VLO 9.30.11 10Q
Table of Contents

 
 
 
 
 
 
 
 
 
 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
R
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2011
OR
o
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the transition period from _______________ to _______________
Commission file number 1-13175
VALERO ENERGY CORPORATION
(Exact name of registrant as specified in its charter)
Delaware
 
74-1828067
(State or other jurisdiction of
 
(I.R.S. Employer
incorporation or organization)
 
Identification No.)
One Valero Way
San Antonio, Texas
(Address of principal executive offices)
78249
(Zip Code)
(210) 345-2000
(Registrant’s telephone number, including area code) 
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes R No o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for shorter period that the registrant was required to submit and post such files). Yes R No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer R
Accelerated filer o
Non-accelerated filer o
Smaller reporting company o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes o No R
The number of shares of the registrant’s only class of common stock, $0.01 par value, outstanding as of October 31, 2011 was 559,726,988.
 
 
 
 
 

VALERO ENERGY CORPORATION AND SUBSIDIARIES
INDEX
 
 
 
Page
 
 
 
 
 
 
 
 
 
 
 
 
 





2

Table of Contents

PART I – FINANCIAL INFORMATION
Item 1. Financial Statements

VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Millions of Dollars, Except Par Value)
 
 
September 30,
2011
 
December 31,
2010
 
(Unaudited)
 
 
ASSETS
 
 
 
Current assets:
 
 
 
Cash and temporary cash investments
$
2,829

 
$
3,334

Receivables, net
7,509

 
4,583

Inventories
5,164

 
4,947

Income taxes receivable
5

 
343

Deferred income taxes
254

 
190

Prepaid expenses and other
109

 
121

Total current assets
15,870

 
13,518

Property, plant and equipment, at cost
31,066

 
28,921

Accumulated depreciation
(6,847
)
 
(6,252
)
Property, plant and equipment, net
24,219

 
22,669

Intangible assets, net
251

 
224

Deferred charges and other assets, net
1,343

 
1,210

Total assets
$
41,683

 
$
37,621

LIABILITIES AND EQUITY
 
 
 
Current liabilities:
 
 
 
Current portion of debt and capital lease obligations
$
867

 
$
822

Accounts payable
8,520

 
6,441

Accrued expenses
785

 
590

Taxes other than income taxes
1,053

 
671

Income taxes payable
136

 
3

Deferred income taxes
322

 
257

Total current liabilities
11,683

 
8,784

Debt and capital lease obligations, less current portion
6,781

 
7,515

Deferred income taxes
4,942

 
4,530

Other long-term liabilities
1,607

 
1,767

Commitments and contingencies

 

Equity:
 
 
 
Valero Energy Corporation stockholders’ equity:
 
 
 
Common stock, $0.01 par value; 1,200,000,000 shares authorized;
   673,501,593 and 673,501,593 shares issued
7

 
7

Additional paid-in capital
7,559

 
7,704

Treasury stock, at cost; 114,855,199 and 105,113,545 common shares
(6,491
)
 
(6,462
)
Retained earnings
15,347

 
13,388

Accumulated other comprehensive income
232

 
388

Total Valero Energy Corporation stockholders’ equity
16,654

 
15,025

Noncontrolling interests
16

 

Total equity
16,670

 
15,025

Total liabilities and equity
$
41,683

 
$
37,621

See Condensed Notes to Consolidated Financial Statements.



3

Table of Contents

VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(Millions of Dollars, Except Per Share Amounts)
(Unaudited)
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2011
 
2010
 
2011
 
2010
Operating revenues (a)
$
33,713

 
$
21,015

 
$
91,314

 
$
60,069

Costs and expenses:
 
 
 
 
 
 
 
Cost of sales
30,033

 
18,915

 
82,981

 
54,198

Operating expenses:
 
 
 
 
 
 
 
Refining
870

 
753

 
2,427

 
2,210

Retail
177

 
169

 
508

 
484

Ethanol
103

 
96

 
302

 
267

General and administrative expenses
161

 
139

 
442

 
367

Depreciation and amortization expense
390

 
353

 
1,141

 
1,043

Asset impairment loss

 

 

 
2

Total costs and expenses
31,734

 
20,425

 
87,801

 
58,571

Operating income
1,979

 
590

 
3,513

 
1,498

Other income, net
1

 
17

 
28

 
29

Interest and debt expense, net of capitalized interest
(88
)
 
(119
)
 
(312
)
 
(363
)
Income from continuing operations before income tax expense
1,892

 
488

 
3,229

 
1,164

Income tax expense
689

 
185

 
1,178

 
421

Income from continuing operations
1,203

 
303

 
2,051

 
743

Income (loss) from discontinued operations, net of income taxes

 
(11
)
 
(7
)
 
19

Net income
1,203

 
292

 
2,044

 
762

Less: Net loss attributable to noncontrolling interests

 

 
(1
)
 

Net income attributable to Valero Energy Corporation stockholders
$
1,203

 
$
292

 
$
2,045

 
$
762

Net income attributable to Valero Energy Corporation stockholders:
 
 
 
 
 
 
 
Continuing operations
$
1,203

 
$
303

 
$
2,052

 
$
743

Discontinued operations

 
(11
)
 
(7
)
 
19

Total
$
1,203

 
$
292

 
$
2,045

 
$
762

Earnings per common share:
 
 
 
 
 
 
 
Continuing operations
$
2.12

 
$
0.54

 
$
3.61

 
$
1.31

Discontinued operations

 
(0.02
)
 
(0.01
)
 
0.03

Total
$
2.12

 
$
0.52

 
$
3.60

 
$
1.34

Weighted-average common shares outstanding (in millions)
564

 
564

 
566

 
563

Earnings per common share – assuming dilution:
 
 
 
 
 
 
 
Continuing operations
$
2.11

 
$
0.53

 
$
3.59

 
$
1.31

Discontinued operations

 
(0.02
)
 
(0.01
)
 
0.03

Total
$
2.11

 
$
0.51

 
$
3.58

 
$
1.34

Weighted-average common shares outstanding –
  assuming dilution (in millions)
569

 
568

 
572

 
567

Dividends per common share
$
0.05

 
$
0.05

 
$
0.15

 
$
0.15

Supplemental information:
 
 
 
 
 
 
 
(a) Includes excise taxes on sales by our U.S. retail system
$
229

 
$
234

 
$
670

 
$
667

See Condensed Notes to Consolidated Financial Statements.



4

Table of Contents

VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Millions of Dollars)
(Unaudited)
 
Nine Months Ended
September 30,
 
2011
 
2010
Cash flows from operating activities:
 
 
 
Net income
$
2,044

 
$
762

Adjustments to reconcile net income to net cash provided by
  operating activities:
 
 
 
Depreciation and amortization expense
1,141

 
1,096

Noncash interest expense and other income, net
20

 
8

Asset impairment loss

 
2

Gain on sale of Delaware City Refinery assets

 
(92
)
Stock-based compensation expense
34

 
32

Deferred income tax expense
393

 
285

Changes in current assets and current liabilities
840

 
592

Changes in deferred charges and credits and other operating activities, net
(144
)
 
(63
)
Net cash provided by operating activities
4,328

 
2,622

Cash flows from investing activities:
 
 
 
Capital expenditures
(1,584
)
 
(1,226
)
Deferred turnaround and catalyst costs
(501
)
 
(410
)
Acquisition of Pembroke Refinery, net of cash acquired
(1,675
)
 

Acquisition of pipeline and terminal facilities
(37
)
 

Acquisitions of ethanol plants

 
(260
)
Proceeds from sale of the Delaware City Refinery assets and
  associated terminal and pipeline assets

 
220

Other investing activities, net
(24
)
 
15

Net cash used in investing activities
(3,821
)
 
(1,661
)
Cash flows from financing activities:
 
 
 
Non-bank debt:
 
 
 
Borrowings

 
1,244

Repayments
(718
)
 
(517
)
Accounts receivable sales program:
 
 
 
Proceeds from the sale of receivables

 
1,225

Repayments

 
(1,325
)
Purchase of common stock for treasury
(270
)
 
(2
)
Issuance of common stock in connection with stock-based compensation plans
42

 
12

Common stock dividends
(85
)
 
(85
)
Debt issuance costs

 
(10
)
Contributions from noncontrolling interests
12

 

Other financing activities, net
17

 
5

Net cash provided by (used in) financing activities
(1,002
)
 
547

Effect of foreign exchange rate changes on cash
(10
)
 
19

Net increase (decrease) in cash and temporary cash investments
(505
)
 
1,527

Cash and temporary cash investments at beginning of period
3,334

 
825

Cash and temporary cash investments at end of period
$
2,829

 
$
2,352

 
See Condensed Notes to Consolidated Financial Statements.



5

Table of Contents

VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Millions of Dollars)
(Unaudited)

 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2011
 
2010
 
2011
 
2010
Net income
$
1,203

 
$
292

 
$
2,044

 
$
762

Other comprehensive income (loss):
 
 
 
 
 
 
 
Foreign currency translation adjustment
(278
)
 
100

 
(166
)
 
63

Pension and other postretirement benefits:
 
 
 
 
 
 
 
Net loss arising during the period,
  net of income tax benefit of $-, $-, $-, and $-

 

 

 
(21
)
Net gain reclassified into income,
  net of income tax expense of $1, $2, $2, and $2
(1
)
 
(2
)
 
(3
)
 
(4
)
Net loss on pension and other
  postretirement benefits
(1
)
 
(2
)
 
(3
)
 
(25
)
 
 
 
 
 
 
 
 
Derivative instruments designated and
  qualifying as cash flow hedges:
 
 
 
 
 
 
 
Net gain (loss) arising during the period,
  net of income tax (expense) benefit of
  $(7), $-, $(7), and $1
13

 

 
13

 
(1
)
Net gain reclassified into income,
  net of income tax expense of $-, $13, $-, and $47

 
(24
)
 

 
(88
)
Net gain (loss) on cash flow hedges
13

 
(24
)
 
13

 
(89
)
Other comprehensive income (loss)
(266
)
 
74

 
(156
)
 
(51
)
Comprehensive income
937

 
366

 
1,888

 
711

Less: Comprehensive loss attributable to
  noncontrolling interests

 

 
(1
)
 

Comprehensive income attributable to
  Valero Energy Corporation stockholders
$
937

 
$
366

 
$
1,889

 
$
711

See Condensed Notes to Consolidated Financial Statements.



6

Table of Contents



VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


1.
BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Basis of Presentation
General
As used in this report, the terms “Valero,” “we,” “us,” or “our” may refer to Valero Energy Corporation, one or more of its consolidated subsidiaries, or all of them taken as a whole.
These unaudited consolidated financial statements have been prepared in accordance with United States generally accepted accounting principles (GAAP) for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the Securities Exchange Act of 1934. Accordingly, they do not include all of the information and notes required by GAAP for complete consolidated financial statements. In the opinion of management, all adjustments considered necessary for a fair presentation have been included. All such adjustments are of a normal recurring nature unless disclosed otherwise. Financial information for the three and nine months ended September 30, 2011 and 2010 included in these Condensed Notes to Consolidated Financial Statements is derived from our unaudited consolidated financial statements. Operating results for the three and nine months ended September 30, 2011 are not necessarily indicative of the results that may be expected for the year ending December 31, 2011.

The consolidated balance sheet as of December 31, 2010 has been derived from our audited financial statements as of that date. For further information, refer to our consolidated financial statements and notes thereto included in our annual report on Form 10-K for the year ended December 31, 2010.
We have evaluated subsequent events that occurred after September 30, 2011 through the filing of this Form 10-Q. Any material subsequent events that occurred during this time have been properly recognized or disclosed in these financial statements.

Noncontrolling Interests
In connection with the acquisition of the Pembroke Refinery (see further discussion in Note 2), we acquired an 85 percent interest in Mainline Pipelines Limited (MLP). MLP owns a pipeline that distributes refined products from the Pembroke Refinery to terminals in the United Kingdom.

On January 21, 2011, we entered into a joint venture agreement with Darling Green Energy LLC, a subsidiary of Darling International, Inc., to form Diamond Green Diesel Holdings LLC (DGD Holdings). DGD Holdings, through its wholly owned subsidiary, Diamond Green Diesel LLC (DGD), will construct and operate a biomass-based diesel plant having a design feed capacity of 10,000 barrels per day that will process animal fats, used cooking oils, and other vegetable oils into renewable green diesel. The plant will be located next to our St. Charles Refinery. The aggregate cost of this facility is estimated to be approximately $368 million and the construction is expected to be completed in late 2012. The joint venture agreement requires that contributions be made to DGD Holdings based on the percentage of units held by each member, which is currently on a 50/50 basis. In addition, on May 31, 2011, we agreed to lend DGD up to $221 million in order to finance 60 percent of the construction costs of the plant.

Because of our controlling financial interests in MLP and DGD Holdings, we have included the financial statements of MLP and DGD Holdings in these consolidated financial statements and have separately disclosed the related noncontrolling interests.



7

Table of Contents



VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Significant Accounting Policies
Reclassifications
As discussed in Note 2, we sold our Paulsboro Refinery in December 2010. As a result, the results of operations of the Paulsboro Refinery have been reclassified to discontinued operations for the three and nine months ended September 30, 2010.

In addition, credit card fees previously recognized in 2010 in retail operating expenses have been reclassified to cost of sales as such fees are directly and jointly related to the sale transaction. This reclassification resulted in an increase in cost of sales and a decrease in retail operating expenses of $23 million and $68 million for the three and nine months ended September 30, 2010, respectively.

Use of Estimates
The preparation of financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates. On an ongoing basis, we review our estimates based on currently available information. Changes in facts and circumstances may result in revised estimates.

New Accounting Pronouncements
In June 2011, the provisions of Accounting Standards Codification (ASC) Topic 220, “Comprehensive Income,” were amended to allow an entity the option to present the total of comprehensive income, the components of net income, and the components of other comprehensive income either in a single continuous statement or in two separate but consecutive statements. In both choices, the entity is required to present reclassification adjustments on the face of the financial statements for items that are reclassified from other comprehensive income to net income in the statement where those components are presented. These provisions are effective for the first interim or annual period beginning after December 15, 2011, and are to be applied retrospectively, with early adoption permitted. The adoption of this guidance effective January 1, 2012 will not affect our financial position or results of operations because these requirements only affect disclosures.

In May 2011, the provisions of ASC Topic 820, “Fair Value Measurement,” were amended to clarify the application of existing fair value measurement requirements and to change certain fair value measurement and disclosure requirements. Amendments that change measurement and disclosure requirements relate to (i) fair value measurement of financial instruments that are managed within a portfolio, (ii) application of premiums and discounts in a fair value measurement, and (iii) additional disclosures about fair value measurements categorized within Level 3 of the fair value hierarchy. These provisions are effective for the first interim or annual period beginning after December 15, 2011. The adoption of this guidance effective January 1, 2012 will not affect our financial position or results of operations, but may result in additional disclosures.

In January 2011, the provisions of ASC Topic 310, “Receivables,” were amended to delay temporarily the effective date of disclosures relating to troubled debt restructurings, which were previously amended in July 2010, in order to allow the Financial Accounting Standards Board time to complete its deliberations on what constitutes a troubled debt restructuring. In April 2011, the provisions of ASC Topic 310 were amended to clarify the guidance on a creditor’s evaluations of whether it has granted a concession to the debtor and whether the debtor is experiencing financial difficulties. These provisions are effective for the first interim



8

Table of Contents



VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

or annual period beginning on or after June 15, 2011. The new guidance should be applied retrospectively to restructurings occurring on or after the beginning of the annual period of adoption, with early adoption permitted. The adoption of this guidance effective July 1, 2011 did not affect our financial position or results of operations.

2.
ACQUISITIONS AND DISPOSITIONS

Meraux Acquisition
On October 1, 2011, we acquired the Meraux Refinery and related logistics assets for an initial payment of $586 million, including inventories of $261 million, from Murphy Oil Corporation, with the total purchase price funded from available cash. We expect to receive a favorable adjustment related to inventories in the fourth quarter of 2011 that will reduce the purchase price by approximately $40 million. The Meraux Refinery has a total throughput capacity of 135,000 barrels per day and is located in Meraux, Louisiana. This acquisition is referred to as the Meraux Acquisition.

The Meraux Acquisition is consistent with our general business strategy and complements our existing refining and marketing network.

A determination of the acquisition-date fair values of the assets acquired and the liabilities assumed in the Meraux Acquisition is pending the completion of an independent appraisal and other evaluations. Disclosure of pro forma information for the Meraux Acquisition for the three and nine months ended September 30, 2011 and 2010 is impracticable as historical financial information is not readily available at this time.

Pembroke Acquisition
On August 1, 2011, we acquired 100 percent of the outstanding shares of Chevron Limited from a subsidiary of Chevron Corporation (Chevron), and we subsequently changed the name of Chevron Limited to Valero Energy Ltd. Valero Energy Ltd owns and operates the Pembroke Refinery, which has a total throughput capacity of approximately 270,000 barrels per day and is located in Wales, United Kingdom. Valero Energy Ltd also owns, directly and through various subsidiaries, an extensive network of marketing and logistics assets throughout the United Kingdom and Ireland. On the acquisition date, we initially paid $1.8 billion from available cash, of which $1.1 billion was for working capital. Subsequent to the acquisition date, the amounts paid have been favorably adjusted for working capital true-up adjustments (primarily inventory), with an adjusted purchase price of $1.675 billion, as outlined below. We expect final settlement by year end. This acquisition is referred to as the Pembroke Acquisition.

The Pembroke Acquisition is consistent with our general business strategy and broadens the geographic diversity of our refining and marketing network.




9

Table of Contents



VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The purchase price for the Pembroke Acquisition has been preliminarily allocated based on estimated fair values of the assets acquired and liabilities assumed at the acquisition date, pending the completion of an independent appraisal and other evaluations. The preliminary purchase price allocation as of September 30, 2011 was as follows (in millions):

Current assets, net of cash acquired
$
2,217

Property, plant and equipment
777

Deferred charges and other assets
17

Intangible assets
50

Current liabilities, less current portion of debt
and capital lease obligations
(1,294
)
Debt and capital leases assumed, including current portion
(12
)
Other long-term liabilities
(77
)
Noncontrolling interest
(3
)
Purchase price, net of cash acquired
$
1,675


The acquired intangible assets are subject to amortization and have preliminary estimated useful lives of 15 years. These acquired intangible assets have been preliminarily assigned to the major intangible asset classes of royalties and licenses and wholesale dealer agreements.

During the three and nine months ended September 30, 2011, we recognized $18 million and $23 million, respectively, of costs related to the Pembroke Acquisition. These costs were expensed and are included in general and administrative expenses.

Our consolidated statements of income include the results of operations of the Pembroke Acquisition commencing on August 1, 2011. The operating revenues and income from continuing operations associated with the Pembroke Acquisition included in our consolidated statements of income for the three and nine months ended September 30, 2011, were as follows (in millions):

 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2011
 
2010
 
2011
 
2010
Operating revenues
$
3,028

 
N/A
 
$
3,028

 
N/A
Income from continuing operations
19

 
N/A
 
19

 
N/A




10

Table of Contents



VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The following pro forma financial information (in millions, except per share amounts) presents our consolidated results assuming the Pembroke Acquisition occurred on January 1, 2010. The pro forma financial information is not necessarily indicative of the results of future operations.

 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2011
 
2010
 
2011
 
2010
Operating revenues
$
35,491

 
$
24,594

 
$
103,030

 
$
70,638

Income from continuing operations
  attributable to Valero stockholders
1,196

 
306

 
1,941

 
767

Earnings per common share from
  continuing operations – basic
2.11

 
0.54

 
3.41

 
1.36

Earnings per common share from
  continuing operations – assuming dilution
2.10

 
0.54

 
3.39

 
1.35


Acquisition of Pipeline and Terminal Facilities
In June 2011, we acquired two product terminal facilities in Louisville and Lexington, Kentucky and a minority interest in the LouLex Pipeline system, which connects the terminal facilities, from a subsidiary of Chevron for cash consideration of $37 million. These assets provide storage and distribution facilities for our wholesale marketing business in eastern Kentucky, which is supplied primarily by our Memphis Refinery.

Because this acquisition was not material to our results of operations, we have not presented actual results of operations for this acquisition from the acquisition date through September 30, 2011 or pro forma results of operations for the three and nine months ended September 30, 2011 and 2010. The consolidated statements of income for the three and nine months ended September 30, 2011 include the results of this acquisition from its acquisition date.

Acquisitions of Ethanol Plants
In December 2009, we signed an agreement with ASA Ethanol Holdings, LLC to buy two ethanol plants located in Linden, Indiana and Bloomingburg, Ohio and made a $20 million advance payment towards the acquisition of these plants. In January 2010, we completed the acquisition of these plants, including certain inventories, for total consideration of $202 million.

Also in December 2009, we received approval from a bankruptcy court to acquire an ethanol plant located near Jefferson, Wisconsin from Renew Energy LLC and made a $1 million advance payment towards the acquisition of this plant. We completed the acquisition of this plant, including certain receivables and inventories, in February 2010 for total consideration of $79 million.




11

Table of Contents



VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Disposition of Paulsboro Refinery
In December 2010, we sold our Paulsboro Refinery to PBF Holding Company LLC (PBF Holding) for total proceeds of $707 million, including $361 million from the sale of working capital, resulting in a pre-tax loss of $980 million ($610 million after taxes). The sale proceeds consisted of $547 million of cash and a $160 million note secured by the Paulsboro Refinery. The note matures in December 2011 and bears interest at LIBOR plus 700 basis points. PBF Holding has the option to extend the note for six months; however, the interest rate for the additional six months will be LIBOR plus 900 basis points.

The results of operations of the Paulsboro Refinery are reflected in discontinued operations, and selected results prior to its sale are shown below (in millions).

 
 
Three Months Ended
September 30, 2010
 
Nine Months Ended
September 30, 2010
Operating revenues
 
$
1,195

 
$
3,559

Loss before income taxes
 
(18
)
 
(36
)

Disposition of Delaware City Refinery Assets and Associated Terminal and Pipeline Assets
In June 2010, we sold our shutdown Delaware City Refinery assets and associated terminal and pipeline assets to wholly owned subsidiaries of PBF Energy Partners LP (PBF) for $220 million of cash proceeds. The sale resulted in a gain of $92 million ($58 million after taxes) related to the shutdown refinery assets and a gain of $3 million related to the terminal and pipeline assets. The gain on the sale of the shutdown refinery assets resulted from the proceeds we received for the scrap value of the assets and the reversal of certain liabilities recorded in the fourth quarter of 2009 associated with the shutdown of the refinery, which we did not incur because of the sale, and this gain is presented in discontinued operations for the nine months ended September 30, 2010.

Results of operations of the Delaware City Refinery are reflected in discontinued operations, and selected results prior to its sale, excluding the gain on the sale, are shown below (in millions):

 
Three Months Ended
September 30, 2010
 
Nine Months Ended
September 30, 2010
Operating revenues
$

 
$

Loss before income taxes

 
(33
)




12

Table of Contents



VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

3.
IMPAIRMENT ANALYSIS

In late 2008, the U.S. and worldwide economies experienced severe disruptions in their capital and commodities markets resulting in a significant slowdown that persisted throughout 2009. This slowdown negatively impacted refining industry fundamentals and the demand and price for our refined products. Because of this negative impact, we decided to shut down our Aruba Refinery temporarily in July 2009, and it remained shut until January 2011. We restarted our Aruba Refinery due to improvements in the U.S. and worldwide economies and the resulting improvement in refining industry fundamentals; however, we analyzed our Aruba Refinery for potential impairment as of September 30, 2011 because of its recent temporary shutdown, its negative operating cash flows subsequent to its restart, the sensitivity of its profitability to sour crude oil differentials, and our decision in July 2011 to renew our exploration of strategic alternatives for the refinery, which may include the sale of the refinery. We considered these matters in our impairment analysis and concluded that our Aruba Refinery was not impaired as of September 30, 2011. Our future cash flow estimates for the refinery are based on our expectation that refining industry fundamentals will continue to improve in connection with an increase in the demand for refined products. Should refining industry fundamentals fail to continue to improve or should we decide to sell the refinery, our future cash flow estimates may be negatively impacted and we could ultimately determine that the refinery is impaired. The Aruba Refinery had a net book value of $950 million as of September 30, 2011; therefore, an impairment loss could be material to our results of operations.

4.
INVENTORIES

Inventories consisted of the following (in millions):

 
September 30,
2011
 
December 31,
2010
Refinery feedstocks
$
2,502

 
$
2,225

Refined products and blendstocks
2,217

 
2,233

Ethanol feedstocks and products
130

 
201

Convenience store merchandise
102

 
101

Materials and supplies
213

 
187

Inventories
$
5,164

 
$
4,947


As of September 30, 2011 and December 31, 2010, the replacement cost (market value) of LIFO inventories exceeded their LIFO carrying amounts by approximately $7.1 billion and $6.1 billion, respectively.




13

Table of Contents



VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

5.
DEBT
Non-Bank Debt
During the nine months ended September 30, 2011, the following activity occurred related to our non-bank debt:
in May 2011, we made a scheduled debt repayment of $200 million related to our 6.125% senior notes;
in April 2011, we made scheduled debt repayments of $8 million related to our Series A 5.45%, Series B 5.40%, and Series C 5.40% industrial revenue bonds;
in February 2011, we made a scheduled debt repayment of $210 million related to our 6.75% senior notes; and
in February 2011, we paid $300 million to acquire the Gulf Opportunity Zone Revenue Bonds Series 2010 (GO Zone Bonds), which were subject to mandatory tender. We expect to hold the GO Zone Bonds for our own account until conditions permit the remarketing of these bonds at an interest rate acceptable to us.

During the nine months ended September 30, 2010, the following activity occurred related to our non-bank debt:
in June 2010, we made a scheduled debt repayment of $25 million related to our 7.25% debentures;
in May 2010, we redeemed our 6.75% senior notes with a maturity date of May 1, 2014 for $190 million, or 102.25% of stated value;
in April 2010, we made scheduled debt repayments of $8 million related to our Series A 5.45%, Series B 5.40%, and Series C 5.40% industrial revenue bonds;
in March 2010, we redeemed our 7.50% senior notes with a maturity date of June 15, 2015 for $294 million, or 102.5% of stated value; and
in February 2010, we issued $400 million of 4.50% notes due in February 2015 and $850 million of 6.125% notes due in February 2020 for total net proceeds of $1.2 billion.

Bank Debt and Credit Facilities
We have a $2.4 billion revolving credit facility (the Revolver) that has a maturity date of November 2012. The Revolver has certain restrictive covenants, including a maximum debt-to-capitalization ratio of 60 percent. As of September 30, 2011 and December 31, 2010, our debt-to-capitalization ratio, calculated in accordance with the terms of the Revolver, was 22 percent and 25 percent, respectively. We believe that we will remain in compliance with this covenant.

In addition to the Revolver, one of our Canadian subsidiaries has a committed revolving credit facility under which it may borrow and obtain letters of credit up to C$115 million.

During the nine months ended September 30, 2011 and 2010, we had no borrowings or repayments under our Revolver or the Canadian revolving credit facility. As of September 30, 2011 and December 31, 2010, we had no borrowings outstanding under the Revolver or the Canadian revolving credit facility.




14

Table of Contents



VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

We had outstanding letters of credit under our committed lines of credit as follows (in millions):
 
 
 
 
 
 
Amounts Outstanding
 
 
Borrowing Capacity
 
Expiration
 
September 30, 2011
 
December 31, 2010
 Letter of credit facility
 
$200
 
June 2012
 
$—
 
$—
 Letter of credit facility
 
$300
 
June 2012
 
$300
 
$100
 Revolver
 
$2,400
 
November 2012
 
$74
 
$399
 Canadian revolving credit facility
 
C$115
 
December 2012
 
C$20
 
C$20

As of September 30, 2011 and December 31, 2010, we had $346 million and $176 million, respectively, of letters of credit outstanding under our uncommitted short-term bank credit facilities.

In connection with the Pembroke Acquisition, we assumed a €2.8 million short-term demand loan, which bears interest at EURIBOR plus a margin. We expect to repay the loan on or before February 2012.

Accounts Receivable Sales Facility
We have an accounts receivable sales facility with a group of third-party entities and financial institutions to sell on a revolving basis up to $1 billion of eligible trade receivables. We amended our agreement in June 2011 to extend the maturity date to June 2012. As of September 30, 2011 and December 31, 2010, the amount of eligible receivables sold was $100 million. There were no sales or repayments of eligible receivables during the nine months ended September 30, 2011. During the nine months ended September 30, 2010, we sold $1.2 billion of eligible receivables and repaid $1.3 billion to the third-party entities and financial institutions. Proceeds from the sale of receivables under this facility are reflected as debt.

Capitalized Interest
Capitalized interest was $41 million and $25 million for the three months ended September 30, 2011 and 2010, respectively, and $101 million and $67 million for the nine months ended September 30, 2011 and 2010, respectively.




15

Table of Contents



VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

6.
COMMITMENTS AND CONTINGENCIES

Environmental Matters
The U.S. Environmental Protection Agency (EPA) began regulating greenhouse gases on January 2, 2011, under the Clean Air Act Amendments of 1990 (Clean Air Act). According to statements by the EPA, any new construction or material expansions will require that, among other things, a greenhouse gas permit be issued at either or both the state or federal level in accordance with the Clean Air Act and regulations, and we will be required to undertake a technology review to determine appropriate controls to be implemented with the project in order to reduce greenhouse gas emissions. The determination will be on a case by case basis, and the EPA has provided only general guidance on which controls will be required. Any such controls, however, could result in material increased compliance costs, additional operating restrictions for our business, and an increase in the cost of the products we produce, which could have a material adverse effect on our financial position, results of operations, and liquidity.

In addition, certain states and foreign governments have pursued independent regulation of greenhouse gases. For example, the California Global Warming Solutions Act, also known as AB 32, directs the California Air Resources Board (CARB) to develop and issue regulations to reduce greenhouse gas emissions in California to 1990 levels by 2020. The CARB has issued a variety of regulations aimed at reaching this goal, including a Low Carbon Fuel Standard (LCFS) as well as a statewide cap-and-trade program. The LCFS is effective in 2011, with small reductions in the carbon intensity of transportation fuels sold in California. The mandated reductions in carbon intensity are scheduled to increase through 2020, after which another step-change in reductions is anticipated. The LCFS is designed to encourage substitution of traditional petroleum fuels, and, over time, it is anticipated that the LCFS will lead to a greater use of electric cars and alternative fuels, such as E85, as companies seek to generate more credits to offset petroleum fuels. The statewide cap-and-trade program will begin in 2013. Initially, the program will apply only to stationary sources of greenhouse gases (e.g., refinery and power plant greenhouse gas emissions). Greenhouse gas emissions from fuels that we sell in California will be covered by the program beginning in 2015. We anticipate that free allocations of credits will be available in the early years of the program, but we expect that compliance costs will increase significantly beginning in 2015, when fuels are included in the program. Complying with AB 32, including the LCFS and the cap-and-trade program, could result in material increased compliance costs for us, increased capital expenditures, increased operating costs, and additional operating restrictions for our business, resulting in an increase in the cost of, and decreases in the demand for, the products we produce. To the degree we are unable to recover these increased costs, these matters could have a material adverse effect on our financial position, results of operations, and liquidity.

On June 30, 2010, the EPA formally disapproved the flexible permits program submitted by the Texas Commission on Environmental Quality (TCEQ) in 1994 for inclusion in its clean-air implementation plan.  The EPA determined that Texas’ flexible permit program did not meet several requirements under the federal Clean Air Act.  Our Port Arthur, Texas City, Three Rivers, McKee, and Corpus Christi East and West Refineries formerly operated under flexible permits administered by the TCEQ.  In the fourth quarter of 2010, we completed the conversion of our flexible permits into federally enforceable conventional state NSR permits (“de-flexed permits”). We are now in the process of incorporating these de-flexed permits into our Title V permits. Continued discussions with the TCEQ and the EPA regarding this matter are likely.




16

Table of Contents



VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Meanwhile, the EPA has formally disapproved other TCEQ permitting programs that historically have streamlined the environmental permitting process in Texas. For example, the EPA has disapproved the TCEQ pollution control standard permit, thus requiring conventional permitting for future pollution control equipment. Litigation is pending from industry groups and others against the EPA for each of these actions. The EPA has also objected to numerous Title V permits in Texas and other states, including permits at our Port Arthur, Corpus Christi East, and McKee Refineries. Environmental activist groups have filed a notice of intent to sue the EPA, seeking to require the EPA to assume control of these permits from the TCEQ. All of these developments have created substantial uncertainty regarding existing and future permitting. Because of this uncertainty, we are unable to determine the costs or effects of the EPA’s actions on our permitting activity. But the EPA’s disruption of the Texas permitting system could result in material increased compliance costs for us, increased capital expenditures, increased operating costs, and additional operating restrictions for our business, resulting in an increase in the cost of, and decreases in the demand for, the products we produce, which could have a material adverse effect on our financial position, results of operations, and liquidity.

Tax Matters
We are subject to extensive tax liabilities, including federal, state, and foreign income taxes and transactional taxes such as excise, sales/use, payroll, franchise, withholding, 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.

Litigation Matters
We are party to claims and legal proceedings arising in the ordinary course of business. We have not recorded a loss contingency liability with respect to some of these matters because we have determined that it is remote that a loss has been incurred.  For other matters, we have recorded a loss contingency liability where we have determined that it is probable that a loss has been incurred and that the loss is reasonably estimable.  These loss contingency liabilities are not material to our financial position. We re-evaluate and update our loss contingency liabilities as matters progress over time, and we believe that any changes to the recorded liabilities will not be material to our financial position or results of operations.




17

Table of Contents



VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

7.
EQUITY

The following is a reconciliation of the beginning and ending balances (in millions) of equity attributable to our stockholders, equity attributable to noncontrolling interests, and total equity for the nine months ended September 30, 2011 and 2010:
 
 
2011
 
2010
 
 
Valero
Stockholders
Equity
 
Non-
controlling
Interests
 
Total
Equity
 
Valero
Stockholders
Equity
 
Non-
controlling
Interests
 
Total
Equity
Balance at beginning of period
 
$
15,025

 
$

 
$
15,025

 
$
14,725

 
$

 
$
14,725

Net income (loss)
 
2,045

 
(1
)
 
2,044

 
762

 

 
762

Dividends
 
(85
)
 

 
(85
)
 
(85
)
 

 
(85
)
Stock-based compensation expense
 
34

 

 
34

 
32

 

 
32

Tax deduction in excess of stock-based compensation expense
 
19

 

 
19

 
7

 

 
7

Transactions in connection with stock-based compensation plans:
 
 
 
 
 
 
 
 
 
 
 
 
Stock issuances
 
42

 

 
42

 
12

 

 
12

Stock repurchases
 
(270
)
 

 
(270
)
 
(2
)
 

 
(2
)
Contributions from noncontrolling interest
 

 
14

 
14

 

 

 

Recognition of noncontrolling interest in connection with Pembroke Acquisition
 

 
3

 
3

 

 

 

Other comprehensive income (loss)
 
(156
)
 

 
(156
)
 
(51
)
 

 
(51
)
Balance at end of period
 
$
16,654

 
$
16

 
$
16,670

 
$
15,400

 
$

 
$
15,400


The noncontrolling interests relate to the ownership interests in MLP and DGD Holdings that are owned by parties unrelated to us, as discussed in Note 1.




18

Table of Contents



VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Treasury Stock
During the nine months ended September 30, 2011 and 2010, we purchased 13.6 million shares and 1.6 million shares, respectively, of our common stock in connection with the administration of our stock-based compensation plans. During the nine months ended September 30, 2011 and 2010, we issued 3.9 million and 1.6 million shares from treasury, respectively, for our stock-based compensation plans.

Common Stock Dividends
On October 27, 2011, our board of directors declared a regular quarterly cash dividend of $0.15 per common share payable on December 14, 2011 to holders of record at the close of business on November 16, 2011.

8.
EMPLOYEE BENEFIT PLANS

The components of net periodic benefit cost related to our defined benefit plans were as follows for the three and nine months ended September 30, 2011 and 2010 (in millions):

 
Pension Plans
 
Other Postretirement
Benefit Plans
 
2011
 
2010
 
2011
 
2010
Three months ended September 30:
 
 
 
 
 
 
 
Service cost
$
28

 
$
22

 
$
4

 
$
3

Interest cost
21

 
21

 
5

 
6

Expected return on plan assets
(28
)
 
(28
)
 

 

Amortization of:

 
 
 
 
 
 
Prior service cost (credit)
1

 
1

 
(6
)
 
(5
)
Net loss
3

 

 

 
1

Net periodic benefit cost
$
25

 
$
16

 
$
3

 
$
5

 
 
 
 
 
 
 
 
Nine months ended September 30:
 
 
 
 
 
 
 
Service cost
$
73

 
$
65

 
$
9

 
$
8

Interest cost
64

 
62

 
16

 
19

Expected return on plan assets
(84
)
 
(84
)
 

 

Amortization of:
 
 
 
 
 
 
 
Prior service cost (credit)
2

 
2

 
(17
)
 
(15
)
Net loss
9

 
1

 
1

 
3

Net periodic benefit cost
$
64

 
$
46

 
$
9

 
$
15


During the nine months ended September 30, 2011 and 2010, we contributed $207 million and $54 million, respectively, to our pension plans.




19

Table of Contents



VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

9.
EARNINGS PER COMMON SHARE

Earnings per common share from continuing operations were computed as follows (dollars and shares in millions, except per share amounts):

 
Three Months Ended September 30,
 
2011
 
2010
 
Restricted 
Stock
 
Common
Stock 
 
Restricted
Stock 
 
 Common
Stock
Earnings per common share from
  continuing operations:
 
 
 
 
 
 
 
Net income attributable to Valero stockholders
  from continuing operations
 
 
$
1,203

 
 
 
$
303

Less dividends paid:
 
 
 
 
 
 
 
Common stock
 
 
28

 
 
 
28

Nonvested restricted stock
 
 

 
 
 

Undistributed earnings
 
 
$
1,175

 
 
 
$
275

 
 
 
 
 
 
 
 
Weighted-average common shares outstanding
3

 
564

 
3

 
564

 
 
 
 
 
 
 
 
Earnings per common share from
  continuing operations:
 
 
 
 
 
 
 
Distributed earnings
$
0.05

 
$
0.05

 
$
0.05

 
$
0.05

Undistributed earnings
2.07

 
2.07

 
0.49

 
0.49

Total earnings per common share from
  continuing operations
$
2.12

 
$
2.12

 
$
0.54

 
$
0.54

 
 
 
 
 
 
 
 
Earnings per common share from
  continuing operations – assuming dilution:
 
 
 
 
 
 
 
Net income attributable to Valero stockholders
  from continuing operations
 
 
$
1,203

 
 
 
$
303

Weighted-average common shares outstanding
 
 
564

 
 
 
564

Common equivalent shares:
 
 

 
 
 
 
Stock options
 
 
3

 
 
 
3

Performance awards and unvested restricted
  stock
 
 
2

 
 
 
1

Weighted-average common shares outstanding –
  assuming dilution
 
 
569

 
 
 
568

Earnings per common share from
  continuing operations – assuming dilution
 
 
$
2.11

 
 
 
$
0.53




20

Table of Contents



VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

 
Nine Months Ended September 30,
 
2011
 
2010
 
Restricted 
Stock
 
Common
Stock 
 
Restricted
Stock 
 
 Common
Stock
Earnings per common share from
  continuing operations:
 
 
 
 
 
 
 
Net income attributable to Valero stockholders
  from continuing operations
 
 
$
2,052

 
 
 
$
743

Less dividends paid:
 
 
 
 
 
 
 
Common stock
 
 
85

 
 
 
85

Nonvested restricted stock
 
 

 
 
 

Undistributed earnings
 
 
$
1,967

 
 
 
$
658

 
 
 
 
 
 
 
 
Weighted-average common shares outstanding
3

 
566

 
3

 
563

 
 
 
 
 
 
 
 
Earnings per common share from
  continuing operations:
 
 
 
 
 
 
 
Distributed earnings
$
0.15

 
$
0.15

 
$
0.15

 
$
0.15

Undistributed earnings
3.46

 
3.46

 
1.16

 
1.16

Total earnings per common share from
  continuing operations
$
3.61

 
$
3.61

 
$
1.31

 
$
1.31

 
 
 
 
 
 
 
 
Earnings per common share from
  continuing operations – assuming dilution:
 
 
 
 
 
 
 
Net income attributable to Valero stockholders
  from continuing operations
 
 
$
2,052

 
 
 
$
743

Weighted-average common shares outstanding
 
 
566

 
 
 
563

Common equivalent shares:
 
 
 
 
 
 
 
Stock options
 
 
4

 
 
 
3

Performance awards and unvested restricted
  stock
 
 
2

 
 
 
1

Weighted-average common shares outstanding –
  assuming dilution
 
 
572

 
 
 
567

Earnings per common share from
  continuing operations – assuming dilution
 
 
$
3.59

 
 
 
$
1.31




21

Table of Contents



VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The following table reflects potentially dilutive securities (in millions) that were excluded from the calculation of “earnings per common share from continuing operations – assuming dilution” as the effect of including such securities would have been antidilutive. These potentially dilutive securities included common stock options for which the exercise prices were greater than the average market price of our common stock during each respective reporting period.

 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2011
 
2010
 
2011
 
2010
Stock options
6

 
17

 
6

 
14


10.
SEGMENT INFORMATION
The following table reflects segment activity related to continuing operations (in millions):

 
 
Refining
 
Retail
 
Ethanol
 
Corporate
 
Total
Three months ended September 30, 2011:
 
 
 
 
 
 
 
 
 
 
Operating revenues from external
  customers
 
$
29,177

 
$
3,053

 
$
1,483

 
$

 
$
33,713

Intersegment revenues
 
2,258

 

 
25

 

 
2,283

Operating income (loss)
 
1,947

 
97

 
107

 
(172
)
 
1,979

 
 
 
 
 
 
 
 
 
 
 
Three months ended September 30, 2010:
 
 
 
 
 
 
 
 
 
 
Operating revenues from external
  customers
 
17,811

 
2,360

 
844

 

 
21,015

Intersegment revenues
 
1,576

 

 
73

 

 
1,649

Operating income (loss)
 
590

 
105

 
47

 
(152
)
 
590

 
 
 
 
 
 
 
 
 
 
 
Nine months ended September 30, 2011:
 
 
 
 
 
 
 
 
 
 
Operating revenues from external
  customers
 
78,660

 
8,865

 
3,789

 

 
91,314

Intersegment revenues
 
6,566

 

 
125

 

 
6,691

Operating income (loss)
 
3,476

 
298

 
215

 
(476
)
 
3,513

 
 
 
 
 
 
 
 
 
 
 
Nine months ended September 30, 2010:
 
 
 
 
 
 
 
 
 
 
Operating revenues from external
  customers
 
51,104

 
6,893

 
2,072

 

 
60,069

Intersegment revenues
 
4,675

 

 
184

 

 
4,859

Operating income (loss)
 
1,479

 
285

 
139

 
(405
)
 
1,498





22

Table of Contents



VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Total assets by reportable segment were as follows (in millions):

 
September 30,
2011
 
December 31, 2010
Refining
$
35,541

 
$
30,363

Retail
1,933

 
1,925

Ethanol
879

 
953

Corporate
3,330

 
4,380

Total consolidated assets
$
41,683

 
$
37,621


11.
SUPPLEMENTAL CASH FLOW INFORMATION
In order to determine net cash provided by operating activities, net income is adjusted by, among other things, changes in current assets and current liabilities as follows (in millions):

 
Nine Months Ended
September 30,
 
2011
 
2010
Decrease (increase) in current assets:
 
 
 
Receivables, net
$
(1,963
)
 
$
(516
)
Inventories
891

 
79

Income taxes receivable
333

 
787

Prepaid expenses and other
12

 
111

Increase (decrease) in current liabilities:
 
 
 
Accounts payable
1,191

 
358

Accrued expenses
137

 
(51
)
Taxes other than income taxes
99

 
(168
)
Income taxes payable
140

 
(8
)
Changes in current assets and current liabilities
$
840

 
$
592


The above changes in current assets and current liabilities differ from changes between amounts reflected in the applicable consolidated balance sheets for the respective periods for the following reasons:
the amounts shown above exclude changes in cash and temporary cash investments, deferred income taxes, and current portion of debt and capital lease obligations, as well as the effect of certain noncash investing and financing activities discussed below;
the amounts shown above exclude the current assets and current liabilities acquired in connection with the the Pembroke Acquisition in August 2011 and the acquisitions of three ethanol plants in the first quarter of 2010;
amounts accrued for capital expenditures and deferred turnaround and catalyst costs are reflected in investing activities when such amounts are paid;
amounts accrued for common stock purchases in the open market that are not settled as of the balance sheet date are reflected in financing activities when the purchases are settled and paid; and



23

Table of Contents



VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

certain differences between consolidated balance sheet changes and the changes reflected above result from translating foreign currency denominated balances at the applicable exchange rates as of each balance sheet date.
During the nine months ended September 30, 2011, we received a noncash contribution of $2 million from the noncontrolling interest for property, plant and equipment related to DGD Holdings. There were no significant noncash investing or financing activities for the nine months ended September 30, 2010.

Cash flows related to interest and income taxes were as follows (in millions):
 
Nine Months Ended
September 30,
 
2011
 
2010
Interest paid in excess of amount capitalized
$
276

 
$
302

Income taxes paid (received), net
289

 
(645
)
Cash flows related to the discontinued operations of the Paulsboro and Delaware City Refineries have been combined with the cash flows from continuing operations within each category in the consolidated statement of cash flows for the nine months ended September 30, 2010 and are summarized as follows (in millions):

Cash provided by (used in) operating activities:
 
Paulsboro Refinery
$
42

Delaware City Refinery
(76
)
Cash used in investing activities:
 
Paulsboro Refinery
(32
)
Delaware City Refinery


12.
FAIR VALUE MEASUREMENTS
General
GAAP requires that certain financial instruments, such as derivative instruments, be recognized at their fair values in our consolidated balance sheets. However, other financial instruments, such as debt obligations, are not required to be recognized at their fair values, but GAAP provides an option to elect fair value accounting for these instruments. GAAP requires the disclosure of the fair values of all financial instruments, regardless of whether they are recognized at their fair values or carrying amounts in our consolidated balance sheets. For financial instruments recognized at fair value, GAAP requires the disclosure of their fair values by type of instrument, along with other information, including changes in the fair values of certain financial instruments recognized in income or other comprehensive income, and this information is provided below under “Recurring Fair Value Measurements.” For financial instruments not recognized at fair value, the disclosure of their fair values is provided below under “Other Financial Instruments.”

Nonfinancial assets, such as property, plant and equipment, and nonfinancial liabilities are recognized at their carrying amounts in our consolidated balance sheets. GAAP does not permit nonfinancial assets and liabilities to be remeasured at their fair values. However, GAAP requires the remeasurement of such assets



24

Table of Contents



VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

and liabilities to their fair values upon the occurrence of certain events, such as the impairment of property, plant and equipment. In addition, if such an event occurs, GAAP requires the disclosure of the fair value of the asset or liability along with other information, including the gain or loss recognized in income in the period the remeasurement occurred. This information is provided below under “Nonrecurring Fair Value Measurements.”

GAAP provides a framework for measuring fair value and establishes a three-level fair value hierarchy that prioritizes inputs to valuation techniques based on the degree to which objective prices in external active markets are available to measure fair value. Following is a description of each of the levels of the fair value hierarchy.
Level 1 - Observable inputs, such as unadjusted quoted prices in active markets for identical assets or liabilities.
Level 2 - Inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. These include quoted prices for similar assets or liabilities in active markets and quoted prices for identical or similar assets or liabilities in markets that are not active.
Level 3 - Unobservable inputs for the asset or liability for which there is little, if any, market activity at the measurement date. Unobservable inputs reflect our own assumptions about what market participants would use to price the asset or liability. The inputs are developed based on the best information available in the circumstances, which might include occasional market quotes or sales of similar instruments or our own financial data such as internally developed pricing models, discounted cash flow methodologies, as well as instruments for which the fair value determination requires significant judgment.

The financial instruments and nonfinancial assets and liabilities included in our disclosure of recurring and nonrecurring fair value measurements are categorized according to the fair value hierarchy based on the inputs used to measure their fair values.




25

Table of Contents



VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Recurring Fair Value Measurements
The tables below present information (in millions) about our financial instruments recognized at their fair values in our consolidated balance sheets categorized according to the fair value hierarchy of the inputs utilized by us to determine the fair values as of September 30, 2011 and December 31, 2010.

 
Fair Value Measurements Using
 
 
 
 
 
Quoted
Prices in
Active
Markets
(Level 1)
 
Significant
Other
Observable
Inputs
(Level 2)
 
Significant
Unobservable
Inputs
(Level 3)
 
 
 
Total as of
September 30,
2011
 
 
 
 
Netting
Adjustments
 
Assets:
 
 
 
 
 
 
 
 
 
Commodity derivative contracts
$
6,764

 
$
238

 
$

 
$
(6,734
)
 
$
268

Physical purchase contracts

 
(81
)
 

 

 
(81
)
Investments of nonqualified benefit plans
81

 

 
11

 

 
92

Other investments

 

 

 

 

Liabilities:
 
 
 
 
 
 
 
 
 
Commodity derivative contracts
6,503

 
338

 

 
(6,734
)
 
107

Nonqualified benefit plan obligations
34

 

 

 

 
34

RINs obligation
137

 

 

 

 
137


 
Fair Value Measurements Using
 
 
 
 
 
Quoted
Prices in
Active
Markets
(Level 1)
 
Significant
Other
Observable
Inputs
(Level 2)
 
Significant
Unobservable
Inputs
(Level 3)
 
 
 
Total as of
December 31,
2010
 
 
 
 
Netting
Adjustments
 
Assets:
 
 
 
 
 
 
 
 
 
Commodity derivative contracts
$
3,240

 
$
489

 
$

 
$
(3,560
)
 
$
169

Physical purchase contracts

 
17

 

 

 
17

Investments of nonqualified benefit plans
104

 

 
10

 

 
114

Other investments

 

 

 

 

Liabilities:
 
 
 
 
 
 
 
 
 
Commodity derivative contracts
3,097

 
502

 

 
(3,560
)
 
39

Nonqualified benefit plan obligations
36

 

 

 

 
36

RINs obligation
51

 

 

 

 
51




26

Table of Contents



VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

A description of our financial instruments and the valuation methods used to measure those instruments at fair value are as follows:
Commodity derivative contracts consist primarily of exchange-traded futures and swaps, and as disclosed in Note 13, some of these contracts are designated as hedging instruments. These contracts are measured at fair value using the market approach. Exchange-traded futures are valued based on quoted prices from the exchange and are categorized in Level 1 of the fair value hierarchy. Swaps are priced using third-party broker quotes, industry pricing services, and exchange-traded curves, with appropriate consideration of counterparty credit risk, but because they have contractual terms that are not identical to exchange-traded futures instruments with a comparable market price, these financial instruments are categorized in Level 2 of the fair value hierarchy.
Physical purchase contracts to purchase inventories represent the fair value of firm commitments to purchase crude oil feedstocks and the fair value of fixed-price corn purchase contracts, and as disclosed in Note 13, some of these contracts are designated as hedging instruments. The fair values of these firm commitments and purchase contracts are measured using a market approach based on quoted prices from the commodity exchange, but because these commitments have contractual terms that are not identical to exchange-traded futures instruments with a comparable market price, they are categorized in Level 2 of the fair value hierarchy.
Nonqualified benefit plan assets consist of investment securities held by our nonqualified defined benefit and nonqualified defined contribution plans. The nonqualified benefit plan obligations relate to our nonqualified defined contribution plans under which our obligations to eligible employees are equal to the fair value of the assets held by those plans. The nonqualified benefit plan assets categorized in Level 1 of the fair value hierarchy are measured at fair value using a market approach based on quotations from national securities exchanges. The nonqualified benefit plan assets categorized in Level 3 of the fair value hierarchy represent insurance contracts, the fair value of which is provided by the insurer.
Other investments consist of (i) equity securities of private companies over which we do not exercise significant influence nor whose financial statements are consolidated into our financial statements and (ii) debt securities of a private company whose financial statements are not consolidated into our financial statements. We have elected to account for these investments at their fair values. These investments are categorized in Level 3 of the fair value hierarchy as the fair values of these investments are determined using the income approach based on internally developed analyses.
Our RINs obligation represents a liability for the purchase of Renewable Identification Numbers (RINs) to satisfy our obligation to blend biofuels into the products we produce. A RIN represents a serial number assigned to each gallon of biofuel produced or imported into the U.S. as required by the EPA’s Renewable Fuel Standard, which was implemented in accordance with the Energy Policy Act of 2005. The EPA sets annual quotas for the percentage of biofuels that must be blended into motor fuels consumed in the U.S., and as a producer of motor fuels from petroleum, we are obligated to blend biofuels into the products we produce at a rate that is at least equal to the EPA’s quota. To the degree we are unable to blend at that rate, we must purchase RINs in the open market to satisfy our obligation. Our RINs obligation is based on our RINs deficiency and the price of those RINs as of the balance sheet date. Our RINs obligation is categorized in Level 1 of the fair value hierarchy and is measured at fair value using the market approach based on quoted prices from an independent pricing service.



27

Table of Contents



VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Cash collateral deposits of $228 million and $403 million with brokers under master netting arrangements are included in the fair value of the commodity derivatives reflected in Level 1 as of September 30, 2011 and December 31, 2010, respectively. Certain of our commodity derivative contracts under master netting arrangements include both asset and liability positions. We have elected to offset the fair value amounts recognized for multiple similar derivative instruments executed with the same counterparty, including any related cash collateral asset or obligation; however, fair value amounts by hierarchy level are presented on a gross basis in the tables above.
The following is a reconciliation of the beginning and ending balances (in millions) for fair value measurements developed using significant unobservable inputs (Level 3).

 
2011
 
2010
 
Investments of Nonqualified
Benefit
Plans
 
Other
Investments
 
Investments of
Nonqualified
Benefit
Plans
 
Other
Investments
Three months ended September 30:
 
 
 
 
 
 
 
Balance at beginning of period
$
11

 
$

 
$
10

 
$

Purchases

 
5

 

 

Total losses included in earnings

 
(5
)
 

 

Transfers in and/or out of Level 3

 

 

 

Balance at end of period
$
11

 
$

 
$
10

 
$

The amount of total losses included
  in earnings attributable to the change in
  unrealized losses relating to assets still
  held at end of period
$

 
$
(5
)
 
$

 
$

 
 
 
 
 
 
 
 
Nine months ended September 30:
 
 
 
 
 
 
 
Balance at beginning of period
$
10

 
$

 
$
10

 
$

Purchases

 
21

 

 
1

Total gains (losses) included in
  earnings
1

 
(21
)
 

 
(1
)
Transfers in and/or out of Level 3

 

 

 

Balance at end of period
$
11

 
$

 
$
10

 
$

The amount of total gains (losses)
  included in earnings attributable to the
  change in unrealized gains (losses)
  relating to assets still held
  at end of period
$
1

 
$
(21
)
 
$

 
$
(1
)
    
Nonrecurring Fair Value Measurements
As of September 30, 2011 and December 31, 2010, there were no assets or liabilities that were measured at fair value on a nonrecurring basis.



28

Table of Contents



VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Other Financial Instruments
Financial instruments that we recognize in our consolidated balance sheets at their carrying amounts include cash and temporary cash investments, receivables, payables, debt and capital lease obligations. The fair values of these financial instruments approximate their carrying amounts, except for debt as shown in the table below (in millions):

 
September 30,
2011
 
December 31,
2010
Carrying amount (excluding capital leases)
$
7,595

 
$
8,300

Fair value
9,169

 
9,492


The fair value of our debt is determined using the market approach based on quoted prices in active markets (Level 1).

13.
PRICE RISK MANAGEMENT ACTIVITIES
We are exposed to market risks related to the volatility in the price of commodities, interest rates and foreign currency exchange rates, and we enter into derivative instruments to manage those risks. We also enter into derivative instruments to manage the price risk on other contractual derivatives into which we have entered. The only types of derivative instruments we enter into are those related to the various commodities we purchase or produce, interest rate swaps, and foreign currency exchange and purchase contracts, as described below. All derivative instruments are recorded as either assets or liabilities measured at their fair values (See Note 12).
When we enter into a derivative instrument, it is designated as a fair value hedge, a cash flow hedge, an economic hedge, or a trading derivative. The gain or loss on a derivative instrument designated and qualifying as a fair value hedge, as well as the offsetting loss or gain on the hedged item attributable to the hedged risk, are recognized currently in income in the same period. The effective portion of the gain or loss on a derivative instrument designated and qualifying as a cash flow hedge is initially reported as a component of other comprehensive income and is then recorded in income in the period or periods during which the hedged forecasted transaction affects income. The ineffective portion of the gain or loss on the cash flow derivative instrument, if any, is recognized in income as incurred. For our economic hedges (derivative instruments not designated as fair value or cash flow hedges) and for derivative instruments entered into by us for trading purposes, the derivative instrument is recorded at fair value and changes in the fair value of the derivative instrument are recognized currently in income. The cash flow effects of all of our derivative instruments are reflected in operating activities in the consolidated statements of cash flows for all periods presented.




29

Table of Contents



VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Commodity Price Risk
We are exposed to market risks related to the price of crude oil, refined products (primarily gasoline and distillate), grain (primarily corn), and natural gas used in our operations. To reduce the impact of price volatility on our results of operations and cash flows, we use commodity derivative instruments, including swaps, futures, and options. We use the futures markets for the available liquidity, which provides greater flexibility in transacting our hedging and trading operations. We use swaps primarily to manage our price exposure. Our positions in commodity derivative instruments are monitored and managed on a daily basis by a risk control group to ensure compliance with our stated risk management policy that has been approved by our board of directors.

For risk management purposes, we use fair value hedges, cash flow hedges, and economic hedges. In addition to the use of derivative instruments to manage commodity price risk, we also enter into certain commodity derivative instruments for trading purposes. Our objective for entering into each type of hedge or trading derivative is described below.

Fair Value Hedges
Fair value hedges are used to hedge price volatility in certain refining inventories and firm commitments to purchase inventories. The level of activity for our fair value hedges is based on the level of our operating inventories, and generally represents the amount by which our inventories differ from our previous year-end LIFO inventory levels.
As of September 30, 2011, we had the following outstanding commodity derivative instruments that were entered into to hedge crude oil and refined product inventories and commodity derivative instruments related to the physical purchase of crude oil and refined products at a fixed price. The information presents the notional volume of outstanding contracts by type of instrument and year of maturity (volumes in thousands of barrels).

 
 
Notional
Contract
Volumes by
Year of
Maturity
Derivative Instrument
 
2011
Crude oil and refined products:
 
 
Futures – long
 
3,025

Futures – short
 
16,453

Physical purchase contracts – long
 
13,428




30

Table of Contents



VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Cash Flow Hedges
Cash flow hedges are used to hedge price volatility in certain forecasted feedstock and refined product purchases, refined product sales, and natural gas purchases. The objective of our cash flow hedges is to lock in the price of forecasted feedstock, product or natural gas purchases or refined product sales at existing market prices that we deem favorable.

As of September 30, 2011, we had the following outstanding commodity derivative instruments that were entered into to hedge forecasted purchases or sales of crude oil and refined products. The information presents the notional volume of outstanding contracts by type of instrument and year of maturity (volumes in thousands of barrels).

 
 
Notional Contract Volumes by Year of Maturity
Derivative Instrument
 
2012
Crude oil and refined products:
 
 
Swaps – long
 
5,241

Swaps – short
 
5,241





31

Table of Contents



VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Economic Hedges
Economic hedges represent commodity derivative instruments that are not designated as fair value or cash flow hedges and are used to manage price volatility in certain (i) refinery feedstock, refined product, and corn inventories, (ii) forecasted refinery feedstock, refined product, and corn purchases, and refined product sales, and (iii) fixed-price corn purchase contracts. Our objective in entering into economic hedges is consistent with the objectives discussed above for fair value hedges and cash flow hedges. However, the economic hedges are not designated as a fair value hedge or a cash flow hedge for accounting purposes, usually due to the difficulty of establishing the required documentation at the date that the derivative instrument is entered into that would allow us to achieve “hedge deferral accounting.”
As of September 30, 2011, we had the following outstanding commodity derivative instruments that were entered into as economic hedges and commodity derivative instruments related to the physical purchase of corn at a fixed price. The information presents the notional volume of outstanding contracts by type of instrument and year of maturity (volumes in thousands of barrels, except those identified as corn contracts that are presented in thousands of bushels).

 
 
Notional Contract Volumes by
Year of Maturity
Derivative Instrument
 
2011
 
2012
 
2013
Crude oil and refined products:
 
 
 
 
 
 
Swaps – long
 
34,708

 
65,040

 

Swaps – short
 
33,890

 
65,040

 

Futures – long
 
200,076

 
40,388

 

Futures – short
 
192,292

 
41,219

 

Options – long
 
606

 
10

 

Options – short
 
600

 

 

Corn:
 
 
 
 
 
 
Futures – long
 
22,325

 
8,405

 

Futures – short
 
41,300

 
23,980

 
260

Physical purchase contracts – long
 
12,166

 
10,991

 
265




32

Table of Contents



VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Trading Derivatives
Our objective in entering into commodity derivative instruments for trading purposes is to take advantage of existing market conditions related to future results of operations and cash flows.

As of September 30, 2011, we had the following outstanding commodity derivative instruments that were entered into for trading purposes. The information presents the notional volume of outstanding contracts by type of instrument and year of maturity (volumes represent thousands of barrels, except those identified as natural gas contracts that are presented in billions of British thermal units and corn contracts that are presented in thousands of bushels).

 
 
Notional Contract Volumes by
Year of Maturity
Derivative Instrument
 
2011
 
2012
Crude oil and refined products:
 
 
 
 
Swaps – long
 
6,196

 
3,240

Swaps – short
 
6,196

 
3,240

Futures – long
 
66,365

 
15,868

Futures – short
 
66,389

 
15,831

Options – short
 
75

 

Natural gas:
 
 
 
 
Futures – long
 
5,050

 

Futures – short
 
5,050

 

Corn:
 
 
 
 
Swaps – long
 

 
1,050

Swaps – short
 

 
1,050

Futures – long
 
3,850

 
60

Futures – short
 
2,350

 
1,060

Interest Rate Risk
Our primary market risk exposure for changes in interest rates relates to our debt obligations. We manage our exposure to changing interest rates through the use of a combination of fixed-rate and floating-rate debt. In addition, at times we have used interest rate swap agreements to manage our fixed to floating interest rate position by converting certain fixed-rate debt to floating-rate debt.

Foreign Currency Risk
We are exposed to exchange rate fluctuations on transactions entered into by our Canadian and European operations that are denominated in currencies other than the local (functional) currencies of those operations. To manage our exposure to these exchange rate fluctuations, we use foreign currency exchange and purchase contracts. These contracts are not designated as hedging instruments for accounting purposes, and therefore they are classified as economic hedges. As of September 30, 2011, we had commitments to purchase $475 million of U.S. dollars. These commitments matured on or before October 28, 2011.




33

Table of Contents



VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Fair Values of Derivative Instruments
The following tables provide information about the fair values of our derivative instruments as of September 30, 2011 and December 31, 2010 (in millions) and the line items in the consolidated balance sheet in which the fair values are reflected. See Note 12 for additional information related to the fair values of our derivative instruments.

As indicated in Note 12, we net fair value amounts recognized for multiple similar derivative instruments executed with the same counterparty under master netting arrangements. The tables below, however, are presented on a gross asset and gross liability basis, which results in the reflection of certain assets in liability accounts and certain liabilities in asset accounts. In addition, in Note 12, we included cash collateral on deposit with or received from brokers in the fair value of the commodity derivatives; these cash amounts are not reflected in the tables below.

 
Consolidated
Balance Sheet
Location
 
September 30, 2011
 
 
Asset
Derivatives  
 
Liability
Derivatives  
Derivatives designated as hedging instruments
 
 
 
 
 
Commodity contracts:
 
 
 
 
 
Futures
Receivables, net
 
$
360

 
$
237

Swaps
Receivables, net
 
46

 
40

Swaps
Accrued expenses
 
4

 
3

Total
 
 
$
410

 
$
280

 
 
 
 
 
 
Derivatives not designated as hedging instruments
 
 
 
 
 
Commodity contracts:
 
 
 
 
 
Futures
Receivables, net
 
$
6,170

 
$
6,266

Swaps
Receivables, net
 
6

 
5

Swaps
Prepaid expenses and other
 
2

 
1

Swaps
Accrued expenses
 
181

 
268

Options
Receivables, net
 
5

 

Options
Accrued expenses
 

 
21

Physical purchase contracts
Inventories
 

 
81

Total
 
 
$
6,364

 
$
6,642

Total derivatives
 
 
$
6,774

 
$
6,922





34

Table of Contents



VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

 
Consolidated
Balance Sheet
Location
 
December 31, 2010
 
 
Asset
Derivatives  
 
Liability
Derivatives  
Derivatives designated as hedging instruments
 
 
 
 
 
Commodity contracts:
 
 
 
 
 
Futures
Receivables, net
 
$
120

 
$
183

Swaps
Prepaid expenses and other
 
55

 
39

Swaps
Accrued expenses
 
31

 
32

Total
 
 
$
206

 
$
254

 
 
 
 
 
 
Derivatives not designated as hedging instruments
 
 
 
 
 
Commodity contracts:
 
 
 
 
 
Futures
Receivables, net
 
$
2,717

 
$
2,914

Swaps
Prepaid expenses and other
 
287

 
277

Swaps
Accrued expenses
 
116

 
148

Options
Accrued expenses
 

 
6

Physical purchase contracts
Inventories
 
17

 

Total
 
 
$
3,137

 
$
3,345

Total derivatives
 
 
$
3,343

 
$
3,599

Market and Counterparty Risk
Our price risk management activities involve the receipt or payment of fixed price commitments into the future. These transactions give rise to market risk, which is the risk that future changes in market conditions may make an instrument less valuable. We closely monitor and manage our exposure to market risk on a daily basis in accordance with policies approved by our board of directors. Market risks are monitored by a risk control group to ensure compliance with our stated risk management policy. Concentrations of customers in the refining industry may impact our overall exposure to counterparty risk because these customers may be similarly affected by changes in economic or other conditions. In addition, financial services companies are the counterparties in certain of our price risk management activities, and such financial services companies may be adversely affected by periods of uncertainty and illiquidity in the credit and capital markets.
As of September 30, 2011, we had net receivables related to derivative instruments of $1 million from counterparties in the refining industry and no amount of net receivables from counterparties in the financial services industry. As of December 31, 2010, we had net receivables related to derivative instruments of $4 million from counterparties in the refining industry and $21 million from counterparties in the financial services industry. These amounts represent the aggregate amount payable to us by companies in those industries, reduced by payables from us to those companies under master netting arrangements that allow for the setoff of amounts receivable from and payable to the same party. We do not require any collateral or other security to support derivative instruments into which we enter. We also do not have any derivative instruments that require us to maintain a minimum investment-grade credit rating.



35

Table of Contents



VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Effect of Derivative Instruments on Consolidated Statements of Income and Other Comprehensive Income
The following tables provide information about the gain or loss recognized in income and other comprehensive income on our derivative instruments and the line items in the consolidated financial statements in which such gains and losses are reflected (in millions).

Derivatives in
Fair Value
Hedging
Relationships
 
Location
 
Gain or (Loss)
Recognized in
Income on
Derivatives
 
Gain or (Loss)
Recognized in
Income on
Hedged Item
 
Gain or (Loss)
Recognized in
Income for
Ineffective Portion
of Derivative
 
 
2011
 
2010
 
2011
 
2010
 
2011
 
2010
Three months ended September 30:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity
  contracts
 
Cost of sales
 
$
170

 
$
54

 
$
(161
)
 
$
(56
)
 
$
9

 
$
(2
)
Nine months ended September 30:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity
  contracts
 
Cost of sales
 
219

 
253

 
(222
)
 
(247
)
 
(3
)
 
6


For fair value hedges, no component of the derivative instruments’ gains or losses was excluded from the assessment of hedge effectiveness for the three and nine months ended September 30, 2011 and 2010. No amounts were recognized in income for hedged firm commitments that no longer qualify as fair value hedges for the three and nine months ended September 30, 2011 and 2010.

Derivatives in
Cash Flow
Hedging
Relationships
 
Gain or (Loss)
Recognized in
OCI on
Derivatives
(Effective Portion)
 
Gain or (Loss)
Reclassified from
Accumulated OCI into
Income (Effective Portion)
 
Gain or (Loss)
Recognized in
Income on Derivatives
(Ineffective Portion)
 
2011
 
2010
 
Location
 
2011
 
2010
 
Location
 
2011
 
2010
Three months ended September 30:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity
  contracts
 
$
20

 
$

 
Cost of sales
 
$

 
$
37

 
Cost of sales
 
$
4

 
$

Nine months ended September 30:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity
  contracts
 
20

 
(2
)
 
Cost of sales
 

 
135

 
Cost of sales
 
4

 





36

Table of Contents



VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

For cash flow hedges, no component of the derivative instruments’ gains or losses was excluded from the assessment of hedge effectiveness for the three and nine months ended September 30, 2011 and 2010. For the three and nine months ended September 30, 2011, cash flow hedges primarily related to forward sales of gasoline and distillates, and associated forward purchases of crude oil, with $13 million of cumulative after-tax gains on cash flow hedges remaining in accumulated other comprehensive income as of September 30, 2011. We estimate that $10 million of the deferred gains as of September 30, 2011 will be reclassified into cost of sales over the next 12 months as a result of hedged transactions that are forecasted to occur. For the three and nine months ended September 30, 2011 and 2010, there were no amounts reclassified from accumulated other comprehensive income into income as a result of the discontinuance of cash flow hedge accounting.

Derivatives Designated as
Economic Hedges and Other
Derivative Instruments
 
Location of Gain or (Loss)
Recognized in Income on
Derivatives
 
Gain or (Loss)
Recognized in
Income on Derivatives
 
 
2011
 
2010
Three months ended September 30:
 
 
 
 
 
 
Commodity contracts
 
Cost of sales
 
$
9

 
$
22

Foreign currency contracts
 
Cost of sales
 
41

 
(5
)
Other contract
 
Cost of sales
 
29

 

Total
 
 
 
$
79

 
$
17

Nine months ended September 30:
 
 
 
 
 
 
Commodity contracts
 
Cost of sales
 
$
(362
)
 
$
(93
)
Foreign currency contracts
 
Cost of sales
 
32

 
(2
)
Other contract
 
Cost of sales
 
29

 

Total
 
 
 
$
(301
)
 
$
(95
)

The gain of $29 million on the other contract for the three and nine months ended September 30, 2011 is related to the difference between the fair value of inventories acquired in connection with the Pembroke Acquisition and the amount paid for such inventories based on the terms of the purchase agreement. The loss of $362 million on commodity contracts for the nine months ended September 30, 2011 includes a $542 million loss related to forward sales of refined products.

Trading Derivatives
 
Location of Gain or (Loss)
Recognized in Income on
Derivatives
 
Gain or (Loss)
Recognized in
Income on Derivatives
 
 
2011
 
2010
Three months ended September 30:
 
 
 
 
 
 
Commodity contracts
 
Cost of sales
 
$
3

 
$
2

Nine months ended September 30:
 
 
 
 
 
 
Commodity contracts
 
Cost of sales
 
17

 
7





37

Table of Contents

Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations

CAUTIONARY STATEMENT FOR THE PURPOSE OF SAFE HARBOR PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995
This Form 10-Q, including without limitation our discussion 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, home 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 those capital investments on our results of operations;
anticipated trends in the supply of and demand for crude oil and other feedstocks and refined products in the U.S., Canada, the United Kingdom, Ireland, and elsewhere;
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, including the U.S., Canada, Europe, the Middle East, Africa, and South America;
domestic and foreign demand for, and supplies of, refined products such as gasoline, diesel fuel, jet fuel, home heating oil, petrochemicals, and ethanol;
domestic and foreign 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;




38

Table of Contents

the actions taken by competitors, including both pricing and adjustments to refining capacity in response to market conditions;
the level of foreign imports of refined products to the U.S., Canada, or the United Kingdom;
accidents or other unscheduled shutdowns affecting our refineries, machinery, pipelines, or equipment, 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;
lower than expected ethanol margins;
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 federal, state, municipal, or foreign legislation or rulemakings, 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; and
overall economic conditions, including the stability and liquidity of financial markets.
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.




39

Table of Contents

OVERVIEW AND OUTLOOK

For the third quarter of 2011, we reported net income attributable to Valero stockholders from continuing operations of $1.2 billion, or $2.11 per share, compared to $303 million, or $0.53 per share, for the third quarter of 2010. For the first nine months of 2011, we reported net income attributable to Valero stockholders from continuing operations of $2.1 billion, or $3.59 per share, compared to $743 million, or $1.31 per share for the first nine months of 2010. Included in the results for the first nine months of 2011 was a $542 million loss ($352 million after taxes, or $0.62 per share) on commodity derivative contracts related to forward sales of refined products. These contracts were closed and realized in the first quarter of 2011. The improvement in net income attributable to Valero stockholders from continuing operations in the third quarter and first nine months of 2011 versus the comparable periods of 2010 was primarily due to an increase in operating income attributable to the business segments outlined in the following tables (in millions):

 
 
Three Months Ended September 30,
 
 
2011
 
2010
 
Change
Operating income (loss) by business segment:
 
 
 
 
 
 
Refining
 
$
1,947

 
$
590

 
$
1,357

Retail
 
97

 
105

 
(8
)
Ethanol
 
107

 
47

 
60

Corporate
 
(172
)
 
(152
)
 
(20
)
Total
 
$
1,979

 
$
590

 
$
1,389

 
 
 
 
 
 
 
 
 
Nine Months Ended September 30,
 
 
2011
 
2010
 
Change
Operating income (loss) by business segment:
 
 
 
 
 
 
Refining
 
$
3,476

 
$
1,479

 
$
1,997

Retail
 
298

 
285

 
13

Ethanol
 
215

 
139

 
76

Corporate
 
(476
)
 
(405
)
 
(71
)
Total
 
$
3,513

 
$
1,498

 
$
2,015


Excluding the impact of the $542 million loss on commodity derivative contracts described above, total company operating income and our refining segment operating income would have been $4.1 billion and $4.0 billion, respectively, for the first nine months of 2011, which reflects an improvement in operating income of $2.6 billion and $2.5 billion, respectively, over the comparable 2010 period.

Refining segment operating income improved primarily due to increased margins for most of the products we produce. Our margin improvement included the benefits from wider sour crude oil differentials (which is the difference between the price of sweet crude oil and the price of sour crude oil) and the favorable difference between the price of waterborne sweet crude oils, such as Louisiana Light Sweet (LLS) and Brent, and inland sweet crude oils, such as West Texas Intermediate (WTI). Many of our refineries process sour crude oils or WTI-type crude oils and these crude oils were priced significantly below waterborne sweet crude oils during the third quarter of 2011 and the first nine months of 2011, versus the comparable 2010 periods.




40

Table of Contents

Our retail segment generated operating income of $97 million for the third quarter of 2011 compared to $105 million for the third quarter of 2010. This decrease of $8 million was due primarily to an increase of $8 million in the fuel margin generated by our Canadian retail operations, offset by a decrease of $10 million in the fuel margin generated by our U.S. retail operations and an increase of $8 million in operating expenses. For the first nine months of 2011, our retail segment generated $298 million of operating income compared to $285 million for the first nine months of 2010. The increase was primarily due to higher fuel margins and volumes in our Canadian operations, including a favorable impact from the strengthening of the Canadian dollar relative to the U.S. dollar.

Our ethanol segment generated operating income of $107 million for the third quarter of 2011 compared to $47 million for the third quarter of 2010, and it generated $215 million of operating income for the first nine months of 2011 compared to $139 million for the first nine months of 2010. The increase in operating income in both the third quarter and first nine months of 2011 was primarily due to improved operating margins combined with a full nine months of operations related to the three ethanol plants we acquired in the first quarter of 2010. The ethanol business is dependent on margins between ethanol and corn feedstocks and is impacted by U.S. government subsidies and biofuels (including ethanol) mandates.

On August 1, 2011, we acquired 100 percent of the outstanding shares of Chevron Limited from a subsidiary of Chevron Corporation and we subsequently changed the name of Chevron Limited to Valero Energy Ltd. Valero Energy Ltd owns and operates the Pembroke Refinery, which has a total throughput capacity of approximately 270,000 barrels per day and is located in Wales, United Kingdom. Valero Energy Ltd also owns, directly and through various subsidiaries, an extensive network of marketing and logistics assets throughout the United Kingdom and Ireland. On the acquisition date, we initially paid $1.8 billion from available cash, of which $1.1 billion was for working capital. Subsequent to the acquisition date, the amounts paid have been favorably adjusted for working capital true-up adjustments (primarily inventory), to an adjusted purchase price of $1.675 billion. We expect final settlement by year end. This acquisition is referred to as the Pembroke Acquisition.

On October 1, 2011, we acquired the Meraux Refinery and related logistics assets for an initial payment of $586 million, including inventories of $261 million, from Murphy Oil Corporation. The purchase price was funded from available cash. We expect to receive a favorable adjustment related to inventories in the fourth quarter of 2011 that will reduce the purchase price by approximately $40 million.

As of the date of the filing of this report, the financial markets continue to experience significant volatility. The overall impact on our business is uncertain at this time and we expect the energy markets and margins to be volatile in the near to mid-term.



41

Table of Contents

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.

Financial Highlights (a) (b) (c)
(millions of dollars, except per share amounts)
 
Three Months Ended September 30,
 
2011
 
2010
 
Change
Operating revenues
$
33,713

 
$
21,015

 
$
12,698

Costs and expenses:
 
 
 
 
 
Cost of sales (d)
30,033

 
18,915

 
11,118

Operating expenses:
 
 
 
 
 
Refining
870

 
753

 
117

Retail (d)
177

 
169

 
8

Ethanol
103

 
96

 
7

General and administrative expenses
161

 
139

 
22

Depreciation and amortization expense:
 
 
 
 
 
Refining
340

 
303

 
37

Retail
29

 
27

 
2

Ethanol
10

 
10

 

Corporate
11

 
13

 
(2
)
Total costs and expenses
31,734

 
20,425

 
11,309

Operating income
1,979

 
590

 
1,389

Other income, net
1

 
17

 
(16
)
Interest and debt expense, net of capitalized interest
(88
)
 
(119
)
 
31

Income from continuing operations
  before income tax expense
1,892

 
488

 
1,404

Income tax expense
689

 
185

 
504

Income from continuing operations
1,203

 
303

 
900

Income (loss) from discontinued operations,
  net of income taxes

 
(11
)
 
11

Net income
1,203

 
292

 
911

Less: Net loss attributable to noncontrolling interests

 

 

Net income attributable to Valero stockholders
$
1,203

 
$
292

 
$
911

 
 
 
 
 
 
Net income attributable to Valero stockholders:
 
 
 
 
 
Continuing operations
$
1,203

 
$
303

 
$
900

Discontinued operations

 
(11
)
 
11

Total
$
1,203

 
$
292

 
$
911

 
 
 
 
 
 
Earnings per common share – assuming dilution:
 

 
 
 
 
Continuing operations
$
2.11

 
$
0.53

 
$
1.58

Discontinued operations

 
(0.02
)
 
0.02

Total
$
2.11

 
$
0.51

 
$
1.60

________________
See note references on page 47.



42

Table of Contents

Operating Highlights
(millions of dollars, except per barrel amounts)

 
Three Months Ended September 30,
 
2011
 
2010
 
Change
Refining (a) (b):
 
 
 
 
 
Operating income
$
1,947

 
$
590

 
$
1,357

Throughput margin per barrel (e)
$
13.24

 
$
8.13

 
$
5.11

Operating costs per barrel:
 
 
 
 
 
Operating expenses
3.65

 
3.71

 
(0.06
)
Depreciation and amortization expense
1.43

 
1.50

 
(0.07
)
Total operating costs per barrel
5.08

 
5.21

 
(0.13
)
Operating income per barrel
$
8.16

 
$
2.92

 
$
5.24

 
 
 
 
 
 
Throughput volumes (thousand barrels per day):
 
 
 
 
 
Feedstocks:
 
 
 
 
 
Heavy sour crude
540

 
443

 
97

Medium/light sour crude
455

 
402

 
53

Acidic sweet crude
150

 
51

 
99

Sweet crude
739

 
708

 
31

Residuals
310

 
239

 
71

Other feedstocks
123

 
113

 
10

Total feedstocks
2,317

 
1,956

 
361

Blendstocks and other
275

 
247

 
28

Total throughput volumes
2,592

 
2,203

 
389

 
 
 
 
 
 
Yields (thousand barrels per day):
 
 
 
 
 
Gasolines and blendstocks
1,196

 
1,088

 
108

Distillates
894

 
766

 
128

Other products (f)
519

 
381

 
138

Total yields
2,609

 
2,235

 
374

_______________
See note references on page 47.




43

Table of Contents

Refining Operating Highlights by Region (g)
(millions of dollars, except per barrel amounts)

 
Three Months Ended September 30,
 
2011
 
2010
 
Change
Gulf Coast:
 
 
 
 
 
Operating income
$
1,167

 
$
388

 
$
779

Throughput volumes (thousand barrels per day)
1,522

 
1,336

 
186

Throughput margin per barrel (e)
$
13.08

 
$
8.34

 
$
4.74

Operating costs per barrel:
 
 
 
 
 
Operating expenses
3.31

 
3.65

 
(0.34
)
Depreciation and amortization expense
1.43

 
1.54

 
(0.11
)
Total operating costs per barrel
4.74

 
5.19

 
(0.45
)
Operating income per barrel
$
8.34

 
$
3.15

 
$
5.19

 
 
 
 
 
 
Mid-Continent:
 
 
 
 
 
Operating income
$
586

 
$
131

 
$
455

Throughput volumes (thousand barrels per day)
400

 
422

 
(22
)
Throughput margin per barrel (e)
$
22.27

 
$
8.06

 
$
14.21

Operating costs per barrel:
 
 
 
 
 
Operating expenses
4.76

 
3.34

 
1.42

Depreciation and amortization expense
1.59

 
1.33

 
0.26

Total operating costs per barrel
6.35

 
4.67

 
1.68

Operating income per barrel
$
15.92

 
$
3.39

 
$
12.53

 
 
 
 
 
 
North Atlantic (a) (b):
 
 
 
 
 
Operating income
$
65

 
$
36

 
$
29

Throughput volumes (thousand barrels per day)
386

 
193

 
193

Throughput margin per barrel (e)
$
5.46

 
$
6.04

 
$
(0.58
)
Operating costs per barrel:
 
 
 
 
 
Operating expenses
2.91

 
2.75

 
0.16

Depreciation and amortization expense
0.74

 
1.30

 
(0.56
)
Total operating costs per barrel
3.65

 
4.05

 
(0.40
)
Operating income per barrel
$
1.81

 
$
1.99

 
$
(0.18
)
 
 
 
 
 
 
West Coast:
 
 
 
 
 
Operating income
$
129

 
$
35

 
$
94

Throughput volumes (thousand barrels per day)
284

 
252

 
32

Throughput margin per barrel (e)
$
11.96

 
$
8.66

 
$
3.30

Operating costs per barrel:
 
 
 
 
 
Operating expenses
4.94

 
5.42

 
(0.48
)
Depreciation and amortization expense
2.08

 
1.74

 
0.34

Total operating costs per barrel
7.02

 
7.16

 
(0.14
)
Operating income per barrel
$
4.94

 
$
1.50

 
$
3.44

 
 
 
 
 
 
Total refining operating income
$
1,947

 
$
590

 
$
1,357

_______________
See note references on page 47.



44

Table of Contents

Average Market Reference Prices and Differentials (h)
(dollars per barrel, except as noted)

 
Three Months Ended September 30,
 
2011
 
2010
 
Change
Feedstocks:
 
 
 
 
 
Louisiana Light Sweet (LLS) crude oil
$
112.21

 
$
78.66

 
$
33.55

LLS less West Texas Intermediate (WTI) crude oil
22.47

 
2.58

 
19.89

LLS less Alaska North Slope (ANS) crude oil
0.60

 
3.03

 
(2.43
)
LLS less Brent crude oil
(1.43
)
 
1.73

 
(3.16
)
LLS less Mars crude oil
2.53

 
3.96

 
(1.43
)
LLS less Maya crude oil
13.48

 
11.04

 
2.44

WTI crude oil
89.74

 
76.08

 
13.66

WTI less Mars crude oil
(19.94
)
 
1.38

 
(21.32
)
WTI less Maya crude oil
(8.99
)
 
8.46

 
(17.45
)
 
 
 
 
 
 
Products:
 
 
 
 
 
Gulf Coast:
 
 
 
 
 
Conventional 87 gasoline less LLS
$
8.20

 
$
4.35

 
$
3.85

Ultra-low-sulfur diesel less LLS
14.19

 
9.12

 
5.07

Propylene less LLS
12.46

 
2.61

 
9.85

Conventional 87 gasoline less WTI
30.67

 
6.93

 
23.74

Ultra-low-sulfur diesel less WTI
36.66

 
11.70

 
24.96

Propylene less WTI
34.93

 
5.19

 
29.74

Mid-Continent:
 
 
 
 
 
Conventional 87 gasoline less WTI
32.11

 
9.20

 
22.91

Ultra-low-sulfur diesel less WTI
38.34

 
13.20

 
25.14

North Atlantic:
 
 
 
 
 
Conventional 87 gasoline less Brent
7.48

 
5.85

 
1.63

Ultra-low-sulfur diesel less Brent
14.55

 
12.16

 
2.39

Conventional 87 gasoline less WTI
31.38

 
6.70

 
24.68

Ultra-low-sulfur diesel less WTI
38.45

 
13.01

 
25.44

West Coast:
 
 
 
 
 
CARBOB 87 gasoline less ANS
10.27

 
16.96

 
(6.69
)
CARB diesel less ANS
15.77

 
15.10

 
0.67

CARBOB 87 gasoline less WTI
32.14

 
16.51

 
15.63

CARB diesel less WTI
37.64

 
14.65

 
22.99

New York Harbor corn crush (dollars per gallon)
0.36

 
0.43

 
(0.07
)
_______________
See note references on page 47.



45

Table of Contents

Operating Highlights (continued)
(millions of dollars, except per gallon amounts)

 
Three Months Ended September 30,
 
2011
 
2010
 
Change
Retail–U.S.: (d)
 
 
 
 
 
Operating income
$
59

 
$
72

 
$
(13
)
Company-operated fuel sites (average)
994

 
990

 
4

Fuel volumes (gallons per day per site)
5,168

 
5,204

 
(36
)
Fuel margin per gallon
$
0.155

 
$
0.176

 
$
(0.021
)
Merchandise sales
$
324

 
$
322

 
$
2

Merchandise margin (percentage of sales)
29.2
%
 
28.8
%
 
0.4
 %
Margin on miscellaneous sales
$
22

 
$
21

 
$
1

Operating expenses
$
111

 
$
108

 
$
3

Depreciation and amortization expense
$
19

 
$
18

 
$
1

 
 
 
 
 
 
Retail–Canada: (d)
 
 
 
 
 
Operating income
$
38

 
$
33

 
$
5

Fuel volumes (thousand gallons per day)
3,214

 
3,214

 

Fuel margin per gallon
$
0.273

 
$
0.247

 
$
0.026

Merchandise sales
$
72

 
$
66

 
$
6

Merchandise margin (percentage of sales)
29.4
%
 
30.4
%
 
(1
)%
Margin on miscellaneous sales
$
11

 
$
10

 
$
1

Operating expenses
$
66

 
$
61

 
$
5

Depreciation and amortization expense
$
10

 
$
9

 
$
1

 
 
 

 
 
Ethanol (c):
 
 

 
 
Operating income
$
107

 
$
47

 
$
60

Production (thousand gallons per day)
3,272

 
3,100

 
172

Gross margin per gallon of production (e)
$
0.73

 
$
0.54

 
$
0.19

Operating costs per gallon of production:
 
 

 
 
Operating expenses
0.34

 
0.34

 

Depreciation and amortization expense
0.04

 
0.03

 
0.01

Total operating costs per gallon of production
0.38

 
0.37

 
0.01

Operating income per gallon of production
$
0.35

 
$
0.17

 
$
0.18

_______________
See note references on page 47.



46

Table of Contents

The following notes relate to references on pages 42 through 46.
(a)
The information presented for the three months ended September 30, 2011 includes the results of operations of our refinery in Wales, United Kingdom (Pembroke Refinery), including the related marketing and logistics business, from the date of its acquisition, August 1, 2011, through September 30, 2011. In addition, the refining segment and North Atlantic region operating highlights for the three months ended September 30, 2011 include the Pembroke Refinery.
(b)
In December 2010, we sold our Paulsboro Refinery to PBF Holding Company LLC. The results of operations of the Paulsboro Refinery have been presented as discontinued operations for the three months ended September 30, 2010. In addition, the refining segment and North Atlantic region operating highlights exclude the Paulsboro Refinery for the three months ended September 30, 2010.
(c)
We acquired three ethanol plants in the first quarter of 2010. The information presented includes the results of operations of those plants commencing on their respective acquisition dates. Ethanol production volumes are based on total production during each period divided by actual calendar days per period.
(d)
Credit card transaction processing fees incurred by our retail segment of $23 million for the three months ended September 30, 2010 have been reclassified from retail operating expenses to cost of sales. The Retail–U.S. and Retail–Canada operating highlights for the three months ended September 30, 2010 have been restated to reflect this reclassification.
(e)
Throughput margin per barrel represents operating revenues less cost of sales of our refining segment divided by throughput volumes. Gross margin per gallon of production represents operating revenues less cost of sales of our ethanol segment divided by production volumes.
(f)
Other products primarily include petrochemicals, gas oils, No. 6 fuel oil, petroleum coke, and asphalt.
(g)
The regions reflected herein contain the following refineries: the Gulf Coast region includes the Corpus Christi East, Corpus Christi West, Texas City, Houston, Three Rivers, St. Charles, Aruba, and Port Arthur Refineries; the Mid-Continent region includes the McKee, Ardmore, and Memphis Refineries; the North Atlantic (formerly known as Northeast) region includes the Pembroke and Quebec City Refineries; and the West Coast region includes the Benicia and Wilmington Refineries.
(h)
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 presented herein 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 light-sweet crude oil began to price at a discount to waterborne light-sweet crude oils, such as LLS and Brent, because of increased WTI supplies resulting from greater domestic production and increased deliveries of crude oil from Canada into the 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 60 percent (or $12.7 billion) for the third quarter of 2011 compared to the third quarter of 2010 primarily as a result of higher refined product prices and higher throughput volumes between the two periods related to our refining segment operations. The higher throughput volumes resulted primarily from the incremental throughput of 178,000 barrels per day1 ($3.0 billion of revenue) from the Pembroke Refinery, which was acquired on August 1, 2011, and throughput of 182,000 barrels per day ($1.8 billion of revenue) from the Aruba Refinery, which restarted operations in January 2011. Both operating income and income from continuing operations before taxes increased $1.4 billion for the third quarter of 2011 compared to amounts reported for the third quarter of 2010 primarily due to a $1.4 billion increase in refining segment operating income discussed below.








_______________
1Calculated based on throughput volumes of the Pembroke Refinery from the date of acquisition (August 1, 2011), divided by the number of days during the third quarter of 2011.




47

Table of Contents

Refining
Refining segment operating income more than tripled (a $1.4 billion increase) from $590 million for the third quarter of 2010 to $1.9 billion for the third quarter of 2011. The $1.4 billion improvement in operating income was due to a $1.5 billion increase in refining margin, offset by a $117 million increase in operating expenses.

The $1.5 billion increase in refining margin was primarily due to a 63 percent increase in throughput margin per barrel (a $5.11 per barrel increase between the comparable periods), and this increase was largely driven by an improvement in gasoline and distillate margins in most of our refining regions, primarily the Mid-Continent and Gulf Coast refining regions, as further explained below.
The WTI-based benchmark reference margin for Mid-Continent conventional 87 gasoline was $32.11 per barrel for the third quarter of 2011, compared to $9.20 per barrel for the third quarter of 2010, representing a favorable increase of $22.91 per barrel. In addition, the WTI-based benchmark reference margin for Mid-Continent ultra-low sulfur diesel (a type of distillate) was $38.34 per barrel for the third quarter of 2011, compared to $13.20 per barrel for the third quarter of 2010, representing a favorable increase of $25.14 per barrel. We estimate that these increases in gasoline and distillate margins per barrel had a positive impact to our refining margin of approximately $500 million and $300 million, respectively, quarter versus quarter. The increases in the gasoline and distillate benchmark reference margins in the Mid-Continent region are primarily due to the substantial discount in the price of WTI crude oil, the primary type of crude oil processed by our Mid-Continent refineries, versus LLS-type crude oils. Historically, the price of WTI crude oil has tracked LLS crude oil, but due to the significant development of crude oil reserves within the Mid-Continent region and increased deliveries of crude oil from Canada into the Mid-Continent region, the increased supply of WTI crude oil has resulted in WTI crude oil currently being priced at a significant discount to LLS crude oil.
The LLS-based benchmark reference margin for Gulf Coast conventional 87 gasoline was $8.20 per barrel for the third quarter of 2011, compared to $4.35 per barrel for the third quarter of 2010, representing a favorable increase of $3.85 per barrel. In addition, the LLS-based benchmark reference margin for Gulf Coast ultra-low sulfur diesel was $14.19 per barrel for the third quarter of 2011, compared to $9.12 per barrel for the third quarter of 2010, representing a favorable increase of $5.07 per barrel. We estimate that these increases in gasoline and distillate margins per barrel had a positive impact to our refining margin of approximately $200 million and $250 million, respectively, quarter versus quarter. The increases in the gasoline and distillate benchmark reference margins are supported by increased exports of gasoline and distillate as well as an increase in demand for distillates.
In addition, our system benefited from the increase in the discount of the price of heavy sour crude oils as compared to the price of sweet crude oils. For example, Maya crude oil, which is a type of heavy sour crude oil, sold at a discount of $13.48 per barrel to LLS crude oil, which is a type of sweet crude oil, during the third quarter of 2011. This compares to a discount of $11.04 per barrel during the third quarter of 2010, representing a favorable increase of $2.44 per barrel. We estimate that the increase in the discounts for all types of sour crude oil that we process had a positive impact to our refining margin of approximately $120 million, quarter versus quarter.
The increase of $117 million in operating expenses discussed above was primarily due to $50 million in operating expenses incurred by the Pembroke Refinery, which was acquired on August 1, 2011. The remaining increase in refining operating expenses of $67 million was primarily due to a $34 million increase in maintenance expenses and a $38 million increase in chemicals and catalyst costs.



48

Table of Contents

Retail
Retail segment operating income was $97 million for the third quarter of 2011 compared to $105 million for the third quarter of 2010. This 8 percent (or $8 million) decrease was due primarily to an increase of $8 million in the fuel margin generated by our Canadian retail operations offset by a decrease of $10 million in the fuel margin generated by our U.S. retail operations and an increase of $8 million in operating expenses between the quarters.

Ethanol
Ethanol segment operating income was $107 million for the third quarter of 2011 compared to $47 million for the third quarter of 2010. The $60 million increase in operating income was primarily due to a $68 million increase in gross margin, partially offset by a $7 million increase in operating expenses.

The increase in gross margin was due to an increase in ethanol production (a 172,000 gallon per day increase between the comparable periods), which resulted from higher utilization rates and increased yield from the corn feedstock that we processed during the third quarter of 2011, and a 35 percent increase in the gross margin per gallon of ethanol production (a $0.19 per gallon increase between the comparable periods).

The increase in operating expenses was due primarily to a $5 million increase in energy costs and chemical expenses.

Corporate Expenses and Other
General and administrative expenses increased $22 million from the third quarter of 2010 to the third quarter of 2011 primarily due to $18 million in costs incurred in connection with the Pembroke Acquisition.
“Other income, net” for the third quarter of 2011 decreased $16 million from the third quarter of 2010 primarily due to a $12 million decrease in investment income earned on the plan assets of certain of our non-qualified benefit plans and earnings of $4 million in the third quarter of 2010 related to our joint venture investment in Cameron Highway Oil Pipeline Company, which did not recur due to the sale of our ownership interest in that joint venture in the fourth quarter of 2010.
“Interest and debt expense, net of capitalized interest” for the third quarter of 2011 decreased $31 million from the third quarter of 2010. This decrease is primarily due to a $16 million increase in capitalized interest due to a corresponding increase in capital expenditures between the quarters and the resumption of construction activity on previously suspended projects combined with a $7 million favorable impact from a decrease in average borrowings and an $8 million favorable impact resulting from the successful resolution of a tax contingency.
Income tax expense increased $504 million from the third quarter of 2010 to the third quarter of 2011 mainly as a result of higher operating income in 2011.



49

Table of Contents

Financial Highlights (a) (b) (c)
(millions of dollars, except per share amounts)

 
Nine Months Ended September 30,
 
2011
 
2010
 
Change
Operating revenues
$
91,314

 
$
60,069

 
$
31,245

Costs and expenses:
 
 
 
 
 
Cost of sales (d) (e)
82,981

 
54,198

 
28,783

Operating expenses:
 
 
 
 
 
Refining
2,427

 
2,210

 
217

Retail (d)
508

 
484

 
24

Ethanol
302

 
267

 
35

General and administrative expenses
442

 
367

 
75

Depreciation and amortization expense:
 
 
 
 
 
Refining
995

 
898

 
97

Retail
84

 
80

 
4

Ethanol
28

 
27

 
1

Corporate
34

 
38

 
(4
)
Asset impairment loss

 
2

 
(2
)
Total costs and expenses
87,801

 
58,571

 
29,230

Operating income
3,513

 
1,498

 
2,015

Other income, net
28

 
29

 
(1
)
Interest and debt expense, net of capitalized interest
(312
)
 
(363
)
 
51

Income from continuing operations
  before income tax expense
3,229

 
1,164

 
2,065

Income tax expense
1,178

 
421

 
757

Income from continuing operations
2,051

 
743

 
1,308

Income (loss) from discontinued operations,
  net of income taxes
(7
)
 
19

 
(26
)
Net income
2,044

 
762

 
1,282

Less: Net loss attributable to noncontrolling interests
(1
)
 

 
(1
)
Net income attributable to Valero stockholders
$
2,045

 
$
762

 
$
1,283

 
 
 
 
 
 
Net income attributable to Valero stockholders:
 
 
 
 
 
Continuing operations
$
2,052

 
$
743

 
$
1,309

Discontinued operations
(7
)
 
19

 
(26
)
Total
$
2,045

 
$
762

 
$
1,283

 
 
 
 
 
 
Earnings per common share – assuming dilution:
 
 
 
 
 
Continuing operations
$
3.59

 
$
1.31

 
$
2.28

Discontinued operations
(0.01
)
 
0.03

 
(0.04
)
Total
$
3.58

 
$
1.34

 
$
2.24

_______________
See note references on page 55.



50

Table of Contents

Operating Highlights
(millions of dollars, except per barrel amounts)
 
Nine Months Ended September 30,
 
2011
 
2010
 
Change
Refining (a) (b):
 
 
 
 
 
Operating income (e)
$
3,476

 
$
1,479

 
$
1,997

Throughput margin per barrel (e) (f)
$
10.80

 
$
7.97

 
$
2.83

Operating costs per barrel:
 
 
 
 
 
Operating expenses
3.80

 
3.84

 
(0.04
)
Depreciation and amortization expense
1.56

 
1.56

 

Total operating costs per barrel
5.36

 
5.40

 
(0.04
)
Operating income per barrel
$
5.44

 
$
2.57

 
$
2.87

 
 
 
 
 
 
Throughput volumes (thousand barrels per day):
 
 
 
 
 
Feedstocks:
 
 
 
 
 
Heavy sour crude
455

 
452

 
3

Medium/light sour crude
415

 
399

 
16

Acidic sweet crude
117

 
51

 
66

Sweet crude
695

 
655

 
40

Residuals
284

 
195

 
89

Other feedstocks
122

 
115

 
7

Total feedstocks
2,088

 
1,867

 
221

Blendstocks and other
252

 
241

 
11

Total throughput volumes
2,340

 
2,108

 
232

 
 
 
 
 
 
Yields (thousand barrels per day):
 
 
 
 
 
Gasolines and blendstocks
1,069

 
1,046

 
23

Distillates
793

 
695

 
98

Other products (g)
491

 
392

 
99

Total yields
2,353

 
2,133

 
220

_______________
See note references on page 55.



51

Table of Contents

Refining Operating Highlights by Region (h)
(millions of dollars, except per barrel amounts)
 
Nine Months Ended September 30,
 
2011
 
2010
 
Change
Gulf Coast:
 
 
 
 
 
Operating income (e)
$
2,064

 
$
1,027

 
$
1,037

Throughput volumes (thousand barrels per day)
1,418

 
1,268

 
150

Throughput margin per barrel (e) (f)
$
10.48

 
$
8.35

 
$
2.13

Operating costs per barrel:
 
 
 

 
 
Operating expenses
3.62

 
3.78

 
(0.16
)
Depreciation and amortization expense
1.53

 
1.60

 
(0.07
)
Total operating costs per barrel
5.15

 
5.38

 
(0.23
)
Operating income per barrel
$
5.33

 
$
2.97

 
$
2.36

 
 
 
 
 
 
Mid-Continent:
 
 
 
 
 
Operating income (e)
$
1,146

 
$
271

 
$
875

Throughput volumes (thousand barrels per day)
401

 
392

 
9

Throughput margin per barrel (e) (f)
$
16.18

 
$
7.59

 
$
8.59

Operating costs per barrel:
 
 
 
 
 
Operating expenses
4.14

 
3.63

 
0.51

Depreciation and amortization expense
1.56

 
1.42

 
0.14

Total operating costs per barrel
5.70

 
5.05

 
0.65

Operating income per barrel
$
10.48

 
$
2.54

 
$
7.94

 
 
 
 
 
 
North Atlantic (a) (b):
 
 
 
 
 
Operating income
$
104

 
$
81

 
$
23

Throughput volumes (thousand barrels per day)
268

 
189

 
79

Throughput margin per barrel (f)
$
5.32

 
$
6.01

 
$
(0.69
)
Operating costs per barrel:
 
 
 
 
 
Operating expenses
2.92

 
2.98

 
(0.06
)
Depreciation and amortization expense
0.98

 
1.47

 
(0.49
)
Total operating costs per barrel
3.90

 
4.45

 
(0.55
)
Operating income per barrel
$
1.42

 
$
1.56

 
$
(0.14
)
 
 
 
 
 
 
West Coast:
 
 
 
 
 
Operating income (e)
$
162

 
$
102

 
$
60

Throughput volumes (thousand barrels per day)
253

 
259

 
(6
)
Throughput margin per barrel (e) (f)
$
9.87

 
$
8.14

 
$
1.73

Operating costs per barrel:
 
 
 
 
 
Operating expenses
5.21

 
5.08

 
0.13

Depreciation and amortization expense
2.31

 
1.62

 
0.69

Total operating costs per barrel
7.52

 
6.70

 
0.82

Operating income per barrel
$
2.35

 
$
1.44

 
$
0.91

 
 
 
 
 
 
Operating income for regions above
$
3,476

 
$
1,481

 
$
1,995

Asset impairment loss applicable to refining

 
(2
)
 
2

Total refining operating income
$
3,476

 
$
1,479

 
$
1,997

_______________
See note references on page 55.



52

Table of Contents

Average Market Reference Prices and Differentials (i)
(dollars per barrel, except as noted)

 
Nine Months Ended September 30,
 
2011
 
2010
 
Change
Feedstocks:
 
 
 
 
 
LLS crude oil
$
111.73

 
$
79.35

 
$
32.38

LLS less WTI
16.34

 
1.83

 
14.51

LLS less ANS crude oil
2.44

 
2.27

 
0.17

LLS less Brent crude oil
(0.82
)
 
2.14

 
(2.96
)
LLS less Mars crude oil
4.05

 
3.39

 
0.66

LLS less Maya crude oil
14.58

 
10.88

 
3.70

WTI crude oil
95.39

 
77.52

 
17.87

WTI less Mars crude oil
(12.29
)
 
1.56

 
(13.85
)
WTI less Maya crude oil
(1.76
)
 
9.05

 
(10.81
)
 
 
 
 
 
 
Products:
 
 
 
 
 
Gulf Coast:
 
 
 
 
 
Conventional 87 gasoline less LLS
$
7.43

 
$
6.26

 
$
1.17

Ultra-low-sulfur diesel less LLS
13.09

 
8.61

 
4.48

Propylene less LLS
19.33

 
7.80

 
11.53

Conventional 87 gasoline less WTI
23.77

 
8.09

 
15.68

Ultra-low-sulfur diesel less WTI
29.43

 
10.44

 
18.99

Propylene less WTI
35.67

 
9.63

 
26.04

Mid-Continent:
 
 
 
 
 
Conventional 87 gasoline less WTI
24.79

 
8.77

 
16.02

Ultra-low-sulfur diesel less WTI
30.75

 
11.06

 
19.69

North Atlantic:
 
 
 
 
 
Conventional 87 gasoline less Brent
6.29

 
8.33

 
(2.04
)
Ultra-low-sulfur diesel less Brent
14.04

 
12.15

 
1.89

Conventional 87 gasoline less WTI
23.45

 
8.02

 
15.43

Ultra-low-sulfur diesel less WTI
31.20

 
11.84

 
19.36

West Coast:
 
 
 
 
 
CARBOB 87 gasoline less ANS
13.39

 
14.97

 
(1.58
)
CARB diesel less ANS
18.56

 
12.95

 
5.61

CARBOB 87 gasoline less WTI
27.29

 
14.53

 
12.76

CARB diesel less WTI
32.46

 
12.51

 
19.95

New York Harbor corn crush (dollars per gallon)
0.17

 
0.41

 
(0.24
)
_______________
See note references on page 55.



53

Table of Contents

Operating Highlights (continued)
(millions of dollars, except per gallon amounts)

 
Nine Months Ended September 30,
 
2011
 
2010
 
Change
Retail–U.S.: (d)
 
 
 
 
 
Operating income
$
165

 
$
181

 
$
(16
)
Company-operated fuel sites (average)
994

 
990

 
4

Fuel volumes (gallons per day per site)
5,053

 
5,115

 
(62
)
Fuel margin per gallon
$
0.146

 
$
0.158

 
$
(0.012
)
Merchandise sales
$
930

 
$
910

 
$
20

Merchandise margin (percentage of sales)
28.6
%
 
28.4
%
 
0.2
 %
Margin on miscellaneous sales
$
66

 
$
65

 
$
1

Operating expenses
$
312

 
$
306

 
$
6

Depreciation and amortization expense
$
56

 
$
54

 
$
2

 
 
 
 
 
 
Retail–Canada: (d)
 
 
 
 
 
Operating income
$
133

 
$
104

 
$
29

Fuel volumes (thousand gallons per day)
3,210

 
3,131

 
79

Fuel margin per gallon
$
0.303

 
$
0.263

 
$
0.040

Merchandise sales
$
197

 
$
179

 
$
18

Merchandise margin (percentage of sales)
29.6
%
 
30.3
%
 
(0.7
)%
Margin on miscellaneous sales
$
33

 
$
29

 
$
4

Operating expenses
$
196

 
$
178

 
$
18

Depreciation and amortization expense
$
28

 
$
26

 
$
2

 
 
 
 
 
 
Ethanol (c):
 
 
 
 
 
Operating income
$
215

 
$
139

 
$
76

Production (thousand gallons per day)
3,317

 
2,943

 
374

Gross margin per gallon of production (f)
$
0.60

 
$
0.54

 
$
0.06

Operating costs per gallon of production:

 

 
 
Operating expenses
0.33

 
0.33

 

Depreciation and amortization expense
0.03

 
0.04

 
(0.01
)
Total operating costs per gallon of production
0.36

 
0.37

 
(0.01
)
Operating income per gallon of production
$
0.24

 
$
0.17

 
$
0.07

_______________
See note references on page 55.



54

Table of Contents

The following notes relate to references on pages 50 through 54.
(a)
The information presented for the nine months ended September 30, 2011 includes the results of operations of our Pembroke Refinery, including the related marketing and logistics business, from the date of its acquisition, August 1, 2011, through September 30, 2011. In addition, the refining segment and North Atlantic region operating highlights for the nine months ended September 30, 2011 include the Pembroke Refinery.
(b)
In December 2010, we sold our Paulsboro Refinery to PBF Holding Company LLC and in June 2010, we sold our shutdown Delaware City Refinery assets and associated terminal and pipeline assets to PBF Energy Partners LP. The results of operations of these refineries have been presented as discontinued operations for the nine months ended September 30, 2010. In addition, the refining segment and North Atlantic region operating highlights exclude these refineries for nine months ended September 30, 2010.
(c)
We acquired three ethanol plants in the first quarter of 2010. The information presented includes the results of operations of those plants commencing on their respective acquisition dates. Ethanol production volumes are based on total production during each period divided by actual calendar days per period.
(d)
Credit card transaction processing fees incurred by our retail segment of $68 million for the nine months ended September 30, 2010 have been reclassified from retail operating expenses to cost of sales. The Retail–U.S. and Retail–Canada operating highlights for the nine months ended September 30, 2010 have been restated to reflect this reclassification.
(e)
Cost of sales for the nine months ended September 30, 2011 includes a loss of $542 million ($352 million after taxes) on commodity derivative contracts related to forward sales of refined products. These contracts were closed and realized during the first quarter of 2011. The $542 million loss is reflected in refining segment operating income, resulting in an $0.85 reduction in refining throughput margin per barrel for the nine months ended September 30, 2011, and is allocated to refining operating income by region, excluding the North Atlantic, based on relative throughput volumes for each region as follows: Gulf Coast- $372 million, or $0.96 per barrel; Mid-Continent- $122 million, or $1.11 per barrel; and West Coast- $48 million, or $0.69 per barrel.
(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 Gulf Coast region includes the Corpus Christi East, Corpus Christi West, Texas City, Houston, Three Rivers, St. Charles, Aruba, and Port Arthur Refineries; the Mid-Continent region includes the McKee, Ardmore, and Memphis Refineries; the North Atlantic region includes the Pembroke and Quebec City Refineries; and the West Coast region includes the Benicia and Wilmington Refineries.
(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 presented herein 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 light-sweet crude oil began to price at a discount to waterborne light-sweet crude oils, such as LLS and Brent, because of increased WTI supplies resulting from greater domestic production and increased deliveries of crude oil from Canada into the 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 52 percent (or $31.2 billion) for the first nine months of 2011 compared to the first nine months of 2010 primarily as a result of higher refined product prices and higher throughput volumes between the two periods related to our refining segment operations. The higher throughput volumes resulted primarily from the incremental throughput of 60,000 barrels per day1 ($3.0 billion of revenue) from the Pembroke Refinery, which was acquired on August 1, 2011, and throughput of 161,000 barrels per day ($4.2 billion of revenue) from the Aruba Refinery, which restarted operations in January 2011. Operating income increased $2.0 billion and income from continuing operations before taxes increased $2.1 billion for the first nine months of 2011 compared to amounts reported for the first nine months of 2010 primarily due to a $2.0 billion increase in refining segment operating income discussed below.


_______________
1Calculated based on throughput volumes of the Pembroke Refinery from the date of acquisition (August 1, 2011), divided by the number of days during the nine months ended September 30, 2011.



55

Table of Contents

Refining
Refining segment operating income more than doubled (a $2.0 billion increase) from $1.5 billion for the first nine months of 2010 to $3.5 billion for the first nine months of 2011. The $2.0 billion improvement in operating income was due to a $2.8 billion increase in refining margin, offset by a $542 million first quarter loss on forward sales of refined products and a $217 million increase in operating expenses.

The $2.8 billion increase in refining margin was primarily due to a 46 percent increase in throughput margin per barrel (a $3.68 per barrel increase between the comparable periods, consisting of the increase of $2.83 per barrel adjusted for the $0.85 per barrel impact of the $542 million loss discussed above). This increase in refining margin was largely driven by an improvement in gasoline and distillate margins in most of our refining regions, especially the Mid-Continent and Gulf Coast refining regions, as further explained below.
The WTI-based benchmark reference margin for Mid-Continent conventional 87 gasoline was $24.79 per barrel for the first nine months of 2011, compared to $8.77 per barrel for the first nine months of 2010, representing a favorable increase of $16.02 per barrel. In addition, the WTI-based benchmark reference margin for Mid-Continent ultra-low sulfur diesel (a type of distillate) was $30.75 per barrel for the first nine months of 2011, compared to $11.06 per barrel for the first nine months of 2010, representing a favorable increase of $19.69 per barrel. We estimate that these increases in gasoline and distillate margins per barrel had a positive impact to our refining margin of approximately $900 million and $800 million, respectively, nine months versus nine months. The increases in the gasoline and distillate benchmark reference margins in the Mid-Continent region are primarily due to the substantial discount in the price of WTI crude oil, the primary type of crude oil processed by our Mid-Continent refineries, versus LLS-type crude oils. Historically, the price of WTI crude oil has tracked LLS crude oil, but due to the significant development of crude oil reserves within the Mid-Continent region and increased deliveries of crude oil from Canada into the Mid-Continent region, the increased supply of WTI crude oil has resulted in WTI crude oil currently being priced at a significant discount to LLS crude oil.

The LLS-based benchmark reference margin for Gulf Coast conventional 87 gasoline was $7.43 per barrel for the first nine months of 2011, compared to $6.26 per barrel for the first nine months of 2010, representing a favorable increase of $1.17 per barrel. In addition, the LLS-based benchmark reference margin for Gulf Coast ultra-low sulfur diesel was $13.09 per barrel for the first nine months of 2011, compared to $8.61 per barrel for the first nine months of 2010, representing a favorable increase of $4.48 per barrel. We estimate that these increases in gasoline and distillate margins per barrel had a positive impact to our refining margin of approximately $200 million and $600 million, respectively, nine months versus nine months. The increases in the gasoline and distillate benchmark reference margins are supported by increased exports of gasoline and distillate as well as an increase in demand for distillates.

In addition, our system benefited from the increase in the discount of the price of heavy sour crude oils as compared to the price of sweet crude oils. For example, Maya crude oil, which is a type of heavy sour crude oil, sold at a discount of $14.58 per barrel to LLS crude oil, which is a type of sweet crude oil, during the first nine months of 2011. This compares to a discount of $10.88 per barrel during the first nine months of 2010, representing a favorable increase of $3.70 per barrel. We estimate that the increase in the discounts for all types of sour crude oil that we process had a positive impact to our refining margin of approximately $450 million, nine months versus nine months.






56

Table of Contents

The increase of $217 million in operating expenses discussed above was partially due to $50 million in operating expenses incurred by the Pembroke Refinery, which was acquired on August 1, 2011. The remaining increase of operating expenses of $167 million was primarily due to a $58 million increase in maintenance expenses, a $64 million increase in employee-related expenses, and a $76 million increase in chemicals and catalyst costs.
Retail
Retail segment operating income was $298 million for the first nine months of 2011 compared to $285 million for the first nine months of 2010. This 5 percent (or $13 million) increase was due to an increase in fuel margins of $23 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 $12 million, offset by increased operating expenses of $24 million.

Ethanol
Ethanol segment operating income was $215 million for the first nine months of 2011 compared to $139 million for the first nine months of 2010. The $76 million increase in operating income was primarily due to a $113 million increase in gross margin, partially offset by a $35 million increase in operating expenses.
Gross margin increased from the first nine months of 2010 to the first nine months of 2011 due to an increase in ethanol production (a 374,000 gallon per day increase between the comparable periods) 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 $0.06 per gallon increase in the ethanol gross margin .
The increase in operating expenses was primarily due to $25 million of additional expenses related to the operation of the three ethanol plants we acquired in the first quarter of 2010 for a full nine months in 2011.
Corporate Expenses and Other
General and administrative expenses increased $75 million from the first nine months of 2010 to the first nine months of 2011 due to a $16 million increase in variable compensation expense, $23 million in costs incurred in connection in with the Pembroke Acquisition, and a favorable settlement with an insurance company for $40 million recorded in the first quarter of 2010, which reduced general and administration expenses in that period.

“Interest and debt expense, net of capitalized interest” for the first nine months of 2011 decreased $51 million from the first nine months of 2010. This decrease is primarily due to an increase of $34 million in capitalized interest due to a corresponding increase in capital expenditures between the nine-month periods and the resumption of construction activity on previously suspended projects combined with favorable impacts from the decrease in average borrowings of $12 million and the decrease in average interest rates of $3 million.
Income tax expense increased $757 million from the first nine months of 2010 to the first nine months of 2011 mainly as a result of higher operating income in 2011 and the nonrecurrence of a $20 million income tax benefit recognized in 2010 related to a tax settlement with the Government of Aruba.

The loss from discontinued operations of $7 million for the first nine months of 2011 primarily represents adjustments to the working capital settlement related to the sale of our Paulsboro Refinery in December 2010. The income from discontinued operations of $19 million for the first nine months of 2010 represents a $58 million after-tax gain on the sale of the shutdown refinery assets at Delaware City, offset by a $39 million loss from the discontinued operations of the Delaware City and Paulsboro Refineries.



57

Table of Contents

LIQUIDITY AND CAPITAL RESOURCES
Cash Flows for the Nine Months Ended September 30, 2011 and 2010
Net cash provided by operating activities for the first nine months of 2011 was $4.3 billion compared to $2.6 billion for the first nine months of 2010. The increase in cash generated from operating activities was primarily due to a $248 million favorable effect from changes in working capital between the periods, combined with the $2.0 billion increase in operating income discussed above under “RESULTS OF OPERATIONS.” Changes in cash provided by or used for working capital during the first nine months of 2011 and 2010 are shown in Note 11 of Condensed Notes to Consolidated Financial Statements.
The net cash provided by operating activities during the first nine months of 2011 combined with $505 million from available cash on hand were used mainly to:
fund $2.1 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,
make scheduled long-term note repayments of $418 million and acquire the Gulf Opportunity Zone Revenue Bonds Series 2010 (GO Zone Bonds) for $300 million;
purchase our common stock for $270 million; and
pay common stock dividends of $85 million.
The net cash provided by operating activities during the first nine months of 2010, combined with $1.2 billion of net proceeds from the issuance of $400 million of 4.50% notes due in February 2015 and $850 million of 6.125% notes due in February 2020 as discussed in Note 5 of Condensed Notes to Consolidated Financial Statements, and $220 million of proceeds from the sale of the Delaware City Refinery assets and associated terminal and pipeline assets as discussed in Note 2 of Condensed Notes to Consolidated Financial Statements, were used mainly to:
fund $1.6 billion of capital expenditures and deferred turnaround and catalyst costs;
redeem our 7.50% senior notes for $294 million and our 6.75% senior notes for $190 million;
make scheduled long-term note repayments of $33 million;
make repayments under our accounts receivable sales facility of $100 million;
purchase additional ethanol plants for $260 million;
pay common stock dividends of $85 million; and
increase available cash on hand by $1.5 billion.

Cash flows related to the discontinued operations of the Paulsboro and Delaware City Refineries have been combined with the cash flows from continuing operations within each category in the consolidated statements of cash flows for the nine months ended September 30, 2010 and are summarized as follows (in millions):

Cash provided by (used in) operating activities:
 
Paulsboro Refinery
$
42

Delaware City Refinery
(76
)
Cash used in investing activities:
 
Paulsboro Refinery
(32
)
Delaware City Refinery




58

Table of Contents

Capital Investments
Our operations, especially those of our refining segment, are highly capital intensive. Each of our refineries is comprised of a large base of assets, consisting of a series of interconnected, highly integrated and interdependent crude oil processing facilities and supporting logistical infrastructure (Units), and these Units are continuously improved. Improvements consist of the addition of new Units and betterments of existing Units, and the cost of these improvements is 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 to further refine crude oil into products with higher market values. Therefore, many of our improvements do not increase throughput capacity significantly.

During the nine months ended September 30, 2011, we expended $1.6 billion for capital expenditures primarily related to improvements to our refineries. We also expended $501 million for deferred turnaround and catalyst costs. Capital expenditures for the nine months ended September 30, 2011 included $168 million of costs related to environmental projects.

For 2011, we expect to incur $3.2 billion for capital investments, including $2.5 billion for capital expenditures primarily related to improvements to our refineries and $650 million for deferred turnaround and catalyst costs. The $2.5 billion for capital expenditures includes $250 million for environmental projects, but excludes expenditures related to strategic business acquisitions.

Contractual Obligations
As of September 30, 2011, our contractual obligations included debt, capital lease obligations, operating leases, purchase obligations, and other long-term liabilities.

During the nine months ended September 30, 2011, we had no material changes outside the ordinary course of our business with respect to our debt, capital lease obligations, operating leases, purchase obligations, or other long-term liabilities; however, we made the following debt repayments:

in May 2011, we made a scheduled debt repayment of $200 million related to our 6.125% senior notes;
in April 2011, we made scheduled debt repayments of $8 million related to our Series A 5.45%, Series B 5.40%, and Series C 5.40% industrial revenue bonds;
in February 2011, we made a scheduled debt repayment of $210 million related to our 6.75% senior notes; and
in February 2011, we paid $300 million to acquire the GO Zone Bonds, which were subject to mandatory tender.




59

Table of Contents

Our 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 Moody’s Investors Service and Standard & Poor’s Ratings Services, the cost of borrowings under some of our bank credit facilities and other arrangements would increase. As of November 9, 2011, 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 (stable 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.
Other Commercial Commitments
As of September 30, 2011, our committed lines of credit were as follows (in millions):

 
 
Borrowing
Capacity
 
Expiration
 
Outstanding Letters of Credit
Letter of credit facility
 
$200
 
June 2012
 
$—
Letter of credit facility
 
$300
 
June 2012
 
$300
Revolving credit facility
 
$2,400
 
November 2012
 
$74
Canadian revolving credit facility
 
C$115
 
December 2012
 
C$20

As of September 30, 2011, we had no amounts borrowed under our revolving credit facilities. The letters of credit outstanding as of September 30, 2011 expire during 2011 and 2012.

Other Matters Impacting Liquidity and Capital Resources
Meraux Acquisition
On October 1, 2011, we acquired the Meraux Refinery and related logistics assets for an initial payment of $586 million, including inventories of $261 million, from Murphy Oil Corporation. The purchase price was funded from available cash. We expect to receive a favorable adjustment related to inventories in the fourth quarter of 2011 that will reduce the purchase price by approximately $40 million.

Contributions to Pension Plans
We have no minimum required contributions to our pension plans during 2011 under the Employee Retirement Income Security Act. However, we contributed $207 million to our pension plans in the first nine months of 2011.




60

Table of Contents

Stock Purchase Programs
As of September 30, 2011, we have approvals under common stock purchase programs to purchase approximately $3.5 billion of our common stock.

Environmental Matters
We are subject to extensive federal, state, and local environmental laws and regulations, including those 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 refineries could require material additional expenditures to comply with environmental laws and regulations.

The U.S. Environmental Protection Agency (EPA) began regulating greenhouse gases on January 2, 2011, under the Clean Air Act Amendments of 1990 (Clean Air Act). According to statements by the EPA, any new construction or material expansions will require that, among other things, a greenhouse gas permit be issued at either or both the state or federal level in accordance with the Clean Air Act and regulations, and we will be required to undertake a technology review to determine appropriate controls to be implemented with the project in order to reduce greenhouse gas emissions. The determination will be on a case by case basis, and the EPA has provided only general guidance on which controls will be required. Any such controls, however, could result in material increased compliance costs, additional operating restrictions for our business, and an increase in the cost of the products we produce, which could have a material adverse effect on our financial position, results of operations, and liquidity.

In addition, certain states and foreign governments have pursued independent regulation of greenhouse gases. For example, the California Global Warming Solutions Act, also known as AB 32, directs the California Air Resources Board (CARB) to develop and issue regulations to reduce greenhouse gas emissions in California to 1990 levels by 2020. CARB has issued a variety of regulations aimed at reaching this goal, including a Low Carbon Fuel Standard (LCFS) as well as a statewide cap-and-trade program. The LCFS is effective in 2011, with small reductions in the carbon intensity of transportation fuels sold in California. The mandated reductions in carbon intensity are scheduled to increase through 2020, after which another step-change in reductions is anticipated. The LCFS is designed to encourage substitution of traditional petroleum fuels, and, over time, it is anticipated that the LCFS will lead to a greater use of electric cars and alternative fuels, such as E85, as companies seek to generate more credits to offset petroleum fuels. The statewide cap-and-trade program will begin in 2013. Initially, the program will apply only to stationary sources of greenhouse gases (e.g., refinery and power plant greenhouse gas emissions). Greenhouse gas emissions from fuels that we sell in California will be covered by the program beginning in 2015. We anticipate that free allocations of credits will be available in the early years of the program, but we expect that compliance costs will increase significantly beginning in 2015, when fuels are included in the program. Complying with AB 32, including the LCFS and the cap-and-trade program, could result in material increased compliance costs for us, increased capital expenditures, increased operating costs, and additional operating restrictions for our business, resulting in an increase in the cost of, and decreases in the demand for, the products we produce. To the degree we are unable to recover these increased costs, these matters could have a material adverse effect on our financial position, results of operations, and liquidity.



61

Table of Contents

On June 30, 2010, the EPA formally disapproved the flexible permits program submitted by the Texas Commission on Environmental Quality (TCEQ) in 1994 for inclusion in its clean-air implementation plan.  The EPA determined that Texas’ flexible permit program did not meet several requirements under the federal Clean Air Act.  Our Port Arthur, Texas City, Three Rivers, McKee, and Corpus Christi East and West Refineries formerly operated under flexible permits administered by the TCEQ.  In the fourth quarter of 2010, we completed the conversion of our flexible permits into federally enforceable conventional state NSR permits (“de-flexed permits”). We are now in the process of incorporating these de-flexed permits into our Title V permits. Continued discussions with the TCEQ and the EPA regarding this matter are likely.

Meanwhile, the EPA has formally disapproved other TCEQ permitting programs that historically have streamlined the environmental permitting process in Texas. For example, the EPA has disapproved the TCEQ pollution control standard permit, thus requiring conventional permitting for future pollution control equipment. Litigation is pending from industry groups and others against the EPA for each of these actions. The EPA has also objected to numerous Title V permits in Texas and other states, including permits at our Port Arthur, Corpus Christi East, and McKee Refineries. Environmental activist groups have filed a notice of intent to sue the EPA, seeking to require the EPA to assume control of these permits from the TCEQ. All of these developments have created substantial uncertainty regarding existing and future permitting. Because of this uncertainty, we are unable to determine the costs or effects of the EPA’s actions on our permitting activity. But the EPA’s disruption of the Texas permitting system could result in material increased compliance costs for us, increased capital expenditures, increased operating costs, and additional operating restrictions for our business, resulting in an increase in the cost of, and decreases in the demand for, the products we produce, which could have a material adverse effect on our financial position, results of operations, and liquidity.

Tax Matters
We are subject to extensive tax liabilities, including federal, state, and foreign income taxes and transactional taxes such as excise, sales/use, payroll, franchise, withholding, 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.

Financial Regulatory Reform
On July 21, 2010, President Obama signed into law the Dodd-Frank Wall Street Reform and Consumer Protection Act (Wall Street Reform Act). The Wall Street Reform Act, among many things, creates new regulations for companies that extend credit to consumers and requires most derivative instruments to be traded on exchanges and routed through clearinghouses. Rules to implement the Wall Street Reform Act are being finalized and therefore, the impact to our operations is not yet known. However, implementation could result in higher margin requirements, 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.




62

Table of Contents

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.

CRITICAL ACCOUNTING POLICIES

The preparation of financial statements in accordance with United States generally accepted accounting principles requires us to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates. Our critical accounting policies are disclosed in our annual report on Form 10-K for the year ended December 31, 2010, except for the addition of the policy reflected below regarding the accounting for our property, plant and equipment, including the manner in which we estimate the useful lives of such assets, which we have identified as a critical accounting policy.

Property, Plant and Equipment
The cost of property, plant and equipment (property assets) purchased or constructed, including betterments of property assets, are capitalized. The cost of repairs to and normal maintenance of property assets, however, 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 is comprised of 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 continuously improved. 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 our property assets 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 15 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 groups 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.



63

Table of Contents

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.
Item 3.
Quantitative and Qualitative Disclosures About Market Risk
We are exposed to market risks related to the volatility in the price of commodities, interest rates and foreign currency exchange rates, and we enter into derivative instruments to manage those risks. We also enter into derivative instruments to manage the price risk on other contractual derivatives into which we have entered. The only types of derivative instruments we enter into are those related to the various commodities we purchase or produce, interest rate swaps, and foreign currency exchange and purchase contracts, as described below. All derivative instruments are recorded on our consolidated balance sheets as either assets or liabilities measured at their fair values.

COMMODITY PRICE RISK

We are exposed to market risks related to the price of crude oil, refined products (primarily gasoline and distillate), grain (primarily corn), and natural gas used in our operations. To reduce the impact of price volatility on our results of operations and cash flows, we use commodity derivative instruments, including swaps, futures, and options to hedge:
inventories and firm commitments to purchase inventories generally for amounts by which our current year LIFO inventory levels differ from our previous year-end LIFO inventory levels and
forecasted feedstock and refined product purchases, refined product sales, and natural gas purchases, and corn purchases to lock in the price of those forecasted transactions at existing market prices that we deem favorable.

We use the futures markets for the available liquidity, which provides greater flexibility in transacting our hedging and trading operations. We use swaps primarily to manage our price exposure. We also enter into certain commodity derivative instruments for trading purposes to take advantage of existing market conditions related to future results of operations and cash flows.

Our positions in commodity derivative instruments are monitored and managed on a daily basis by a risk control group to ensure compliance with our stated risk management policy that has been approved by our board of directors.




64

Table of Contents

The following sensitivity analysis includes all positions at the end of the reporting period with which we have market risk (in millions):

 
Derivative Instruments Held For
 
Non-Trading
Purposes
 
Trading
Purposes
September 30, 2011:
 
 
 
Gain (loss) in fair value due to:
 
 
 
10% increase in underlying commodity prices
$
(56
)
 
$

10% decrease in underlying commodity prices
56

 

 
 
 
 
December 31, 2010:
 
 
 
Gain (loss) in fair value due to:
 
 
 
10% increase in underlying commodity prices
(199
)
 

10% decrease in underlying commodity prices
189

 
(1
)

See Note 13 of Condensed Notes to Consolidated Financial Statements for notional volumes associated with these derivative contracts as of September 30, 2011.

INTEREST RATE RISK

The following table provides information about our debt instruments (dollars in millions), the fair values of which are sensitive to changes in interest rates. Principal cash flows and related weighted-average interest rates by expected maturity dates are presented. We had no interest rate derivative instruments outstanding as of September 30, 2011 or December 31, 2010.

 
September 30, 2011
 
Expected Maturity Dates
 
 
 
 
 
2011
 
2012
 
2013
 
2014
 
2015
 
There-
after
 
Total
 
Fair
Value
Debt (excluding capital lease obligations):
 
 
 
 
 
 
 
 
 
 
Fixed rate
$

 
$
759

 
$
489

 
$
209

 
$
484

 
$
5,605

 
$
7,546

 
$
9,065

Average interest rate
%
 
6.9
%
 
5.5
%
 
4.8
%
 
5.2
%
 
7.2
%
 
6.9
%
 
 
Floating rate
$

 
$
104

 
$

 
$

 
$

 
$

 
$
104

 
$
104

Average interest rate
%
 
0.7
%
 
%
 
%
 
%
 
%
 
0.7
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
December 31, 2010
 
Expected Maturity Dates
 
 
 
 
 
2011
 
2012
 
2013
 
2014
 
2015
 
There-
after
 
Total
 
Fair
Value
Debt (excluding capital lease obligations):
 
 
 
 
 
 
 
 
 
 
 
 
Fixed rate
$
418

 
$
759

 
$
489

 
$
209

 
$
484

 
$
5,605

 
$
7,964

 
$
9,092

Average interest rate
6.4
%
 
6.9
%
 
5.5
%
 
4.8
%
 
5.2
%
 
7.2
%
 
6.9
%
 
 
Floating rate
$
400

 
$

 
$

 
$

 
$

 
$

 
$
400

 
$
400

Average interest rate
0.5
%
 
%
 
%
 
%
 
%
 
%
 
0.5
%
 
 



65

Table of Contents

FOREIGN CURRENCY RISK
We are exposed to exchange rate fluctuations on transactions entered into by our Canadian and European operations that are denominated in currencies other than the local (functional) currencies of those operations. To manage our exposure to these exchange rate fluctuations, we use foreign currency exchange and purchase contracts. As of September 30, 2011, we had commitments to purchase $475 million of U.S. dollars. Our market risk was minimal on these contracts, as they matured on or before October 28, 2011, resulting in a $17 million loss in the fourth quarter of 2011.

Item 4. Controls and Procedures
(a)
Evaluation of disclosure controls and procedures.
Our management has evaluated, with the participation of our principal executive officer and principal financial officer, the effectiveness of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934) as of the end of the period covered by this report, and has concluded that our disclosure controls and procedures were effective as of September 30, 2011.
(b)
Changes in internal control over financial reporting.
There has been no change in our internal control over financial reporting that occurred during our last fiscal quarter that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.




66

Table of Contents

PART II – OTHER INFORMATION

Item 1.
Legal Proceedings
The information below describes new proceedings or material developments in proceedings that we previously reported in our annual report on Form 10-K for the year ended December 31, 2010, or our quarterly reports on Form 10-Q for the quarters ended March 31, 2011 and June 30, 2011.
Litigation
We hereby incorporate by reference into this Item our disclosures made in Part I, Item 1 of this Report included in Note 6 of Condensed Notes to Consolidated Financial Statements under the caption “Litigation Matters.”

Environmental Enforcement Matters
While it is not possible to predict the outcome of the following environmental proceedings, if any one or more of them were decided against us, we believe that there would be no material effect on our financial position or results of operations. We are reporting these proceedings to comply with SEC regulations, which require us to disclose certain information about proceedings arising under federal, state, or local provisions regulating the discharge of materials into the environment or protecting the environment if we reasonably believe that such proceedings will result in monetary sanctions of $100,000 or more.

Texas Commission on Environmental Quality (TCEQ) (McKee Refinery). In our quarterly report on Form 10-Q for the quarter ended June 30, 2011, we disclosed that our McKee Refinery had received a proposed agreed order from the TCEQ relating to alleged violations noted during an annual air compliance inspection. In the third quarter of 2011, we settled this matter with the TCEQ.

TCEQ (Three Rivers Refinery). In September 2011, our Three Rivers Refinery received a proposed agreed order that assesses a penalty of $192,663 for various alleged air violations. We believe that we have several defenses to the allegations and are working with the TCEQ to settle this matter.

Item 1A. Risk Factors
There have been no material changes from the risk factors disclosed in our annual report on Form 10-K for the year ended December 31, 2010.




67

Table of Contents

Item 2.
Unregistered Sales of Equity Securities and Use of Proceeds
(a)
Unregistered Sales of Equity Securities. Not applicable.
(b)
Use of Proceeds. Not applicable.
(c)
Issuer Purchases of Equity Securities. The following table discloses purchases of shares of our common stock made by us or on our behalf for the periods shown below.
Period
Total
Number of
Shares
Purchased
Average
Price
Paid per
Share
Total Number of
Shares Not
Purchased as Part
of Publicly
Announced Plans
or Programs (a)
Total Number of
Shares Purchased as
Part of Publicly
Announced Plans
or Programs
Approximate Dollar
Value of Shares that
May Yet Be Purchased
Under the Plans
or Programs (b)
July 2011
9,560

$
26.35

9,560


$3.46 billion
August 2011
10,597,275

$
19.90

10,597,275


$3.46 billion
September 2011
2,936,270

$
19.27

2,936,270


$3.46 billion
Total
13,543,105

$
19.77

13,543,105


$3.46 billion
(a)
The shares reported in this column represent purchases settled in the third quarter of 2011 relating to (a) our purchases of shares in open-market transactions to meet our obligations under employee stock compensation plans, and (b) our purchases of shares from our employees and non-employee directors in connection with the exercise of stock options, the vesting of restricted stock, and other stock compensation transactions in accordance with the terms of our incentive compensation plans.
(b)
On April 26, 2007, we publicly announced an increase in our common stock purchase program from $2 billion to $6 billion, as authorized by our board of directors on April 25, 2007. The $6 billion common stock purchase program has no expiration date. On February 28, 2008, we announced that our board of directors approved a $3 billion common stock purchase program. This program is in addition to the $6 billion program. This $3 billion program has no expiration date.

Item 6. Exhibits
Exhibit No.
Description
 
 
12.01
Statements of Computations of Ratios of Earnings to Fixed Charges and Ratios of Earnings to Fixed Charges and Preferred Stock Dividends.
 
 
31.01
Rule 13a-14(a) Certification (under Section 302 of the Sarbanes-Oxley Act of 2002) of principal executive officer.
 
 
31.02
Rule 13a-14(a) Certification (under Section 302 of the Sarbanes-Oxley Act of 2002) of principal financial officer.
 
 
32.01
Section 1350 Certifications (as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002).
 
 
101
Interactive Data Files




68

Table of Contents

SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

 
 
 
 
 
 
VALERO ENERGY CORPORATION
(Registrant)                    
 
 
By:  
/s/ Michael S. Ciskowski  
 
 
Michael S. Ciskowski 
 
 
Executive Vice President and
 
 
 
Chief Financial Officer
 
 
(Duly Authorized Officer and Principal
 
 
Financial and Accounting Officer) 
Date: November 9, 2011



69