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

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

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

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

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

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


•	future refining margins, including gasoline and distillate margins;


•	future retail margins, including gasoline, diesel, heating oil, and convenience store merchandise margins;


•	future ethanol margins;


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


•	anticipated levels of crude oil and refined product inventories;


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


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


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


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

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


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


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


•	demand for, and supplies of, refined products such as gasoline, diesel fuel, jet fuel, heating oil, 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 (OPEC) to agree on and to maintain crude oil price and production controls;


•	the level of consumer demand, including seasonal fluctuations;


•	refinery overcapacity or undercapacity;


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


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


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


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


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


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


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


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


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


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


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


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


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


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


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

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

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

OVERVIEW AND OUTLOOK

Overview

For the year ended December 31, 2012, we reported net income attributable to Valero stockholders from continuing operations of $2.1 billion, or $3.75 per share (assuming dilution), which was comparable to the $2.1 billion, or $3.69 per share (assuming dilution), in net income attributable to Valero stockholders from continuing operations for the year ended December 31, 2011. Included in our 2012 results, however, were noncash asset impairment losses totaling $983 million after taxes, or $1.77 per share (assuming dilution), primarily related to the impairment of the refining assets of our Aruba Refinery in connection with our decision in September 2012 to reorganize the refinery into a crude oil and refined products terminal. This matter is more fully discussed in Note 4 of Notes to Consolidated Financial Statements.

Our operating income increased $330 million from 2011 to 2012 as outlined by business segment in the following table (in millions):



	Year Ended December 31,
	2012			2011			Change
Operating income (loss) by business segment:
Refining	$	4,450		$	3,516		$	934
Retail	348			381			(33		)
Ethanol	(47		)	396			(443		)
Corporate	(741		)	(613		)	(128		)
Total	$	4,010		$	3,680		$	330

Operating income for 2012 was also negatively impacted by the noncash asset impairment losses discussed above, as well as severance expense of $41 million related to the operations at our Aruba Refinery, and operating income for 2011 was impacted by a $542 million loss on commodity derivative contracts related to forward sales of refined product. Excluding these significant items, total operating income for 2012 and 2011 would have been $5.1 billion and $4.2 billion, respectively, reflecting a $900 million favorable increase between the years, and refining segment operating income for 2012 and 2011 would have been $5.5 billion and $4.1 billion, respectively, reflecting a favorable increase of $1.4 billion between the years.

The $1.4 billion increase in refining segment operating income was primarily the result of improvements in the margin generated by our U.S. Mid-Continent and North Atlantic refining operations, which experienced increases in throughput margin of $2.58 per barrel and $3.81 per barrel, respectively, in 2012 compared to 2011. Our U.S. Mid-Continent region continued to benefit from the favorable difference between the price of Brent crude oil and WTI-type crude oil, which is the type of crude oil primarily processed by our refineries in this region. Because the market for refined products generally tracks the price of Brent crude oil, we benefit when the price of WTI-type crude oil is lower than the price of Brent crude oil. The favorable difference between the price of WTI and Brent crude oil improved by $1.67 per barrel in 2012 compared to 2011, which contributed significantly to the increase in the throughput margin generated by our operations in this region. The results of our North Atlantic region were favorably impacted by increases in refined product prices due largely to a reduction in the supply of refined products in this region as compared to the prior year. This reduction in supply resulted from the continued shutdown of refineries in the U.S. East Coast, Caribbean, and Western Europe during 2012, which was due to poor refining economics in these areas, and supply disruptions caused by Hurricane Sandy, which struck the U.S. East Coast in October 2012.

The favorable results of our refining segment were partially offset by the $443 million decrease in our ethanol segment’s operating income in 2012 compared to 2011. This decrease was due to significantly lower gross

margins in 2012 caused by a combination of high corn prices and an oversupply of ethanol in the market. The increase in corn prices in 2012 was largely due to the severe drought experienced in grain producing regions of the U.S. in 2012, and the oversupply of ethanol inventories was largely attributable to lower exports of ethanol to Europe and increased imports of ethanol from Brazil.

Outlook

Throughout 2011 and 2012, our refining business benefited from processing sweet crude oils sourced from the inland U.S., such as WTI crude oil, due to the favorable difference between the price of this type of crude oil and the price of a benchmark sweet crude oil, such as Brent crude oil. Historically, the price of WTI-type crude oil has closely approximated Brent crude oil, but due to the significant development of crude oil reserves within the U.S. Mid-Continent region and increased deliveries of crude oil from Canada into the U.S. Mid-Continent region, the increased supply of WTI crude oil has resulted in WTI crude oil being priced at a significant discount to Brent crude oil. This benefit, however, may decline as various crude oil pipeline and logistics projects are completed. These projects will allow cost-advantaged crude oils from the inland U.S. and Canada to be transported to the U.S. Gulf Coast region, which is expected to result in a narrowing of the price differential of WTI-priced crude oils relative to Brent-priced crude oils. As a result, the margins for refined products for refiners that process WTI-priced crude oils may decline.

Continued refinery closures in the U.S. East Coast, Caribbean, and Western Europe and additional closures expected to occur in the industry combined with poor reliability and low utilization in Latin American refineries create opportunities for competitive refineries to export quality products at higher margins. However, some marginally profitable refineries may continue to be operated, which could negatively impact refined product margins.

Thus far in the first quarter of 2013, ethanol margins have improved, but the improvement is not significant and the margins remain far below those experienced in 2011. We expect a continued modest improvement in ethanol margins throughout 2013 relative to those in 2012.

Energy markets and margins are volatile, and we expect them to continue to be volatile in the near to mid-term.

We continue to make progress in the separation of our retail business under a new company named CST Brands, Inc. The separation is planned by way of a pro rata distribution of 80 percent of the outstanding shares of CST common stock to Valero stockholders. The distribution is expected to take place in the second quarter of 2013, assuming a favorable private letter ruling from the IRS and clearance of all comments from the SEC relating to CST’s registration statement on Form 10. When the distribution occurs, we expect to receive approximately $1.1 billion of cash and incur a tax liability of approximately $230 million. We also expect to liquidate the remaining 20 percent of CST outstanding shares within 18 months of the distribution. Details of the separation and distribution are provided in filings with the SEC by CST.

RESULTS OF OPERATIONS

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

2012 Compared to 2011

Financial Highlights (a) (b)

(millions of dollars, except per share amounts)



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

Net income attributable to Valero stockholders:
Continuing operations	$	2,083		$	2,097		$	(14	)
Discontinued operations	—			(7		)	7
Total	$	2,083		$	2,090		$	(7	)

Earnings per common share – assuming dilution:
Continuing operations	$	3.75		$	3.69		$	0.06
Discontinued operations	—			(0.01		)	0.01
Total	$	3.75		$	3.68		$	0.07

See note references on page 35.

Refining Operating Highlights

(millions of dollars, except per barrel amounts)



	Year Ended December 31,
	2012		2011		Change
Refining (a) (b):
Operating income (c) (d) (e)	$	4,450	$	3,516	$	934
Throughput margin per barrel (f)	$	10.96	$	9.91	$	1.05
Operating costs per barrel:
Operating expenses (d)	3.79		3.83		(0.04		)
Depreciation and amortization expense	1.44		1.51		(0.07		)
Total operating costs per barrel (e)	5.23		5.34		(0.11		)
Operating income per barrel	$	5.73	$	4.57	$	1.16

Throughput volumes (thousand BPD):
Feedstocks:
Heavy sour crude	453		454		(1		)
Medium/light sour crude	547		442		105
Acidic sweet crude	81		116		(35		)
Sweet crude	910		745		165
Residuals	200		282		(82		)
Other feedstocks	120		122		(2		)
Total feedstocks	2,311		2,161		150
Blendstocks and other	302		273		29
Total throughput volumes	2,613		2,434		179

Yields (thousand BPD):
Gasolines and blendstocks	1,251		1,120		131
Distillates	918		834		84
Other products (g)	467		494		(27		)
Total yields	2,636		2,448		188

See note references on page 35.

Refining Operating Highlights by Region (h)

(millions of dollars, except per barrel amounts)



	Year Ended December 31,
	2012			2011			Change
U.S. Gulf Coast (a):
Operating income (c) (d) (e)	$	2,541		$	2,205		$	336
Throughput volumes (thousand BPD)	1,488			1,450			38
Throughput margin per barrel (c) (f)	$	9.65		$	9.33		$	0.32
Operating costs per barrel:
Operating expenses (d)	3.55			3.66			(0.11		)
Depreciation and amortization expense	1.44			1.50			(0.06		)
Total operating costs per barrel (d) (e)	4.99			5.16			(0.17		)
Operating income per barrel	$	4.66		$	4.17		$	0.49

U.S. Mid-Continent:
Operating income (c)	$	2,044		$	1,535		$	509
Throughput volumes (thousand BPD)	430			411			19
Throughput margin per barrel (c) (f)	$	18.49		$	15.91		$	2.58
Operating costs per barrel:
Operating expenses	4.02			4.15			(0.13		)
Depreciation and amortization expense	1.48			1.52			(0.04		)
Total operating costs per barrel	5.50			5.67			(0.17		)
Operating income per barrel	$	12.99		$	10.24		$	2.75

North Atlantic (b):
Operating income	$	752		$	171		$	581
Throughput volumes (thousand BPD)	428			317			111
Throughput margin per barrel (f)	$	9.24		$	5.43		$	3.81
Operating costs per barrel:
Operating expenses	3.59			3.08			0.51
Depreciation and amortization expense	0.85			0.87			(0.02		)
Total operating costs per barrel	4.44			3.95			0.49
Operating income per barrel	$	4.80		$	1.48		$	3.32

U.S. West Coast:
Operating income (c)	$	147		$	147		$	—
Throughput volumes (thousand BPD)	267			256			11
Throughput margin per barrel (c) (f)	$	8.84		$	9.11		$	(0.27	)
Operating costs per barrel:
Operating expenses	5.09			5.25			(0.16		)
Depreciation and amortization expense	2.25			2.29			(0.04		)
Total operating costs per barrel	7.34			7.54			(0.20		)
Operating income per barrel	$	1.50		$	1.57		$	(0.07	)

Operating income for regions above	$	5,484		$	4,058		$	1,426
Loss on derivative contracts related to the forward sales of refined product (c)	—			(542		)	542
Severance expense (d)	(41		)	—			(41		)
Asset impairment loss applicable to refining (e)	(993		)	—			(993		)
Total refining operating income	$	4,450		$	3,516		$	934

See note references on page 35.

Average Market Reference Prices and Differentials

(dollars per barrel, except as noted)



	Year Ended December 31,
	2012			2011			Change
Feedstocks:
Brent crude oil	$	111.70		$	110.93		0.77
Brent less WTI crude oil	17.55			15.88			1.67
Brent less Alaska North Slope (ANS) crude oil	1.08			1.39			(0.31	)
Brent less LLS crude oil	(0.91		)	(0.54		)	(0.37	)
Brent less Mars crude oil	3.97			3.46			0.51
Brent less Maya crude oil	12.06			12.18			(0.12	)
LLS crude oil	112.61			111.47			1.14
LLS less Mars crude oil	4.88			4.00			0.88
LLS less Maya crude oil	12.97			12.72			0.25
WTI crude oil	94.15			95.05			(0.90	)

Natural gas (dollars per million British thermal units)	2.71			3.96			(1.25	)

Products:
U.S. Gulf Coast:
Conventional 87 gasoline less Brent	6.49			5.58			0.91
Ultra-low-sulfur diesel less Brent	16.48			13.78			2.70
Propylene less Brent	(22.38		)	8.23			(30.61	)
Conventional 87 gasoline less LLS	5.58			5.04			0.54
Ultra-low-sulfur diesel less LLS	15.57			13.24			2.33
Propylene less LLS	(23.29		)	7.69			(30.98	)
U.S. Mid-Continent:
Conventional 87 gasoline less WTI	25.40			22.37			3.03
Ultra-low-sulfur diesel less WTI	34.96			31.06			3.90
North Atlantic:
Conventional 87 gasoline less Brent	11.46			6.24			5.22
Ultra-low-sulfur diesel less Brent	19.06			15.64			3.42
U.S. West Coast:
CARBOB 87 gasoline less ANS	15.39			11.48			3.91
CARB diesel less ANS	19.93			18.47			1.46
CARBOB 87 gasoline less WTI	31.86			25.97			5.89
CARB diesel less WTI	36.40			32.96			3.44
New York Harbor corn crush (dollars per gallon)	(0.15		)	0.25			(0.40	)

See note references on page 35.

Retail and Ethanol Operating Highlights

(millions of dollars, except per gallon amounts)



	Year Ended December 31,
	2012			2011			Change
Retail–U.S.:
Operating income (e)	$	240		$	213		$	27
Company-operated fuel sites (average)	1,013			994			19
Fuel volumes (gallons per day per site)	5,083			5,060			23
Fuel margin per gallon	$	0.162		$	0.144		$	0.018
Merchandise sales	$	1,239		$	1,223		$	16
Merchandise margin (percentage of sales)	29.7		%	28.7		%	1.0		%
Margin on miscellaneous sales	$	89		$	88		$	1
Operating expenses	$	434		$	416		$	18
Depreciation and amortization expense	$	77		$	77		$	—
Asset impairment loss (e)	$	12		$	—		$	12

Retail–Canada:
Operating income (e)	$	108		$	168		$	(60	)
Fuel volumes (thousand gallons per day)	3,096			3,195			(99		)
Fuel margin per gallon	$	0.258		$	0.299		$	(0.041	)
Merchandise sales	$	257		$	261		$	(4	)
Merchandise margin (percentage of sales)	29.0		%	29.4		%	(0.4		)%
Margin on miscellaneous sales	$	44		$	43		$	1
Operating expenses	$	252		$	262		$	(10	)
Depreciation and amortization expense	$	42		$	38		$	4
Asset impairment loss (e)	$	9		$	—		$	9

Ethanol:
Operating income (loss)	$	(47	)	$	396		$	(443	)
Ethanol production (thousand gallons per day)	2,967			3,352			(385		)
Gross margin per gallon of production (f)	$	0.30		$	0.68		$	(0.38	)
Operating costs per gallon of production:
Operating expenses	0.30			0.33			(0.03		)
Depreciation and amortization expense	0.04			0.03			0.01
Total operating costs per gallon of production	0.34			0.36			(0.02		)
Operating income (loss) per gallon of production	$	(0.04	)	$	0.32		$	(0.36	)

See note references on page 35.

The following notes relate to references on pages 30 through 34.


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


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


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

(c)

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


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

(d)

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


(e)	During the year ended December 31, 2012, we recognized the following asset impairment losses (in millions):



Refining segment:
Aruba Refinery	$	928
Cancelled capital projects	65
Asset impairment losses - refining segment	993
Retail segment:
U.S. stores	12
Canada stores	9
Asset impairment losses - retail segment	21
Total asset impairment losses	$	1,014

The asset impairment loss related to the Aruba Refinery resulted from our decision in March 2012 to suspend refining operations at the refinery and our subsequent decision in September 2012 to reorganize the refinery into a crude oil and refined products terminal, as discussed in note (d). We recognized an asset impairment loss of $595 million in March 2012 and an additional asset impairment loss of $308 million in September 2012, resulting in no remaining book value being associated with the refinery’s idled processing units and related infrastructure (refining assets). In addition, we recorded a loss of $25 million related to supplies inventories that supported the refining operations. The refining operations will remain suspended indefinitely; however, we continue to maintain the refining assets to allow them to be restarted and do not consider them to be abandoned. No income tax benefits were recorded related to this asset impairment loss.

We also recognized asset impairment losses related to permanently cancelled capital projects at certain of our refineries and related to our determination that the net book values of certain of our retail stores were not recoverable through the future operation and disposition of those stores. The after-tax amount of these asset impairment losses was $55 million for the year ended December 31, 2012.

The asset impairment losses reflected in the table above are included in the operating income of the respective segment for the year ended December 31, 2012. However, the asset impairment losses related to the refining segment are excluded from the segment’s operating costs per barrel and from the operating income and operating costs per barrel by region.


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


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


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

(h)

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

General

Operating revenues increased 11 percent (or $13.3 billion) for the year ended December 31, 2012 compared to the year ended December 31, 2011 primarily as a result of higher average refined product prices for most of the products we produce and higher throughput volumes between the two years related to our refining segment operations. Refined product prices are most significantly influenced by the price of crude oil, which is a worldwide commodity whose price is influenced by many factors, including, but not limited to, worldwide supply and demand characteristics, worldwide political conditions, and worldwide economic conditions. However, regional factors also impact the price of refined product prices in those geographic regions. Regional factors can be similar to those that affect the worldwide price of crude oil, but they can also be significantly influenced by weather conditions that disrupt the supply of and demand for refined products in the region. For example, in October 2012, Hurricane Sandy struck the U.S. East Coast and disrupted the supply of refined products in that region for some time, which contributed to the increase of $5.99 per barrel in the North Atlantic benchmark reference price of conventional 87 gasoline in 2012 compared to 2011. The higher throughput volumes in 2012 resulted primarily from the incremental throughput of 75,000 BPD from the Meraux Refinery, which was acquired on October 1, 2011, and incremental throughput of 95,000 BPD from the Pembroke Refinery, which was acquired on August 1, 2011.

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

Refining

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

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

The $526 million increase in refining margin in the U.S. Mid-Continent region was largely due to improved gasoline and distillate margins in that region in 2012 compared to 2011. For example, the U.S. Mid-Continent benchmark reference margins for conventional 87 gasoline and ultra-low-sulfur diesel, a type of distillate, increased year over year by $3.03 per barrel and $3.90 per barrel, respectively, and these increases were primarily the result of a $1.67 per barrel increase in the discount between the price of WTI crude oil versus Brent crude oil. Brent crude oil is the type of crude oil used by the market to set the price of refined products, but our refineries in the U.S. Mid-Continent region primarily process WTI-type crude oil; therefore, the increase in the price discount between WTI crude oil versus Brent crude oil had a positive impact to our refining margin in this region of approximately $300 million. WTI crude oil priced at a significant discount

to Brent crude oil during 2012 because of increases in crude oil reserves within the U.S. Mid-Continent region and increased deliveries of crude oil from Canada into that region, coupled with the inability to transport significant quantities of that crude oil to refineries in other regions of the country. As discussed in “OVERVIEW AND OUTLOOK.” we believe these conditions to remain in the near term; however, we believe the discount will begin to narrow as crude oil pipeline and logistics projects are completed and other forms of transportation are obtained, such as rail cars, to enable significant quantities of WTI-type crude oil to be transported to other regions.

The $821 million increase in refining margin in the North Atlantic region was also due to improved gasoline and distillate margins in that region in 2012 compared to 2011. For example, the North Atlantic benchmark reference margins for conventional 87 gasoline and ultra-low-sulfur diesel increased year over year by $5.22 per barrel and $3.42 per barrel, respectively, and these increases were due largely to a reduction in the supply of refined products, which resulted from the continued shutdown of refineries in the U.S. East Coast, Caribbean, and Western Europe during 2012, and supply disruptions caused by Hurricane Sandy, which struck the U.S. East Coast in October 2012.

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

Retail

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

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

Ethanol

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

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

Corporate Expenses and Other

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

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

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

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

2011 Compared to 2010

Financial Highlights (a) (b) (d) (e)

(millions of dollars, except per share amounts)



	Year Ended December 31,
	2011			2010			Change
Operating revenues	$	125,987		$	82,233		$	43,754
Costs and expenses:
Cost of sales (c)	115,719			74,458			41,261
Operating expenses:
Refining	3,406			2,944			462
Retail	678			654			24
Ethanol	399			363			36
General and administrative expenses	571			531			40
Depreciation and amortization expense:
Refining	1,338			1,210			128
Retail	115			108			7
Ethanol	39			36			3
Corporate	42			51			(9		)
Asset impairment loss	—			2			(2		)
Total costs and expenses	122,307			80,357			41,950
Operating income	3,680			1,876			1,804
Other income, net	43			106			(63		)
Interest and debt expense, net of capitalized interest	(401		)	(484		)	83
Income from continuing operations before income tax expense	3,322			1,498			1,824
Income tax expense	1,226			575			651
Income from continuing operations	2,096			923			1,173
Loss from discontinued operations, net of income taxes	(7		)	(599		)	592
Net income	2,089			324			1,765
Less: Net loss attributable to noncontrolling interest	(1		)	—			(1		)
Net income attributable to Valero stockholders	$	2,090		$	324		$	1,766

Net income (loss) attributable to Valero stockholders:
Continuing operations	$	2,097		$	923		$	1,174
Discontinued operations	(7		)	(599		)	592
Total	$	2,090		$	324		$	1,766

Earnings per common share – assuming dilution:
Continuing operations	$	3.69		$	1.62		$	2.07
Discontinued operations	(0.01		)	(1.05		)	1.04
Total	$	3.68		$	0.57		$	3.11

See note references on page 44.

Refining Operating Highlights

(millions of dollars, except per barrel amounts)



	Year Ended December 31,
	2011		2010		Change
Refining (a) (b) (d):
Operating income (c)	$	3,516	$	1,903	$	1,613
Throughput margin per barrel (f)	$	9.91	$	7.80	$	2.11
Operating costs per barrel:
Operating expenses	3.83		3.79		0.04
Depreciation and amortization expense	1.51		1.56		(0.05		)
Total operating costs per barrel	5.34		5.35		(0.01		)
Operating income per barrel	$	4.57	$	2.45	$	2.12

Throughput volumes (thousand BPD):
Feedstocks:
Heavy sour crude	454		458		(4		)
Medium/light sour crude	442		386		56
Acidic sweet crude	116		60		56
Sweet crude	745		668		77
Residuals	282		204		78
Other feedstocks	122		110		12
Total feedstocks	2,161		1,886		275
Blendstocks and other	273		243		30
Total throughput volumes	2,434		2,129		305

Yields (thousand BPD):
Gasolines and blendstocks	1,120		1,048		72
Distillates	834		712		122
Other products (g)	494		395		99
Total yields	2,448		2,155		293

See note references on page 44.

Refining Operating Highlights by Region (h)

(millions of dollars, except per barrel amounts)



	Year Ended December 31,
	2011			2010			Change
U.S. Gulf Coast (a):
Operating income (c)	$	2,205		$	1,349		$	856
Throughput volumes (thousand BPD)	1,450			1,280			170
Throughput margin per barrel (f)	$	9.33		$	8.20		$	1.13
Operating costs per barrel:
Operating expenses	3.66			3.71			(0.05		)
Depreciation and amortization expense	1.50			1.60			(0.10		)
Total operating costs per barrel	5.16			5.31			(0.15		)
Operating income per barrel	$	4.17		$	2.89		$	1.28

U.S. Mid-Continent:
Operating income (c)	$	1,535		$	339		$	1,196
Throughput volumes (thousand BPD)	411			398			13
Throughput margin per barrel (f)	$	15.91		$	7.33		$	8.58
Operating costs per barrel:
Operating expenses	4.15			3.60			0.55
Depreciation and amortization expense	1.52			1.40			0.12
Total operating costs per barrel	5.67			5.00			0.67
Operating income per barrel	$	10.24		$	2.33		$	7.91

North Atlantic (b):
Operating income	$	171		$	129		$	42
Throughput volumes (thousand BPD)	317			195			122
Throughput margin per barrel (f)	$	5.43		$	6.18		$	(0.75	)
Operating costs per barrel:
Operating expenses	3.08			2.99			0.09
Depreciation and amortization expense	0.87			1.39			(0.52		)
Total operating costs per barrel	3.95			4.38			(0.43		)
Operating income per barrel	$	1.48		$	1.80		$	(0.32	)

U.S. West Coast:
Operating income (c)	$	147		$	88		$	59
Throughput volumes (thousand BPD)	256			256			—
Throughput margin per barrel (f)	$	9.11		$	7.73		$	1.38
Operating costs per barrel:
Operating expenses	5.25			5.09			0.16
Depreciation and amortization expense	2.29			1.69			0.60
Total operating costs per barrel	7.54			6.78			0.76
Operating income per barrel	$	1.57		$	0.95		$	0.62

Operating income for regions above	$	4,058		$	1,905		$	2,153
Loss on derivative contracts related to the forward sales of refined product (c)	(542		)	—			(542		)
Asset impairment loss applicable to refining	—			(2		)	2
Total refining operating income	$	3,516		$	1,903		$	1,613

See note references on page 44.

Average Market Reference Prices and Differentials (i)

(dollars per barrel, except as noted)



	Year Ended December 31,
	2011			2010			Change
Feedstocks:
Brent crude oil	$	110.93		$	79.54		$	31.39
Brent less WTI	15.88			0.13			15.75
Brent less ANS crude oil	1.39			0.46			0.93
Brent less LLS crude oil	(0.54		)	(2.09		)	1.55
Brent less Mars crude oil	3.46			1.54			1.92
Brent less Maya crude oil	12.18			9.26			2.92
LLS	111.47			81.62			29.85
LLS less Mars crude oil	4.00			3.62			0.38
LLS less Maya crude oil	12.72			11.34			1.38
WTI crude oil	95.05			79.41			15.64

Natural gas (dollars per million British thermal units)	3.96			4.34			(0.38		)

Products:
U.S. Gulf Coast:
Conventional 87 gasoline less Brent	5.58			7.39			(1.81		)
Ultra-low-sulfur diesel less Brent	13.78			11.01			2.77
Propylene less Brent	8.23			7.79			0.44
Conventional 87 gasoline less LLS	5.04			5.30			(0.26		)
Ultra-low-sulfur diesel less LLS	13.24			8.93			4.31
Propylene less LLS	7.69			5.71			1.98
U.S. Mid-Continent:
Conventional 87 gasoline less WTI	22.37			8.20			14.17
Ultra-low-sulfur diesel less WTI	31.06			11.91			19.15
North Atlantic:
Conventional 87 gasoline less Brent	6.24			8.38			(2.14		)
Ultra-low-sulfur diesel less Brent	15.64			12.63			3.01
U.S. West Coast:
CARBOB 87 gasoline less ANS	11.48			14.21			(2.73		)
CARB diesel less ANS	18.47			13.79			4.68
CARBOB 87 gasoline less WTI	25.97			13.88			12.09
CARB diesel less WTI	32.96			13.45			19.51
New York Harbor corn crush (dollars per gallon)	0.25			0.39			(0.14		)

See note references on page 44.

Retail and Ethanol Operating Highlights

(millions of dollars, except per gallon amounts)



	Year Ended December 31,
	2011			2010			Change
Retail–U.S.:
Operating income	$	213		$	200		$	13
Company-operated fuel sites (average)	994			990			4
Fuel volumes (gallons per day per site)	5,060			5,086			(26		)
Fuel margin per gallon	$	0.144		$	0.140		$	0.004
Merchandise sales	$	1,223		$	1,205		$	18
Merchandise margin (percentage of sales)	28.7		%	28.3		%	0.4		%
Margin on miscellaneous sales	$	88		$	86		$	2
Operating expenses	$	416		$	412		$	4
Depreciation and amortization expense	$	77		$	73		$	4

Retail–Canada:
Operating income	$	168		$	146		$	22
Fuel volumes (thousand gallons per day)	3,195			3,168			27
Fuel margin per gallon	$	0.299		$	0.271		$	0.028
Merchandise sales	$	261		$	240		$	21
Merchandise margin (percentage of sales)	29.4		%	30.1		%	(0.7		)%
Margin on miscellaneous sales	$	43		$	38		$	5
Operating expenses	$	262		$	242		$	20
Depreciation and amortization expense	$	38		$	35		$	3

Ethanol (e):
Operating income	$	396		$	209		$	187
Ethanol production (thousand gallons per day)	3,352			3,021			331
Gross margin per gallon of production (f)	$	0.68		$	0.55		$	0.13
Operating costs per gallon of production:
Operating expenses	0.33			0.33			—
Depreciation and amortization expense	0.03			0.03			—
Total operating costs per gallon of production	0.36			0.36			—
Operating income per gallon of production	$	0.32		$	0.19		$	0.13

See note references on page 44.

The following notes relate to references on pages 39 through 43.


(a)	The financial highlights and operating highlights for the refining segment and U.S. Gulf Coast region reflect the results of operations of our Meraux Refinery, including related logistics assets, from the date of its acquisition on October 1, 2011 through December 31, 2011.


(b)	The financial highlights and operating highlights for the refining segment and North Atlantic region reflect the results of operations of our Pembroke Refinery, including the related market and logistics business, from the date of its acquisition on August 1, 2011 through December 31, 2011.

(c)

(d)

In 2010, we sold our Paulsboro Refinery and our shutdown Delaware City refinery assets and associated terminal and pipeline assets. The results of operations of these refineries have been presented as discontinued operations for the year ended December 31, 2010. In addition, the operating highlights for the refining segment and North Atlantic region exclude these refineries for the year ended December 31, 2010.


(e)	We acquired three ethanol plants in the first quarter of 2010. The information presented reflects the results of operations of these plants commencing on their respective acquisition dates. Ethanol production volumes are based on total production during each year divided by actual calendar days per year.


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


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

(h)

(i)

Average market reference prices for LLS crude oil, along with price differentials between the price of LLS crude oil and other types of crude oil, have been included in the table of Average Market Reference Prices and Differentials. The table also includes price differentials by region between the prices of certain products and the benchmark crude oil that provides the best indicator of product margins for each region. Prior to the first quarter of 2011, feedstock and product differentials were based on the price of WTI crude oil. However, the price of WTI crude oil no longer provides a reasonable benchmark price of crude oil for all regions. Beginning in late 2010, WTI crude oil began to price at a discount to benchmark sweet crude oils, such as LLS and Brent, because of increased WTI supplies resulting from greater U.S. production and increased deliveries of crude oil from Canada into the U.S. Mid-Continent region. Therefore, the use of the price of WTI crude oil as a benchmark price for regions that do not process WTI crude oil is no longer reasonable.

General

Operating revenues increased 53 percent (or $43.8 billion) for the year ended December 31, 2011 compared to the year ended December 31, 2010 primarily as a result of higher average refined product prices and higher throughput volumes between the two years related to our refining segment operations. The higher throughput volumes resulted primarily from the incremental throughput of 33,000 BPD1 ($1.3 billion of revenue) from the Meraux Refinery, which was acquired on October 1, 2011, incremental throughput of 109,000 BPD1 ($7.5 billion of revenue) from the Pembroke Refinery, which was acquired on August 1, 2011, and incremental throughput of 145,000 BPD ($4.9 billion of revenue) from the Aruba Refinery, which restarted operations in January 2011. Operating income increased $1.8 billion and income from continuing operations before taxes also increased $1.8 billion for the year ended December 31, 2011 compared to the amounts reported for the year ended December 31, 2010 primarily due to a $1.6 billion increase in refining segment operating income discussed below.

1Calculated based on throughput volumes of the Meraux Refinery and the Pembroke Refinery from the date of their respective acquisitions (October 1, 2011 and August 1, 2011), divided by the number of days during the year ended December 31, 2011.

Refining

Refining segment operating income nearly doubled from $1.9 billion for the year ended December 31, 2010 to $3.5 billion for the year ended December 31, 2011. The $1.6 billion improvement in operating income was due to a $2.2 billion increase in refining margin, partially offset by a $462 million increase in operating expenses.

The $2.2 billion increase in refining margin was primarily due to a 27 percent increase in throughput margin per barrel (a $2.11 per barrel increase between the years). This increase in refining margin was largely driven by an improvement in the U.S. Mid-Continent region, which experienced an increase in its throughput margin per barrel of $8.58. The U.S. Mid-Continent throughput margin per barrel of $15.91 for the year ended December 31, 2011 was more than double the throughput margin per barrel of $7.33 for the year ended December 31, 2010. This increase was due to the substantial discount in the price of WTI-type crude oil, the primary type of crude oil processed by our U.S. Mid-Continent refineries, versus the price of LLS and Brent crude oils. Historically, the price of WTI-type crude oil has closely approximated LLS and Brent crude oils, but due to the significant development of crude oil reserves within the U.S. Mid-Continent region and increased deliveries of crude oil from Canada into the U.S. Mid-Continent region, the increased supply of WTI-type crude oil resulted in WTI-type crude oil being priced at a significant discount to LLS and Brent crude oils during 2011. For example, the WTI-based benchmark reference margin for U.S. Mid-Continent conventional 87 gasoline was $22.37 per barrel for the year ended December 31, 2011 compared to $8.20 per barrel for the year ended December 31, 2010, representing a favorable increase of $14.17 per barrel. In addition, the WTI-based benchmark reference margin for U.S. Mid-Continent ultra-low sulfur diesel (a type of distillate) was $31.06 per barrel for the year ended December 31, 2011 compared to $11.91 per barrel for the year ended December 31, 2010, representing a favorable increase of $19.15 per barrel. We estimate that these increases in gasoline and distillate margins per barrel had a positive impact to our refining margin of approximately $1.1 billion and $1.0 billion, respectively, year over year.

The increase of $462 million in operating expenses discussed above was partially due to $42 million in operating expenses of the Meraux Refinery, which was acquired on October 1, 2011, and $141 million in operating expenses of the Pembroke Refinery, which was acquired on August 1, 2011. The remaining increase of $279 million was due to a $107 million increase in chemicals and catalyst costs due to higher prices of rare earth metals used in our fluid catalytic cracking units, an $86 million increase in employee-related expenses due to higher incentive compensation, and a $75 million increase in reliability expenses due to the re-start of the Aruba Refinery and higher routine maintenance during refinery downtime.

Retail

Retail operating income was $381 million for the year ended December 31, 2011 compared to $346 million for the year ended December 31, 2010. This 10 percent (or $35 million) increase was primarily due to increases in fuel margins of $43 million primarily from our Canadian operations, including a favorable impact from the strengthening of the Canadian dollar relative to the U.S. dollar, and an increase in merchandise margins of $15 million, offset by increased operating expenses of $24 million. The increase in operating expenses was primarily from our Canadian operations which were impacted by the strengthening of the Canadian dollar relative to the U.S. dollar. On average, Cdn$1 was equal to $1.01 during 2011 compared to $0.96 during 2010, representing an increase in value of five percent.

Ethanol

Ethanol segment operating income was $396 million for the year ended December 31, 2011 compared to $209 million for the year ended December 31, 2010. This increase of $187 million was primarily due to a $226 million increase in gross margin, partially offset by a $36 million increase in operating expenses.

Gross margin increased from the year ended December 31, 2010 to the year ended December 31, 2011 due to an increase in ethanol production (a 331,000 gallon per day increase between the years) primarily resulting from the full operation of three additional plants acquired in the first quarter of 2010 and higher utilization rates and increased yields during 2011 combined with a $0.13 per gallon increase in the ethanol gross margin.

The increase in operating expenses was primarily due to $27 million of additional expenses related to the three ethanol plants acquired in the first quarter of 2010. We operated these plants for all of 2011 compared to part of 2010.

Corporate Expenses and Other

General and administrative expenses increased $40 million for the year ended December 31, 2011 compared to the year ended December 31, 2010 due to a $25 million increase in variable compensation expense, $27 million in costs incurred in connection with the Pembroke Acquisition, and a favorable settlement with an insurance company for $40 million recorded in 2010, which reduced general and administrative expenses in 2010. These increases in general and administrative expenses were partially offset by favorable legal settlements of $47 million in 2011.

“Other income, net” for the year ended December 31, 2011 decreased $63 million from the year ended December 31, 2010 due to a pre-tax gain of $55 million related to the sale of our 50 percent interest in Cameron Highway Oil Pipeline Company (CHOPS) recognized in November 2010 and the $16 million effect of earnings on our interest in CHOPS recognized in 2010.

“Interest and debt expense, net of capitalized interest” for the year ended December 31, 2011 decreased $83 million from the year ended December 31, 2010. This decrease is primarily due to an increase of $62 million in capitalized interest related to an increase in capital expenditures between the years and the resumption of construction activity on previously suspended projects combined with a $19 million favorable impact from the decrease in average borrowings.

Income tax expense for the year ended December 31, 2011 increased $651 million from the year ended December 31, 2010 mainly as a result of higher operating income in 2011 and a one-time $20 million income tax benefit recognized in 2010 related to a tax settlement with the Government of Aruba (GOA).

The loss from discontinued operations of $7 million for the year ended December 31, 2011 is primarily due to adjustments to the working capital settlement related to the sale of our Paulsboro Refinery in December 2010. The loss from discontinued operations of $599 million for the year ended December 31, 2010 represents a $47 million after-tax loss from the discontinued operations of the Delaware City and Paulsboro Refineries and a $610 million after-tax loss on the sale of the Paulsboro Refinery, partially offset by a $58 million after-tax gain on the sale of the shutdown refinery assets at Delaware City.

LIQUIDITY AND CAPITAL RESOURCES

Cash Flows for the Year Ended December 31, 2012

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

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


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


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


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


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


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


•	purchase common stock for treasury of $281 million;


•	pay common stock dividends of $360 million; and


•	increase available cash on hand by $699 million.

Cash Flows for the Year Ended December 31, 2011

Net cash provided by operating activities for the year ended December 31, 2011 was $4.0 billion compared to $3.0 billion for the year ended December 31, 2010. The increase in cash generated from operating activities was primarily due to the $1.8 billion increase in operating income discussed above under “RESULTS OF OPERATIONS.” Changes in cash provided by or used for working capital during the years ended December 31, 2011 and 2010 are shown in Note 19 of Notes to Consolidated Financial Statements. Both receivables and accounts payable increased in 2011 due to significant increases in prices for gasoline, distillate, and crude oil at the end of 2011 compared to such prices at the end of 2010.

The net cash generated from operating activities during the year ended December 31, 2011 combined with $150 million of proceeds from the sale of receivables and $2.3 billion from available cash on hand was used mainly to:


•	fund $3.0 billion of capital expenditures and deferred turnaround and catalyst costs;


•	purchase the Pembroke Refinery and the related marketing and logistics business for $1.7 billion;


•	purchase the Meraux Refinery for $547 million;


•	redeem our Series 1997B 5.4% and Series 1997C 5.4% industrial revenue bonds for $56 million;


•	make scheduled long-term note repayments of $418 million;


•	acquire the GO Zone Revenue Bonds Series 2010 for $300 million;


•	purchase our common stock for $349 million; and


•	pay common stock dividends of $169 million.

Capital Investments

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 higher volumes of sour crude oil, which lowers our feedstock costs, and enables us to refine crude oil into products with higher market values. Therefore, many of our improvements do not increase throughput capacity significantly.

During the year ended December 31, 2012, we expended $2.9 billion for capital expenditures and $479 million for deferred turnaround and catalyst costs. Capital expenditures for the year ended December 31, 2012 included $135 million of costs related to environmental projects.

For 2013, we expect to incur approximately $1.9 billion for capital expenditures (approximately $100 million of which is for environmental projects) and approximately $600 million for deferred turnaround and catalyst costs. The capital expenditure estimate excludes expenditures related to future strategic acquisitions. We continuously evaluate our capital budget and make changes as conditions warrant.

Contractual Obligations

Our contractual obligations as of December 31, 2012 are summarized below (in millions).



	Payments Due by Period
	2013		2014		2015		2016		2017		Thereafter		Total
Debt and capital lease obligations (including interest on capital lease obligations)	$	592	$	210	$	484	$	8	$	957	$	4,859	$	7,110
Operating lease obligations	337		250		179		133		86		350		1,335
Purchase obligations	33,255		1,950		1,129		1,049		416		1,178		38,977
Other long-term liabilities	—		134		128		127		126		1,615		2,130
Total	$	34,184	$	2,544	$	1,920	$	1,317	$	1,585	$	8,002	$	49,552

Debt and Capital Lease Obligations

During 2012, the following debt activity occurred:


•	in March 2012, we exercised the call provisions on our Series 1997 5.6%, Series 1998 5.6%, Series 1999 5.7%, Series 2001 6.65%, and Series 1997A 5.45% industrial revenue bonds, which were redeemed on May 3, 2012 for $108 million, or 100 percent of their outstanding stated values;


•	in April 2012, we made scheduled debt repayments of $4 million related to our Series 1997A 5.45% industrial revenue bonds and $750 million related to our 6.875% notes;


•	in May 2012, we borrowed $1.1 billion under our revolving credit facility;


•	in June 2012, we repaid $1.1 billion under our revolving credit facility; and


•	also in June 2012, we received proceeds of $300 million from the remarketing of the 4.0% GO Zone Bonds, which are due December 1, 2040, but are subject to mandatory tender on June 1, 2022.

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 2012, we amended our agreement to increase the facility from $1.0 billion to $1.5 billion and extended the maturity date to July 2013. During the year ended December 31, 2012, we sold $1.5 billion of interests in eligible receivables to the third-party entities and financial institutions under this facility, and we repaid $1.7 billion under this facility. As of December 31, 2012, 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 to below investment grade ratings by S&P, Moody’s and Fitch, the cost of borrowings under some of our bank credit facilities and other arrangements would increase. As of December 31, 2012, all of our ratings on our senior unsecured debt are at or above investment grade level as follows:



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

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

Operating Lease Obligations

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

Purchase Obligations

A purchase obligation is an enforceable and legally binding agreement to purchase goods or services that specifies significant terms, including (i) fixed or minimum quantities to be purchased, (ii) fixed, minimum, or variable price provisions, and (iii) the approximate timing of the transaction. We have various purchase obligations including industrial gas and chemical supply arrangements (such as hydrogen supply arrangements), crude oil and other feedstock supply arrangements, and various throughput and terminalling agreements. We enter into these contracts to ensure an adequate supply of utilities and feedstock and adequate storage capacity to operate our refineries. Substantially all of our purchase obligations are based on market prices or adjustments based on market indices. Certain of these purchase obligations include fixed or minimum volume requirements, while others are based on our usage requirements. The purchase obligation amounts shown in the table above include both short- and long-term obligations and are based on (a) fixed

or minimum quantities to be purchased and (b) fixed or estimated prices to be paid based on current market conditions. As of December 31, 2012, our short- and long-term purchase obligations decreased by approximately $3 billion from the amount reported as of December 31, 2011. The decrease is primarily attributable to contracts expiring in 2013.

Other Long-term Liabilities

Our other long-term liabilities are described in Note 10 of Notes to Consolidated Financial Statements. For purposes of reflecting amounts for other long-term liabilities in the table above, we made our best estimate of expected payments for each type of liability based on information available as of December 31, 2012.

Other Commercial Commitments

As of December 31, 2012, our committed lines of credit were as follows (in millions):



	Borrowing Capacity		Expiration	Outstanding Letters of Credit
Letter of credit facilities	$	550	June 2013	$	418
U.S. revolving credit facility	$	3,000	December 2016	$	59
Canadian revolving credit facility	C$	50	November 2013	C$	10

As of December 31, 2012, we had no amounts borrowed under our revolving credit facilities. The letters of credit outstanding as of December 31, 2012 expire during 2013 and 2014.

Other Matters Impacting Liquidity and Capital Resources

Stock Purchase Programs

As of December 31, 2012, we have approvals under common stock purchase programs previously approved by our board of directors to purchase approximately $3.3 billion of our common stock.

Pension Plan Funding

We have $30 million of minimum required contributions to one of our international pension plans during 2013. In addition, we plan to contribute approximately $115 million to our other pension plans and $21 million to our other postretirement plans during 2013.

On February 15, 2013, we announced changes to certain of our pension plans that will reduce our benefit costs and obligations for 2013 and future years, as further discussed in Note 14 of Notes to Consolidated Financial Statements. These changes, however, will not impact our planned contributions during 2013, but we expect future contributions to decline.

Environmental Matters

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

Tax Matters

We are subject to extensive tax liabilities imposed by multiple jurisdictions, including income taxes, indirect taxes (excise/duty, sales/use, gross receipts, and value-added taxes), payroll taxes, franchise taxes, withholding taxes, and ad valorem taxes. New tax laws and regulations and changes in existing tax laws and regulations are continuously being enacted or proposed that could result in increased expenditures for tax liabilities in the future. Many of these liabilities are subject to periodic audits by the respective taxing authority. Subsequent changes to our tax liabilities as a result of these audits may subject us to interest and penalties. See Notes 12 and 16 of Notes to Consolidated Financial Statements for a further discussion of our tax matters.

As of December 31, 2012, the Internal Revenue Service (IRS) has ongoing tax audits related to our U.S. federal tax returns from 2002 through 2009, as discussed in Note 16 of Notes to Consolidated Financial Statements. We have received Revenue Agent Reports on our tax years for 2002 through 2007 and we are vigorously contesting many of the tax positions and assertions from the IRS. Although we believe our tax liabilities are fairly stated and properly reflected in our financial statements, should the IRS eventually prevail, it could result in a material amount of our deferred tax liabilities being reclassified to current liabilities which could have a material adverse effect on our 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 16 of Notes to Consolidated Financial Statements. We believe, however, that a substantial portion of our international cash can be returned to the U.S. without significant tax consequences through means other than a repatriation of earnings. As of December 31, 2012, $1.1 billion of our cash and temporary cash investments was held by our international subsidiaries.

Financial Regulatory Reform

In July 2010, President Obama signed into law the Dodd-Frank Wall Street Reform and Consumer Protection Act (Wall Street Reform Act). Key provisions of the Wall Street Reform Act create new statutory requirements that require most derivative instruments to be traded on exchanges and routed through clearinghouses, as well as impose new recordkeeping and reporting responsibilities on market participants. While certain final rules implementing the Wall Street Reform Act became effective in the fourth quarter of 2012, others will not become effective until 2013; therefore, the ultimate impact to our operations is yet unknown. However, the implementation could result in higher clearing costs and more reporting requirements with respect to our derivative activities.

Concentration of Customers

Our refining and marketing operations have a concentration of customers in the refining industry and customers who are refined product wholesalers and retailers. These concentrations of customers may impact our overall exposure to credit risk, either positively or negatively, in that these customers may be similarly affected by changes in economic or other conditions. However, we believe that our portfolio of accounts receivable is sufficiently diversified to the extent necessary to minimize potential credit risk. Historically, we have not had any significant problems collecting our accounts receivable.

Sources of Liquidity

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

NEW ACCOUNTING PRONOUNCEMENTS

As discussed in Note 1 of Notes to Consolidated Financial Statements, certain new financial accounting pronouncements have been issued that either have already been reflected in the accompanying financial statements, or will become effective for our financial statements at various dates in the future. The adoption of these pronouncements has not had, and is not expected to have, a material effect on our financial statements.

CRITICAL ACCOUNTING POLICIES INVOLVING CRITICAL ACCOUNTING ESTIMATES

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

Property, Plant and Equipment

The cost of property, plant and equipment (property assets) purchased or constructed, including betterments of property assets, are capitalized. However, the cost of repairs to and normal maintenance of property assets is expensed as incurred. Betterments of property assets are those which either extend the useful life, increase the capacity or improve the operating efficiency of the asset, or improve the safety of our operations. The cost of property assets constructed includes interest and certain overhead costs allocable to the construction activities.

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. Improvements consist of the addition of new Units and betterments of existing Units. We plan for these improvements by developing a multi-year capital program that is updated and revised based on changing internal and external factors.

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.

Also under the composite method of depreciation, the historical cost of a minor property asset (net of salvage value) that is retired or replaced is charged to accumulated depreciation and no gain or loss is recognized in income. However, a gain or loss is recognized in income for a major property asset that is retired, replaced or sold and for an abnormal disposition of a property asset (primarily involuntary conversions). Gains and losses are reflected in depreciation and amortization expense, unless such amounts are reported separately due to materiality.

Impairment of Assets

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

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

We evaluate our equity method investments for impairment when there is evidence that we may not be able to recover the carrying amount of our investments or the investee is unable to sustain an earnings capacity that justifies the carrying amount. A loss in the value of an investment that is other than a temporary decline is recognized currently in earnings, and is based on the difference between the estimated current fair value of the investment and its carrying amount.

Environmental Matters

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

Accruals for environmental liabilities are based on best estimates of probable undiscounted future costs over a 20-year time period using currently available technology and applying current regulations, as well as our

own internal environmental policies. However, environmental liabilities are difficult to assess and estimate due to uncertainties related to the magnitude of possible remediation, the timing of such remediation, and the determination of our obligation in proportion to other parties. Such estimates are subject to change due to many factors, including the identification of new sites requiring remediation, changes in environmental laws and regulations and their interpretation, additional information related to the extent and nature of remediation efforts, and potential improvements in remediation technologies. An estimate of the sensitivity to earnings for changes in those factors is not practicable due to the number of contingencies that must be assessed, the number of underlying assumptions, and the wide range of possible outcomes.

The amount of and changes in our accruals for environmental matters as of and for the years ended December 31, 2012, 2011, and 2010 is included in Note 10 of Notes to Consolidated Financial Statements.

Pension and Other Postretirement Benefit Obligations

We have significant pension and other postretirement benefit liabilities and costs that are developed from actuarial valuations. Inherent in these valuations are key assumptions including discount rates, expected return on plan assets, future compensation increases, and health care cost trend rates. Changes in these assumptions are primarily influenced by factors outside our control. For example, the discount rate assumption represents a yield curve comprised of various long-term bonds that have an average rating of double-A when averaging all available ratings by the recognized rating agencies, while the expected return on plan assets is based on a compounded return calculated assuming an asset allocation that is representative of the asset mix in our pension plans. 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, 2012 and net periodic benefit cost for the year ending December 31, 2013 (in millions):



	Pension Benefits		Other Postretirement Benefits
Increase in projected benefit obligation resulting from:
Discount rate decrease	$	109	$	12
Compensation rate increase	36		n/a
Health care cost trend rate increase	n/a		4

Increase in expense resulting from:
Discount rate decrease	17		—
Expected return on plan assets decrease	4		n/a
Compensation rate increase	9		n/a
Health care cost trend rate increase	n/a		—

See Note 14 of Notes to Consolidated Financial Statements for a further discussion of our pension and other postretirement benefit obligations. As discussed in Note 14, we announced changes to certain of our pension plans on February 15, 2013 that will reduce our benefit costs and obligations for 2013 and future years.

Tax Matters

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

Legal Matters

A variety of claims have been made against us in various lawsuits. We record a liability related to a loss contingency attributable to such legal matters if we determine that it is probable that a loss has been incurred and that the loss is reasonably estimable. The recording of such liabilities requires judgments and estimates, the results of which can vary significantly from actual litigation results due to differing interpretations of relevant law and differing opinions regarding the degree of potential liability and the assessment of reasonable damages. However, an estimate of the sensitivity to earnings if other assumptions were used in recording our legal liabilities is not practicable due to the number of contingencies that must be assessed and the wide range of reasonably possible outcomes, both in terms of the probability of loss and the estimates of such loss.

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