UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

 

Form 10-Q

 

 

Commission file number 1-368-2

Chevron Corporation

(Exact name of registrant as specified in its charter)

 

 

Registrant’s telephone number, including area code: (925) 842-1000

 

NONE

(Former name or former address, if changed since last report.)

 

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 þ     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 such shorter period that the registrant was required to submit and post such files).  Yes o      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. (Check one):

 

(Do not check if a smaller

reporting company)

 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  Yes o     No þ

 

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date:

 

 

 

INDEX

 

 

This quarterly report on Form 10-Q of Chevron Corporation contains forward-looking statements relating to Chevron’s operations that are based on management’s current expectations, estimates and projections about the petroleum, chemicals, and other energy-related industries. Words such as “anticipates,” “expects,” “intends,” “plans,” “targets,” “projects,” “believes,” “seeks,” “schedules,” “estimates,” “budgets” and similar expressions are intended to identify such forward-looking statements. These statements are not guarantees of future performance and are subject to certain risks, uncertainties and other factors, some of which are beyond the company’s control and are difficult to predict. Therefore, actual outcomes and results may differ materially from what is expressed or forecasted in such forward-looking statements. The reader should not place undue reliance on these forward-looking statements, which speak only as of the date of this report. Unless legally required, Chevron undertakes no obligation to update publicly any forward-looking statements, whether as a result of new information, future events or otherwise.

 

Among the important factors that could cause actual results to differ materially from those in the forward-looking statements are crude-oil and natural-gas prices; refining, marketing and chemicals margins; actions of competitors or regulators; timing of exploration expenses; timing of crude-oil liftings; the competitiveness of alternate-energy sources or product substitutes; technological developments; the results of operations and financial condition of equity affiliates; the inability or failure of the company’s joint-venture partners to fund their share of operations and development activities; the potential failure to achieve expected net production from existing and future crude-oil and natural-gas development projects; potential delays in the development, construction or start-up of planned projects; the potential disruption or interruption of the company’s net production or manufacturing facilities or delivery/transportation networks due to war, accidents, political events, civil unrest, severe weather or crude-oil production quotas that might be imposed by OPEC (Organization of Petroleum Exporting Countries); the potential liability for remedial actions or assessments under existing or future environmental regulations and litigation; significant investment or product changes under existing or future environmental statutes, regulations and litigation; the potential liability resulting from pending or future litigation; the company’s acquisition or disposition of assets; gains and losses from asset dispositions or impairments; government-mandated sales, divestitures, recapitalizations, industry-specific taxes, changes in fiscal terms or restrictions on scope of company operations; foreign currency movements compared with the U.S. dollar; the effects of changed accounting rules under generally accepted accounting principles promulgated by rule-setting bodies; and the factors set forth under the heading “Risk Factors” on pages 30 and 31 of the company’s 2008 Annual Report on Form 10-K. In addition, such statements could be affected by general domestic and international economic and political conditions. Unpredictable or unknown factors not discussed in this report could also have material adverse effects on forward-looking statements.

 

 

CHEVRON CORPORATION AND SUBSIDIARIES

 

CONSOLIDATED STATEMENT OF INCOME

 

 

See accompanying notes to consolidated financial statements.

CHEVRON CORPORATION AND SUBSIDIARIES

 

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME

 

 

See accompanying notes to consolidated financial statements.

CHEVRON CORPORATION AND SUBSIDIARIES

 

CONSOLIDATED BALANCE SHEET

 

 

See accompanying notes to consolidated financial statements.

CHEVRON CORPORATION AND SUBSIDIARIES

 

CONSOLIDATED STATEMENT OF CASH FLOWS

 

 

See accompanying notes to consolidated financial statements.

 

 

The accompanying consolidated financial statements of Chevron Corporation and its subsidiaries (the company) have not been audited by an independent registered public accounting firm. In the opinion of the company’s management, the interim data include all adjustments necessary for a fair statement of the results for the interim periods. These adjustments were of a normal recurring nature. The results for the three-month period ended March 31, 2009, are not necessarily indicative of future financial results. The term “earnings” is defined as net income attributable to Chevron Corporation.

 

Certain notes and other information have been condensed or omitted from the interim financial statements presented in this Quarterly Report on Form 10-Q. Therefore, these financial statements should be read in conjunction with the company’s 2008 Annual Report on Form 10-K.

 

In the first quarter 2009, the company recorded after-tax gains of $400 million on the sale of international downstream assets.

 

 

The company adopted FASB Statement No. 160, Noncontrolling Interests in Consolidated Financial Statements, an amendment of ARB No. 51 (FAS 160), effective January 1, 2009, and retroactive to the earliest period presented. Prospectively, certain changes in a parent’s ownership interest are to be accounted for as equity transactions and when a subsidiary is deconsolidated, any noncontrolling equity investment in the former subsidiary is to be initially measured at fair value.

 

With the adoption of FAS 160, ownership interests in the company’s subsidiaries held by parties other than the parent are presented separately from the parent’s equity on the Consolidated Balance Sheet. The amount of consolidated net income attributable to the parent and the noncontrolling interests are both presented on the face of the Consolidated Statement of Income.

 

Shown in the table below is activity for the equity attributable to noncontrolling interests during the first quarters of 2009 and 2008:

 

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

 

The “Net (increase) decrease in operating working capital” was composed of the following operating changes:

 

 

In accordance with the cash-flow classification requirements of FAS 123R, Share-Based Payment, the “Net (increase) decrease in operating working capital” includes reductions of $2 million and $13 million for excess income tax benefits associated with stock options exercised during the three months ended March 31, 2009, and 2008, respectively. These amounts are offset by an equal amount in “Net sales (purchases) of treasury shares.”

 

“Net Cash Provided by Operating Activities” included the following cash payments for interest on debt and for income taxes:

 

 

The “Net sales of marketable securities” consisted of the following gross amounts:

 

 

The “Net sales (purchases) of treasury shares” represents the cost of common shares less the cost of shares issued for share-based compensation plans. Net sales totaled $11 million in the first quarter 2009 and net purchases totaled $1.9 billion in the 2008 period. Purchases in the first quarter 2008 were under the company’s stock repurchase program initiated in September 2007. No purchases were made under the program in the 2009 period.

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

The major components of “Capital expenditures” and the reconciliation of this amount to the capital and exploratory expenditures, including equity affiliates are presented in the following table:

 

 

“Additions to properties, plant and equipment” in the 2009 period includes $2 billion for a cash payment related to the extension of an upstream concession agreement.

 

 

Although each subsidiary of Chevron is responsible for its own affairs, Chevron Corporation manages its investments in these subsidiaries and their affiliates. For this purpose, the investments are grouped as follows: upstream — exploration and production; downstream — refining, marketing and transportation; chemicals; and all other. The first three of these groupings represent the company’s “reportable segments” and “operating segments” as defined in Financial Accounting Standards Board (FASB) Statement No. 131, Disclosures about Segments of an Enterprise and Related Information (FAS 131).

 

The segments are separately managed for investment purposes under a structure that includes “segment managers” who report to the company’s “chief operating decision maker” (CODM) (terms as defined in FAS 131). The CODM is the company’s Executive Committee, a committee of senior officers that includes the Chief Executive Officer, and that in turn reports to the Board of Directors of Chevron Corporation.

 

The operating segments represent components of the company as described in FAS 131 terms that engage in activities (a) from which revenues are earned and expenses are incurred; (b) whose operating results are regularly reviewed by the CODM, which makes decisions about resources to be allocated to the segments and to assess their performance; and (c) for which discrete financial information is available.

 

Segment managers for the reportable segments are directly accountable to and maintain regular contact with the company’s CODM to discuss the segment’s operating activities and financial performance. The CODM approves annual capital and exploratory budgets at the reportable segment level, as well as reviews capital and exploratory funding for major projects and approves major changes to the annual capital and exploratory budgets. However, business-unit managers within the operating segments are directly responsible for decisions relating to project implementation and all other matters connected with daily operations. Company officers who are members of the Executive Committee also have individual management responsibilities and participate in other committees for purposes other than acting as the CODM.

 

“All other” activities include mining operations, power generation businesses, worldwide cash management and debt financing activities, corporate administrative functions, insurance operations, real estate activities, alternative fuels and technology companies.

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

The company’s primary country of operation is the United States of America, its country of domicile. Other components of the company’s operations are reported as “International” (outside the United States).

 

Segment Earnings The company evaluates the performance of its operating segments on an after-tax basis, without considering the effects of debt financing interest expense or investment interest income, both of which are managed by the company on a worldwide basis. Corporate administrative costs and assets are not allocated to the operating segments. However, operating segments are billed for the direct use of corporate services. Nonbillable costs remain at the corporate level in “All Other.” Earnings by major operating area for the three-month period ended March 31, 2009 and 2008 are presented in the following table:

 

Segment Earnings

 

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

Segment Assets Segment assets do not include intercompany investments or intercompany receivables. “All Other” assets in 2009 consist primarily of worldwide cash, cash equivalents and marketable securities, real estate, information systems, mining operations, power generation businesses, technology companies and assets of the corporate administrative functions. Segment assets at March 31, 2009, and December 31, 2008, are as follows:

 

Segment Assets

 

 

Segment Sales and Other Operating Revenues Operating-segment sales and other operating revenues, including internal transfers, for the three-month periods ended March 31, 2009, and 2008, are presented in the following table. Products are transferred between operating segments at internal product values that approximate market prices. Revenues for the upstream segment are derived primarily from the production and sale of crude oil and natural gas, as well as the sale of third-party production of natural gas. Revenues for the downstream segment are derived from the refining and marketing of petroleum products such as gasoline, jet fuel, gas oils, lubricants, residual fuel oils and other products derived from crude oil. This segment also generates revenues from the transportation and trading of crude oil and refined products. Revenues for the chemicals segment are derived primarily from the manufacture and sale of additives for lubricants and fuels. “All Other” activities include revenues from mining operations, power generation businesses, insurance operations, real estate activities and technology companies.

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

Sales and Other Operating Revenues

 

 

 

Chevron U.S.A. Inc. (CUSA) is a major subsidiary of Chevron Corporation. CUSA and its subsidiaries manage and operate most of Chevron’s U.S. businesses. Assets include those related to the exploration and production of crude

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

oil, natural gas and natural gas liquids and those associated with refining, marketing, supply and distribution of products derived from petroleum, excluding most of the regulated pipeline operations of Chevron. CUSA also holds the company’s investment in the Chevron Phillips Chemical Company LLC joint venture, which is accounted for using the equity method.

 

During 2008, Chevron implemented legal reorganizations in which certain Chevron subsidiaries transferred assets to or under CUSA. The summarized financial information for CUSA and its consolidated subsidiaries presented in the table below gives retroactive effect to the reorganizations as if they had occurred on January 1, 2008. However, the financial information below may not reflect the financial position and operating results in the future or the historical results in the period presented if the reorganization actually had occurred on that date.

 

The summarized financial information for CUSA and its consolidated subsidiaries is presented in the table below:

 

 

 

 

Chevron Transport Corporation Limited (CTC), incorporated in Bermuda, is an indirect, wholly owned subsidiary of Chevron Corporation. CTC is the principal operator of Chevron’s international tanker fleet and is engaged in the marine transportation of crude oil and refined petroleum products. Most of CTC’s shipping revenue is derived by providing transportation services to other Chevron companies. Chevron Corporation has fully and unconditionally guaranteed this subsidiary’s obligations in connection with certain debt securities issued by a third party. Summarized financial information for CTC and its consolidated subsidiaries is presented as follows:

 

 

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

 

There were no restrictions on CTC’s ability to pay dividends or make loans or advances at March 31, 2009.

 

 

Taxes on income for the first quarter of 2009 were $1.3 billion, compared with $4.5 billion for the comparable period in 2008. The associated effective tax rates (calculated as the amount of Income Tax Expense divided by Income Before Income Tax Expense) were 42 percent and 46 percent, respectively. The rate in the first quarter of 2009 was lower due to proportionally higher income being earned in international downstream businesses that were taxed at relatively low rates compared with average rates in international upstream tax jurisdictions.

 

 

The company has defined-benefit pension plans for many employees. The company typically prefunds defined-benefit plans as required by local regulations or in certain situations where pre-funding provides economic advantages. In the United States, this includes all qualified plans subject to the Employee Retirement Income Security Act of 1974 (ERISA) minimum funding standard. The company does not typically fund U.S. nonqualified pension plans that are not subject to funding requirements under applicable laws and regulations because contributions to these pension plans may be less economic and investment returns may be less attractive than the company’s other investment alternatives.

 

The company also sponsors other postretirement plans that provide medical and dental benefits, as well as life insurance for some active and qualifying retired employees. The plans are unfunded, and the company and the retirees share the costs. Medical coverage for Medicare-eligible retirees in the company’s main U.S. medical plan is secondary to Medicare (including Part D) and the increase to the company contribution for retiree medical coverage is limited to no more than 4 percent each year. Certain life insurance benefits are paid by the company.

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

The components of net periodic benefit costs for 2009 and 2008 were:

 

 

 

 

At the end of 2008, the company estimated it would contribute $800 million to employee pension plans during 2009 (composed of $550 million for the U.S. plans and $250 million for the international plans). Through March 31, 2009, a total of $91 million was contributed (including $60 million to the U.S. plans). Total estimated contributions for the full year continue to be $800 million, but the company may contribute an amount that differs from this estimate. Actual contribution amounts are dependent upon investment returns, changes in pension obligations, regulatory environments and other economic factors. Additional funding may ultimately be required if investment returns are insufficient to offset increases in plan obligations.

 

During the first quarter 2009, the company made payments of $46 million for other postretirement benefits. The company anticipates payments of $163 million during the remainder of 2009.

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

 

The company accounts for the cost of exploratory wells in accordance with FASB Statement No. 19, Financial Accounting and Reporting by Oil and Gas Producing Companies, as amended by FASB Staff Position FAS 19-1, Accounting for Suspended Well Costs, which provides that an exploratory well continues to be capitalized after the completion of drilling if certain criteria are met. The company’s capitalized cost of suspended wells at March 31, 2009, was $2.2 billion, an increase of $100 million from year-end 2008 due to drilling activities in the United States. For the category of exploratory well costs at year-end 2008 that were suspended more than one year, a total of $48 million was expensed in the first three months of 2009.

 

 

MTBE Chevron and many other companies in the petroleum industry have used methyl tertiary butyl ether (MTBE) as a gasoline additive. Chevron is a party to 36 pending lawsuits and claims, the majority of which involve numerous other petroleum marketers and refiners. Resolution of these lawsuits and claims may ultimately require the company to correct or ameliorate the alleged effects on the environment of prior release of MTBE by the company or other parties. Additional lawsuits and claims related to the use of MTBE, including personal-injury claims, may be filed in the future. The company’s ultimate exposure related to pending lawsuits and claims is not currently determinable, but could be material to net income in any one period. The company no longer uses MTBE in the manufacture of gasoline in the United States.

 

Ecuador Chevron is a defendant in a civil lawsuit before the Superior Court of Nueva Loja in Lago Agrio, Ecuador, brought in May 2003 by plaintiffs who claim to be representatives of certain residents of an area where an oil production consortium formerly had operations. The lawsuit alleges damage to the environment from the oil exploration and production operations, and seeks unspecified damages to fund environmental remediation and restoration of the alleged environmental harm, plus a health monitoring program. Until 1992, Texaco Petroleum Company (Texpet), a subsidiary of Texaco Inc., was a minority member of this consortium with Petroecuador, the Ecuadorian state-owned oil company, as the majority partner; since 1990, the operations have been conducted solely by Petroecuador. At the conclusion of the consortium and following an independent third-party environmental audit of the concession area, Texpet entered into a formal agreement with the Republic of Ecuador and Petroecuador for Texpet to remediate specific sites assigned by the government in proportion to Texpet’s ownership share of the consortium. Pursuant to that agreement, Texpet conducted a three-year remediation program at a cost of $40 million. After certifying that the sites were properly remediated, the government granted Texpet and all related corporate entities a full release from any and all environmental liability arising from the consortium operations.

 

Based on the history described above, Chevron believes that this lawsuit lacks legal or factual merit. As to matters of law, the company believes first, that the court lacks jurisdiction over Chevron; second, that the law under which plaintiffs bring the action, enacted in 1999, cannot be applied retroactively to Chevron; third, that the claims are barred by the statute of limitations in Ecuador; and, fourth, that the lawsuit is also barred by the releases from liability previously given to Texpet by the Republic of Ecuador and Petroecuador. With regard to the facts, the company believes that the evidence confirms that Texpet’s remediation was properly conducted and that the remaining environmental damage reflects Petroecuador’s failure to timely fulfill its legal obligations and Petroecuador’s further conduct since assuming full control over the operations.

 

In April 2008, a mining engineer appointed by the court to identify and determine the cause of environmental damage, and to specify steps needed to remediate it, issued a report recommending that the court assess $8 billion, which would, according to the engineer, provide financial compensation for purported damages, including wrongful death claims, and pay for, among other items, environmental remediation, health care systems, and additional infrastructure for Petroecuador. The engineer’s report also asserted that an additional $8.3 billion could be assessed against Chevron for unjust enrichment. The engineer’s report is not binding on the court. Chevron also believes that the engineer’s work was performed and his report prepared in a manner contrary to law and in violation of the court’s orders. Chevron submitted a rebuttal to the report in which it asked the court to strike the report in its

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

entirety. In November 2008, the engineer revised the report and, without additional evidence, recommended an increase in the financial compensation for purported damages to a total of $18.9 billion and an increase in the assessment for purported unjust enrichment to a total of $8.4 billion. Chevron submitted a rebuttal to the revised report, and Chevron will continue a vigorous defense of any attempted imposition of liability.

 

Management does not believe an estimate of a reasonably possible loss (or a range of loss) can be made in this case. Due to the defects associated with the engineer’s report, management does not believe the report itself has any utility in calculating a reasonably possible loss (or a range of loss). Moreover, the highly uncertain legal environment surrounding the case provides no basis for management to estimate a reasonably possible loss (or a range of loss).

 

 

Guarantees The company and its subsidiaries have certain other contingent liabilities with respect to guarantees, direct or indirect, of debt of affiliated companies or third parties. Under the terms of the guarantee arrangements, generally the company would be required to perform should the affiliated company or third party fail to fulfill its obligations under the arrangements. In some cases, the guarantee arrangements may have recourse provisions that would enable the company to recover any payments made under the terms of the guarantees from assets provided as collateral.

 

Off-Balance-Sheet Obligations The company and its subsidiaries have certain other contractual obligations relating to long-term unconditional purchase obligations and commitments, including throughput and take-or-pay agreements, some of which relate to suppliers’ financing arrangements. The agreements typically provide goods and services, such as pipeline, storage and regasification capacity, drilling rigs, utilities and petroleum products, to be used or sold in the ordinary course of the company’s business.

 

Indemnifications The company provided certain indemnities of contingent liabilities of Equilon and Motiva to Shell and Saudi Refining, Inc., in connection with the February 2002 sale of the company’s interests in those investments. The company would be required to perform if the indemnified liabilities become actual losses. Were that to occur, the company could be required to make future payments up to $300 million. Through the end of March 2009, the company paid $48 million under these indemnities and continues to be obligated for possible additional indemnification payments in the future.

 

The company has also provided indemnities relating to contingent environmental liabilities related to assets originally contributed by Texaco to the Equilon and Motiva joint ventures and environmental conditions that existed prior to the formation of Equilon and Motiva or that occurred during the period of Texaco’s ownership interest in the joint ventures. In general, the environmental conditions or events that are subject to these indemnities must have arisen prior to December 2001. Claims had to be asserted by February 2009 for Equilon indemnities and must be asserted no later than February 2012 for Motiva indemnities. Under the terms of these indemnities, there is no maximum limit on the amount of potential future payments. In February 2009, Shell delivered a letter to the company purporting to preserve unmatured claims for certain Equilon indemnities. The letter itself provides no estimate of the ultimate claim amount, and management does not believe the letter provides a basis to estimate the amount, if any, of a range of loss or potential range of loss with respect to the Equilon or the Motiva indemnities. The company posts no assets as collateral and has made no payments under the indemnities.

 

The amounts payable for the indemnities described above are to be net of amounts recovered from insurance carriers and others and net of liabilities recorded by Equilon or Motiva prior to September 30, 2001, for any applicable incident.

 

In the acquisition of Unocal, the company assumed certain indemnities relating to contingent environmental liabilities associated with assets that were sold in 1997. Under the indemnification agreement, the company’s liability is unlimited until April 2022, when the liability expires. The acquirer of the assets sold in 1997 shares in certain environmental remediation costs up to a maximum obligation of $200 million, which had not been reached as of March 31, 2009.

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

Noncontrolling Interests The company has commitments of $503 million related to noncontrolling interests in subsidiary companies.

 

Environmental The company is subject to loss contingencies pursuant to laws, regulations, private claims and legal proceedings related to environmental matters that are subject to legal settlements or that in the future may require the company to take action to correct or ameliorate the effects on the environment of prior release of chemicals or petroleum substances, including MTBE, by the company or other parties. Such contingencies may exist for various sites, including, but not limited to, federal Superfund sites and analogous sites under state laws, refineries, crude-oil fields, service stations, terminals, land development areas, and mining operations, whether operating, closed or divested. These future costs are not fully determinable due to such factors as the unknown magnitude of possible contamination, the unknown timing and extent of the corrective actions that may be required, the determination of the company’s liability in proportion to other responsible parties, and the extent to which such costs are recoverable from third parties.

 

Although the company has provided for known environmental obligations that are probable and reasonably estimable, the amount of additional future costs may be material to results of operations in the period in which they are recognized. The company does not expect these costs will have a material effect on its consolidated financial position or liquidity. Also, the company does not believe its obligations to make such expenditures have had, or will have, any significant impact on the company’s competitive position relative to other U.S. or international petroleum or chemical companies.

 

Financial Instruments The company believes it has no material market or credit risks to its operations, financial position or liquidity as a result of its commodities and other derivatives activities, including forward-exchange contracts and interest rate swaps.

 

Equity Redetermination For oil and gas producing operations, ownership agreements may provide for periodic reassessments of equity interests in estimated crude-oil and natural-gas reserves. These activities, individually or together, may result in gains or losses that could be material to earnings in any given period. One such equity redetermination process has been under way since 1996 for Chevron’s interests in four producing zones at the Naval Petroleum Reserve at Elk Hills, California, for the time when the remaining interests in these zones were owned by the U.S. Department of Energy. A wide range remains for a possible net settlement amount for the four zones. For this range of settlement, Chevron estimates its maximum possible net before-tax liability at approximately $200 million, and the possible maximum net amount that could be owed to Chevron is estimated at about $150 million. The timing of the settlement and the exact amount within this range of estimates are uncertain.

 

Other Contingencies Chevron receives claims from and submits claims to customers; trading partners; U.S. federal, state and local regulatory bodies; governments; contractors; insurers; and suppliers. The amounts of these claims, individually and in the aggregate, may be significant and take lengthy periods to resolve.

 

The company and its affiliates also continue to review and analyze their operations and may close, abandon, sell, exchange, acquire or restructure assets to achieve operational or strategic benefits and to improve competitiveness and profitability. These activities, individually or together, may result in gains or losses in future periods.

 

 

FASB Statement No. 157, Fair Value Measurements (FAS 157), and its various amendments, establishes a framework for measuring fair value and stipulates disclosures about fair-value measurements. FAS 157 generally applies to recurring and nonrecurring financial and nonfinancial assets and liabilities under other accounting pronouncements that require or permit fair-value measurements. FAS 157 became effective for Chevron on January 1, 2008, for all financial assets and liabilities and recurring nonfinancial assets and liabilities. On January 1, 2009, FAS 157 became effective for nonrecurring nonfinancial assets and liabilities. Among the required

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

disclosures is the fair-value hierarchy of inputs the company uses to value an asset or a liability. The three levels of the fair-value hierarchy are described as follows:

 

Level 1: Quoted prices (unadjusted) in active markets for identical assets and liabilities. For the company, Level 1 inputs include exchange-traded futures contracts for which the parties are willing to transact at the exchange-quoted price and marketable securities that are actively traded.

 

Level 2: Inputs other than Level 1 that are observable, either directly or indirectly. For the company, Level 2 inputs include quoted prices for similar assets or liabilities, prices obtained through third-party broker quotes and prices that can be corroborated with other observable inputs for substantially the complete term of a contract.

 

Level 3: Unobservable inputs. The company does not use Level 3 inputs for any of its recurring fair-value measurements. Level 3 inputs may be required for the determination of fair value associated with certain nonrecurring measurements of nonfinancial assets and liabilities. In the first quarter, the company used Level 3 inputs to determine the fair value of a nonrecurring nonfinancial asset.

 

The fair value hierarchy for recurring assets and liabilities measured at fair value at March 31, 2009, is as follows:

 

Assets and Liabilities Measured at Fair Value on a Recurring Basis

 

 

Marketable securities The company calculates fair value for its marketable securities based on quoted market prices for identical assets and liabilities.

 

Derivatives The company records its derivative instruments — other than any commodity derivative contracts that are designated as normal purchase and normal sale — on the Consolidated Balance Sheet at fair value, with virtually all the offsetting amounts to the Consolidated Statement of Income. For derivatives with identical or similar provisions as contracts that are publicly traded on a regular basis, the company uses the market values of the publicly traded instruments as an input for fair-value calculations.

 

The company’s derivative instruments principally include crude oil, natural gas and refined-product futures, swaps, options and forward contracts, as well as foreign-currency forward contracts. Derivatives classified as Level 1 include futures, swaps and options contracts traded in active markets such as the NYMEX (New York Mercantile Exchange).

 

Derivatives classified as Level 2 include swaps, options, and forward (including foreign currency) contracts principally with financial institutions and other oil and gas companies, the fair values for which are obtained from third party broker quotes, industry pricing services and exchanges. The company obtains multiple sources of pricing information for the Level 2 instruments. Since this pricing information is generated from observable market data, it has historically been very consistent. The company does not materially adjust this information. The company incorporates internal review, evaluation and assessment procedures, including a comparison of Level 2 fair values derived from the company’s internally developed forward curves (on a sample basis) with the pricing information to document reasonable, logical and supportable fair-value determinations and proper level of classification.

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

The fair value hierarchy for nonrecurring assets and liabilities measured at fair value at March 31, 2009, is as follows:

 

Assets and Liabilities Measured at Fair Value on a Non-Recurring Basis

 

 

Impairments of Properties, plant and equipment In accordance with the provisions of FASB Statement No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets (FAS 144), long-lived assets held and used with a carrying amount of $134 million were written down to a fair value of $24 million, resulting in a before-tax loss of $110 million. The fair value was determined by the application of an internal discounted cash-flow model. Cash flows were determined based on company estimates of future production and discounted using an internal rate of return consistent with that used by the company to evaluate cash flows of other assets of a similar nature.

 

Also in accordance with the provisions of FAS 144, long-lived assets held for sale with a carrying amount of $56 million were written down to a fair value of $12 million, resulting in a before-tax loss of $44 million.

 

 

The company implemented FASB Statement No. 161, Disclosures about Derivative Instruments and Hedging Activities, an amendment of FASB Statement No. 133 (FAS 161), as of January 1, 2009.

 

Implementation of FAS 161 did not have any effect on the company’s results of operations or consolidated financial position and similarly had no effect on the company’s existing use of derivative instruments or hedging activities. However, FAS 161 amended and expanded the disclosures required by FAS 133 in order that they provide an enhanced understanding of how and why the company uses derivative instruments, how derivative instruments and related hedged items are accounted for under FAS 133 and its related interpretations, and how derivative instruments affect the company’s financial position, financial performance and cash flows.

 

The company’s derivative instruments principally include crude-oil, natural-gas and refined-product futures, swaps, options and forward contracts, as well as foreign-currency forward contracts. None of the company’s derivative instruments are designated as hedging instruments. The company’s derivatives that are not designated as hedging instruments have no material effect on the company’s financial position, financial performance or cash flows.

 

The company believes it has no material market or credit risks to its operations, financial position or liquidity as a result of its commodities and other derivatives activities, including forward-exchange contracts.

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

Derivative instruments, measured at fair value at March 31, 2009, and their classification on the Consolidated Balance Sheet and Consolidated Statement of Income are as follows:

 

Consolidated Balance Sheet:
Fair Value of Derivatives not Designated as Hedging Instruments

 

 

Consolidated Statement of Income:
The Effect of Derivatives not Designated as Hedging Instruments

 

 

 

At March 31, 2009, the company classified $92 million of net properties, plant and equipment as “Assets held for sale” on the Consolidated Balance Sheet. These assets relate to upstream and downstream and are anticipated to be sold in 2009.

 

 

FASB Staff Position FAS 141(R)-1 Accounting for Assets Acquired and Liabilities Assumed in a Business Combination (FSP FAS 141(R)-1) The FASB issued FSP FAS 141(R)-1 in April 2009, which became effective for business combinations having an acquisition date on or after January 1, 2009. This standard requires an asset or liability arising from a contingency in a business combination to be recognized at fair value if fair value can be reasonably determined. If it cannot, the asset or liability must be recognized in accordance with FASB Statement No. 5, Accounting for Contingencies, and FASB Interpretation No. 14, Reasonable Estimation of the Amount of the Loss.

 

FASB Staff Position No. FAS 157-4, Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly (FSP FAS 157-4) In

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

April 2009, the FASB issued FSP FAS 157-4, which will become effective for the company’s interim and annual reporting beginning in the second quarter 2009. The FSP provides additional guidance related to the estimation of fair value when the volume and level of activity for the asset or liability have significantly decreased, the identification of transactions that are not orderly, and the use of judgment in evaluating the relevance of inputs such as transaction prices. The company does not anticipate the implementation of this new accounting standard will significantly change its valuation or disclosure of financial and nonfinancial assets and liabilities under the scope of FAS 157.

 

FASB Staff Position No. FAS 115-2 and FAS 124-2, Recognition and Presentation of Other-Than-Temporary Impairments (FSP FAS 115-2 and FAS 124-2) The FASB issued FSP FAS 115-2 and FAS 124-2 during April 2009, and the standard became effective as of April 1, 2009. This FSP changes the requirements for recognition and disclosure of other-than-temporary impairment for debt securities and changes the trigger used to assess the collectability of cash flows. The company does not anticipate the implementation of this new accounting standard will significantly change the valuation and disclosure of its investments in debt securities because the securities are primarily short-term, highly liquid, investment-grade instruments.

 

FASB Staff Position No. 107-1 and APB 28-1, Interim Disclosures about Fair Value of Financial Instruments (FSP FAS 107-1 and APB 28-1) The FASB issued FSP FAS 107-1 and APB 28-1 during April 2009 to require the associated disclosures to be presented in both interim and annual reports. The FSP becomes effective for the company’s reporting in the second quarter 2009.

 

First Quarter 2009 Compared With First Quarter 2008

 

Key Financial Results

 

Earnings by Business Segment

 

 

Net income attributable to Chevron Corporation for the first quarter 2009 was $1.8 billion ($0.92 per share — diluted), compared with $5.2 billion ($2.48 per share — diluted) in the corresponding 2008 period.

 

Upstream earnings in the first quarter 2009 were $1.3 billion, compared with $5.1 billion in the 2008 quarter. The decrease between periods was mainly due to sharply lower prices for crude oil and natural gas.

 

Downstream earnings were $823 million in the first quarter 2009, up $571 million from a year earlier. The increase was primarily associated with $400 million of gains on the sale of assets.

 

Chemicals earned $39 million and $43 million for the first quarters of 2009 and 2008, respectively.

 

Refer to pages 27 to 29 for additional discussion of results by business segment and “All Other” activities for the first quarter of 2009 versus the same period in 2008.

 

Business Environment and Outlook

 

Chevron is a global energy company with significant business activities in the following countries: Angola, Argentina, Australia, Azerbaijan, Bangladesh, Brazil, Cambodia, Canada, Chad, China, Colombia, Democratic Republic of the Congo, Denmark, France, Indonesia, Kazakhstan, Myanmar, the Netherlands, Nigeria, Norway, the Partitioned Neutral Zone between Saudi Arabia and Kuwait, the Philippines, Qatar, Republic of the Congo, Singapore, South Africa, South Korea, Thailand, Trinidad and Tobago, the United Kingdom, the United States, Venezuela, and Vietnam.

 

Earnings of the company depend largely on the profitability of its upstream (exploration and production) and downstream (refining, marketing and transportation) business segments. The single biggest factor that affects the results of operations for both segments is movement in the price of crude oil. In the downstream business, crude oil

is the largest cost component of refined products. The overall trend in earnings is typically less affected by results from the company’s chemicals business and other activities and investments. Earnings for the company in any period may also be influenced by events or transactions that are infrequent and/or unusual in nature.

 

In recent years and through most of 2008, Chevron and the oil and gas industry at large experienced an increase in certain costs that exceeded the general trend of inflation in many areas of the world. This increase in costs affected the company’s operating expenses and capital programs for all business segments, but particularly for upstream. These cost pressures began to soften somewhat in late 2008 and into the first quarter 2009. As the price of crude oil dropped precipitously from a record high in mid-year 2008, the demand for some goods and services in the industry began to slacken. This downward cost trend is expected to continue during 2009 if crude-oil prices do not significantly rebound. The company is actively managing its schedule of work and contracting and procurement activities to capture the value associated with this decline in costs. (Refer to the “Upstream” section below for a discussion of the trend in crude-oil prices.)

 

The company’s operations, especially upstream, can also be affected by changing economic, regulatory and political environments in the various countries in which it operates, including the United States. Civil unrest, acts of violence or strained relations between a government and the company or other governments may impact the company’s operations or investments. Those developments have at times significantly affected the company’s operations and results and are carefully considered by management when evaluating the level of current and future activity in such countries.

 

To sustain its long-term competitive position in the upstream business, the company must develop and replenish an inventory of projects that offer adequate financial returns for the investment required. Identifying promising areas for exploration, acquiring the necessary rights to explore for and to produce crude oil and natural gas, drilling successfully, and handling the many technical and operational details in a safe and cost-effective manner are all important factors in this effort. Projects often require long lead times and large capital commitments. From time to time, certain governments have sought to renegotiate contracts or impose additional costs on the company. Governments may attempt to do so in the future. The company will continue to monitor these developments, take them into account in evaluating future investment opportunities, and otherwise seek to mitigate any risks to the company’s current operations or future prospects.

 

The company also continually evaluates opportunities to dispose of assets that are not expected to provide sufficient long-term value or to acquire assets or operations complementary to its asset base to help augment the company’s growth. Refer to the “Results of Operations” section beginning on page 27 for discussions of net gains on asset sales during the first quarter 2009. Asset dispositions and restructurings may occur in future periods and could result in significant gains or losses.

 

The company continues to closely monitor developments in the financial and credit markets, the general contraction of worldwide economic activity and the implications to the company from weakness in prices for crude oil and natural gas. Management is taking these developments into account in the conduct of daily operations and for business planning. The company remains confident of its underlying financial strength to deal with potential problems presented in this environment. (Refer also to discussion of the company’s liquidity and capital resources on page 31.)

 

Comments related to earnings trends for the company’s major business areas are as follows:

 

Upstream Earnings for the upstream segment are closely aligned with industry price levels for crude oil and natural gas. Crude-oil and natural-gas prices are subject to external factors over which the company has no control, including product demand connected with global economic conditions, industry inventory levels, production quotas imposed by the Organization of Petroleum Exporting Countries (OPEC), weather-related damage and disruptions, competing fuel prices, and regional supply interruptions or fears thereof that may be caused by military conflicts, civil unrest or political uncertainty. Moreover, any of these factors could also inhibit the company’s production capacity in an affected region. The company monitors developments closely in the countries in which it operates and holds investments, and attempts to manage risks in operating its facilities and business. Besides the impact of the fluctuation in prices for crude oil and natural gas, the longer-term trend in earnings for the upstream segment is

also a function of other factors, including the company’s ability to find or acquire and efficiently produce crude oil and natural gas, changes in fiscal terms of contracts and changes in tax rates on income.

 

Price levels for capital and exploratory costs and operating expenses associated with the efficient production of crude oil and natural gas can also be subject to external factors beyond the company’s control. External factors include not only the general level of inflation but also prices charged by the industry’s material- and service-providers, which can be affected by the volatility of the industry’s own supply-and-demand conditions for such materials and services. Capital and exploratory expenditures and operating expenses also can be affected by damages to production facilities caused by severe weather or civil unrest. The chart below shows the trend in benchmark prices for West Texas Intermediate (WTI) crude oil and U.S Henry Hub natural gas. During 2008, industry price levels for WTI averaged $100 per barrel. The WTI price peaked at $147 in July 2008 and fell sharply to $45 at the end of the year. The WTI price in the first quarter 2009 averaged $43 and ended April at $51. The decline in prices from mid-2008 is largely associated with a weakening in global economic conditions and a reduction in the demand for crude oil. In an April 2009 report, the International Energy Agency (IEA) predicted global demand for crude oil in 2009 would decline nearly 3 percent from the 2008 level of consumption. Such a contraction in demand would be the most severe since the early 1980s.

 

 

In contrast to price movements in the global market for crude oil, price changes for natural gas in many regional markets are more closely aligned with supply and demand conditions in those markets. Prices at Henry Hub averaged $4 per thousand cubic feet (MCF) in the first quarter 2009, compared with almost $9 for the first three months and for the full-year 2008. At the end of April 2009, the Henry Hub spot price was about $3.25 per MCF. Fluctuations in the price for natural gas in the United States are closely associated with the volumes produced in North America and the level of inventory in underground storage relative to customer demand. The lower U.S. price levels in 2009 are also associated with a softening in demand as a result of the economic slowdown. In an April 2009 report, the U.S. Energy Information Administration (EIA) forecasted natural-gas demand in the United States would be nearly two percent lower than in 2008.

 

Certain other regions of the world in which the company operates have different supply, demand and regulatory circumstances, which until recently have resulted in significantly lower average sales prices than in the United States for the company’s production of natural gas. As a result of the U.S. natural gas supply-and-demand conditions in the first quarter 2009, the company’s U.S. and international realizations were about the same. (Refer to page 31 for the company’s average natural gas realizations for the U.S. and international regions.)

 

In the first quarter 2009, the company’s worldwide net oil-equivalent production averaged 2.66 million barrels per day. During the period, net oil production was constrained by about 50,000 barrels per day due to quotas imposed by OPEC. About one-fifth of the company’s net oil-equivalent production in the first quarter occurred in the OPEC-member countries of Angola, Nigeria and Venezuela and in the Partitioned Neutral Zone between Saudi Arabia and Kuwait. In the United States during the first quarter 2009, approximately 35,000 barrels of oil-equivalent production remained offline as a result of damage caused by hurricanes in the Gulf of Mexico last September. Restoration of these volumes is expected to occur as repairs to third-party pipelines and production facilities are completed.

The production outlook for 2009 and beyond is subject to many factors and uncertainties, including additional quotas that may be imposed by OPEC, price effects on production volumes calculated under cost-recovery and variable-royalty provisions of certain contracts, changes in fiscal terms or restrictions on the scope of company operations, delays in project startups, fluctuations in demand for natural gas in various markets, weather conditions that may shut in production, civil unrest, changing geopolitics, or other disruptions to operations. The outlook for future production levels also is affected by the size and number of economic investment opportunities and, for new large-scale projects, the time lag between initial exploration and the beginning of production. A significant majority of Chevron’s upstream investment is currently being made outside the United States. Investments in upstream projects generally begin well in advance of the start of the associated crude-oil and natural-gas production.

 

Refer to the Results of Operations on pages 27 through 28 for additional discussion of the company’s upstream business.

 

Downstream Earnings for the downstream segment are closely tied to margins on the refining and marketing of products that include gasoline, diesel, jet fuel, lubricants, fuel oil and feedstocks for chemical manufacturing. Industry margins are sometimes volatile and can be affected by the global and regional supply-and-demand balance for refined products and by changes in the price of crude oil used for refinery feedstock. Industry margins can also be influenced by refined-product inventory levels, geopolitical events, refinery maintenance programs and disruptions at refineries resulting from unplanned outages that may be due to severe weather, fires or other operational events.

 

Other factors affecting profitability for downstream operations include the reliability and efficiency of the company’s refining and marketing network, the effectiveness of the crude-oil and product-supply functions and the economic returns on invested capital. Profitability can also be affected by the volatility of tanker-charter rates for the company’s shipping operations, which are driven by the industry’s demand for crude-oil and product tankers. Other factors beyond the company’s control include the general level of inflation and energy costs to operate the company’s refinery and distribution network.

 

The company’s most significant marketing areas are the West Coast of North America, the U.S. Gulf Coast, Latin America, Asia, southern Africa and the United Kingdom. Chevron operates or has ownership interests in refineries in each of these areas, except Latin America. As part of its downstream strategy to focus on areas of market strength, the company announced plans to sell marketing businesses in several countries. Refer to the discussion in “Operating Developments” below.

 

The company’s refining and marketing margins in the first quarter 2009 were generally weak, as demand for refined products in most areas was dampened by the economic slowdown and refined-product supplies in most areas were plentiful.

 

Refer to the Results of Operations on page 28 for additional discussion of the company’s downstream operations.

 

Chemicals Earnings in the petrochemicals business are closely tied to global chemical demand, industry inventory levels and plant capacity utilization. Feedstock and fuel costs, which tend to follow crude-oil and natural-gas price movements, also influence earnings in this segment.

 

Refer to the Results of Operations on page 28 for additional discussion of chemical earnings.

 

Operating Developments

 

Noteworthy operating developments for the upstream business in recent months included the following:

 

 

 

In the downstream business, the company finalized sales of marketing businesses in Brazil, Nigeria, Uganda and Benin.

 

Results of Operations

 

Business Segments The following section presents the results of operations for the company’s business segments — upstream, downstream and chemicals — as well as for “all other” — the departments and companies managed at the corporate level. (Refer to Note 4 beginning on page 9 for a discussion of the company’s “reportable segments,” as defined in FAS 131, Disclosures about Segments of an Enterprise and Related Information.)

 

Upstream

 

 

U.S. upstream earnings of $21 million in the first quarter 2009 decreased $1.58 billion from a year earlier due mainly to sharply lower prices for crude oil and natural gas. The 2009 quarter also included about $100 million of write-offs associated with exploration activities.

 

The average realization for crude oil and natural gas liquids in the first quarter of 2009 was about $36 per barrel, compared with $87 a year earlier. The average natural-gas realization was $4.14 per thousand cubic feet in the 2009 quarter, compared with $7.55 in the year-ago period.

 

Net oil-equivalent production was 671,000 barrels per day in the first quarter 2009, down 44,000 from a year earlier due mainly to production shut-in due to damage caused by hurricanes in the Gulf of Mexico last September and normal field declines. Partially offsetting these effects was an increase of 35,000 barrels per day between periods that was associated with the late-2008 start-up of the Blind Faith project in the Gulf of Mexico. The net liquids component of oil-equivalent production increased about 1 percent between quarters to 441,000 barrels per day. Net natural-gas production declined 17 percent for the quarter to 1.38 billion cubic feet per day, with nearly half the decline associated with the hurricane effects.

 

 

International upstream earnings of $1.25 billion in the first quarter 2009 decreased $2.28 billion from a year ago due mainly to lower prices for crude oil. An approximate $400 million benefit between periods from higher sales volumes was largely offset by higher depreciation expenses. Foreign-currency effects increased earnings by $33 million in the 2009 quarter, compared with a reduction of $167 million a year earlier.

 

The average realization for crude oil and natural gas liquids for the first quarter 2009 was about $39 per barrel, versus $86 in the 2008 period. The average natural-gas realization in the 2009 first quarter was $4.21 per thousand cubic feet, down from $4.83 in the first quarter last year.

 

Net oil-equivalent production was 1.99 million barrels per day in the first quarter 2009, up about 6 percent from a year earlier. The increase included about 150,000 barrels per day of production associated with the mid-2008 start-up at Agbami in Nigeria and the expansion project at Tengiz in Kazakhstan. The impact of lower prices on cost-recovery volumes and other contractual provisions affecting Chevron’s share of production resulted in a net

increase of about 50,000 barrels per day between periods. This increase was offset by about the same volume of OPEC-related curtailments. The net liquids component of oil-equivalent production was 1.38 million barrels per day in the first quarter 2009, up 10 percent from the year-ago quarter. Net natural-gas production of 3.64 billion cubic feet per day in the first quarter 2009 decreased about 3 percent between periods.

 

Downstream

 

 

U.S. downstream earnings of $133 million in the first quarter 2009 increased $129 million on a slight improvement in refined-product margins from the depressed level a year ago.

 

Crude-oil inputs to the company’s refineries were 938,000 barrels per day in the first quarter 2009, up about 5 percent from a year earlier when the crude unit at the refinery in Pascagoula, Mississippi, was down for part of the quarter. Refined-product sales volumes of 1.40 million barrels per day in the 2009 first quarter were down 2 percent from the corresponding 2008 quarter. Branded gasoline sales for the first quarter 2009 were 613,000 barrels per day, up 2 percent.