrease in gasoline margins per barrel in 2016 compared to 2015 had an unfavorable impact to our refining margin of approximately $1.7 billion.

•

Decrease in distillate margins - We experienced a decrease in distillate margins throughout all of our regions in 2016 compared to 2015. For example, the Brent-based benchmark reference margin for U.S. Gulf Coast ultra-low-sulfur diesel was $10.21 per barrel in 2016 compared to $12.64 per barrel in 2015, representing an unfavorable decrease of $2.43 per barrel. Another example is the WTI-based benchmark reference margin for U.S. Mid-Continent ultra-low-sulfur diesel that was $13.03 per barrel in 2016 compared to $19.02 per barrel in 2015, representing an unfavorable decrease of $5.99 per barrel. We estimate that the decrease in distillate margins per barrel in 2016 compared to 2015 had an unfavorable impact to our refining margin of approximately $1.6 billion.

•

Lower discounts on light sweet crude oils and sour crude oils - The market prices for refined petroleum products generally track the price of Brent crude oil, which is a benchmark sweet crude oil, and we benefit when we process crude oils that are priced at a discount to Brent crude oil, such as WTI crude oil, in periods when pricing terms are favorable. During 2016, we benefited from processing WTI crude oil; however, that benefit declined compared to the benefit from processing WTI crude oil during 2015. For example, WTI crude oil processed in our U.S. Mid-Continent region sold at a discount of $1.83 per barrel to Brent crude oil in 2016 compared to a discount of $4.91 per barrel in 2015, representing an unfavorable decrease of $3.08 per barrel. Another example is Maya crude oil (a type of sour crude oil) that sold at a discount of $8.63 per barrel to Brent crude oil in 2016 compared to a discount of $9.54 per barrel in 2015, representing an unfavorable decrease of $0.91 per barrel. We estimate that the cost of light sweet crude oils and sour crude oils during 2016 had an unfavorable impact to our refining margin of approximately $900 million.

•

Higher costs of biofuel credits - As more fully described in Note 19 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 $309 million from $440 million in 2015 to $749 million in 2016. This increase was due to an increase in the market price of RINs caused by an expected shortage in the market of available RINs that worsened in November 2016 with the release of the U.S. EPA’s final 2017 renewable fuel volume requirements.

•	Higher throughput volumes - Refining throughput volumes increased by 56,000 BPD in 2016. We estimate that the increase in refining throughput volumes had a positive impact on our refining margin of approximately $175 million.

Ethanol

Ethanol segment adjusted operating income increased $98 million for 2016 compared to 2015, primarily due to an $81 million (or $0.06 per gallon) increase in gross margin and a $33 million decrease in operating expenses.

The increase in ethanol segment gross margin of $81 million was primarily due to the following:

•

Lower corn prices - Corn prices were lower in 2016 compared to 2015 primarily due to higher yields from the current corn crop in the corn-producing regions of the U.S. Mid-Continent. For example, the Chicago Board of Trade (CBOT) corn price was $3.58 per bushel in 2016 compared to $3.77 per bushel in 2015. We estimate that the decrease in the price of corn that we processed during 2016 had a favorable impact to our ethanol margin of approximately $105 million.

•

Higher ethanol prices - Ethanol prices were slightly higher in 2016 compared to 2015 primarily due to increased ethanol demand. Despite higher domestic production during 2016, inventory levels declined during the year primarily due to higher exports. For example, the CBOT ethanol price was $1.53 per gallon in 2016 compared to $1.50 per gallon in 2015. We estimate that the increase in the price of ethanol per gallon during 2016 had a favorable impact to our ethanol margin of approximately $24 million.

•

Increased production volumes - Ethanol margin was favorably impacted by increased production volumes of 15,000 gallons per day in 2016 compared to 2015 primarily due to improved operating efficiencies and mechanical reliability. Our ethanol margin was also favorably impacted by higher co-product production volumes between the years. We estimate that the increase in ethanol and co-product production volumes had a favorable impact to our ethanol margin of approximately $22 million.

•	Lower co-product prices - A decrease in export demand for corn-related co-products, primarily distillers grains, had an unfavorable effect on the prices we received. We estimate that the decrease in corn-related co-products prices had an unfavorable impact to our ethanol margin of approximately $70 million.

The $33 million decrease in operating expenses was primarily due to a $14 million decrease in energy costs related to lower natural gas prices ($2.46 per MMBtu in 2016 compared to $2.58 per MMBtu in 2015) and a $15 million decrease in chemical costs.

The increase of $16 million in depreciation and amortization expense was primarily due to a $10 million gain on the sale of certain plant assets in 2015 that was reflected in depreciation and amortization expense thereby reducing depreciation and amortization expense in that period.

Other

Income tax expense decreased $1.1 billion from 2015 to 2016 primarily as a result of lower income before income tax expense. The effective tax rates of 24 percent in 2016 and 31 percent in 2015 are lower than the U.S. statutory rate of 35 percent because income from our international operations is taxed at statutory rates that are lower than in the U.S. The 2016 rate was lower than the 2015 rate due to (i) the reversal of the lower of cost or market inventory valuation reserve of $747 million, the majority of which impacted our international operations that are taxed at lower statutory tax rates, (ii) a benefit of $42 million associated with the transfer of ownership of the Aruba Refinery and Aruba Terminal to the GOA, and (iii) a benefit of $35 million resulting from the settlement of an income tax audit. The transfer of ownership of the Aruba Refinery and the Aruba Terminal to the GOA is more fully described in Note 2 of Notes to Consolidated Financial Statements.

2015 Compared to 2014

Financial Highlights

(millions of dollars, except share and 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) (e)	73,861				118,141				(44,280		)
Lower of cost or market inventory valuation adjustment (a)	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
Weighted-average common shares outstanding – assuming dilution (in millions)	500				530				(30		)

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See note references on pages 50 through 52.

Reconciliation of Non-GAAP Measures to Most Comparable Measures

Reported under U.S. GAAP (d)

(millions of dollars)

	Year Ended December 31,
	2015				2014
Reconciliation of net income from continuing operations attributable to Valero Energy Corporation stockholders to adjusted net income from continuing operations attributable to Valero Energy Corporation stockholders
Net income from continuing operations attributable to Valero Energy Corporation stockholders	$	3,990			$	3,694
Exclude adjustments:
Lower of cost or market inventory valuation adjustment (a)	(790		)		—
Income tax benefit related to the lower of cost or market inventory valuation adjustment	166				—
Lower of cost or market inventory valuation adjustment, net of taxes	(624		)		—
Last-in, first out (LIFO) gain (e)	—				233
Income tax expense related to the LIFO gain	—				(82		)
LIFO gain, net of taxes	—				151
Total adjustments	(624		)		151
Adjusted net income from continuing operations attributable to Valero Energy Corporation stockholders	$	4,614			$	3,543

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See note references on pages 50 through 52.

Reconciliation of Non-GAAP Measures to Most Comparable Measures

Reported under U.S. GAAP (d)

(millions of dollars)

	Year Ended December 31,
	2015				2014
Reconciliation of operating income to gross margin and reconciliation of operating income to adjusted operating income by segment
Refining segment
Operating income	$	6,973			$	5,884
Add back:
Lower of cost or market inventory valuation adjustment (a)	740				—
Operating expenses	3,795				3,900
Depreciation and amortization expense	1,745				1,597
Asset impairment loss (b)	—				—
Less LIFO gain (e)	—				(229		)
Gross margin	$	13,253			$	11,152
Operating income	$	6,973			$	5,884
Exclude adjustments:
Lower of cost or market inventory valuation adjustment (a)	(740		)		—
LIFO gain (e)	—				229
Adjusted operating income	$	7,713			$	5,655
Ethanol segment
Operating income	$	142			$	786
Add back:
Lower of cost or market inventory valuation adjustment (a)	50				—
Operating expenses	448				487
Depreciation and amortization expense	50				49
Less LIFO gain (e)	—				(4		)
Gross margin	$	690			$	1,318
Operating income	$	142			$	786
Exclude adjustments:
Lower of cost or market inventory valuation adjustment (a)	(50		)		—
LIFO gain (e)	—				4
Adjusted operating income	$	192			$	782
Adjusted operating income (loss) by segment
Refining	$	7,713			$	5,655
Ethanol	192				782
Corporate segment	(757		)		(768		)
Total adjusted operating income	$	7,148			$	5,669

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See note references on pages 50 through 52.

Reconciliation of Non-GAAP Measures to Most Comparable Measures

Reported under U.S. GAAP (d)

(millions of dollars)

	Year Ended December 31,
	2015				2014
Reconciliation of operating income to gross margin and reconciliation of operating income to adjusted operating income by refining segment region (f)
U.S. Gulf Coast region
Operating income	$	3,945			$	3,484
Add back:
Lower of cost or market inventory valuation adjustment (a)	33				—
Operating expenses	2,113				2,134
Depreciation and amortization expense	1,036				937
Less LIFO gain (e)	—				(116		)
Gross margin	$	7,127			$	6,439
Operating income	$	3,945			$	3,484
Exclude adjustments:
Lower of cost or market inventory valuation adjustment (a)	(33		)		—
LIFO gain (e)	—				116
Adjusted operating income	$	3,978			$	3,368
U.S. Mid-Continent region
Operating income	$	1,425			$	1,358
Add back:
Lower of cost or market inventory valuation adjustment (a)	9				—
Operating expenses	586				635
Depreciation and amortization expense	278				263
Less LIFO gain (e)	—				(35		)
Gross margin	$	2,298			$	2,221
Operating income	$	1,425			$	1,358
Exclude adjustments:
Lower of cost or market inventory valuation adjustment (a)	(9		)		—
LIFO gain (e)	—				35
Adjusted operating income	$	1,434			$	1,323

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See note references on pages 50 through 52.

Reconciliation of Non-GAAP Measures to Most Comparable Measures

Reported under U.S. GAAP (d)

(millions of dollars)

	Year Ended December 31,
	2015				2014
Reconciliation of operating income to gross margin and reconciliation of operating income to adjusted operating income by refining segment region (f) (continued)
North Atlantic region
Operating income	$	753			$	971
Add back:
Lower of cost or market inventory valuation adjustment (a)	693				—
Operating expenses	521				567
Depreciation and amortization expense	211				193
Less LIFO gain (e)	—				(60		)
Gross margin	$	2,178			$	1,671
Operating income	$	753			$	971
Exclude adjustments:
Lower of cost or market inventory valuation adjustment (a)	(693		)		—
LIFO gain (e)	—				60
Adjusted operating income	$	1,446			$	911
U.S. West Coast region
Operating income	$	850			$	71
Add back:
Lower of cost or market inventory valuation adjustment (a)	5				—
Operating expenses	575				564
Depreciation and amortization expense	220				204
Less LIFO gain (e)	—				(18		)
Gross margin	$	1,650			$	821
Operating income	$	850			$	71
Exclude adjustments:
Lower of cost or market inventory valuation adjustment (a)	(5		)		—
LIFO gain (e)	—				18
Adjusted operating income	$	855			$	53

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See note references on pages 50 through 52.

Refining Segment Operating Highlights

(millions of dollars, except per barrel amounts)

	Year Ended December 31,
	2015				2014				Change
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 (g)	408				423				(15		)
Total yields	2,838				2,799				39
Refining segment operating statistics
Gross margin (d)	$	13,253			$	11,152			$	2,101
Adjusted operating income (d)	$	7,713			$	5,655			$	2,058
Throughput volumes (thousand BPD)	2,799				2,765				34
Throughput margin per barrel (h)	$	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		)
Adjusted operating income per barrel (i)	$	7.55			$	5.60			$	1.95

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See note references on pages 50 through 52.

Ethanol Segment Operating Highlights

(millions of dollars, except per gallon amounts)

	Year Ended December 31,
	2015				2014				Change
Ethanol segment operating statistics
Gross margin (d)	$	690			$	1,318			$	(628	)
Adjusted operating income (d)	$	192			$	782			$	(590	)
Production volumes (thousand gallons per day)	3,827				3,422				405
Gross margin per gallon of production (h)	$	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		)
Adjusted operating income per gallon of production (i)	$	0.14			$	0.63			$	(0.49	)

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See note references on pages 50 through 52.

Refining Segment Operating Highlights

(millions of dollars, except per barrel amounts)

	Year Ended December 31,
	2015				2014				Change
Refining segment operating statistics by region (f)
U.S. Gulf Coast region
Gross margin (d)	$	7,127			$	6,439			$	688
Adjusted operating income (d)	$	3,978			$	3,368			$	610
Throughput volumes (thousand BPD)	1,592				1,600				(8		)
Throughput margin per barrel (h)	$	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
Adjusted operating income per barrel (i)	$	6.85			$	5.77			$	1.08
U.S. Mid-Continent region
Gross margin (d)	$	2,298			$	2,221			$	77
Adjusted operating income (d)	$	1,434			$	1,323			$	111
Throughput volumes (thousand BPD)	447				446				1
Throughput margin per barrel (h)	$	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		)
Adjusted operating income per barrel (i)	$	8.79			$	8.12			$	0.67

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See note references on pages 50 through 52.

Refining Segment Operating Highlights

(millions of dollars, except per barrel amounts)

	Year Ended December 31,
	2015				2014				Change
Refining segment operating statistics by region (f) (continued)
North Atlantic region
Gross margin (d)	$	2,178			$	1,671			$	507
Adjusted operating income (d)	$	1,446			$	911			$	535
Throughput volumes (thousand BPD)	494				457				37
Throughput margin per barrel (h)	$	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		)
Adjusted operating income per barrel (i)	$	8.01			$	5.46			$	2.55
U.S. West Coast region
Gross margin (d)	$	1,650			$	821			$	829
Adjusted operating income (d)	$	855			$	53			$	802
Throughput volumes (thousand BPD)	266				262				4
Throughput margin per barrel (h)	$	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
Adjusted operating income per barrel (i)	$	8.82			$	0.55			$	8.27

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See note references on pages 50 through 52.

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 WTI crude oil	4.91				6.40				(1.49		)
Brent less ANS crude oil	0.67				1.73				(1.06		)
Brent less LLS crude oil (j)	1.26				2.77				(1.51		)
Brent less ASCI crude oil (k)	5.63				7.20				(1.57		)
Brent less Maya crude oil	9.54				13.73				(4.19		)
LLS crude oil (j)	52.36				96.80				(44.44		)
LLS less ASCI crude oil (j) (k)	4.37				4.43				(0.06		)
LLS less Maya crude oil (j)	8.28				10.96				(2.68		)
WTI crude oil	48.71				93.17				(44.46		)
Natural gas (dollars per 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 (j)	11.09				6.31				4.78
Ultra-low-sulfur diesel less LLS (j)	13.90				17.05				(3.15		)
Propylene less LLS (j)	(4.68		)		8.34				(13.02		)
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		)

---

See note references on pages 50 through 52.

The following notes relate to references on pages 27 through 36 and pages 40 through 49.

(a)

In accordance with U.S. GAAP, we are required to state our inventories at the lower of cost or market. When the market price of our inventory falls below cost, we record a lower of cost or market inventory valuation adjustment to write down the value to market. In subsequent periods, the value of our inventory is reassessed and a lower of cost or market inventory valuation adjustment is recorded to reflect the net change in the lower of cost or market inventory valuation reserve between periods. As of December 31, 2016, the market price of our inventory was above cost; therefore, we did not have a lower of cost or market inventory valuation reserve as of that date. During the year ended December 31, 2016, we recorded a change in our inventory valuation reserve that was established on December 31, 2015, resulting in a noncash benefit of $747 million, of which $697 million and $50 million were attributable to our refining segment and ethanol segment, respectively. The year ended December 31, 2015 includes a lower of cost or market inventory valuation adjustment that resulted in a noncash charge of $790 million, of which $740 million and $50 million were attributable to our refining segment and ethanol segment, respectively. The noncash benefit for the year ended December 31, 2016 differs from the noncash charge for the year ended December 31, 2015 due to the foreign currency effect of inventories held by our international operations. This adjustment is further discussed in Note 4 of Notes to Consolidated Financial Statements.

(b)

Effective October 1, 2016, we (i) transferred ownership of all of our assets in Aruba, other than certain hydrocarbon inventories and working capital, to Refineria di Aruba N.V. (RDA), an entity wholly-owned by the GOA, (ii) settled our obligations under various agreements with the GOA, including agreements that required us to dismantle our leasehold improvements under certain conditions, and (iii) sold the working capital of our Aruba operations, including hydrocarbon inventories, to the GOA, CITGO Aruba Refining N.V. (CAR), and CITGO Petroleum Corporation (together with CAR and certain other affiliates, collectively, CITGO). We refer to this transaction as the “Aruba Disposition.”

In June 2016, we recognized an asset impairment loss of $56 million representing all of the remaining carrying value of the long-lived assets of our crude oil and refined petroleum products terminal and transshipment facility in Aruba (collectively, the Aruba Terminal). We recognized the impairment loss at that time because we concluded that it was more likely than not that we would ultimately transfer ownership of these assets to the GOA as a result of agreements entered into in June 2016 between the GOA and CITGO for the GOA’s lease of those assets to CITGO.

In September 2016 and in connection with the Aruba Disposition, our U.S. subsidiaries cancelled all outstanding debt obligations owed to them by our Aruba subsidiaries, which resulted in the recognition by us of an income tax benefit in the U.S. during the year ended December 31, 2016. We had no income tax effect in Aruba from the cancellation of debt or other effects of the Aruba Disposition because of net operating loss carryforwards associated with our operations in Aruba against which we had previously recorded a full valuation allowance. There was no other significant effect to our results of operations or cash flows from the Aruba Disposition during the year ended December 31, 2016.

(c)

The variation in the customary relationship between income tax expense and income before income tax expense for the year ended December 31, 2016 is primarily due to the higher earnings from our international operations that are taxed at statutory rates that are lower than in the U.S. and the recognition of an income tax benefit in the U.S. in connection with the Aruba Disposition (see note (b) above).

(d)	We use certain financial measures (as noted below) that are not defined under U.S. GAAP and are considered to be non-GAAP measures.

We have defined these non-GAAP measures and believe they are useful to the external users of our financial statements, including industry analysts, investors, lenders, and rating agencies. We believe these measures are useful to assess our ongoing financial performance because, when reconciled to their most comparable U.S. GAAP measures, they provide improved comparability between periods through the exclusion of certain items that we believe are not indicative of our core operating performance and that may obscure our underlying business results and trends. These non-GAAP measures should not be considered as alternatives to their most comparable U.S. GAAP measures nor should they be considered in isolation or as a substitute for an analysis of our results of

operations as reported under U.S. GAAP. In addition, these non-GAAP measures may not be comparable to similarly titled measures used by other companies because we may define them differently, which diminishes the utility of these measures.

Non-GAAP measures are as follows:

◦	Adjusted net income attributable to Valero Energy Corporation stockholders is defined as net income attributable to Valero Energy Corporation stockholders excluding the lower of cost or market inventory valuation adjustment, its related income tax effect, the asset impairment loss, and the income tax benefit on the Aruba Disposition.

◦	Adjusted net income from continuing operations attributable to Valero Energy Corporation stockholders is defined as net income from continuing operations attributable to Valero Energy Corporation stockholders excluding the lower of cost or market inventory valuation adjustment, its related income tax effect, the LIFO gain, and its related income tax effect (see (e) below).

◦	Gross margin is defined as operating income excluding the lower of cost or market inventory valuation adjustment, operating expenses, depreciation and amortization expense, asset impairment loss, and LIFO gain (see (e) below).

◦	Adjusted operating income is defined as operating income excluding the lower of cost or market inventory valuation adjustment and the asset impairment loss. For the year ended December 31, 2014, adjusted operating income is further defined to exclude the LIFO gain (see (e) below).

(e)	“Cost of sales (excluding the lower of cost or market inventory valuation adjustment)” for the year ended December 31, 2014 reflects a LIFO gain of $233 million, of which $229 million and $4 million were attributable to our refining segment and ethanol segment, respectively.

(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.

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

(h)

Throughput margin per barrel represents gross margin (as defined in (d) above) for our refining segment or refining regions divided by the respective throughput volumes. Gross margin per gallon of production represents gross margin (as defined in (d) above) for our ethanol segment divided by production volumes. Throughput and production volumes are calculated by multiplying throughput and production volumes per day (as provided in the accompanying tables) by the number of days in the applicable period.

(i)

Adjusted operating income per barrel represents adjusted operating income (defined in (d) above) for our refining segment or refining regions divided by the respective throughput volumes. Adjusted operating income per gallon of production represents adjusted operating income (defined in (d) above) for our ethanol segment divided by production volumes. Throughput and production volumes are calculated by multiplying throughput and production volumes per day (as provided in the accompanying tables) by the number of days in the applicable period.

(j)

Average market reference prices for LLS crude oil, along with price differentials between the price of LLS crude oil and other types of crude oils are reflected without adjusting for the impact of the futures pricing for the corresponding delivery month. Therefore, the prices reported reflect the prompt month pricing only, without an adjustment for futures pricing (known in the industry as the Calendar Month Average (CMA) “roll” adjustment). We previously had provided average market reference prices that included the CMA “roll” adjustment. Accordingly, the average market reference price and price differentials for LLS crude oil for the years ended December 31, 2015 and 2014 have been adjusted to conform to the current presentation.

(k)

Average market reference price differentials to Mars crude oil have been replaced by average market reference price differentials to ASCI crude oil. Mars crude oil is one of the three grades of sour crude oil used to create ASCI crude oil, and therefore, ASCI crude oil is a more comprehensive price marker for medium sour crude oil. Accordingly, the price differentials for ASCI crude oil for the years ended December 31, 2015 and 2014 are included to conform to the current presentation.

General

Operating revenues decreased $43.0 billion (or 33 percent) and “cost of sales (excluding the lower of cost or market inventory valuation adjustment)” decreased $44.3 billion (or 37 percent) for 2015 compared to 2014 primarily due to a decrease in refined petroleum product prices and crude oil feedstock costs, respectively. Despite the decrease in operating revenues, “cost of sales (excluding the lower of cost or market inventory valuation adjustment)” 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. Adjusted operating income increased $1.5 billion in 2015 compared to 2014, primarily due to an increase in refining segment adjusted operating income of $2.1 billion, partially offset by a decrease in ethanol segment adjusted operating income of $590 million. The reasons for these changes in the operating results of our segments, as well as other items that affected our income, are discussed below.

Refining

Refining segment adjusted operating income increased $2.1 billion for 2015 compared to 2014, primarily due to a $2.1 billion increase in refining gross margin and a $105 million decrease in operating expenses, partially offset by a $148 million increase in depreciation and amortization expense.

Refining gross margin increased $2.1 billion (a $1.92 per barrel increase) for 2015 compared to 2014, primarily due 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 petroleum products margins - We experienced an increase in the margins of other refined petroleum products such as petroleum coke, propane, sulfur, and lubes in 2015 compared to 2014. Margins for other refined petroleum 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 petroleum 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 petroleum 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 petroleum 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 $1.26 per barrel to Brent crude oil in 2015 compared to $2.77 per barrel in 2014, representing an unfavorable decrease of $1.51 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 petroleum 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 adjusted operating income decreased $590 million for 2015 compared to 2014, primarily due to a $628 million decrease in gross margin, partially offset by a $39 million decrease in operating expenses.

The decrease in ethanol segment gross margin of $628 million was primarily due 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 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 its $750 million senior unsecured revolving credit facility agreement (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 primarily due 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.

LIQUIDITY AND CAPITAL RESOURCES

Cash Flows for the Year Ended December 31, 2016

Our operations generated $4.8 billion of cash in 2016, driven primarily by net income of $2.4 billion, net noncash charges to income of $1.4 billion, and a positive change in working capital of $976 million. Noncash charges include $1.9 billion of depreciation and amortization expense, $56 million for the asset impairment loss associated with our Aruba Terminal, and $230 million of deferred income tax expense, partially offset by a benefit of $747 million from a lower of cost or market inventory valuation adjustment. See “RESULTS OF OPERATIONS” for further discussion of our operations. The change in our working capital is further detailed in Note 17 of Notes to Consolidated Financial Statements. This source of cash mainly resulted from:

•	an increase in accounts payable, offset by an increase in receivables, primarily as a result of higher commodity prices;

•	a reduction of our inventories; and

•	a reduction in income taxes receivable due to utilization in 2016 of our 2015 overpayment of taxes.

The $4.8 billion of cash generated by our operations, along with $2.2 billion in proceeds from the issuance of debt (including $1.25 billion of 3.4 percent Senior Notes due September 15, 2026, $500 million of 4.375 percent Senior Notes due December 15, 2026 issued by VLP, and borrowings under the VLP Revolver of $349 million as discussed in Note 8 of Notes to Consolidated Financial Statements), were used mainly to:

•	fund $2.0 billion in capital investments,which include capital expenditures, deferred turnaround and catalyst costs, and equity-method joint venture investments;

•	redeem our 6.125 percent Senior Notes for $778 million (or 103.70 percent of stated value) and our 7.2 percent Senior Notes for $213 million (or 106.27 percent of stated value);

•	make payments on debt and capital lease obligations of $525 million, of which $494 million related to borrowings under the VLP Revolver, $9 million related to capital lease obligations, and $22 million related to other non-bank debt;

•	pay off a long-term liability of $137 million owed to a joint venture partner for an owner-method joint venture investment;

•	purchase common stock for treasury of $1.3 billion;

•	pay common stock dividends of $1.1 billion;

•	pay distributions of $65 million to noncontrolling interests; and

•	increase available cash on hand by $702 million.

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 net noncash charges to income of $2.8 billion. Noncash charges include $1.8 billion of depreciation and amortization expense, $790 million from a lower of cost or market inventory valuation adjustment, and $165 million of deferred income tax 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 $1.3 billion as shown in Note 17 of Notes to Consolidated Financial Statements. This use of cash mainly resulted from:

•	a decrease in accounts payable, net of a decrease in receivables, primarily as a result of a decrease in commodity prices from December 2014 to December 2015;

•	an increase in income taxes receivable and a decrease in income taxes payable 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; and

•	an increase in inventories, 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 10 of Notes to Consolidated Financial Statements, were used mainly to:

•	fund $2.4 billion in capital investments, which include capital expenditures, deferred turnaround and catalyst costs, and equity-method 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 $2.2 billion of noncash charges to income. Noncash charges include $1.7 billion of depreciation and amortization expense, $63 million of asset retirement and other expenses associated with our Aruba Refinery, and $445 million of deferred income tax 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 as shown in Note 17 of Notes to Consolidated Financial Statements. This use of cash mainly resulted from:

•	a decrease in accounts receivable, which was offset by a decrease in accounts payable, primarily as a result of a decrease in commodity prices from December 2013 to December 2014;

•	a decrease in income taxes payable resulting from income tax payments exceeding income tax liabilities incurred in 2014 due to the payment of liabilities associated with prior period earnings; and

•	an increase in inventories 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 generated by our operations in 2014, along with $603 million from available cash on hand, were used mainly to:

•	fund $2.8 billion in capital investments, which include capital expenditures, deferred turnaround and catalyst costs, and equity-method joint venture investments;

•	make payments on debt and capital lease obligations 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 equity-method 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 All American 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. We have contributed $138 million in Diamond Pipeline and expect to continue making contributions as the construction progresses.

For 2017, we expect to incur approximately $2.7 billion for capital investments, including capital expenditures, deferred turnaround and catalyst costs, and equity-method joint venture investments. This consists of approximately $1.6 billion for stay-in-business capital and $1.1 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, 2016 are summarized below (in millions).

	Payments Due by Period
	2017				2018				2019				2020				2021				Thereafter				Total
Debt and capital lease obligations (a)	$	122			$	21			$	771			$	898			$	17			$	6,281			$	8,110
Operating lease obligations	479				321				221				162				106				362				1,651
Purchase obligations	21,750				3,517				1,986				1,446				1,116				5,483				35,298
Other long-term liabilities	—				125				88				85				80				1,366				1,744
Total	$	22,351			$	3,984			$	3,066			$	2,591			$	1,319			$	13,492			$	46,803

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(a)	Debt obligations exclude amounts related to unamortized discounts and debt issuance costs. Capital lease obligations include related interest expense. These items are further described in Note 8 of Notes to Consolidated Financial Statements.

In October 2016, we entered into agreements to lease storage tanks located at three of our refineries. The leases commenced in January 2017. The lease agreements will be accounted for as capital leases and we expect to recognize capital lease assets and related obligations of approximately $490 million. These capital

lease agreements have initial terms of 10 years each and each agreement has successive 10-year automatic renewal terms.

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 2016, we amended our agreement to decrease the facility from $1.4 billion to $1.3 billion and extended the maturity date to July 2017. As of December 31, 2016, 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
Rating Agency		Valero		VLP
Moody’s Investors Service		Baa2 (stable outlook)		Baa3 (stable outlook)
Standard & Poor’s Ratings Services		BBB (stable outlook)		BBB- (stable outlook)
Fitch Ratings		BBB (stable outlook)		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 petroleum 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 7 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, 2016.

Summary of Credit Facilities

As of December 31, 2016, we had outstanding borrowings, letters of credit issued, and availability under our credit facilities as follows (in millions):

								December 31, 2016
		Facility Amount				Maturity Date		Outstanding Borrowings				Letters of Credit Issued				Availability
Committed facilities:
Valero Revolver		$	3,000			November 2020		$	—			$	53			$	2,947
VLP Revolver		$	750			November 2020		$	30			$	—			$	720
Canadian Revolver		C$	25			November 2017		C$	—			C$	10			C$	15
Accounts receivable sales facility		$	1,300			July 2017		$	100			$	—			$	1,200
Letter of credit facilities		$	225			June 2017 and November 2017		$	—			$	—			$	225
Uncommitted facilities:
Letter of credit facilities		$	670			N/A		$	—			$	202			$	468

Letters of credit issued as of December 31, 2016 expire in 2017 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 September 21, 2016, our board of directors authorized our purchase of up to an additional $2.5 billion of our outstanding common stock (the 2016 program) with no expiration date. This authorization was in addition to the remaining amount available under a $2.5 billion program authorized on July 13, 2015 (the 2015 program). As of December 31, 2016, we had approximately $2.5 billion remaining available under the 2015 program and the 2016 program, but we have no obligation to make purchases under these programs.

Pension Plan Funding

We plan to contribute approximately $28 million to our pension plans and $19 million to our other postretirement benefit plans during 2017.

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

Tax Matters

During 2016, we settled the audit related to our U.S. federal income tax returns for 2008 and 2009. The IRS has ongoing tax audits related to our U.S. federal income tax returns from 2010 through 2014, and we have received Revenue Agent Reports (RARs) in connection with the 2010 and 2011 audit. 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. We believe that the ultimate settlement of these audits will not be material to our financial position, results of operations, or liquidity.

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 14 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, 2016, $2.2 billion of our cash and temporary cash investments was held by our international subsidiaries.

Concentration of Customers

Our operations have a concentration of customers in the refining industry and customers who are refined petroleum 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 petroleum products, which requires us to make estimates regarding the refined petroleum products expected to be produced from those feedstocks and the conversion costs required to convert those feedstocks into refined petroleum 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 adjustments for the years ended December 31, 2016 and 2015 are discussed in Note 4 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 9 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, 2016 and 2015 are included in Note 7 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 12 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, 2016 was 5.50 percent. The actual return on assets for the years ended December 31, 2016, 2015, and 2014 was 7.77 percent, 1.46 percent, and 7.33 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, 2016 and net periodic benefit cost for the year ending December 31, 2017 (in millions):

	Pension Benefits				Other Postretirement Benefits
Increase in projected benefit obligation resulting from:
Discount rate decrease	$	106			$	9
Compensation rate increase	12				n/a
Health care cost trend rate increase	n/a				1
Increase in expense resulting from:
Discount rate decrease	9				1
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 is determined using the spot-rate approach. Under this approach, our net periodic benefit cost is 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 $18 million for pension benefits and $2 million for other postretirement benefits in 2017.

See Note 12 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 Note 14 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.