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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
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R | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended March 31, 2011
OR
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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)
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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.
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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 April 29, 2011 was 570,250,193.
VALERO ENERGY CORPORATION AND SUBSIDIARIES
INDEX
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EX-12.01 |
EX-31.01 |
EX-31.02 |
EX-32.01 |
EX-101 INSTANCE DOCUMENT |
EX-101 SCHEMA DOCUMENT |
EX-101 CALCULATION LINKBASE DOCUMENT |
EX-101 LABELS LINKBASE DOCUMENT |
EX-101 PRESENTATION LINKBASE DOCUMENT |
EX-101 DEFINITION LINKBASE DOCUMENT |
PART I – FINANCIAL INFORMATION
Item 1. Financial Statements
VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Millions of Dollars, Except Par Value)
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| | | | | | | |
| March 31, 2011 | | December 31, 2010 |
| (Unaudited) | | |
ASSETS | | | |
Current assets: | | | |
Cash and temporary cash investments | $ | 4,133 | | | $ | 3,334 | |
Receivables, net | 5,858 | | | 4,583 | |
Inventories | 4,338 | | | 4,947 | |
Income taxes receivable | 316 | | | 343 | |
Deferred income taxes | 262 | | | 190 | |
Prepaid expenses and other | 149 | | | 121 | |
Total current assets | 15,056 | | | 13,518 | |
Property, plant and equipment, at cost | 29,404 | | | 28,921 | |
Accumulated depreciation | (6,509 | ) | | (6,252 | ) |
Property, plant and equipment, net | 22,895 | | | 22,669 | |
Intangible assets, net | 225 | | | 224 | |
Deferred charges and other assets, net | 1,416 | | | 1,210 | |
Total assets | $ | 39,592 | | | $ | 37,621 | |
LIABILITIES AND STOCKHOLDERS’ EQUITY | | | |
Current liabilities: | | | |
Current portion of debt and capital lease obligations | $ | 312 | | | $ | 822 | |
Accounts payable | 8,653 | | | 6,441 | |
Accrued expenses | 729 | | | 590 | |
Taxes other than income taxes | 517 | | | 671 | |
Income taxes payable | 55 | | | 3 | |
Deferred income taxes | 140 | | | 257 | |
Total current liabilities | 10,406 | | | 8,784 | |
Debt and capital lease obligations, less current portion | 7,517 | | | 7,515 | |
Deferred income taxes | 4,693 | | | 4,530 | |
Other long-term liabilities | 1,752 | | | 1,767 | |
Commitments and contingencies | | | |
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 | 7,641 | | | 7,704 | |
Treasury stock, at cost; 103,498,265 and 105,113,545 common shares | (6,361 | ) | | (6,462 | ) |
Retained earnings | 13,458 | | | 13,388 | |
Accumulated other comprehensive income | 479 | | | 388 | |
Total stockholders’ equity | 15,224 | | | 15,025 | |
Total liabilities and stockholders’ equity | $ | 39,592 | | | $ | 37,621 | |
See Condensed Notes to Consolidated Financial Statements.
VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(Millions of Dollars, Except Per Share Amounts)
(Unaudited)
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| Three Months Ended March 31, |
| 2011 | | 2010 |
Operating revenues (a) | $ | 26,308 | | | $ | 18,493 | |
Costs and expenses: | | | |
Cost of sales | 24,568 | | | 17,056 | |
Operating expenses: | | | |
Refining | 744 | | | 764 | |
Retail | 162 | | | 152 | |
Ethanol | 95 | | | 80 | |
General and administrative expenses | 130 | | | 97 | |
Depreciation and amortization expense | 365 | | | 340 | |
Total costs and expenses | 26,064 | | | 18,489 | |
Operating income | 244 | | | 4 | |
Other income, net | 17 | | | 11 | |
Interest and debt expense: | | | |
Incurred | (144 | ) | | (147 | ) |
Capitalized | 27 | | | 20 | |
Income (loss) from continuing operations before income tax expense (benefit) | 144 | | | (112 | ) |
Income tax expense (benefit) | 40 | | | (32 | ) |
Income (loss) from continuing operations | 104 | | | (80 | ) |
Loss from discontinued operations, net of income taxes | (6 | ) | | (33 | ) |
Net income (loss) | $ | 98 | | | $ | (113 | ) |
Earnings (loss) per common share: | | | |
Continuing operations | $ | 0.18 | | | $ | (0.14 | ) |
Discontinued operations | (0.01 | ) | | (0.06 | ) |
Total | $ | 0.17 | | | $ | (0.20 | ) |
Weighted-average common shares outstanding (in millions) | 566 | | | 562 | |
Earnings (loss) per common share – assuming dilution: | | | |
Continuing operations | $ | 0.18 | | | $ | (0.14 | ) |
Discontinued operations | (0.01 | ) | | (0.06 | ) |
Total | $ | 0.17 | | | $ | (0.20 | ) |
Weighted-average common shares outstanding – assuming dilution (in millions) | 573 | | | 562 | |
Dividends per common share | $ | 0.05 | | | $ | 0.05 | |
______________________________
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Supplemental information: | | | |
(a) Includes excise taxes on sales by our U.S. retail system | $ | 214 | | | $ | 208 | |
See Condensed Notes to Consolidated Financial Statements.
VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Millions of Dollars)
(Unaudited)
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| Three Months Ended March 31, |
| 2011 | | 2010 |
Cash flows from operating activities: | | | |
Net income (loss) | $ | 98 | | | $ | (113 | ) |
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | | | |
Depreciation and amortization expense | 365 | | | 357 | |
Noncash interest expense and other income, net | 7 | | | (1 | ) |
Stock-based compensation expense | 12 | | | 12 | |
Deferred income tax expense (benefit) | (44 | ) | | 17 | |
Changes in current assets and current liabilities | 1,603 | | | 753 | |
Changes in deferred charges and credits and other operating activities, net | 17 | | | (43 | ) |
Net cash provided by operating activities | 2,058 | | | 982 | |
Cash flows from investing activities: | | | |
Capital expenditures | (438 | ) | | (382 | ) |
Deferred turnaround and catalyst costs | (299 | ) | | (229 | ) |
Advance payment related to acquisition of refinery | (37 | ) | | — | |
Acquisitions of ethanol plants | — | | | (260 | ) |
Other investing activities, net | (9 | ) | | 15 | |
Net cash used in investing activities | (783 | ) | | (856 | ) |
Cash flows from financing activities: | | | |
Non-bank debt: | | | |
Borrowings | — | | | 1,244 | |
Repayments | (510 | ) | | (294 | ) |
Accounts receivable sales program: | | | |
Proceeds from the sale of receivables | — | | | 1,225 | |
Repayments | — | | | (1,225 | ) |
Purchase of common stock for treasury | — | | | (1 | ) |
Issuance of common stock in connection with stock-based compensation plans | 21 | | | 4 | |
Common stock dividends | (28 | ) | | (28 | ) |
Debt issuance costs | — | | | (10 | ) |
Other financing activities, net | 5 | | | 1 | |
Net cash provided by (used in) financing activities | (512 | ) | | 916 | |
Effect of foreign exchange rate changes on cash | 36 | | | 20 | |
Net increase in cash and temporary cash investments | 799 | | | 1,062 | |
Cash and temporary cash investments at beginning of period | 3,334 | | | 825 | |
Cash and temporary cash investments at end of period | $ | 4,133 | | | $ | 1,887 | |
See Condensed Notes to Consolidated Financial Statements.
VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Millions of Dollars)
(Unaudited)
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| Three Months Ended March 31, |
| 2011 | | 2010 |
Net income (loss) | $ | 98 | | | $ | (113 | ) |
Other comprehensive income (loss): | | | |
Foreign currency translation adjustment | 92 | | | 101 | |
Pension and other postretirement benefits: | | | |
Net gain reclassified into income, net of income tax expense of $1 and $- | (1 | ) | | (1 | ) |
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Derivative instruments designated and qualifying as cash flow hedges: | | | |
Net loss arising during the period, net of income tax benefit of $- and $1 | — | | | (1 | ) |
Net gain reclassified into income, net of income tax expense of $- and $17 | — | | | (32 | ) |
Net loss on cash flow hedges | — | | | (33 | ) |
Other comprehensive income | 91 | | | 67 | |
Comprehensive income (loss) | $ | 189 | | | $ | (46 | ) |
See Condensed Notes to Consolidated Financial Statements.
VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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1. | BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES |
Basis of Presentation
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 months ended March 31, 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 months ended March 31, 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 the audited financial statements as of that date. For further information, refer to the 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 March 31, 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 our financial statements.
Significant Accounting Policies
Reclassifications
In December 2010, we sold our Paulsboro Refinery to PBF Holding Company LLC. The results of operations of the Paulsboro Refinery for the three months ended March 31, 2010, therefore, have been presented as discontinued operations in the consolidated statement of income and are shown below (in millions):
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Operating revenues | | $ | 1,150 | |
Loss before income taxes | | (36 | ) |
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 $21 million for the three months ended March 31, 2010.
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.
VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
New Accounting Pronouncement
In January 2011, the provisions of Accounting Standards Codification (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 2010, 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 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 is not expected to materially affect our financial position or results of operations.
On March 10, 2011, we agreed to acquire 100 percent of the stock of Chevron Limited, which owns and operates the Pembroke Refinery in Wales, United Kingdom, from a subsidiary of Chevron Corporation. The Pembroke Refinery has a total throughput capacity of 270,000 barrels per day of which 220,000 barrels per day is crude capacity. Directly and through various subsidiaries, Chevron Limited also owns extensive marketing and logistics assets throughout the United Kingdom and Ireland. The purchase price for this acquisition is $730 million, plus working capital, which has an estimated value of $1 billion based on current market prices, although the final value will be determined at closing. We expect to fund the transaction from available cash and to close the transaction in the third quarter of 2011, subject to regulatory approvals.
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 decided to restart our Aruba Refinery due to improvements in the U.S. and worldwide economies during 2010 and the resulting improvement in refining industry fundamentals, both of which continued to improve during the first three months of 2011. Despite these improvements and the restart of the refinery, we evaluated our Aruba Refinery for potential impairment as of March 31, 2011 because of its recent temporary shutdown and the sensitivity of its profitability to sour crude oil differentials. The price of sour crude oil is generally less than the price of sweet crude oil, and that price difference is referred to as the sour crude oil differential. Sour crude oil differentials have improved along with other refining industry fundamentals. We considered these positive developments in our impairment evaluation and concluded that our Aruba Refinery was not impaired as of March 31, 2011. Our cash flow estimates for the refinery are based on our expectation that sour crude oil differentials will continue to improve in connection with an increase in the demand for refined products and the increased production of sour crude oils. Should differentials fail to widen or fail to widen to amounts experienced in prior years, our 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 $967 million as of March 31, 2011; therefore, an impairment loss could be material to our results of operations.
VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Inventories consisted of the following (in millions):
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| March 31, 2011 | | December 31, 2010 |
Refinery feedstocks | $ | 2,810 | | | $ | 2,225 | |
Refined products and blendstocks | 988 | | | 2,233 | |
Ethanol feedstocks and products | 250 | | | 201 | |
Convenience store merchandise | 100 | | | 101 | |
Materials and supplies | 190 | | | 187 | |
Inventories | $ | 4,338 | | | $ | 4,947 | |
As of March 31, 2011 and December 31, 2010, the replacement cost (market value) of LIFO inventories exceeded their LIFO carrying amounts by approximately $8.5 billion and $6.1 billion, respectively.
Non-Bank Debt
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. Proceeds from the issuance of these notes totaled $1.244 billion, before deducting underwriting discounts and other issuance costs of $10 million.
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. These notes had a carrying amount of $296 million as of the redemption date, resulting in a $2 million gain that was included in “other income, net.”
In February 2011, we made a scheduled debt repayment of $210 million related to our 6.75% senior notes. Also 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.
On May 2, 2011, we made a scheduled debt repayment of $200 million related to our 6.125% senior notes.
Bank 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 March 31, 2011 and December 31, 2010, our debt-to-capitalization ratios, calculated in accordance with the terms of the Revolver, were 19.5 percent and 25.0 percent, respectively. We believe that we will remain in compliance with this covenant.
VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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 credits up to C$115 million.
During the three months ended March 31, 2011 and 2010, we had no borrowings or repayments under our Revolver or the Canadian revolving credit facility. As of March 31, 2011 and December 31, 2010, we had no borrowings outstanding under the Revolver or the Canadian revolving credit facility.
We had outstanding letters of credit under our committed lines of credit as follows (in millions):
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| | Borrowing Capacity | | Expiration | | March 31, 2011 | | December 31, 2010 |
Letter of credit facility | | $200 | | June 2011 | | $200 | | $— |
Letter of credit facility | | $300 | | June 2011 | | $— | | $100 |
Revolver | | $2,400 | | November 2012 | | $80 | | $399 |
Canadian revolving credit facility | | C$115 | | December 2012 | | C$20 | | C$20 |
We anticipate that we will be able to renew or replace the June 2011 credit facilities prior to their expiration.
As of March 31, 2011 and December 31, 2010, we had $329 million and $176 million, respectively, of letters of credit outstanding under our uncommitted short-term bank credit facilities.
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 2010 to extend the maturity date to June 2011. As of March 31, 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 three months ended March 31, 2011. During the three months ended March 31, 2010, we sold and repaid $1.2 billion of eligible receivables to the third-party entities and financial institutions. Proceeds from the sale of receivables under this facility are reflected as debt. We anticipate that we will be able to renew this facility prior to its expiration in June 2011.
Other Disclosures
The estimated fair value of our debt, including the current portion, was as follows (in millions):
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| March 31, 2011 | | December 31, 2010 |
Carrying amount (excluding capital leases) | $ | 7,793 | | | $ | 8,300 | |
Fair value | 8,872 | | | 9,492 | |
The carrying amount of our debt is the amount of debt that is reflected on our consolidated balance sheets. The fair value of that debt is based on quoted prices in active markets or quoted prices for debt of other companies with similar credit ratings, interest rates, and terms.
VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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6. | COMMITMENTS AND CONTINGENCIES |
Environmental Matters
While debate continues in the U.S. Congress regarding greenhouse gas legislation, the regulation of greenhouse gases at the federal level has now shifted to the U.S. Environmental Protection Agency (EPA), which 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 have pursued independent regulation of greenhouse gases at the state level. 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 state-wide 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 state-wide cap-and-trade program will begin in 2012. 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 be significant, particularly 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.
VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Litigation Matters
Retail Fuel Temperature Litigation
In 2006, a class action complaint was filed against us and several other defendants engaged in the retail and wholesale petroleum marketing business. The complaint alleges that because fuel volume increases with fuel temperature, the defendants violated state consumer protection laws by failing to adjust the volume or price of fuel when the fuel temperature exceeded 60 degrees Fahrenheit. The complaints seek to certify classes of retail consumers who purchased fuel in various locations. The complaints seek an order compelling the installation of temperature correction devices as well as monetary relief. Following the 2006 complaint, numerous other federal complaints were filed, and there are now a total of 46 lawsuits of which 21 involve us. (We are named in classes involving several states where we have no retail presence.) The lawsuits are consolidated into a multi-district litigation case in the U.S. District Court for the District of Kansas (Kansas City) (Multi-District Litigation Docket No. 1840, In re: Motor Fuel Temperature Sales Practices Litigation). In May 2010, the court issued an order in response to the plaintiffs’ motion for class certification of the Kansas cases. The court certified an “injunction class” covering nonmonetary relief but deferred ruling on a “damages class.” The court has scheduled trial in the Kansas cases for May 2012. We anticipate that the non-Kansas cases will be remanded in late 2011 or early 2012 with no additional rulings on the merits or class certification. We are a party to the Kansas cases, but we have no company-owned retail locations in Kansas. We believe that we have several strong defenses to these lawsuits and intend to contest them. We have not recorded a loss contingency liability with respect to this matter, but due to the inherent uncertainty of litigation, we believe that it is reasonably possible that we may suffer a loss with respect to one or more of the lawsuits. An estimate of the possible loss or range of loss from an adverse result in all or substantially all of these cases cannot reasonably be made.
Other Litigation
We are also a party to additional claims and legal proceedings arising in the ordinary course of business. We believe that there is only a remote likelihood that future costs related to known contingent liabilities related to these legal proceedings would have a material adverse impact on our consolidated results of operations or financial position.
On April 28, 2011, our board of directors declared a regular quarterly cash dividend of $0.05 per common share payable on June 15, 2011 to holders of record at the close of business on May 18, 2011.
VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The components of net periodic benefit cost related to our defined benefit plans were as follows for the three months ended March 31, 2011 and 2010 (in millions):
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| Pension Plans | | Other Postretirement Benefit Plans |
| 2011 | | 2010 | | 2011 | | 2010 |
Components of net periodic benefit cost: | | | | | | | |
Service cost | $ | 23 | | | $ | 22 | | | $ | 3 | | | $ | 3 | |
Interest cost | 21 | | | 20 | | | 6 | | | 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 | $ | 20 | | | $ | 15 | | | $ | 3 | | | $ | 5 | |
Our anticipated contributions to our pension plans during 2011 have not changed from amounts previously disclosed in our consolidated financial statements for the year ended December 31, 2010. There were no contributions made to our pension plans during the three months ended March 31, 2011. During the three months ended March 31, 2010, we contributed $50 million to our pension plans.
VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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9. | EARNINGS (LOSS) PER COMMON SHARE |
Earnings (loss) per common share from continuing operations were computed as follows (dollars and shares in millions, except per share amounts):
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| Three Months Ended March 31, |
| 2011 | | 2010 |
| Restricted Stock | | Common Stock | | Restricted Stock | | Common Stock |
Earnings (loss) per common share from continuing operations: | | | | | | | |
Income (loss) from continuing operations | | | $ | 104 | | | | | $ | (80 | ) |
Less dividends paid: | | | | | | | |
Common stock | | | 28 | | | | | 28 | |
Nonvested restricted stock | | | — | | | | | — | |
Undistributed earnings (loss) | | | $ | 76 | | | | | $ | (108 | ) |
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Weighted-average common shares outstanding | 3 | | | 566 | | | 3 | | | 562 | |
| | | | | | | |
Earnings (loss) per common share from continuing operations: | | | | | | | |
Distributed earnings | $ | 0.05 | | | $ | 0.05 | | | $ | 0.05 | | | $ | 0.05 | |
Undistributed earnings (loss) | 0.13 | | | 0.13 | | | — | | | (0.19 | ) |
Total earnings (loss) per common share from continuing operations | $ | 0.18 | | | $ | 0.18 | | | $ | 0.05 | | | $ | (0.14 | ) |
| | | | | | | |
Earnings (loss) per common share from continuing operations – assuming dilution: | | | | | | | |
Income (loss) from continuing operations | | | $ | 104 | | | | | $ | (80 | ) |
| | | | | | | |
Weighted-average common shares outstanding | | | 566 | | | | | 562 | |
Common equivalent shares: | | | | | | | |
Stock options | | | 5 | | | | | — | |
Performance awards and unvested restricted stock | | | 2 | | | | | — | |
Weighted-average common shares outstanding – assuming dilution | | | 573 | | | | | 562 | |
| | | | | | | |
Earnings (loss) per common share from continuing operations – assuming dilution | | | $ | 0.18 | | | | | $ | (0.14 | ) |
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 (loss) 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 equivalent shares (primarily stock options), which were excluded due to the loss from continuing operations for the three months ended March 31, 2010, and stock options for which the exercise prices were greater than the average market price of our common shares during each respective reporting period.
|
| | | | | |
| Three Months Ended March 31, |
| 2011 | | 2010 |
Common equivalent shares | — | | | 5 | |
Stock options | 6 | | | 14 | |
The following table reflects segment activity related to continuing operations (in millions):
|
| | | | | | | | | | | | | | | | | | | | |
| | Refining | | Retail | | Ethanol | | Corporate | | Total |
Three months ended March 31, 2011: | | | | | | | | | | |
Operating revenues from external customers | | $ | 22,562 | | | $ | 2,684 | | | $ | 1,062 | | | $ | — | | | $ | 26,308 | |
Intersegment revenues | | 1,997 | | | — | | | 48 | | | — | | | 2,045 | |
Operating income (loss) | | 276 | | | 66 | | | 44 | | | (142 | ) | | 244 | |
| | | | | | | | | | |
Three months ended March 31, 2010: | | | | | | | | | | |
Operating revenues from external customers | | 15,747 | | | 2,176 | | | 570 | | | — | | | 18,493 | |
Intersegment revenues | | 1,508 | | | — | | | 55 | | | — | | | 1,563 | |
Operating income (loss) | | (15 | ) | | 71 | | | 57 | | | (109 | ) | | 4 | |
Total assets by reportable segment were as follows (in millions):
|
| | | | | | | |
| March 31, 2011 | | December 31, 2010 |
Refining | $ | 31,619 | | | $ | 30,363 | |
Retail | 1,978 | | | 1,925 | |
Ethanol | 996 | | | 953 | |
Corporate | 4,999 | | | 4,380 | |
Total consolidated assets | $ | 39,592 | | | $ | 37,621 | |
VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
| |
11. | SUPPLEMENTAL CASH FLOW INFORMATION |
In order to determine net cash provided by operating activities, net income (loss) is adjusted by, among other things, changes in current assets and current liabilities as follows (in millions):
|
| | | | | | | |
| Three Months Ended March 31, |
| 2011 | | 2010 |
Decrease (increase) in current assets: | | | |
Receivables, net | $ | (1,258 | ) | | $ | (189 | ) |
Inventories | 622 | | | 168 | |
Income taxes receivable | (25 | ) | | 830 | |
Prepaid expenses and other | 10 | | | 32 | |
Increase (decrease) in current liabilities: | | | |
Accounts payable | 2,143 | | | 155 | |
Accrued expenses | 174 | | | (47 | ) |
Taxes other than income taxes | (160 | ) | | (126 | ) |
Income taxes payable | 97 | | | (70 | ) |
Changes in current assets and current liabilities | $ | 1,603 | | | $ | 753 | |
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 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 |
| |
• | certain differences between consolidated balance sheet changes and the changes reflected above result from translating foreign currency denominated balances at the applicable exchange rate as of each balance sheet date. |
There were no significant noncash investing or financing activities for the three months ended March 31, 2011 and 2010.
VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Cash flows related to interest and income taxes were as follows (in millions):
|
| | | | | | | |
| Three Months Ended March 31, |
| 2011 | | 2010 |
Interest paid in excess of amount capitalized | $ | 77 | | | $ | 56 | |
Income taxes received (paid), net | (3 | ) | | (839 | ) |
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 three months ended March 31, 2010 and are summarized as follows (in millions):
|
| | | |
Cash used in operating activities: | |
Paulsboro Refinery | $ | (3 | ) |
Delaware City Refinery | (12 | ) |
Cash used in investing activities: | |
Paulsboro Refinery | (6 | ) |
Delaware City Refinery | — | |
| |
12. | FAIR VALUE MEASUREMENTS |
General
A fair value hierarchy (Level 1, Level 2, or Level 3) is used to categorize fair value amounts based on the quality of inputs used to measure fair value. Accordingly, fair values determined by Level 1 inputs utilize quoted prices in active markets for identical assets or liabilities. Fair values determined by Level 2 inputs are based on quoted prices for similar assets and liabilities in active markets, and inputs other than quoted prices that are observable for the asset or liability. Level 3 inputs are unobservable inputs for the asset or liability, and include situations where there is little, if any, market activity for the asset or liability. We use appropriate valuation techniques based on the available inputs to measure the fair values of our applicable assets and liabilities. When available, we measure fair value using Level 1 inputs because they generally provide the most reliable evidence of fair value.
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 assets and liabilities measured and recorded at fair value on a recurring basis and indicate the fair value hierarchy of the inputs utilized by us to determine the fair values as of March 31, 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 March 31, 2011 |
| | | | Netting Adjustments | |
Assets: | | | | | | | | | |
Commodity derivative contracts | $ | 9,612 | | | $ | 332 | | | $ | — | | | $ | (9,558 | ) | | $ | 386 | |
Nonqualified benefit plans | 107 | | | — | | | 11 | | | — | | | 118 | |
Liabilities: | | | | | | | | | |
Commodity derivative contracts | 9,242 | | | 518 | | | — | | | (9,558 | ) | | 202 | |
Nonqualified benefit plans | 38 | | | — | | | — | | | — | | | 38 | |
|
| | | | | | | | | | | | | | | | | | | |
| 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 | |
Nonqualified benefit plans | 104 | | | — | | | 10 | | | — | | | 114 | |
Liabilities: | | | | | | | | | |
Commodity derivative contracts | 3,097 | | | 502 | | | — | | | (3,560 | ) | | 39 | |
Nonqualified benefit plans | 36 | | | — | | | — | | | — | | | 36 | |
The valuation methods used to measure our financial instruments at fair value are as follows:
| |
• | Commodity derivative contracts, consisting primarily of exchange-traded futures and swaps, 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. |
| |
• | The nonqualified benefit plan assets and nonqualified benefit plan liabilities 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. |
VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Cash collateral deposits of $692 million and $403 million with brokers under master netting arrangements is included in the fair value of the commodity derivatives reflected in Level 1 as of March 31, 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.
|
| | | | | | | |
| Nonqualified Benefit Plans |
| 2011 | | 2010 |
Three months ended March 31: | | | |
Balance at beginning of period | $ | 10 | | | $ | 10 | |
Total gains included in earnings | 1 | | | — | |
Transfers in and/or out of Level 3 | — | | | — | |
Balance at end of period | $ | 11 | | | $ | 10 | |
The amount of total gains included in earnings attributable to the change in unrealized gains relating to assets still held at end of period | $ | 1 | | | $ | — | |
Non-Recurring Fair Value Measurements
As of March 31, 2011 and December 31, 2010, there were no nonfinancial assets or liabilities that were measured and recorded at fair value on a nonrecurring basis.
VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
| |
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.
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 activity. 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 hedging relationships (hedges 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 contracts are reflected in operating activities in the consolidated statements of cash flows for all periods presented.
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 refining 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 activity is described below.
VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Fair Value Hedges
Fair value hedges are used to hedge 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 March 31, 2011, we had the following outstanding commodity derivative instruments that were entered into to hedge crude oil and refined product inventories. 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 | | 3,599 | |
Futures – short | | 13,767 | |
Cash Flow Hedges
Cash flow hedges are used to hedge 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 March 31, 2011, we had no outstanding commodity derivative instruments that were designated as cash flow hedges.
VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Economic Hedges
Economic hedges are hedges 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 March 31, 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 |
Crude oil and refined products: | | | | |
Swaps – long | | 128,021 | | | 34,500 | |
Swaps – short | | 127,854 | | | 34,500 | |
Futures – long | | 219,361 | | | 2,655 | |
Futures – short | | 212,164 | | | 5,443 | |
Options – long | | 1,802 | | | — | |
Options – short | | 1,800 | | | — | |
Corn: | | | | |
Futures – long | | 11,795 | | | 40 | |
Futures – short | | 53,545 | | | 6,190 | |
Physical purchase contracts – long | | 6,407 | | | 2,144 | |
VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Trading Activities
Derivatives entered into for trading purposes represent commodity derivative instruments held or issued for trading purposes. Our objective in entering into commodity derivative instruments for trading purposes is to take advantage of existing market conditions related to commodities that we perceive as opportunities to benefit our results of operations and cash flows, but for which there are no related physical transactions.
As of March 31, 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 | | 18,390 | | | 600 | |
Swaps – short | | 18,045 | | | 600 | |
Futures – long | | 17,042 | | | 3,608 | |
Futures – short | | 16,789 | | | 3,608 | |
Options – long | | 2,500 | | | — | |
Options – short | | 2,500 | | | — | |
Natural gas: | | | | |
Futures – long | | 2,450 | | | — | |
Futures – short | | 2,300 | | | — | |
Corn: | | | | |
Swaps – long | | 1,790 | | | — | |
Swaps – short | | 6,730 | | | — | |
Futures – long | | 1,500 | | | 20 | |
Futures – short | | 1,500 | | | 20 | |
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.
VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Foreign Currency Risk
We are exposed to exchange rate fluctuations on transactions entered into by our Canadian operations that are denominated in currencies other than the Canadian dollar, which is the functional currency 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 March 31, 2011, we had commitments to purchase $600 million of U.S. dollars and commitments to sell $90 million of U.S. dollars. These commitments matured on or before April 29, 2011.
Fair Values of Derivative Instruments
The following tables provide information about the fair values of our derivative instruments as of March 31, 2011 and December 31, 2010 (in millions) and the line items in the 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.
|
| | | | | | | | | |
| | | Fair Value as of March 31, 2011 |
| Balance Sheet Location | | Asset Derivatives | | Liability Derivatives |
Derivatives designated as hedging instruments | | | | | |
Commodity contracts: | | | | | |
Futures | Receivables, net | | $ | 295 | | | $ | 398 | |
Total | | | $ | 295 | | | $ | 398 | |
| | | | | |
Derivatives not designated as hedging instruments | | | | | |
Commodity contracts: | | | | | |
Futures | Receivables, net | | $ | 8,622 | | | $ | 8,844 | |
Swaps | Receivables, net | | 1 | | | — | |
Swaps | Prepaid expenses and other | | 85 | | | 70 | |
Swaps | Accrued expenses | | 246 | | | 419 | |
Options | Receivables, net | | 3 | | | — | |
Options | Accrued expenses | | — | | | 29 | |
Total | | | $ | 8,957 | | | $ | 9,362 | |
Total derivatives | | | $ | 9,252 | | | $ | 9,760 | |
VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
|
| | | | | | | | | |
| | | Fair Value as of December 31, 2010 |
| Balance Sheet Location | | 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 | |
Total | | | $ | 3,120 | | | $ | 3,345 | |
Total derivatives | | | $ | 3,326 | | | $ | 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 March 31, 2011, we had net receivables related to derivative instruments of $9 million from counterparties in the refining industry and $6 million 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.
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 March 31: | | | | | | | | | | | | |
Commodity contracts | | Cost of sales | | $ | (91 | ) | | $ | (17 | ) | | $ | 86 | | | $ | 16 | | | $ | (5 | ) | | $ | (1 | ) |
For fair value hedges, no component of the derivative instruments’ gains or losses was excluded from the assessment of hedge effectiveness. No amounts were recognized in income for hedged firm commitments that no longer qualify as fair value hedges.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
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 March 31: | | | | | | | | | | | | |
Commodity contracts | | $ | — | | | $ | (2 | ) | | Cost of sales | | $ | — | | | $ | 49 | | | Cost of sales | | $ | — | | | $ | — | |
For cash flow hedges, no component of the derivative instruments’ gains or losses was excluded from the assessment of hedge effectiveness. There was no amount of cumulative after-tax gains on cash flow hedges remaining in accumulated other comprehensive income as of March 31, 2011. For the three months ended March 31, 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.
VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
|
| | | | | | | | | | |
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 March 31: | | | | | | |
Commodity contracts | | Cost of sales | | $ | (299 | ) | | $ | (39 | ) |
Foreign currency contracts | | Cost of sales | | (14 | ) | | (13 | ) |
Total | | | | $ | (313 | ) | | $ | (52 | ) |
Included in the results above for the three months ended March 31, 2011 was a $542 million pre-tax loss on commodity contracts related to the forward sales of refined products.
|
| | | | | | | | | | |
Derivatives Designated as Trading Activities | | Location of Gain or (Loss) Recognized in Income on Derivatives | | Gain or (Loss) Recognized in Income on Derivatives |
| | 2011 | | 2010 |
Three months ended March 31: | | | | | | |
Commodity contracts | | Cost of sales | | $ | 6 | | | $ | (3 | ) |
| |
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; |
| |
• | 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, and elsewhere; |
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• | expectations regarding environmental, tax, and other regulatory initiatives; and |
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• | 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:
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• | 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; |
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• | political and economic conditions in nations that consume refined products, including the United States, and in crude oil producing regions, including the Middle East and South America; |
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• | domestic and foreign demand for, and supplies of, refined products such as gasoline, diesel fuel, jet fuel, home heating oil, and petrochemicals; |
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• | domestic and foreign demand for, and supplies of, crude oil and other feedstocks; |
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• | 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; |
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• | the level of consumer demand, including seasonal fluctuations; |
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• | refinery overcapacity or undercapacity; |
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• | our ability to successfully integrate any acquired businesses into our operations; |
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• | the actions taken by competitors, including both pricing and adjustments to refining capacity in response to market conditions; |
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• | the level of foreign imports of refined products; |
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• | accidents or other unscheduled shutdowns affecting our refineries, machinery, pipelines, or equipment, or those of our suppliers or customers; |
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• | changes in the cost or availability of transportation for feedstocks and refined products; |
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• | the price, availability, and acceptance of alternative fuels and alternative-fuel vehicles; |
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• | the levels of government subsidies for ethanol and other alternative fuels; |
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• | 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; |
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• | lower than expected ethanol margins; |
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• | 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; |
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• | 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; |
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• | 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 AB32) and the EPA’s regulation of greenhouse gases, which may adversely affect our business or operations; |
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• | changes in the credit ratings assigned to our debt securities and trade credit; |
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• | changes in currency exchange rates, including the value of the Canadian dollar relative to the U.S. dollar; and |
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• | 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.
OVERVIEW AND OUTLOOK
For the first quarter of 2011, we reported income from continuing operations of $104 million, or $0.18 per share, compared to a loss from continuing operations of $80 million, or $0.14 per share, for the first quarter of 2010. Included in these results for the first quarter 2011 was a $542 million loss ($352 million after taxes, or $0.61 per share) on commodity derivative contracts related to the forward sales of refined products. These contracts were closed and realized in the first quarter of 2011. The improvement in income from continuing operations in the first quarter of 2011 as compared to the first quarter of 2010 was primarily due to an increase in operating income of $240 million, attributable to the business segments outlined in the following table (in millions):
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| | | | | | | | | | | | |
| | Three Months Ended March 31, |
| | 2011 | | 2010 | | Change |
Operating income (loss) by business segment: | | | | | | |
Refining | | $ | 276 | | | $ | (15 | ) | | $ | 291 | |
Retail | | 66 | | | 71 | | | (5 | ) |
Ethanol | | 44 | | | 57 | | | (13 | ) |
Total before corporate | | 386 | | | 113 | | | 273 | |
Corporate | | (142 | ) | | (109 | ) | | (33 | ) |
Total | | $ | 244 | | | $ | 4 | | | $ | 240 | |
Excluding the impact of the $542 million loss on commodity derivative contracts, operating income for the first quarter of 2011 would have been $786 million, an increase of $782 million over the comparable 2010 period, and refining operating income would have been $818 million for the first quarter of 2011, an increase of $833 million over the comparable 2010 period.
Refining operating income improved primarily due to increased margins for most of the products we produce. In addition, refining operating income benefited 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 difference between the price of waterborne sweet crude oils, such as Louisiana Light Sweet and Brent, and inland sweet crude oils, such as West Texas Intermediate (WTI). Many of our refineries process sour crude oils and WTI-type crude oils and these crude oils were priced significantly below waterborne sweet crudes during the first quarter of 2011, as compared to the first quarter of 2010.
Our retail segment generated operating income of $66 million for the first quarter of 2011 compared to operating income of $71 million for the first quarter of 2010. The decrease in operating income was primarily due to higher operating expenses.
Our ethanol segment generated operating income of $44 million for the first quarter of 2011 compared to operating income of $57 million for the first quarter of 2010. The decrease in operating income was primarily due to increased operating costs related to the full quarter of operations of 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 March 10, 2011, we agreed to acquire 100 percent of the stock of Chevron Limited, which owns and operates the Pembroke Refinery in Wales, United Kingdom, from a subsidiary of Chevron Corporation. Directly and through various subsidiaries, Chevron Limited also owns extensive marketing and logistics assets throughout the United Kingdom and Ireland. The purchase price for this acquisition is $730 million, plus working capital, which has an estimated value of $1 billion based on current market prices, although the final value will be determined at closing. We expect to fund the transaction from available cash and to close the transaction in the third quarter of 2011, subject to regulatory approvals.
We anticipate the U.S. and worldwide economies to continue to recover during 2011, which should have a positive affect on refined product demand. The price of crude oil, however, has increased significantly over the past several months, increasing the absolute price of refined products for our customers. We believe if this rapid and significant increase in price continues, it could be a negative offsetting affect on overall worldwide demand. The overall impact of high energy prices on the U.S. and worldwide economies and our refined product margins is uncertain, and we expect the energy markets and margins to be volatile in the near to mid-term.
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)
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| | | | | | | | | | | |
| Three Months Ended March 31, |
| 2011 | | 2010 | | Change |
Operating revenues | $ | 26,308 | | | $ | 18,493 | | | $ | 7,815 | |
Costs and expenses: | | | | | |
Cost of sales (d) (e) | 24,568 | | | 17,056 | | | 7,512 | |
Operating expenses: | | | | | |
Refining | 744 | | | 764 | | | (20 | ) |
Retail (d) | 162 | | | 152 | | | 10 | |
Ethanol | 95 | | | 80 | | | 15 | |
General and administrative expenses | 130 | | | 97 | | | 33 | |
Depreciation and amortization expense: | | | | | |
Refining | 316 | | | 294 | | | 22 | |
Retail | 28 | | | 26 | | | 2 | |
Ethanol | 9 | | | 8 | | | 1 | |
Corporate | 12 | | | 12 | | | — | |
Total costs and expenses | 26,064 | | | 18,489 | | | 7,575 | |
Operating income | 244 | | | 4 | | | 240 | |
Other income, net | 17 | | | 11 | | | 6 | |
Interest and debt expense: | | | | | |
Incurred | (144 | ) | | (147 | ) | | 3 | |
Capitalized | 27 | | | 20 | | | 7 | |
Income (loss) from continuing operations before income tax expense (benefit) | 144 | | | (112 | ) | | 256 | |
Income tax expense (benefit) | 40 | | | (32 | ) | | 72 | |
Income (loss) from continuing operations | 104 | | | (80 | ) | | 184 | |
Loss from discontinued operations, net of income taxes | (6 | ) | | (33 | ) | | 27 | |
Net income (loss) | $ | 98 | | | $ | (113 | ) | | $ | 211 | |
Earnings (loss) per common share – assuming dilution: | | | | | |
Continuing operations | $ | 0.18 | | | $ | (0.14 | ) | | $ | 0.32 | |
Discontinued operations | (0.01 | ) | | (0.06 | ) | | 0.05 | |
Total | $ | 0.17 | | | $ | (0.20 | ) | | $ | 0.37 | |
________________
See note references on page 36.
Operating Highlights
(millions of dollars, except per barrel and per gallon amounts)
|
| | | | | | | | | | | |
| Three Months Ended March 31, |
| 2011 | | 2010 | | Change |
Refining (a) (b): | | | | | |
Operating income (loss) (e) | $ | 276 | | | $ | (15 | ) | | $ | 291 | |
Throughput margin per barrel (e) (f) | $ | 7.05 | | | $ | 5.98 | | | $ | 1.07 | |
Operating costs per barrel | | | | | |
Operating expenses | 3.93 | | | 4.38 | | | (0.45 | ) |
Depreciation and amortization expense | 1.66 | | | 1.68 | | | (0.02 | ) |
Total operating costs per barrel | 5.59 | | | 6.06 | | | (0.47 | ) |
Operating income (loss) per barrel | $ | 1.46 | | | $ | (0.08 | ) | | $ | 1.54 | |
Throughput volumes (thousand barrels per day): | | | | | |
Feedstocks: | | | | | |
Heavy sour crude | 372 | | | 440 | | | (68 | ) |
Medium/light sour crude | 372 | | | 385 | | | (13 | ) |
Acidic sweet crude | 72 | | | 42 | | | 30 | |
Sweet crude | 666 | | | 588 | | | 78 | |
Residuals | 249 | | | 137 | | | 112 | |
Other feedstocks | 137 | | | 118 | | | 19 | |
Total feedstocks | 1,868 | | | 1,710 | | | 158 | |
Blendstocks and other | 238 | | | 230 | | | 8 | |
Total throughput volumes | 2,106 | | | 1,940 | | | 166 | |
Yields (thousand barrels per day): | | | | | |
Gasolines and blendstocks | 956 | | | 967 | | | (11 | ) |
Distillates | 695 | | | 597 | | | 98 | |
Other products (g) | 465 | | | 398 | | | 67 | |
Total yields | 2,116 | | | 1,962 | | | 154 | |
Retail–U.S.: (d) | | | | | |
Operating income | $ | 19 | | | $ | 33 | | | $ | (14 | ) |
Company-operated fuel sites (average) | 993 | | | 989 | | | 4 | |
Fuel volumes (gallons per day per site) | 4,895 | | | 4,942 | | | (47 | ) |
Fuel margin per gallon | $ | 0.076 | | | $ | 0.108 | | | $ | (0.032 | ) |
Merchandise sales | $ | 283 | | | $ | 272 | | | $ | 11 | |
Merchandise margin (percentage of sales) | 28.3 | % | | 28.2 | % | | 0.1 | % |
Margin on miscellaneous sales | $ | 22 | | | $ | 22 | | | $ | — | |
Operating expenses | $ | 98 | | | $ | 94 | | | $ | 4 | |
Depreciation and amortization expense | $ | 19 | | | $ | 18 | | | $ | 1 | |
Retail–Canada: (d) | | | | | |
Operating income | $ | 47 | | | $ | 38 | | | $ | 9 | |
Fuel volumes (thousand gallons per day) | 3,234 | | | 3,078 | | | 156 | |
Fuel margin per gallon | $ | 0.317 | | | $ | 0.284 | | | $ | 0.033 | |
Merchandise sales | $ | 57 | | | $ | 52 | | | $ | 5 | |
Merchandise margin (percentage of sales) | 29.7 | % | | 30.8 | % | | (1.1 | )% |
Margin on miscellaneous sales | $ | 11 | | | $ | 10 | | | $ | 1 | |
Operating expenses | $ | 64 | | | $ | 58 | | | $ | 6 | |
Depreciation and amortization expense | $ | 9 | | | $ | 8 | | | $ | 1 | |
________________
See note references on page 36.
Operating Highlights (continued)
(millions of dollars, except per gallon amounts)
|
| | | | | | | | | | | |
| Three Months Ended March 31, |
| 2011 | | 2010 | | Change |
Ethanol (c): | | | | | |
Operating income | $ | 44 | | | $ | 57 | | | $ | (13 | ) |
Ethanol production (thousand gallons per day) | 3,282 | | | 2,534 | | | 748 | |
Gross margin per gallon of ethanol production | $ | 0.50 | | | $ | 0.63 | | | $ | (0.13 | ) |
Operating costs per gallon of ethanol production: | | | | | |
Operating expenses | 0.32 | | | 0.35 | | | (0.03 | ) |
Depreciation and amortization expense | 0.03 | | | 0.03 | | | — | |
Total operating costs per gallon of ethanol production | 0.35 | | | 0.38 | | | (0.03 | ) |
Ethanol operating income per gallon of production | $ | 0.15 | | | $ | 0.25 | | | $ | (0.10 | ) |
_______________
See note references on page 36.
Refining Operating Highlights by Region (e) (h)
(millions of dollars, except per barrel amounts)
|
| | | | | | | | | | | |
| Three Months Ended March 31, |
| 2011 | | 2010 | | Change |
Gulf Coast: | | | | | |
Operating income (loss) | $ | 111 | | | $ | (11 | ) | | $ | 122 | |
Throughput volumes (thousand barrels per day) | 1,299 | | | 1,137 | | | 162 | |
Throughput margin per barrel (f) | $ | 6.45 | | | $ | 6.08 | | | $ | 0.37 | |
Operating costs per barrel: | | | | | |
Operating expenses | 3.86 | | | 4.44 | | | (0.58 | ) |
Depreciation and amortization expense | 1.64 | | | 1.74 | | | (0.10 | ) |
Total operating costs per barrel | 5.50 | | | 6.18 | | | (0.68 | ) |
Operating income (loss) per barrel | $ | 0.95 | | | $ | (0.10 | ) | | $ | 1.05 | |
Mid-Continent: | | | | | |
Operating income (loss) | $ | 167 | | | $ | (11 | ) | | $ | 178 | |
Throughput volumes (thousand barrels per day) | 403 | | | 363 | | | 40 | |
Throughput margin per barrel (f) | $ | 9.68 | | | $ | 5.34 | | | $ | 4.34 | |
Operating costs per barrel: | | | | | |
Operating expenses | 3.65 | | | 4.07 | | | (0.42 | ) |
Depreciation and amortization expense | 1.44 | | | 1.60 | | | (0.16 | ) |
Total operating costs per barrel | 5.09 | | | 5.67 | | | (0.58 | ) |
Operating income (loss) per barrel | $ | 4.59 | | | $ | (0.33 | ) | | $ | 4.92 | |
Northeast (a) (b): | | | | | |
Operating income | $ | 56 | | | $ | 38 | | | $ | 18 | |
Throughput volumes (thousand barrels per day) | 209 | | | 178 | | | 31 | |
Throughput margin per barrel (f) | $ | 7.02 | | | $ | 7.77 | | | $ | (0.75 | ) |
Operating costs per barrel: | | | | | |
Operating expenses | 2.81 | | | 3.73 | | | (0.92 | ) |
Depreciation and amortization expense | 1.20 | | | 1.66 | | | (0.46 | ) |
Total operating costs per barrel | 4.01 | | | 5.39 | | | (1.38 | ) |
Operating income per barrel | $ | 3.01 | | | $ | 2.38 | | |