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

                                    Form 8-K

                                 Current Report

     Pursuant to Section 13 of 15(d) of the Securities Exchange Act of 1934

        Date of Report (Date of earliest event reported): March 6, 2000


                               Chevron Corporation
              ----------------------------------------------------
             (Exact name of registrant as specified in its charter)

        Delaware                      1-368-2                 94-0890210
 ---------------------------   ----------------------     -------------------
(State or other jurisdiction  (Commission File Number)   (I.R.S. Employer No.)
        of incorporation )

       575 Market Street, San Francisco, CA                    94105
      --------------------------------------                  --------
     (Address of principal executive offices)                (Zip Code)

       Registrant's telephone number, including area code: (415) 894-7700


                                      NONE
           -----------------------------------------------------------
          (Former name or former address, if changed since last report)

Item 5. Other Events.
        ------------

        Chevron Corporation's Audited 1999 Financial Statements are attached
        as Item 7, Exhibit 99.1.

Item 7. Financial Statements, Pro Forma Financial Information and Exhibits
        ------------------------------------------------------------------

        (c) Exhibits.

            99.1  Chevron Corporation's Audited 1999 Financial Statements.

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SIGNATURE Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized. Dated: March 6, 2000 CHEVRON CORPORATION By /s/ S.J. CROWE ------------------------- S. J. Crowe, Comptroller (Principal accounting Officer and Duly Authorized Officer)


                                                                 Exhibit 99.1

REPORT OF MANAGEMENT

TO THE STOCKHOLDERS OF CHEVRON CORPORATION

Management of Chevron is responsible  for preparing the  accompanying  financial
statements and for ensuring their integrity and objectivity. The statements were
prepared in accordance  with  accounting  principles  generally  accepted in the
United States and fairly represent the  transactions  and financial  position of
the  company.  The  financial  statements  include  amounts  that  are  based on
management's  best estimates and judgments.

The  company's  statements  have been  audited  by  PricewaterhouseCoopers  LLP,
independent  accountants,  selected by the Audit  Committee  and approved by the
stockholders.  Management has made available to  PricewaterhouseCoopers  LLP all
the  company's  financial  records and related  data,  as well as the minutes of
stockholders' and directors' meetings.

Management  of the company has  established  and  maintains a system of internal
accounting controls that is designed to provide reasonable assurance that assets
are safeguarded,  transactions are properly  recorded and executed in accordance
with management's  authorization,  and the books and records  accurately reflect
the disposition of assets. The system of internal controls includes  appropriate
division of  responsibility.  The company maintains an internal audit department
that conducts an extensive program of internal audits and independently assesses
the effectiveness of the internal  controls.

The Audit  Committee is composed of directors  who are not officers or employees
of the company.  It meets  regularly  with members of  management,  the internal
auditors  and  the  independent  accountants  to  discuss  the  adequacy  of the
company's internal controls,  its financial  statements,  and the nature, extent
and results of the audit effort.  Both the internal auditors and the independent
accountants  have free and  direct  access to the Audit  Committee  without  the
presence of management.


/s/ David J. O'Reilly        /s/ Martin R. Klitten        /s/ Stephen J. Crowe
---------------------        ---------------------      ----------------------
David J. O'Reilly            Martin R. Klitten            Stephen J. Crowe
Chairman of the Board        Vice President               Comptroller
and Chief Executive Officer  and Chief Financial Officer

February 23, 2000


REPORT OF INDEPENDENT ACCOUNTANTS

TO THE STOCKHOLDERS
AND THE BOARD OF DIRECTORS OF CHEVRON CORPORATION

In our opinion,  the  accompanying  consolidated  balance  sheet and the related
consolidated  statements of income,  comprehensive income,  stockholders' equity
and cash flows present fairly, in all material respects,  the financial position
of Chevron  Corporation and its  subsidiaries at December 31, 1999 and 1998, and
the results of their operations and their cash flows for each of the three years
in the period ended December 31, 1999, in conformity with accounting  principles
generally  accepted in the United  States.  These  financial  statements are the
responsibility of the company's management;  our responsibility is to express an
opinion on these  financial  statements  based on our audits.  We conducted  our
audits of these  statements in  accordance  with  auditing  standards  generally
accepted in the United States,  which require that we plan and perform the audit
to obtain reasonable  assurance about whether the financial  statements are free
of material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and  disclosures in the financial  statements,  assessing
the accounting principles used and significant estimates made by management, and
evaluating the overall  financial  statement  presentation.  We believe that our
audits provide a reasonable basis for the opinion expressed above.


/s/ PricewaterhouseCoopers LLP

San Francisco, California
February 23, 2000


                                       1

<TABLE> <CAPTION> CONSOLIDATED STATEMENT OF INCOME -------------------------------- Year ended December 31 ----------------------------- Millions of dollars, except per-share amounts 1999 1998 1997 ----------------------------------------------------------------------------------- <S> <C> <C> <C> REVENUES Sales and other operating revenues* ....... $35,448 $29,943 $40,596 Income from equity affiliates .............. 526 228 688 Other income ............................... 612 386 679 ----------------------------------------------------------------------------------- TOTAL REVENUES ...................................... 36,586 30,557 41,963 ----------------------------------------------------------------------------------- COSTS AND OTHER DEDUCTIONS Purchased crude oil and products ........... 17,982 14,036 20,223 Operating expenses ......................... 5,090 4,834 5,280 Selling, general and administrative expenses 1,404 2,239 1,533 Exploration expenses ....................... 538 478 493 Depreciation, depletion and amortization ... 2,866 2,320 2,300 Taxes other than on income* ................ 4,586 4,411 6,320 Interest and debt expense .................. 472 405 312 ----------------------------------------------------------------------------------- TOTAL COSTS AND OTHER DEDUCTIONS .................... 32,938 28,723 36,461 ----------------------------------------------------------------------------------- INCOME BEFORE INCOME TAX EXPENSE .................... 3,648 1,834 5,502 INCOME TAX EXPENSE .................................. 1,578 495 2,246 =================================================================================== NET INCOME .......................................... $ 2,070 $ 1,339 $ 3,256 =================================================================================== NET INCOME PER SHARE OF COMMON STOCK - BASIC ........ $ 3.16 $ 2.05 $ 4.97 - DILUTED ...... $ 3.14 $ 2.04 $ 4.95 =================================================================================== <FN> *Includes consumer excise taxes: .................... $ 3,910 $ 3,756 $ 5,587 See accompanying notes to consolidated financial statements. </FN> </TABLE> <TABLE> <CAPTION> CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME ---------------------------------------------- Year ended December 31 -------------------------------- Millions of dollars ................................. 1999 1998 1997 ------------------------------------------------------------------------------------- <S> <C> <C> <C> NET INCOME .......................................... $ 2,070 $ 1,339 $ 3,256 ------------------------------------------------------------------------------------- Currency translation adjustment ............ (43) (1) (173) Unrealized holding gain (loss) on securities 29 3 (4) Minimum pension liability adjustment ....... (11) (15) 4 ------------------------------------------------------------------------------------- OTHER COMPREHENSIVE INCOME, NET OF TAX .............. (25) (13) (173) ------------------------------------------------------------------------------------- COMPREHENSIVE INCOME ................................ $ 2,045 $ 1,326 $ 3,083 ===================================================================================== <FN> See accompanying notes to consolidated financial statements. </FN> </TABLE> 2

<TABLE> <CAPTION> CONSOLIDATED BALANCE SHEET -------------------------- At December 31 ----------------------- Millions of dollars 1999 1998 ---------------------------------------------------------------------------------------------------- <S> <C> <C> ASSETS Cash and cash equivalents ................................................... $ 1,345 $ 569 Marketable securities ....................................................... 687 844 Accounts and notes receivable (less allowance: 1999 - $36; 1998 - $27) ...... 3,688 2,813 Inventories: Crude oil and petroleum products ................................... 585 600 Chemicals .......................................................... 526 559 Materials, supplies and other ...................................... 291 296 ---------------------- 1,402 1,455 Prepaid expenses and other current assets ................................... 1,175 616 ---------------------------------------------------------------------------------------------------- TOTAL CURRENT ASSETS ........................................................ 8,297 6,297 Long-term receivables ....................................................... 815 872 Investments and advances .................................................... 5,231 4,604 Properties, plant and equipment, at cost .................................... 54,212 51,337 Less: accumulated depreciation, depletion and amortization .................. 28,895 27,608 ---------------------- 25,317 23,729 Deferred charges and other assets ........................................... 1,008 1,038 ---------------------------------------------------------------------------------------------------- TOTAL ASSETS ................................................................ $ 40,668 $ 36,540 ==================================================================================================== LIABILITIES AND STOCKHOLDERS' EQUITY Short-term debt ............................................................. $ 3,434 $ 3,165 Accounts payable ............................................................ 3,103 2,170 Accrued liabilities ......................................................... 1,210 1,202 Federal and other taxes on income ........................................... 718 226 Other taxes payable ......................................................... 424 403 ---------------------------------------------------------------------------------------------------- TOTAL CURRENT LIABILITIES ................................................... 8,889 7,166 Long-term debt .............................................................. 5,174 4,128 Capital lease obligations ................................................... 311 265 Deferred credits and other noncurrent obligations ........................... 1,739 2,560 Noncurrent deferred income taxes ............................................ 5,010 3,645 Reserves for employee benefit plans ......................................... 1,796 1,742 ---------------------------------------------------------------------------------------------------- TOTAL LIABILITIES ........................................................... 22,919 19,506 ---------------------------------------------------------------------------------------------------- Preferred stock (authorized 100,000,000 shares, $1.00 par value, none issued) - - Common stock (authorized 1,000,000,000 shares, $1.50 par value, 712,487,068 shares issued) ........................ 1,069 1,069 Capital in excess of par value .............................................. 2,215 2,097 Deferred compensation ....................................................... (646) (691) Accumulated other comprehensive income ...................................... (115) (90) Retained earnings ........................................................... 17,400 16,942 Treasury stock, at cost (1999 - 56,140,994 shares; 1998 - 59,460,666 shares) (2,174) (2,293) ---------------------------------------------------------------------------------------------------- TOTAL STOCKHOLDERS' EQUITY .................................................. 17,749 17,034 ---------------------------------------------------------------------------------------------------- TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY .................................. $ 40,668 $ 36,540 ==================================================================================================== <FN> See accompanying notes to consolidated financial statements. </FN> </TABLE> 3

<TABLE> <CAPTION> CONSOLIDATED STATEMENT OF CASH FLOWS ------------------------------------ Year ended December 31 ------------------------------------------- Millions of dollars 1999 1998 1997 ------------------------------------------------------------------------------------------------------------------ <S> <C> <C> <C> OPERATING ACTIVITIES Net income ......................................................... $ 2,070 $ 1,339 $ 3,256 Adjustments Depreciation, depletion and amortization ........................... 2,866 2,320 2,300 Dry hole expense related to prior years' expenditures .............. 126 40 31 Distributions (less than) greater than income from equity affiliates (258) 25 (353) Net before-tax gains on asset retirements and sales ................ (471) (45) (344) Net foreign currency losses (gains) ................................ 23 (20) (69) Deferred income tax provision ...................................... 226 266 622 Net decrease (increase) in operating working capital(1) ............ 636 (809) (253) (Decrease) increase in Cities Service provision .................... (149) 924 - Cash settlement of Cities Service litigation ....................... (775) - - Other, net ......................................................... 187 (309) (310) ------------------------------------------------------------------------------------------------------------------ NET CASH PROVIDED BY OPERATING ACTIVITIES(2) ......................... 4,481 3,731 4,880 ------------------------------------------------------------------------------------------------------------------ INVESTING ACTIVITIES Capital expenditures ............................................... (4,366) (3,880) (3,899) Proceeds from asset sales .......................................... 992 434 1,235 Net sales (purchases) of marketable securities(3)................... 262 (183) 101 Other, net ......................................................... 32 (230) (297) ------------------------------------------------------------------------------------------------------------------ NET CASH USED FOR INVESTING ACTIVITIES ............................... (3,080) (3,859) (2,860) ------------------------------------------------------------------------------------------------------------------ FINANCING ACTIVITIES Net borrowings (repayments) of short-term obligations .............. 219 1,713 (163) Proceeds from issuances of long-term debt .......................... 1,221 224 26 Repayments of long-term debt and other financing obligations ....... (549) (388) (421) Cash dividends paid ................................................ (1,625) (1,596) (1,493) Net sales (purchases) of treasury shares ........................... 108 (261) 173 ------------------------------------------------------------------------------------------------------------------ NET CASH USED FOR FINANCING ACTIVITIES ............................... (626) (308) (1,878) ------------------------------------------------------------------------------------------------------------------ EFFECT OF FOREIGN CURRENCY EXCHANGE RATE CHANGES ON CASH AND CASH EQUIVALENTS ....................................... 1 (10) (19) ------------------------------------------------------------------------------------------------------------------ NET CHANGE IN CASH AND CASH EQUIVALENTS .............................. 776 (446) 123 CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR ....................... 569 1,015 892 ------------------------------------------------------------------------------------------------------------------ CASH AND CASH EQUIVALENTS AT YEAR-END ................................ $ 1,345 $ 569 $ 1,015 ================================================================================================================== <FN> See accompanying notes to consolidated financial statements. (1) "Net decrease (increase) in operating working capital" is composed of the following: (Increase) decrease in accounts and notes receivable $ (810) $ 552 $ 474 Decrease (increase) in inventories 72 (116) (11) (Increase) decrease in prepaid expenses and other current assets (43) (23) 59 Increase (decrease) in accounts payable and accrued liabilities 915 (807) (685) Increase (decrease) in income and other taxes payable 502 (415) (90) ------------------------------------------------------------------------------------------------------------------ Net decrease (increase) in operating working capital $ 636 $ (809) $ (253) ================================================================================================================== (2) "Net cash provided by operating activities" includes the following cash payments for interest and income taxes: Interest paid on debt (net of capitalized interest) $ 438 $ 407 $ 318 Income taxes paid $ 864 $ 654 $ 1,706 =================================================================================================================== (3) "Net sales (purchases) of marketable securities" consists of the following gross amounts: Marketable securities purchased $(2,812) $(2,679) $(2,724) Marketable securities sold 3,074 2,496 2,825 ------------------------------------------------------------------------------------------------------------------- Net sales (purchases) of marketable securities $ 262 $ (183) $ 101 =================================================================================================================== </FN> </TABLE> 4

<TABLE> <CAPTION> CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY ---------------------------------------------- 1999 1998 1997 ----------------------- ------------------------ ------------------------ Amounts in millions of dollars Shares Amount Shares Amount Shares Amount ---------------------------------------------------------------------------------------------------------------- <S> <C> <C> <C> <C> <C> <C> COMMON STOCK Balance at January 1 712,487,068 $ 1,069 712,487,068 $ 1,069 712,487,068 $ 1,069 Change during year - - - - - - ----------------------------------------------------------------------------- Balance at December 31 712,487,068 $ 1,069 712,487,068 $ 1,069 712,487,068 $ 1,069 ---------------------------------------------------------------------------------------------------------------- TREASURY STOCK AT COST Balance at January 1 59,460,666 $(2,293) 56,555,871 $(1,977) 59,401,015 $(2,024) Purchases 56,052 (5) 5,246,100 (398) 1,255,022 (95) Reissuances (3,375,724) 124 (2,341,305) 82 (4,100,166) 142 ----------------------------------------------------------------------------- Balance at December 31 56,140,994 $(2,174) 59,460,666 $(2,293) 56,555,871 $(1,977) ---------------------------------------------------------------------------------------------------------------- CAPITAL IN EXCESS OF PAR Balance at January 1 $ 2,097 $ 2,022 $ 1,874 Treasury stock transactions 118 75 148 ------- ------- ------- Balance at December 31 $ 2,215 $ 2,097 $ 2,022 ---------------------------------------------------------------------------------------------------------------- DEFERRED COMPENSATION Balance at January 1 $ (691) $ (750) $ (800) Net Reduction of ESOP debt and other 45 59 50 ------- ------- ------- Balance at December 31 $ (646) $ (691) $ (750) ---------------------------------------------------------------------------------------------------------------- ACCUMULATED OTHER COMPREHENSIVE INCOME(1) Balance at January 1 $ (90) $ (77) $ 96 Change during year (25) (13) (173) ------- ------- ------- Balance at December 31 $ (115) $ (90) $ (77) ---------------------------------------------------------------------------------------------------------------- RETAINED EARNINGS Balance at January 1 $16,942 $17,185 $15,408 Net Income 2,070 1,339 3,256 Cash dividends (per-share amounts 1999: $2.48; 1998: $2.44; 1997: $2.28) (1,625) (1,596) (1,493) Tax benefit from dividends paid on unallocated ESOP shares 13 14 14 ------- ------- ------- Balance at December 31 $17,400 $16,942 $17,185 ---------------------------------------------------------------------------------------------------------------- TOTAL STOCKHOLDERS' EQUITY AT DECEMBER 31 $17,749 $17,034 $17,472 ================================================================================================================ <FN> See accompanying notes to consolidated financial statements. (1) ACCUMULATED OTHER COMPREHENSIVE INCOME: Currency Translation Unrealized Holding Minimum Pension Adjustment Gain on Securities Liability Adjustment Total ----------------------------------------------------------------------------------------------------------------------------- Balance at January 1, 1997 $ 118 $ 14 $ (36) $ 96 Change during year (173) (4) 4 (173) ----------------------------------------------------------------------------------------------------------------------------- Balance at December 31, 1997 $ (55) $ 10 $ (32) $ (77) Change during year (1) 3 (15) (13) ----------------------------------------------------------------------------------------------------------------------------- Balance at December 31, 1998 $ (56) $ 13 $ (47) $ (90) Change during year (43) 29 (11) (25) ----------------------------------------------------------------------------------------------------------------------------- Balance at December 31, 1999 $ (99) $ 42 $ (58) $ (115) ============================================================================================================================= </FN> </TABLE> 5

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Millions of dollars, except per-share amounts Note 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Chevron Corporation is an international company that, through its subsidiaries and affiliates, engages in fully integrated petroleum operations, chemicals operations and coal mining in the United States and more than 100 countries. Petroleum operations consist of exploring for, developing and producing crude oil and natural gas; transporting crude oil, natural gas and products by pipelines, marine vessels and motor equipment; refining crude oil into finished petroleum products; and marketing crude oil, natural gas and refined petroleum products. Chemicals operations include the manufacture and marketing of a wide range of chemicals for industrial uses. In preparing its consolidated financial statements, the company follows accounting policies that are in accordance with accounting principles generally accepted in the United States. This requires the use of estimates and assumptions that affect the assets, liabilities, revenues and expenses reported in the financial statements, as well as amounts included in the notes thereto, including discussion and disclosure of contingent liabilities. While the company uses its best estimates and judgments, actual results could differ from these estimates as future confirming events occur. The nature of the company's operations and the many countries in which it operates subject it to changing economic, regulatory and political conditions. Also, the company imports crude oil for its U.S. refining operations. The company does not believe it is vulnerable to the risk of a near-term severe impact as a result of any concentration of its activities. Subsidiary and Affiliated Companies The consolidated financial statements include the accounts of subsidiary companies more than 50 percent owned. Investments in and advances to affiliates in which the company has a substantial ownership interest of approximately 20 percent to 50 percent, or for which the company exercises significant influence but not control over policy decisions, are accounted for by the equity method. Under this accounting, remaining unamortized cost is increased or decreased by the company's share of earnings or losses after dividends. Oil and Gas Accounting The successful efforts method is used for oil and gas exploration and production activities. Derivatives Gains and losses on hedges of existing assets or liabilities are included in the carrying amounts of those assets or liabilities and are ultimately recognized in income as part of those carrying amounts. Gains and losses related to qualifying hedges of firm commitments or anticipated transactions also are deferred and are recognized in income or as adjustments of carrying amounts when the underlying hedged transaction occurs. Cash flows associated with these derivatives are reported with the underlying hedged transaction's cash flows. If, subsequent to being hedged, underlying transactions are no longer likely to occur, the related derivatives gains and losses are recognized currently in income. Gains and losses on derivatives contracts that do not qualify as hedges are recognized currently in "Other income." Short-Term Investments All short-term investments are classified as available for sale and are in highly liquid debt or equity securities. Those investments that are part of the company's cash management portfolio with original maturities of three months or less are reported as cash equivalents. The balance of the short-term investments is reported as "Marketable securities." Short-term investments are marked-to-market with any unrealized gains or losses included in other comprehensive income. Inventories Crude oil, petroleum products and chemicals are stated at cost, using a Last-In, First-Out (LIFO) method. In the aggregate, these costs are below market. Materials, supplies and other inventories generally are stated at average cost. Properties, Plant and Equipment All costs for development wells, related plant and equipment, and proved mineral interests in oil and gas properties are capitalized. Costs of exploratory wells are capitalized pending determination of whether the wells found proved reserves. Costs of wells that are assigned proved reserves remain capitalized. All other exploratory wells and costs are expensed. Long-lived assets, including proved oil and gas properties, are assessed for possible impairment by comparing their carrying values to the undiscounted future net before-tax cash flows. Impaired assets are written down to their estimated fair values, generally their discounted cash flows. For proved oil and gas properties in the United States, the company generally performs the impairment review on an individual field basis. Outside the United States, reviews are performed on a country or concession basis. Impairment amounts are recorded as incremental depreciation expense in the period in which the event occurs. Depreciation and depletion (including provisions for future abandonment and restoration costs) of all capitalized costs of proved oil and gas producing properties, except mineral interests, are expensed using the unit-of-production method by individual fields as the proved developed reserves are produced. Depletion expenses for capitalized costs of proved mineral interests are recognized using the unit-of-production method by individual fields as the related proved reserves are produced. Periodic valuation provisions for impairment of capitalized costs of unproved mineral interests are expensed. Depreciation and depletion expenses for coal are determined using the unit-of-production method as the proved reserves are produced. The capitalized costs of all other plant and equipment are depreciated or amortized over estimated useful lives. In general, the declining-balance method is used to depreciate plant and equipment in the United States; the straight-line method generally is used to depreciate international plant and equipment and to amortize all capitalized leased assets. Gains or losses are not recognized for normal retirements of properties, plant and equipment subject to composite group amortization or depreciation. Gains or losses from abnormal retirements or sales are included in income. Expenditures for maintenance, repairs and minor renewals to maintain facilities in operating condition are expensed. Major replacements and renewals are capitalized. 6

Note 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Continued Environmental Expenditures Environmental expenditures that relate to current ongoing operations or to conditions caused by past operations are expensed. Expenditures that create future benefits or contribute to future revenue generation are capitalized. Liabilities related to future remediation costs are recorded when environmental assessments and/or cleanups are probable and the costs can be reasonably estimated. Other than for assessments, the timing and magnitude of these accruals are generally based on the company's commitment to a formal plan of action, such as an approved remediation plan or the sale or disposal of an asset. For the company's U.S. and Canadian marketing facilities, the accrual is based on the probability that a future remediation commitment will be required. For oil and gas and coal producing properties, a provision is made through depreciation expense for anticipated abandonment and restoration costs at the end of the property's useful life. For Superfund sites, the company records a liability for its share of costs when it has been named as a Potentially Responsible Party (PRP) and when an assessment or cleanup plan has been developed. This liability includes the company's own portion of the costs and also the company's portion of amounts for other PRPs when it is probable that they will not be able to pay their share of the cleanup obligation. The company records the gross amount of its liability based on its best estimate of future costs using currently available technology and applying current regulations as well as the company's own internal environmental policies. Future amounts are not discounted. Recoveries or reimbursements are recorded as an asset when receipt is reasonably ensured. Currency Translation The U.S. dollar is the functional currency for the company's consolidated operations as well as for substantially all operations of its equity method companies. For those operations, all gains or losses from currency transactions are currently included in income. The cumulative translation effects for the few equity affiliates using functional currencies other than the U.S. dollar are included in the currency translation adjustment in stockholders' equity. Taxes Income taxes are accrued for retained earnings of international subsidiaries and corporate joint ventures intended to be remitted. Income taxes are not accrued for unremitted earnings of international operations that have been, or are intended to be, reinvested indefinitely. Revenue Recognition Revenues associated with sales of crude oil, natural gas, coal, petroleum and chemicals products, and all other sources are recorded when title passes to the customer, net of royalties, discounts and allowances, as applicable. Revenues from natural gas production from properties in which Chevron has an interest with other producers are recognized on the basis of the company's net working interest (entitlement method). Stock Compensation The company applies Accounting Principles Board (APB) Opinion No. 25, "Accounting for Stock Issued to Employees," and related interpretations in accounting for stock options and presents in Note 19 pro forma net income and earnings per share data as if the accounting prescribed by SFAS No. 123, "Accounting for Stock-Based Compensation," had been applied. Note 2.SPECIAL ITEMS AND OTHER FINANCIAL INFORMATION Net income is affected by transactions that are unrelated to or are not necessarily representative of the company's ongoing operations for the periods presented. These transactions, defined by management and designated "special items," can obscure the underlying results of operations for a year as well as affect comparability of results between years. Listed below are categories of special items and their net increase (decrease) to net income, after related tax effects. <TABLE> <CAPTION> Year ended December 31 ------------------------- 1999 1998 1997 ------------------------------------------------------------------------------ <S> <C> <C> <C> Asset write-offs and revaluations Asset impairments - Oil and gas properties ......... $(204) $ (50) $ (68) - Coal assets .................... (34) - - U.S. refining, marketing and transportation assets ............ - (22) - Chemicals assets .......................... (43) (19) (10) Real estate assets ........................ - (9) - Other ..................................... (65) (59) (8) -------------------------- (346) (159) (86) ------------------------------------------------------------------------------- Asset dispositions, net Pipeline interests ........................ 75 - - Real estate ............................... 60 - - Coal assets ............................... 60 - - Marketable securities ..................... 30 - - Oil and gas assets ........................ 17 (9) 240 Caltex interest in equity affiliate ....... (31) - - Chemicals affiliate ....................... - - 33 U.K. refining and marketing exit .......... - - (72) Domestic shipping assets .................. - - (18) -------------------------- 211 (9) 183 ------------------------------------------------------------------------------- Prior-year tax adjustments ......................... 109 271 152 ------------------------------------------------------------------------------- Environmental remediation provisions, net .......... (123) (39) (35) ------------------------------------------------------------------------------- Restructurings and reorganizations Corporate ................................. (158) - - Caltex affiliate .......................... (25) (43) (6) Dynegy affiliate .......................... - - (54) -------------------------- (183) (43) (60) ------------------------------------------------------------------------------- LIFO inventory gains (losses) ...................... 38 (25) 5 ------------------------------------------------------------------------------- Other, net Litigation and regulatory issues* ......... 78 (682) (24) Settlement of insurance claims ............ - 105 7 Caltex write-off of start-up costs (SOP 98-5) - (25) - Performance stock options ................. - - (66) -------------------------- 78 (602) (83) ------------------------------------------------------------------------------- Total special items, after tax ..................... $(216) $(606) $ 76 =============================================================================== <FN> * 1999 and 1998 include effects related to Cities Service litigation. </FN> </TABLE> 7

Note 2. SPECIAL ITEMS AND OTHER FINANCIAL INFORMATION - Continued Other financial information is as follows. <TABLE> <CAPTION> Year ended December 31 ------------------------ 1999 1998 1997 ----------------------------------------------------------------- <S> <C> <C> <C> Total financing interest and debt costs $ 481 $ 444 $ 411 Less: capitalized interest ............ 9 39 99 ------------------------ Interest and debt expense ............. 472 405 312 Research and development expenses ..... 182 187 179 Foreign currency (losses) gains* ...... $ (38) $ (47) $ 246 ================================================================= <FN> *Includes $(15), $(68) and $177 in 1999, 1998 and 1997, respectively, for the company's share of affiliates' foreign currency (losses) gains. </FN> </TABLE> The excess of current cost (based on average acquisition costs for the year) over the carrying value of inventories for which the LIFO method is used was $871, $584 and $1,089 at December 31, 1999, 1998 and 1997, respectively. Note 3. CUMULATIVE EFFECT ON NET INCOME FROM ACCOUNTING CHANGES In April 1998, the AICPA released Statement of Position 98-5, "Reporting on the Costs of Start-up Activities" (SOP 98-5), which introduced a broad definition of items to expense as incurred for start-up activities, including new products/services, entering new territories, initiating new processes or commencing new operations. Chevron was substantially in compliance with the pronouncement. However, Caltex capitalized these types of costs for certain projects. Chevron recorded its $25 share of the charge associated with Caltex's 1998 implementation of SOP 98-5, effective January 1, 1998. In 1998, Chevron changed its method of calculating certain Canadian deferred income taxes, effective January 1, 1998. The benefit from this change was $32. The net benefit to Chevron's 1998 net income from the cumulative effect of adopting SOP 98-5 by Caltex and the change in Chevron's method of calculating Canadian deferred taxes was immaterial. Note 4. INFORMATION RELATING TO THE CONSOLIDATED STATEMENT OF CASH FLOWS The Consolidated Statement of Cash Flows excludes the following significant noncash transactions. During 1999, the company acquired the Rutherford-Moran Oil Corporation and Petrolera Argentina San Jorge S.A. Only the net cash component of these transactions is included as "Capital expenditures." Consideration for the Rutherford-Moran transaction included 1.1 million shares of the company's treasury stock valued at $91. During 1997, the company's Venice, Louisiana, natural gas facility was contributed to a partnership with Dynegy Inc. (Dynegy). An increase in "Investments and advances" resulted primarily from the contribution of properties, plant and equipment. The major components of "Capital expenditures" in the Consolidated Statement of Cash Flows and the reconciliation of this amount to total capital and exploratory expenditures, are presented in the following table. <TABLE> <CAPTION> Year ended December 31 ------------------------------- 1999 1998 1997 -------------------------------------------------------------------------------------- <S> <C> <C> <C> Additions to properties, plant and equipment ......................... $ 5,018 $ 3,678 $ 3,840 Additions to investments ............................. 449 306 153 Payments for other liabilities and assets, net(1)........................... (1,101) (104) (94) -------------------------------------------------------------------------------------- Capital expenditures ................................. 4,366 3,880 3,899 Expensed exploration expenditures .................... 413 438 462 Payments of long-term debt and other financing obligations(2)........... 572 2 6 -------------------------------------------------------------------------------------- Capital and exploratory expenditures, excluding equity affiliates ........ $ 5,351 $ 4,320 $ 4,367 ====================================================================================== <FN> (1) 1999 includes liabilities assumed in acquisitions of Rutherford-Moran Oil Corporation and Petrolera Argentina San Jorge S.A (2) 1999 includes obligations assumed in acquisition of Rutherford-Moran Oil Corporation and other capital lease additions. </FN> </TABLE> Note 5. STOCKHOLDERS' EQUITY Retained earnings at December 31, 1999 and 1998, include $2,048 and $2,121, respectively, for the company's share of undistributed earnings of equity affiliates. In 1998, the company declared a dividend distribution of one Right to purchase Chevron Participating Preferred Stock. The Rights will be exercisable, unless redeemed earlier by the company, if a person or group acquires, or obtains the right to acquire, 10 percent or more of the outstanding shares of common stock or commences a tender or exchange offer that would result in acquiring 10 percent or more of the outstanding shares of common stock, either event occurring without the prior consent of the company. The amount of Chevron Series A Participating Preferred Stock that the holder of a Right is entitled to receive and the purchase price payable upon exercise of the Chevron Right are both subject to adjustment. The person or group who had acquired 10 percent or more of the outstanding shares of common stock without the prior consent of the company would not be entitled to this purchase. The Rights will expire in November 2008, or they may be redeemed by the company at 1 cent per Right prior to that date. The Rights do not have voting or dividend rights and, until they become exercisable, have no dilutive effect on the earnings per share of the company. Five million shares of the company's preferred stock have been designated Series A Participating Preferred Stock and reserved for issuance upon exercise of the Rights. No event during 1999 made the Rights exercisable. Rights associated with a 1988 dividend distribution expired in 1998. Note 6. FINANCIAL AND DERIVATIVE INSTRUMENTS Off-Balance-Sheet Risk The company utilizes a variety of derivative instruments, both financial and commodity-based, as hedges to manage a small portion of its exposure to price volatility stemming from its integrated petroleum activities. Relatively straightforward and involving little complexity, the derivative instruments consist mainly of futures contracts traded on the New York Mercantile Exchange and the International Petroleum Exchange and of both crude and natural gas swap contracts entered into principally with major financial institutions. The futures contracts hedge anticipated 8

Note 6. FINANCIAL AND DERIVATIVE INSTRUMENTS - Continued crude oil purchases and sales and product sales, generally forecast to occur within a 60- to 90-day period. Crude oil swaps are used to hedge sales forecasted to occur within the next four years. The terms of the swap contracts have maturities of the same period. Natural gas swaps are used primarily to hedge firmly committed sales, and the terms of the swap contracts held at year-end 1999 had an average remaining maturity of 58 months. Gains and losses on these derivative instruments offset and are recognized in income concurrently with the recognition of the underlying physical transactions. In addition, the company in 1998 entered into managed programs using swaps and options to take advantage of perceived opportunities for favorable price movements in natural gas. The results of these programs were reflected in income and were not material in 1998. The company enters into forward exchange contracts, generally with terms of 90 days or less, as a hedge against some of its foreign currency exposures, primarily anticipated purchase transactions forecast to occur within 90 days. The company enters into interest rate swaps as part of its overall strategy to manage the interest rate risk on its debt. Under the terms of the swaps, net cash settlements, based on the difference between fixed-rate and floating-rate interest amounts calculated by reference to agreed notional principal amounts, are made semiannually and are recorded monthly as "Interest and debt expense." At December 31, 1999, there was one outstanding contract, with a remaining term of five years and six months. Concentrations of Credit Risk The company's financial instruments that are exposed to concentrations of credit risk consist primarily of its cash equivalents, marketable securities, derivative financial instruments and trade receivables. The company's short-term investments are placed with a wide array of financial institutions with high credit ratings. This diversified investment policy limits the company's exposure both to credit risk and to concentrations of credit risk. Similar standards of diversity and creditworthiness are applied to the company's counterparties in derivative instruments. The trade receivable balances, reflecting the company's diversified sources of revenue, are dispersed among the company's broad customer base worldwide. As a consequence, concentrations of credit risk are limited. The company routinely assesses the financial strength of its customers. Letters of credit, or negotiated contracts when the financial strength of a customer is not considered sufficient, are the principal securities obtained to support lines of credit. Fair Value Fair values are derived either from quoted market prices where available or, in their absence, the present value of the expected cash flows. The fair values reflect the cash that would have been received or paid if the instruments were settled at year-end. At December 31, 1999 and 1998, the fair values of the financial and derivative instruments were: Long-term debt of $2,449 and $1,403 had estimated fair values of $2,430 and $1,485. The notional principal amounts of the interest rate swaps totaled $350 and $700, with approximate fair values totaling $11 and $(21). The notional amounts of these and other derivative instruments do not represent assets or liabilities of the company but, rather, are the basis for the settlements under the contract terms. The company holds cash equivalents and U.S. dollar marketable securities in domestic and offshore portfolios. Eurodollar bonds, floating-rate notes, time deposits and commercial paper are the primary instruments held. Cash equivalents and marketable securities had fair values of $1,762 and $1,206. Of these balances, $1,075 and $362 classified as cash equivalents had average maturities under 90 days, while the remainder, classified as marketable securities, had average maturities of approximately three years and two years. For other derivatives the contract or notional values were as follows: Crude oil and products futures had net contract values of $143 and $33. Forward exchange contracts had contract values of $123 and $180. Gas swap contracts are based on notional gas volumes of approximately 44 and 67 billion cubic feet. Crude oil swap contracts are based on notional crude volumes of approximately 9 million barrels. Fair values for all of these derivatives were not material in 1999 and 1998. Deferred gains and losses that were accrued on the Consolidated Balance Sheet were not material. Note 7. SUMMARIZED FINANCIAL DATA - CHEVRON U.S.A. INC. At December 31, 1999, Chevron U.S.A. Inc. was Chevron's principal operating company, consisting primarily of its U.S. integrated petroleum operations (excluding most of the domestic pipeline operations) and, effective February 1, 1998, the majority of its worldwide petrochemicals operations. In 1999, these operations were conducted primarily by three divisions: Chevron U.S.A. Production Company, Chevron Products Company and Chevron Chemical Company LLC. Summarized financial information for Chevron U.S.A. Inc. and its consolidated subsidiaries is presented below. <TABLE> <CAPTION> Year ended December 31 --------------------------- 1999 1998 1997 <S> <C> <C> <C> Sales and other operating revenues $28,957 $24,440 $28,130 Total costs and other deductions ... 28,329 24,338 26,354 Net income ......................... 885 346 1,484 ================================================================== </TABLE> <TABLE> At December 31 ------------------- 1999 1998* ------------------------------------------------- <S> <C> <C> Current assets .... $ 3,889 $ 3,227 Other assets ...... 19,403 18,330 Current liabilities 4,676 3,809 Other liabilities . 8,455 6,541 Net equity ........ 10,161 11,207 ================================================= Memo: Total Debt $ 7,462 $ 3,546 <FN> * Certain amounts have been reclassified to conform to current presentation. </FN> </TABLE> The primary cause of the reduction in net equity from 1998 to 1999 was a return of $2,000 of capital to Chevron Corporation in exchange for a loan. Note 8. SUMMARIZED FINANCIAL DATA - CHEVRON TRANSPORT CORPORATION LIMITED Effective July 1999, Chevron Transport Corporation, a Liberian corporation, was merged into Chevron Transport Corporation Limited (CTC), a Bermuda corporation, which assumed all of the assets and liabilities of 9

Note 8. SUMMARIZED FINANCIAL DATA - CHEVRON TRANSPORT CORPORATION LIMITED - Continued Chevron Transport Corporation. CTC 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 oil and refined petroleum products. Most of CTC's shipping revenue is derived by providing transportation services to other Chevron companies. Chevron Corporation has guaranteed this subsidiary's obligations in connection with certain debt securities where CTC is deemed to be an issuer. In accordance with the Securities and Exchange Commission's disclosure requirements, summarized financial information for CTC and its consolidated subsidiaries is presented below. This information was derived from the financial statements prepared on a stand-alone basis in conformity with generally accepted accounting principles. During 1999, CTC's parent contributed an additional $62 of paid-in capital. Separate CTC financial statements and other disclosures are omitted, as such information is not material to investors in the debt securities deemed issued by CTC. There were no restrictions on CTC's ability to pay dividends or make loans or advances at December 31, 1999. <TABLE> <CAPTION> Year ended December 31 ------------------------ 1999 1998 1997 -------------------------------------------------------------- <S> <C> <C> <C> Sales and other operating revenues.. $ 504 $ 573 $ 544 Total costs and other deductions ... 572 580 557 Net (loss) income .................. (50) 17 28 ============================================================== </TABLE> <TABLE> <CAPTION> At December 31 ----------------- 1999 1998 ------------------------------------------------------ <S> <C> <C> Current assets ......... $184 $270 Other assets ........... 742 982 Current liabilities..... 580 898 Other liabilities ...... 264 284 Net equity ............. 82 70 ====================================================== </TABLE> Note 9. OPERATING SEGMENTS AND GEOGRAPHIC DATA Chevron manages its exploration and production; refining, marketing and transportation; and chemicals businesses separately. The company's primary country of operation is the United States, its country of domicile. The remainder of the company's operations is reported as International (outside the United States), since its activities in no other country meet the requirements for separate disclosure. In February 2000, Chevron and Phillips Petroleum Company signed a letter of intent and exclusivity agreement to combine most of their chemicals businesses in a joint venture. Each company will own 50 percent of the joint venture, which would have had 1999 sales of $6,000 and is expected to have total assets of about $6,000. The combination is subject to final approval of the companies' boards of directors, signing of definitive agreements and regulatory review, all of which are expected to be completed by mid-2000. 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 corporation on a worldwide basis. Corporate administrative costs and assets are not allocated to the operating segments; instead, operating segments are billed only for direct corporate services. Nonbillable costs remain as corporate center expenses. After-tax segment operating earnings for the years 1999, 1998 and 1997 are presented in the following table. <TABLE> <CAPTION> Year ended December 31 ------------------------------ 1999 1998 1997 -------------------------------------------------------------------- <S> <C> <C> <C> EXPLORATION AND PRODUCTION United States ............. $ 526 $ 365 $ 1,001 International ............. 1,093 707 1,252 -------------------------------------------------------------------- TOTAL EXPLORATION AND PRODUCTION ............ 1,619 1,072 2,253 -------------------------------------------------------------------- REFINING, MARKETING AND TRANSPORTATION United States ............. 357 572 601 International ............. 74 28 298 -------------------------------------------------------------------- TOTAL REFINING, MARKETING AND TRANSPORTATION ........ 431 600 899 -------------------------------------------------------------------- CHEMICALS United States ............. 44 79 138 International ............. 65 43 90 -------------------------------------------------------------------- TOTAL CHEMICALS .................... 109 122 228 -------------------------------------------------------------------- TOTAL SEGMENT INCOME ............... 2,159 1,794 3,380 -------------------------------------------------------------------- Interest Expense ................... (333) (270) (189) Interest Income .................... 21 63 75 Other .............................. 223 (248) (10) -------------------------------------------------------------------- NET INCOME ................ $ 2,070 $ 1,339 $ 3,256 ==================================================================== NET INCOME - UNITED STATES $ 976 $ 642 $ 1,622 NET INCOME - INTERNATIONAL $ 1,094 $ 697 $ 1,634 -------------------------------------------------------------------- TOTAL NET INCOME .......... $ 2,070 $ 1,339 $ 3,256 ==================================================================== </TABLE> Segment Assets Segment assets do not include intercompany investments or intercompany receivables. "All Other" assets consist primarily of worldwide cash and marketable securities, company real estate, information systems, and coal mining assets. Segment assets at year-end 1999 and 1998 are as follows. <TABLE> <CAPTION> At December 31 ------------------ 1999 1998 ------------------------------------------------ <S> <C> <C> EXPLORATION AND PRODUCTION United States ..... $ 5,566 $ 6,026 International ..... 13,748 10,794 ------------------------------------------------ TOTAL EXPLORATION AND PRODUCTION .... 19,314 16,820 ------------------------------------------------ REFINING, MARKETING AND TRANSPORTATION United States ..... 8,178 8,084 International ..... 3,609 3,559 ------------------------------------------------ TOTAL REFINING, MARKETING AND TRANSPORTATION 11,787 11,643 ------------------------------------------------ CHEMICALS United States ..... 3,303 3,045 International ..... 923 828 ------------------------------------------------ TOTAL CHEMICALS ............ 4,226 3,873 ------------------------------------------------ TOTAL SEGMENT ASSETS ....... 35,327 32,336 ------------------------------------------------ ALL OTHER United States ..... 3,821 2,467 International ..... 1,867 1,737 ------------------------------------------------ TOTAL All OTHER ............ 5,688 4,204 ------------------------------------------------ TOTAL ASSETS - UNITED STATES 20,868 19,622 TOTAL ASSETS - INTERNATIONAL 20,147 16,918 ------------------------------------------------ TOTAL ASSETS ...... $41,015 $36,540 ================================================ </TABLE> 10

Note 9. OPERATING SEGMENTS AND GEOGRAPHIC DATA - Continued Segment Income Taxes Segment income tax expenses for the years 1999, 1998 and 1997 are as follows. <TABLE> <CAPTION> Year ended December 31 ----------------------------- 1999 1998 1997 ----------------------------------------------------------------- <S> <C> <C> <C> EXPLORATION AND PRODUCTION United States .......... $ 266 $ 164 $ 559 International .......... 1,341 595 1,488 ----------------------------------------------------------------- TOTAL EXPLORATION AND PRODUCTION ......... 1,607 759 2,047 ----------------------------------------------------------------- REFINING, MARKETING AND TRANSPORTATION United States .......... 135 309 346 International .......... 41 54 6 ----------------------------------------------------------------- TOTAL REFINING, MARKETING AND TRANSPORTATION ..... 176 363 352 ----------------------------------------------------------------- CHEMICALS United States .......... (13) 25 77 International .......... 45 14 57 ----------------------------------------------------------------- TOTAL CHEMICALS ................. 32 39 134 ----------------------------------------------------------------- All Other .............. (237) (666) (287) ----------------------------------------------------------------- TOTAL INCOME TAX EXPENSE $ 1,578 $ 495 $ 2,246 ================================================================= </TABLE> Segment Sales and Other Operating Revenues Revenues for the exploration and production segments are derived primarily from the production of crude oil and natural gas. Revenues for the refining, marketing and transportation segments are derived from the refining and marketing of petroleum products such as gasoline, jet fuel, gas oils, kerosene, 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. Chemicals segment revenues are derived from the manufacture and sale of petrochemicals, plastic resins, and lube oil and fuel additives. "All Other" activities include corporate administrative costs, worldwide cash management and debt financing activities, coal mining operations, insurance operations, and real estate activities. Reportable operating segment sales and other operating revenues, including internal transfers, for the years 1999, 1998 and 1997 are presented in the table that follows. Sales from the transfer of products between segments are at estimated market prices. <TABLE> <CAPTION> Year ended December 31 ------------------------------- 1999 1998(1) 1997(1) -------------------------------------------------------------------------------------------- <S> <C> <C> <C> EXPLORATION AND PRODUCTION United States Crude oil ...................................... $ - $ - $ (3) Natural gas .................................... 1,578 1,599 1,978 Natural gas liquids ............................ 159 128 185 Other .......................................... 8 12 20 Intersegment ................................... 1,985 1,453 4,362 -------------------------------- Total United States ............................ 3,730 3,192 6,542 -------------------------------------------------------------------------------------------- International Refined products ............................... 2 1 2 Crude oil ...................................... 2,586 1,761 2,790 Natural gas .................................... 678 505 590 Natural gas liquids ............................ 116 89 170 Other .......................................... 205 130 116 Intersegment ................................... 2,876 1,984 2,810 -------------------------------- Total International ............................ 6,463 4,470 6,478 -------------------------------------------------------------------------------------------- TOTAL EXPLORATION AND PRODUCTION ............... 10,193 7,662 13,020 -------------------------------------------------------------------------------------------- REFINING, MARKETING AND TRANSPORTATION United States Refined products ............................... 12,765 10,148 12,586 Crude oil ...................................... 3,618 2,971 4,531 Natural gas liquids ............................ 133 100 158 Other .......................................... 654 622 592 Excise taxes ................................... 3,702 3,503 3,386 Intersegment ................................... 366 216 313 -------------------------------- Total United States ............................ 21,238 17,560 21,566 -------------------------------------------------------------------------------------------- International Refined products ............................... 975 1,312 2,998 Crude oil ...................................... 3,874 3,049 3,978 Natural gas liquids ............................ 24 5 40 Other .......................................... 248 299 390 Excise taxes ................................... 178 213 2,188 Intersegment ................................... 16 20 15 -------------------------------- Total International ............................ 5,315 4,898 9,609 -------------------------------------------------------------------------------------------- TOTAL REFINING, MARKETING AND TRANSPORTATION ........... 26,553 22,458 31,175 -------------------------------------------------------------------------------------------- CHEMICALS United States Products ....................................... 2,794 2,468 2,933 Excise taxes ................................... 2 2 - Intersegment ................................... 162 121 112 -------------------------------- Total United States ............................ 2,958 2,591 3,045 -------------------------------------------------------------------------------------------- International Products ....................................... 715 568 559 Other .......................................... 35 18 28 Excise taxes ................................... 28 38 13 Intersegment ................................... 1 1 2 -------------------------------- Total International ............................ 779 625 602 -------------------------------------------------------------------------------------------- TOTAL CHEMICALS ....................... 3,737 3,216 3,647 -------------------------------------------------------------------------------------------- ALL OTHER United States - Coal .................................... 360 399 359 United States - Other ................................... 8 (1) 8 International ........................................... 3 4 1 Intersegment - United States ............................ 55 52 47 Intersegment - International ............................ 4 2 - -------------------------------------------------------------------------------------------- TOTAL ALL OTHER ....................... 430 456 415 -------------------------------------------------------------------------------------------- Sales and Other Operating Revenues - United States ................................ 28,349 23,793 31,567 - International ................................ 12,564 9,999 16,690 -------------------------------------------------------------------------------------------- Total Segment Sales and Other Operating Revenues ....................... 40,913 33,792 48,257 -------------------------------------------------------------------------------------------- Elimination of Intersegment Sales ....................... (5,465) (3,849) (7,661) -------------------------------------------------------------------------------------------- Total Sales and Other Operating Revenues ....................... $35,448 $29,943 $40,596 ============================================================================================ <FN> (1) Certain amounts have been restated to conform to the 1999 presentation </FN> </TABLE> Other Segment Information Investments in and earnings from affiliated companies are included in the segments in which the affiliates operate. Dynegy Inc. is included in U.S. exploration and production; P.T. Caltex Pacific Indonesia (CPI) and Tengizchevroil (TCO) are included in International exploration and production; and Caltex Corporation is included in International refining, marketing and transportation. The company's other affiliates are not material to any segment's assets or results of operations. Information on equity affiliates, including carrying value and equity earnings, is included in Note 12. Additions to long-lived assets and depreciation expense, by operating segment, are included in Note 13. 11

Note 10. LITIGATION The company is a party, along with other oil companies, to numerous lawsuits and claims, including actions challenging oil and gas royalty and severance tax payments based on posted prices, and actions related to the use of the chemical MTBE in certain oxygenated gasolines. In some of these actions, plaintiffs may seek to recover large and sometimes unspecified amounts. In others, the plaintiffs may seek to have the company perform specific actions, including remediation of alleged damages. These matters may remain unresolved for several years, and it is not practical to estimate a range of possible loss. Although losses could be material with respect to earnings in any given period, management believes that resolution of these matters will not result in any significant liability to the company in relation to its consolidated financial position or have a significant effect on its liquidity. In a lawsuit in Los Angeles, Calif., brought in 1995, the company and five other oil companies are contesting the validity of a patent granted to Unocal Corporation (Unocal) for certain types of reformulated gasoline, which the company sells in California during certain months of the year. The first two phases of the trial were concluded in 1997, with the jury upholding the validity of the patent and assessing damages at the rate of 5.75 cents per gallon of gasoline produced in infringement of the patent between March 1 and July 1, 1996. In the third phase of the trial, the judge heard evidence to determine if the patent was enforceable. In 1998, the judge ruled the patent was enforceable. The defendants filed an appeal in January 1999 and oral arguments were made before the court in July 1999. While the ultimate outcome of this matter cannot be determined with certainty, the company believes Unocal's patent is invalid and any unfavorable rulings should be reversed upon appeal. Unocal also has filed for additional patents for alternate formulations. Should the jury's finding and Unocal's patent ultimately be upheld, the company's financial exposure includes royalties, plus interest, for past production of gasoline that is ruled to have infringed the applicable patent and royalty payments for any future production of gasoline that infringes this patent. The effect of unfavorable rulings with respect to future reformulated gasoline production would depend on the availability of alternate formulations and the industry's ability to recover additional costs of production through prices charged to its customers. The company believes that its ultimate exposure in this matter will not materially affect its financial position or liquidity, although the costs of resolution of any unfavorable ruling could be material with respect to earnings in any given period. Note 11. LEASE COMMITMENTS Certain noncancelable leases are classified as capital leases, and the leased assets are included as part of "Properties, plant and equipment." Other leases are classified as operating leases and are not capitalized. Details of the capitalized leased assets are as follows. <TABLE> <CAPTION> At December 31 --------------------- 1999 1998 ------------------------------------------------------------- <S> <C> <C> Exploration and Production .......... $ 86 $ 5 Refining, Marketing and Transportation 779 757 ------------------------------------------------------------- Total ....................... 865 762 Less: accumulated amortization ....... 425 398 ------------------------------------------------------------- Net capitalized leased assets ........ $ 440 $ 364 ============================================================= </TABLE> Rental expenses incurred for operating leases during 1999, 1998 and 1997 were as follows. <TABLE> <CAPTION> Year ended December 31 ------------------------------------- 1999 1998 1997 ---------------------------------------------------------------------- <S> <C> <C> <C> Minimum rentals ............ $465 $503 $443 Contingent rentals ......... 3 5 5 ---------------------------------------------------------------------- Total ............. 468 508 448 Less: sublease rental income 3 3 5 ---------------------------------------------------------------------- Net rental expense ......... $465 $505 $443 ====================================================================== </TABLE> At December 31, 1999, the future minimum lease payments under operating and capital leases are as follows. <TABLE> <CAPTION> At December 31 -------------------------- Operating Capital Leases Leases ------------------------------------------------------------ <S> <C> <C> Year 2000 $ 157 $ 81 2001 180 77 2002 180 72 2003 178 103 2004 177 46 Thereafter 312 889 ------------------------------------------------------------ Total $1,184 1,268 ============================================= Less: amounts representing interest and executory costs 625 ------------------------------------------------------------ Net present values 643 Less: capital lease obligations included in short-term debt 332 ------------------------------------------------------------ Long-term capital lease obligations $ 311 ============================================================ Future sublease rental income $ 1 $ - ============================================================ </TABLE> Contingent rentals are based on factors other than the passage of time, principally sales volumes at leased service stations. Certain leases include escalation clauses for adjusting rentals to reflect changes in price indices, renewal options ranging from one to 25 years, and/or options to purchase the leased property during or at the end of the initial lease period for the fair market value at that time. Note 12. INVESTMENTS AND ADVANCES Chevron owns 50 percent each of P.T. Caltex Pacific Indonesia, an exploration and production company operating in Indonesia; Caltex Corporation, which, through its subsidiaries and affiliates, conducts refining and marketing activities in Asia, Africa, the Middle East, Australia and New Zealand; and American Overseas Petroleum Limited, which, through its subsidiary, manages certain of the company's operations in Indonesia. These companies and their subsidiaries and affiliates are collectively called the Caltex Group. Tengizchevroil (TCO) is a joint venture formed in 1993 to develop the Tengiz and Korolev oil fields in Kazakhstan over a 40-year period. Chevron's ownership was reduced from 50 percent to 45 percent in April 1997 through a sale of a portion of its interest. The company has an obligation of $420, payable to the Republic of Kazakhstan upon the attainment of a dedicated export system with the capability of the greater of 260,000 barrels of oil per day or TCO's production capacity. This amount was included in the value of the investment, as the company believed at the time, and continues to believe, that its payment is beyond a reasonable doubt given the original intent and continuing commitment 12

Note 12. INVESTMENTS AND ADVANCES - Continued of both parties to realizing the full potential of the venture over its 40-year life. Chevron owns 28 percent of Dynegy Inc., a gatherer, processor, transporter and marketer of energy products in North America and the United Kingdom. These products include natural gas, natural gas liquids, crude oil and electricity. The market value of Chevron's shares of Dynegy common stock at December 31, 1999, was $1,133 based on quoted closing market prices. In February 2000, Dynegy completed a merger with Illinova Corporation, an energy services holding company in Illinois. Chevron increased its investment by $200 to maintain a 28 percent ownership in the merged company. The company received dividends and distributions of $268, $254 and $335 in 1999, 1998 and 1997, respectively, including $212, $167 and $207 from the Caltex Group. During 1998, Dynegy repaid a $155 loan from Chevron, which is reflected as a decrease in the company's investment in the affiliate. The company's transactions with affiliated companies are summarized in the table that follows. These are primarily for the purchase of Indonesian crude oil from CPI, the sale of crude oil and products to Caltex Corporation's refining and marketing companies, the sale of natural gas to Dynegy, and the purchase of natural gas and natural gas liquids from Dynegy. "Accounts and notes receivable" in the Consolidated Balance Sheet include $277 and $156 at December 31, 1999 and 1998, respectively, of amounts due from affiliated companies. "Accounts payable" include $53 and $41 at December 31, 1999 and 1998, respectively, of amounts due to affiliated companies. <TABLE> <CAPTION> Year ended December 31 -------------------------- 1999 1998 1997 ------------------------------------------------------------------- <S> <C> <C> <C> Sales to Caltex Group .................. $ 687 $ 772 $1,335 Sales to Dynegy Inc. ................... 1,407 1,307 1,822 Sales to Fuel & Marine Marketing LLC* .. 234 22 - Sales to other affiliates .............. 12 4 8 ------------------------------------------------------------------- Total sales to affiliates .... $2,340 $2,105 $3,165 =================================================================== Purchases from Caltex Group ............ $ 867 $ 681 $ 932 Purchases from Dynegy Inc. ............. 785 642 854 Purchases from other affiliates ........ 6 2 16 ------------------------------------------------------------------- Total purchases from affiliates $1,658 $1,325 $1,802 =================================================================== <FN> * Affiliate formed in November 1998 owned 31 percent by Chevron. </FN> </TABLE> Equity in earnings, together with investments in and advances to companies accounted for using the equity method, and other investments accounted for at or below cost, are as follows. <TABLE> <CAPTION> Investments and Advances Equity in Earnings ----------------------------------------------------- At December 31 Year ended December 31 ----------------------------------------------------- 1999 1998 1999 1998 1997* ---------------------------------------------------------------------------------- <S> <C> <C> <C> <C> <C> Exploration and Production Tengizchevroil ........ $1,722 $1,455 $ 177 $ 60 $ 169 Caltex Group .......... 455 452 139 107 171 Dynegy Inc. ........... 351 265 51 49 (17) Other ................. 198 134 32 4 13 ---------------------------------------------------------------------------------- Total Exploration and Production 2,726 2,306 399 220 336 ---------------------------------------------------------------------------------- Refining, Marketing and Transportation Caltex Group .......... 1,683 1,751 56 (36) 252 Other ................. 379 124 70 24 57 ---------------------------------------------------------------------------------- Total Refining, Marketing and Transportation 2,062 1,875 126 (12) 309 ---------------------------------------------------------------------------------- Chemicals ............... 145 135 1 - 25 All Other ............... 31 74 - 20 18 ---------------------------------------------------------------------------------- Total Equity Method ... $4,964 $4,390 $ 526 $ 228 $ 688 ---------------------------------------------------------------------------------- Other at or Below Cost .. 267 214 Total Investments and Advances .... $5,231 $4,604 ================================================================================== <FN> * Reclassified to conform to the 1998 presentation. </FN> </TABLE> The following tables summarize the combined financial information for the Caltex Group and all of the other equity-method companies, together with Chevron's share. Amounts shown for the affiliates are 100 percent. <TABLE> <CAPTION> Caltex Group Other Affiliates Chevron's Share ---------------------------------------------------------------------------------------- Year ended December 31 1999 1998* 1997* 1999 1998 1997 1999 1998* 1997* -------------------------------------------------------------------------------------------------------------------------- <S> <C> <C> <C> <C> <C> <C> <C> <C> <C> Total revenues ................. $14,915 $11,506 $15,699 $20,645 $16,842 $16,574 $13,660 $11,194 $12,717 Total costs and other deductions 14,134 10,986 14,489 19,805 16,430 15,770 12,863 10,672 11,789 Net income ..................... 390 143 846 610 295 556 526 228 688 ========================================================================================================================== </TABLE> <TABLE> <CAPTION> Caltex Group Other Affiliates Chevron's Share ---------------------------------------------------------------------------------------- At December 31 ................. 1999 1998 1997 1999 1998 1997 1999 1998 1997 -------------------------------------------------------------------------------------------------------------------------- <S> <C> <C> <C> <C> <C> <C> <C> <C> <C> Current assets ................. $ 4,928 $ 1,974 $ 2,521 $ 4,640 $ 3,326 $ 3,232 $ 3,962 $ 2,015 $ 2,289 Other assets ................... 5,381 7,683 7,193 10,255 8,868 6,713 6,009 6,663 5,971 Current liabilities ............ 3,395 2,840 2,991 3,709 2,723 2,565 2,665 2,162 2,232 Other liabilities .............. 2,638 2,420 2,131 8,362 7,147 5,448 2,342 2,126 1,740 Net equity ..................... 4,276 4,397 4,592 2,824 2,324 1,932 4,964 4,390 4,288 ========================================================================================================================== <FN> *Caltex "Total revenues" and "Total costs and other deductions" have been reclassified to net certain offsetting trading sale and purchase contracts. The reclassifications conform to the 1999 presentation and have no impact on net income. </FN> </TABLE> Note 13. PROPERTIES, PLANT AND EQUIPMENT <TABLE> <CAPTION> At December 31 Year ended December 31 ---------------------------------------------------- ---------------------------------------------- Gross Investment at Cost Net Investment Additions at Cost(1) Depreciation Expense --------------------------- ------------------------ ---------------------- ---------------------- 1999 1998 1997 1999 1998 1997 1999 1998 1997 1999 1998 1997 ------------------------------------------------------------------------------------------------------------------------------- <S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> Exploration and Production United States $17,947 $18,372 $18,104 $4,709 $5,237 $5,052 $ 710 $1,000 $1,166 $1,130 $ 818 $ 887 International 15,876 12,755 11,752 9,465 7,148 6,691 3,251 1,221 1,310 851 730 634 ------------------------------------------------------------------------------------------------------------------------------- Total Exploration and Production 33,823 31,127 29,856 14,174 12,385 11,743 3,961 2,221 2,476 1,981 1,548 1,521 ------------------------------------------------------------------------------------------------------------------------------- Refining, Marketing and Transportation United States 12,025 11,793 11,378 6,196 6,268 6,186 515 665 538 478 483 464 International 1,838 2,005 2,063 1,030 1,139 1,210 30 50 57 79 81 111 ------------------------------------------------------------------------------------------------------------------------------- Total Refining, Marketing and Transportation 13,863 13,798 13,441 7,226 7,407 7,396 545 715 595 557 564 575 ------------------------------------------------------------------------------------------------------------------------------- Chemicals United States 3,689 3,436 3,039 2,354 2,211 1,931 326 385 470 174 109 92 International 714 662 549 453 414 309 59 116 157 19 10 12 ------------------------------------------------------------------------------------------------------------------------------- Total Chemicals 4,403 4,098 3,588 2,807 2,625 2,240 385 501 627 193 119 104 ------------------------------------------------------------------------------------------------------------------------------- All Other(2) 2,123 2,314 2,348 1,110 1,312 1,292 103 202 110 135 89 100 ------------------------------------------------------------------------------------------------------------------------------- Total United States 35,783 35,915 34,867 14,369 15,028 14,461 1,654 2,252 2,284 1,917 1,499 1,543 Total International 18,429 15,422 14,366 10,948 8,701 8,210 3,340 1,387 1,524 949 821 757 ------------------------------------------------------------------------------------------------------------------------------- Total $54,212 $51,337 $49,233 $25,317 $23,729 $22,671 $4,994 $3,639 $3,808 $2,866 $2,320 $2,300 =============================================================================================================================== <FN> (1) Net of dry hole expense related to prior years' expenditures of $126, $40 and $31 in 1999, 1998 and 1997, respectively. (2) Primarily coal and real estate assets and management information systems. </FN> </TABLE> Note 14. TAXES <TABLE> <CAPTION> Year ended December 31 --------------------------- 1999 1998 1997 ------------------------------------------------------------------------- <S> <C> <C> <C> Taxes other than on income United States Excise taxes on products and merchandise $3,704 $3,505 $3,386 Property and other miscellaneous taxes 272 262 274 Payroll taxes .............. 119 129 123 Taxes on production ........ 94 92 118 ------------------------------------------------------------------------- Total United States 4,189 3,988 3,901 ------------------------------------------------------------------------- International Excise taxes on products and merchandise ... 206 251 2,201 Property and other miscellaneous taxes 145 137 185 Payroll taxes .............. 32 26 23 Taxes on production ........ 14 9 10 ------------------------------------------------------------------------- Total International 397 423 2,419 ------------------------------------------------------------------------- Total taxes other than on income ............. $4,586 $4,411 $6,320 ========================================================================= </TABLE> U.S. federal income tax expense was reduced by $89, $84 and $93 in 1999, 1998 and 1997, respectively, for low-income housing and other business tax credits. In 1999, before-tax income, including related corporate and other charges, for U.S. operations was $1,254, compared with $728 in 1998 and $2,054 in 1997. For international operations, before-tax income was $2,394, $1,106 and $3,448 in 1999, 1998 and 1997, respectively. The deferred income tax provisions included costs of $788, $470 and $304 related to properties, plant and equipment in 1999, 1998 and 1997, respectively. <TABLE> <CAPTION> Year ended December 31 ------------------------------ 1999 1998 1997 -------------------------------------------------------------------------------- <S> <C> <C> <C> Taxes on income U.S. federal Current .................... $ 135 $ (176) $ 369 Deferred ..................... 145 71 357 State and local ....................... (14) 20 81 -------------------------------------------------------------------------------- Total United States . 266 (85) 807 -------------------------------------------------------------------------------- International Current ...................... 1,231 385 1,174 Deferred ..................... 81 195 265 -------------------------------------------------------------------------------- Total International . 1,312 580 1,439 -------------------------------------------------------------------------------- Total taxes on income $ 1,578 $ 495 $ 2,246 ================================================================================ </TABLE> The company's effective income tax rate varied from the U.S. statutory federal income tax rate because of the following. <TABLE> <CAPTION> Year ended December 31 ----------------------------- 1999 1998 1997 ---------------------------------------------------------------------------------- <S> <C> <C> <C> Statutory U.S. federal income tax rate .......... 35.0% 35.0% 35.0% Effect of income taxes from international operations in excess of taxes at the U.S. statutory rate .................... 15.6 7.6 9.6 State and local taxes on income, net of U.S. federal income tax benefit (0.2) 0.2 1.3 Prior-year tax adjustments ..................... - (4.5) (0.3) Tax credits ..................................... (2.4) (4.6) (1.7) Other ........................................... (2.2) (6.4) (1.7) ---------------------------------------------------------------------------------- Consolidated companies ........ 45.8 27.3 42.2 Effect of recording equity in income of certain affiliated companies on an after-tax basis .................. (2.5) (0.3) (1.4) ---------------------------------------------------------------------------------- Effective tax rate ............ 43.3% 27.0% 40.8% ================================================================================== </TABLE> 13

Note 14. TAXES - Continued The increase in the 1999 effective tax rate from the prior year is primarily due to increased foreign taxes on higher foreign earnings in 1999 compared with 1998. Additional increases in the effective tax rate in 1999 were from tax credits as a smaller proportion of before-tax income in 1999 than 1998 and from less beneficial prior-period tax adjustments on the 1998 tax return compared with the 1997 tax return. The other effects on the 1999 effective tax rate include settlement of outstanding issues, utilization of additional capital loss benefits and permanent differences. These factors were slightly offset by the effect of lower taxable income received from equity affiliates in 1999. The company records its deferred taxes on a tax-jurisdiction basis and classifies those net amounts as current or noncurrent based on the balance sheet classification of the related assets or liabilities. At December 31, 1999 and 1998, deferred taxes were classified in the Consolidated Balance Sheet as follows. <TABLE> <CAPTION> At December 31 ------------------- 1999 1998 -------------------------------------------------------------- <S> <C> <C> Prepaid expenses and other current assets $ (546) $ (30) Deferred charges and other assets ....... (195) (264) Federal and other taxes on income ....... 1 - Noncurrent deferred income taxes ........ 5,010 3,645 -------------------------------------------------------------- Total deferred income taxes, net $ 4,270 $ 3,351 ============================================================== </TABLE> The reported deferred tax balances are composed of the following deferred tax liabilities (assets). <TABLE> <CAPTION> At December 31 ------------------------- 1999 1998 ------------------------------------------------------------------- <S> <C> <C> Properties, plant and equipment ....... $ 5,800 $ 5,150 Inventory ............................. 149 144 Miscellaneous ......................... 190 184 ------------------------------------------------------------------- Total deferred tax liabilities 6,139 5,478 ------------------------------------------------------------------- Abandonment/environmental reserves .... (611) (774) Employee benefits ..................... (611) (592) AMT/other tax credits ................. (588) (354) Other accrued liabilities ............. (195) (408) Miscellaneous ......................... (316) (294) ------------------------------------------------------------------- Total deferred tax assets .... (2,321) (2,422) ------------------------------------------------------------------- Deferred tax assets valuation allowance 452 295 ------------------------------------------------------------------- Total deferred taxes, net .... $ 4,270 $ 3,351 =================================================================== </TABLE> It is the company's policy for subsidiaries included in the U.S. consolidated tax return to record income tax expense as though they filed separately, with the parent recording the adjustment to income tax expense for the effects of consolidation. Undistributed earnings of international consolidated subsidiaries and affiliates for which no deferred income tax provision has been made for possible future remittances totaled approximately $4,602 at December 31, 1999. Substantially all of this amount represents earnings reinvested as part of the company's ongoing business. It is not practical to estimate the amount of taxes that might be payable on the eventual remittance of such earnings. On remittance, certain countries impose withholding taxes that, subject to certain limitations, are then available for use as tax credits against a U.S. tax liability, if any. The company estimates withholding taxes of approximately $187 would be payable upon remittance of these earnings. Note 15. SHORT-TERM DEBT Redeemable long-term obligations consist primarily of tax-exempt variable-rate put bonds that are included as current liabilities because they become redeemable at the option of the bondholders during the year following the balance sheet date. The company has entered into interest rate swaps on a portion of its short-term debt. At December 31, 1999 and 1998, the company had swapped notional amounts of $350 and $700 of floating rate debt to fixed rates. The effect of these swaps on the company's interest expense was not material. <TABLE> <CAPTION> At December 31 -------------------------- 1999 1998 -------------------------------------------------------------------------- <S> <C> <C> <C> Commercial paper(1) .......................... $ 5,265 $ 4,875 Current maturities of long-term debt ......... 127 123 Current maturities of long-term capital leases 35 33 Redeemable long-term obligations Long-term debt ...................... 301 301 Capital leases ...................... 297 273 Notes payable(2).............................. 134 285 -------------------------------------------------------------------------- Subtotal(3).......................... 6,159 5,890 Reclassified to long-term debt ............... (2,725) (2,725) -------------------------------------------------------------------------- Total short-term debt ............... $ 3,434 $ 3,165 ========================================================================== <FN> (1) Weighted-average interest rates at December 31, 1999 and 1998, were 6.0 percent and 5.6 percent, respectively, including the effect of interest rate swaps. (2) Includes $10 guarantee of ESOP debt. (3) Weighted-average interest rates at December 31, 1999 and 1998, were 5.8 percent for both years, including the effect of interest rate swaps. </FN> </TABLE> Note 16. LONG-TERM DEBT Chevron has three "shelf" registrations on file with the Securities and Exchange Commission that together would permit the issuance of $2,800 of debt securities pursuant to Rule 415 of the Securities Act of 1933. At year-end 1999, the company had $4,750 of committed credit facilities with banks worldwide, $2,725 of which had termination dates beyond one year. The facilities support the company's commercial paper borrowings. Interest on borrowings under the terms of specific agreements may be based on the London Interbank Offered Rate, the Reserve Adjusted Domestic Certificate of Deposit Rate, or bank prime rate. No amounts were outstanding under these credit agreements during the year or at year-end. At December 31, 1999 and 1998, the company classified $2,725 of short-term debt as long-term. Settlement of these obligations is not expected to require the use of working capital in 2000 as the company has both the intent and ability to refinance this debt on a long-term basis. Consolidated long-term debt maturing in each of the five years after December 31, 1999, is as follows: 2000-$127, 2001-$285, 2002-$172, 2003-$184 and 2004-$1,134. 14

Note 16.LONG-TERM DEBT - Continued <TABLE> <CAPTION> At December 31 -------------------- 1999 1998 ------------------------------------------------------------------------ <S> <C> <C> 8.11% amortizing notes due 2004(1) ................ $ 620 $ 690 6.625% notes due 2004 ............................. 495 - 7.327% amortizing notes due 2014(2)................ 430 - 7.45% notes due 2004 .............................. 349 349 7.61% amortizing bank loans due 2003 .............. 143 172 LIBOR-based bank loan due 2001 .................... 134 100 7.677% notes due 2016(2)........................... 90 - 7.627% notes due 2015(2)........................... 80 - 6.92% bank loans due 2005 ......................... 51 51 6.98% bank loans due 2004(2)....................... 25 - 6.22% notes due 2001(2)............................ 10 - Other foreign currency obligations (6.0%)(3)....... 75 94 Other long-term debt (6.6%)(3)..................... 74 70 ------------------------------------------------------------------------ Total including debt due within one year . 2,576 1,526 Debt due within one year ........ (127) (123) Reclassified from short-term debt 2,725 2,725 ------------------------------------------------------------------------ Total long-term debt .............................. $ 5,174 $ 4,128 ======================================================================== <FN> (1) Debt assumed from ESOP in 1999. (2) Guarantee of ESOP debt. (3) Less than $50 individually; weighted-average interest rates at December 31, 1999. </FN> </TABLE> Note 17. OTHER COMPREHENSIVE INCOME The components of changes in other comprehensive income and the related tax effects are shown below. <TABLE> <CAPTION> Year ended December 31 ------------------------- 1999 1998 1997 ---------------------------------------------------------------------- <S> <C> <C> <C> Currency translation adjustment Before-tax change ................ $ (43) $ (1) $(173) Tax benefit (expense) ............. - - - ------------------------ Change, net of tax ................ (43) (1) (173) Unrealized holding gain (loss) on securities Before-tax change ................. 60 3 (4) Tax benefit (expense) ............. (31) - - ------------------------ Change, net of tax ................ 29 3 (4) Minimum pension liability adjustment Before-tax change ................. (16) (24) 6 Tax benefit (expense) ............. 5 9 (2) ------------------------ Change, net of tax ................ (11) (15) 4 ---------------------------------------------------------------------- TOTAL OTHER COMPREHENSIVE INCOME Before-tax change ............... $ 1 $ (22) $(171) Tax benefit (expense) ............. (26) 9 (2) ------------------------ Change, net of tax ................ $ (25) $ (13) $(173) ======================================================================= </TABLE> Note 18. EMPLOYEE BENEFIT PLANS Pension Plans The company has defined benefit pension plans for most employees and provides for certain health care and life insurance plans for active and qualifying retired employees. The company's policy is to fund the minimum necessary to satisfy requirements of the Employee Retirement Income Security Act for the company's pension plans. The company's annual contributions for medical and dental benefits are limited to the lesser of actual medical claims or a defined fixed per-capita amount. Life insurance benefits are paid by the company, and annual contributions are based on actual plan experience. Nonfunded pension and postretirement benefits are paid directly when incurred; accordingly, these payments are not reflected as changes in Plan assets in the table below. The status of the company's pension plans and other postretirement benefit plans for 1999 and 1998 is as follows. <TABLE> <CAPTION> Pension Benefits Other Benefits ----------------------------------------- 1999 1998 1999 1998 ------------------------------------------------------------------------------------------- <S> <C> <C> <C> <C> Change in benefit obligation Benefit obligation at January 1 ................ $ 4,278 $ 4,069 $ 1,468 $ 1,362 Service cost .......................... 99 113 21 19 Interest cost ......................... 274 275 96 93 Plan participants' contributions ...... 1 1 - - Plan amendments ....................... 60 - - - Actuarial (gain) loss ................. (106) 248 (112) 72 Foreign currency exchange rate changes ................. (33) (10) - - Benefits paid ......................... (801) (418) (81) (78) Special termination benefits ..................... 205 - - - ------------------------------------------ Benefit obligation at December 31 ........................ 3,977 4,278 1,392 1,468 ------------------------------------------------------------------------------------------- Change in plan assets Fair value of plan assets at January 1 .......................... 4,741 4,454 - - Actual return on plan assets .......... 720 675 - - Foreign currency exchange rate changes ................. (25) (6) - - Employer contribution ................. 10 11 - - Plan participants' contribution ....... 1 1 - - Benefits paid ......................... (774) (394) - - ------------------------------------------ Fair value of plan assets at December 31 ........................ 4,673 4,741 - - ------------------------------------------------------------------------------------------- Funded status .................................. 696 463 (1,392) (1,468) Unrecognized net actuarial gain ....... (480) (155) (160) (46) Unrecognized prior-service cost ....... 124 88 - - Unrecognized net transitional assets ....................... (44) (85) - - ------------------------------------------------------------------------------------------- Total recognized at December 31 ................ $ 296 $ 311 $(1,552) $(1,514) =========================================================================================== Amounts recognized in the Consolidated Balance Sheet at December 31 Prepaid benefit cost ......... $ 495 $ 524 $ - $ - Accrued benefit liability .... (298) (298) (1,552) (1,514) Intangible asset ............. 10 12 - - Accumulated other comprehensive income(1) 89 73 - - ------------------------------------------ Net amount recognized .......................... $ 296 $ 311 $(1,552) $(1,514) =========================================================================================== Weighted-average assumptions as of December 31 Discount rate ................ 7.6% 6.7% 7.8% 6.8% Expected return on plan assets 9.7% 9.1% - - Rate of compensation increase 4.5% 4.6% 4.5% 4.5% =========================================================================================== <FN> (1) Accumulated other comprehensive income includes deferred income tax of $31 and $26 in 1999 and 1998, respectively. </FN> </TABLE> 15

Note 18. EMPLOYEE BENEFIT PLANS - Continued For measurement purposes, separate health care cost-trend rates were used for pre-age 65 and post-age 65 retirees. The 2000 annual rates of change were assumed to be 5.2 percent and 9.7 percent, respectively, before gradually converging to the average ultimate rate of 5.0 percent in 2021 for both pre-age 65 and post-age 65. A one-percentage-point change in the assumed health care rates would have had the following effects. One-Percentage- One-Percentage- Point Increase Point Decrease ----------------------------------------------------------------------- Effect on total service and interest cost components $ 17 $ (19) Effect on postretirement benefit obligation $ 129 $(107) ======================================================================= The components of net periodic benefit cost for 1999, 1998 and 1997 were: <TABLE> <CAPTION> Pension Benefits Other Benefits ------------------------------------------------ 1999 1998 1997 1999 1998 1997 ------------------------------------------------------------------------------- <S> <C> <C> <C> <C> <C> <C> Service cost ............... $ 99 $ 113 $ 106 $ 21 $ 19 $ 17 Interest cost .............. 274 275 274 96 93 90 Expected return on plan assets ....... (394) (397) (371) - - - Amortization of transitional assets (35) (38) (40) - - - Amortization of prior- service costs ..... 16 14 14 - - - Recognized actuarial losses (gains) .... 1 4 4 2 (5) (11) Settlement gains ........... (104) (11) (29) - - - Curtailment losses ......... 7 - - - - - Special termination benefit recognition 205 - 13 - - - ------------------------------------------------ Net periodic benefit cost $ 69 $ (40) $ (29) $ 119 $ 107 $ 96 =============================================================================== </TABLE> The projected benefit obligation, accumulated benefit obligation, and fair value of plan assets for pension plans with accumulated benefit obligations in excess of plan assets were $428, $368 and $80, respectively, at December 31, 1999, and $408, $364 and $87, respectively at December 31, 1998. Profit Sharing/Savings Plan Eligible employees of the company and certain of its subsidiaries who have completed one year of service may participate in the Profit Sharing/Savings Plan. Charges to expense for the profit sharing part of the Profit Sharing/Savings Plan were $86, $60 and $79 in 1999, 1998 and 1997, respectively. Commencing in October 1997, the company's Savings Plus Plan contributions are being funded with leveraged ESOP shares. Employee Stock Ownership Plan (ESOP) In December 1989, the company established a leveraged ESOP as part of the Profit Sharing/Savings Plan. The ESOP Trust Fund borrowed $1,000 and purchased 28.2 million previously unissued shares of the company's common stock. In June 1999, the ESOP borrowed $25 at 6.98 percent interest, using the proceeds to pay interest due on the existing ESOP debt. In July 1999, the company's leveraged ESOP issued notes of $620 at an average interest rate of 7.42 percent, guaranteed by Chevron Corporation. The debt proceeds were paid to Chevron Corporation in exchange for Chevron's assumption of the existing 8.11 percent ESOP long-term debt of $620 million. The ESOP provides a partial prefunding of the company's future commitments to the Profit Sharing/Savings Plan, which will result in annual income tax savings for the company. As permitted by AICPA Statement of Position 93-6, "Employers' Accounting for Employee Stock Ownership Plans," the company has elected to continue its practices, which are based on Statement of Position 76-3, "Accounting Practices for Certain Employee Stock Ownership Plans" and subsequent consensus of the Emerging Issues Task Force of the Financial Accounting Standards Board. Accordingly, the debt of the ESOP is recorded as debt, and shares pledged as collateral are reported as deferred compensation in the Consolidated Balance Sheet and Statement of Stockholders' Equity. The company reports compensation expense equal to the ESOP debt principal repayments less dividends received by the ESOP. Interest incurred on the ESOP debt is recorded as interest expense. Dividends paid on ESOP shares are reflected as a reduction of retained earnings. All ESOP shares are considered outstanding for earnings-per-share computations. The company recorded expense for the ESOP of $84, $58 and $53 in 1999, 1998 and 1997, respectively, including $49, $56 and $61 of interest expense related to the ESOP debt. All dividends paid on the shares held by the ESOP are used to service the ESOP debt. The dividends used were $33, $57 and $57 in 1999, 1998 and 1997, respectively. The company made contributions to the ESOP of $64, $60 and $55 in 1999, 1998 and 1997, respectively, to satisfy ESOP debt service in excess of dividends received by the ESOP. The ESOP shares were pledged as collateral for its debt. Shares are released from a suspense account and allocated to the accounts of Plan participants, based on the debt service deemed to be paid in the year in proportion to the total of current year and remaining debt service. The charge (credit) to compensation expense was $36, $2 and $(8) in 1999, 1998 and 1997, respectively. The ESOP shares as of December 31, 1999 and 1998, were as follows. Thousands 1999 1998 ------------------------------------------ Allocated shares 10,785 10,819 Unallocated shares 12,963 14,087 ------------------------------------------ Total ESOP shares 23,748 24,906 ========================================== Management Incentive Plans The company has two incentive plans, the Management Incentive Plan (MIP) and the Long-Term Incentive Plan (LTIP) for officers and other regular salaried employees of the company and its subsidiaries who hold positions of significant responsibility. The MIP is an annual cash incentive plan that links awards to performance results of the prior year. The cash awards may be deferred by conversion to stock units or, beginning with awards deferred in 1996, stock units or other investment fund alternatives. Awards under the LTIP may take the form of, but are not limited to, stock options, restricted stock, stock units and nonstock grants. Charges to expense for the combined man- 16

Note 18. EMPLOYEE BENEFIT PLANS - Continued agement incentive plans, excluding expense related to LTIP stock options, which is discussed in Note 19, "Stock Options," were $41, $28 and $55 in 1999, 1998 and 1997, respectively. Chevron Success Sharing The company has a program that provides eligible employees with an annual cash bonus if the company achieves certain financial and safety goals. Until 2000, the total maximum payout under the program was 8 percent of the employee's annual salary. Charges for the program were $47, $51 and $116 in 1999, 1998 and 1997, respectively. In 2000, the maximum payout under the program increases to 10 percent. Note 19. STOCK OPTIONS The company applies APB Opinion No. 25 and related interpretations in accounting for stock options awarded under its Broad-Based Employee Stock Option Programs and its Long-Term Incentive Plan, which are described below. Had compensation cost for the company's stock options been determined based on the fair market value at the grant dates of the awards consistent with the methodology prescribed by SFAS No. 123, the company's net income and earnings per share for 1999, 1998 and 1997 would have been the pro forma amounts shown below. <TABLE> <CAPTION> 1999 1998 1997 --------------------------- <S> <C> <C> <C> Net Income As reported $2,070 $1,339 $3,256 Pro forma $2,027 $1,294 $3,302 Earnings per share As reported - basic $3.16 $2.05 $4.97 - diluted $3.14 $2.04 $4.95 Pro forma - basic $3.09 $1.98 $5.04 - diluted $3.08 $1.97 $5.02 </TABLE> The effects of applying SFAS No. 123 in this pro forma disclosure are not indicative of future amounts. SFAS No. 123 does not apply to awards granted prior to 1995. In addition, certain options vest over several years, and awards in future years, whose terms and conditions may vary, are anticipated. Long-Term Incentive Plan Stock options granted under the LTIP are generally awarded at market price on the date of grant and are exercisable not earlier than one year and not later than 10 years from the date of grant. However, a portion of the LTIP options granted in 1996 had terms similar to the broad-based employee stock options, which are described in the following table. The maximum number of shares of common stock that may be granted each year is 1 percent of the total outstanding shares of common stock as of January 1 of such year. A summary of the status of stock options awarded under the company's LTIP, excluding awards granted with terms similar to the broad-based employee stock options, for 1999, 1998 and 1997 follows. <TABLE> <CAPTION> Weighted- Average Options Exercise (000s) Price ----------------------------------------------------- <S> <C> <C> Outstanding at December 31, 1996 7,277 $44.84 ----------------------------------------------------- Granted 1,801 80.78 Exercised (710) 38.65 Forfeited (115) 72.18 ----------------------------------------------------- Outstanding at December 31, 1997 8,253 $52.83 ----------------------------------------------------- Granted 1,872 79.13 Exercised (796) 40.47 Forfeited (106) 80.70 ----------------------------------------------------- Outstanding at December 31, 1998 9,223 $58.91 ----------------------------------------------------- Granted 1,830 89.88 Exercised (1,298) 44.29 Forfeited (152) 83.12 ----------------------------------------------------- Outstanding at December 31, 1999 9,603 $66.41 ===================================================== Exercisable at December 31 1997 6,502 $45.31 1998 7,367 $53.82 1999 7,839 $61.13 ===================================================== </TABLE> The weighted-average fair market value of options granted in 1999, 1998 and 1997 was $20.40, $21.10 and $17.64 per share, respectively. The fair market value of each option on the date of grant was estimated using the Black-Scholes option-pricing model with the following assumptions for 1999, 1998 and 1997, respectively: risk-free interest rate of 5.5, 4.5 and 6.1 percent; dividend yield of 3.0, 3.1 and 2.8 percent; volatility of 20.1, 28.6 and 15.2 percent and expected life of seven years in all years. As of December 31, 1999, 9,602,900 shares were under option at exercise prices ranging from $31.9375 to $99.75 per share. The following table summarizes information about stock options outstanding under the LTIP, excluding awards granted with terms similar to the broad-based employee stock options, at December 31, 1999. <TABLE> <CAPTION> Options Outstanding Options Exercisable ---------------------------------------- ---------------------------- Weighted- Average Weighted- Weighted- Range of Number Remaining Average Number Average Exercise Outstanding Contractual Exercise Exercisable Exercise Prices (000s) Life (Years) Price (000s) Price ----------------------------------------------------------------------------------------- <S> <C> <C> <C> <C> <C> $31 to $ 41 614 2.12 $34.55 614 $34.55 41 to 51 3,128 4.72 45.18 3,128 45.18 51 to 61 15 6.31 56.49 15 56.49 61 to 71 766 6.83 66.25 766 66.25 71 to 81 3,299 8.34 79.91 3,297 79.91 81 to 91 1,758 9.80 89.80 19 82.80 91 to 101 23 9.55 92.14 - - ----------------------------------------------------------------------------------------- $31 to $101 9,603 6.91 $66.41 7,839 $61.13 ========================================================================================= </TABLE> Broad-Based Employee Stock Options In 1996, the company granted to all eligible employees an option for 150 shares of stock or equivalents at an exercise price of $51.875 per share. In addition, a portion of the awards granted under the LTIP had terms similar to the broad-based employee stock options. When the options were issued in February 1996, vesting was contingent upon one of two conditions being met: By Decem- 17

Note 19. STOCK OPTIONS - Continued ber 31, 1998, the price of Chevron stock closed at or above $75.00 per share for three consecutive business days or, alternatively, the company had the highest annual total stockholder return of its competitor group for the years 1994 through 1998. The options vested in June 1997 when the share price performance condition was met. Options for 7,204,800 shares, including similar-termed LTIP awards, were granted in 1996. Forfeitures of options for 820,050 shares and exercises of 4,171,300 reduced the outstanding option shares to 2,213,450 at December 31, 1997. In 1998, exercises of 1,361,000 and forfeitures of 10,800 had reduced the outstanding option shares to 841,650 at year-end 1998. In 1999, exercises of 740,725, forfeitures of 61,850 and expirations of 39,075 had reduced the outstanding option shares to zero at March 31, 1999, the date of expiration. Under APB Opinion No. 25, the company recorded expenses of $(2), $0 and $125 for these options in 1999, 1998 and 1997, respectively. The fair market value of each option share on the date of grant under SFAS No. 123 was estimated at $5.66 using a binomial option-pricing model with the following assumptions: risk-free interest rate of 5.1 percent, dividend yield of 4.2 percent, expected life of three years and a volatility of 20.9 percent. In 1998, the company announced a new broad-based Employee Stock Option Program that granted to all eligible employees an option that varied from 100 to 300 shares of stock or equivalents, dependent on the employee's salary or job grade. These options were to vest in two years or, if the company had the highest total stockholder return among its competitor group for the years 1994 through 1998, in one year. Since the stockholders' return performance condition was not met, the options vested in February 2000. Options for 4,820,800 shares were awarded at an exercise price of $76.3125 per share. Forfeitures of options for 854,550 shares reduced the outstanding option shares to 3,966,250 at December 31, 1999, at which date none was exercisable. The options expire on February 11, 2008. Under APB Opinion No. 25, the company recorded expenses of $4 and $2 for these options in 1999 and 1998, respectively. The fair value of each option share on the date of grant under SFAS No. 123 was estimated at $19.08 using the average results of Black-Scholes models for the preceding 10 years. The 10-year averages of each assumption used by the Black-Sholes models were: risk-free interest rate of 7.0 percent, dividend yield of 4.2 percent, expected life of seven years and a volatility of 24.7 percent. Note 20. EARNINGS PER SHARE (EPS) Basic EPS includes the effects of deferrals of salary and other compensation awards that are invested in Chevron stock units by certain officers and employees of the company. Diluted EPS includes the effects of these deferrals as well as the dilutive effects of outstanding stock options awarded under the LTIP and Broad-Based Employee Stock Option Program (see Note 19, "Stock Options"). The following table sets forth the computation of basic and diluted EPS. <TABLE> <CAPTION> 1999 1998 1997 ------------------------------------------------------------------------------------------------------ Net Shares Per-Share Net Shares Per-Share Net Shares Per-Share Income (millions) Amount Income (millions) Amount Income (millions) Amount -------------------------------------------------------------------------------------------------------------------------------- <S> <C> <C> <C> <C> <C> <C> <C> <C> <C> Net income $ 2,070 $ 1,339 $ 3,256 Weighted-average common shares outstanding 655.5 653.7 655.0 Dividend equivalents paid on Chevron stock units 3 3 2 Deferred awards held as Chevron stock units 1.0 1.2 1.3 -------------------------------------------------------------------------------------------------------------------------------- BASIC EPS COMPUTATION $ 2,073 656.5 $3.16 $ 1,342 654.9 $2.05 $ 3,258 656.3 $4.97 Dilutive effects of stock options 3.0 2.2 2.1 -------------------------------------------------------------------------------------------------------------------------------- DILUTED EPS COMPUTATION $ 2,073 659.5 $3.14 $ 1,342 657.1 $2.04 $ 3,258 658.4 $4.95 ================================================================================================================================ </TABLE> 18

Note 21.OTHER CONTINGENCIES AND COMMITMENTS The U.S. federal income tax and California franchise tax liabilities of the company have been settled through 1990 and 1991, respectively. Settlement of open tax years, as well as tax issues in other countries where the company conducts its businesses, is not expected to have a material effect on the consolidated financial position or liquidity of the company and, in the opinion of management, adequate provision has been made for income and franchise taxes for all years under examination or subject to future examination. At December 31, 1999, the company and its subsidiaries, as direct or indirect guarantors, had contingent liabilities of $25 for notes of affiliated companies and $362 for notes of others. The company and its subsidiaries have certain contingent liabilities relating to long-term unconditional purchase obligations and commitments, throughput agreements and take-or-pay agreements, some of which relate to suppliers' financing arrangements. The aggregate amounts of required payments under these various commitments are: 2000-$228; 2001-$297; 2002-$270; 2003-$253; 2004-$225; 2005 and after-$1,029. Total payments under the agreements were $258 in 1999, $201 in 1998 and $243 in 1997. The company is subject to loss contingencies pursuant to environmental laws and regulations that in the future may require the company to take action to correct or ameliorate the effects on the environment of prior disposal or release of chemical or petroleum substances, including MTBE, by the company or other parties. Such contingencies may exist for various sites including, but not limited to: Superfund sites and refineries, oil fields, service stations, terminals, and land development areas, whether operating, closed or sold. The amount of such future cost is indeterminable 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. While the company has provided for known environmental obligations that are probable and reasonably estimable, the amount of future costs may be material to results of operations in the period in which they are recognized. The company does not expect these costs to 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 domestic or international petroleum or chemical concerns. 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. However, the results of operations and financial position of certain equity affiliates may be affected by their business activities involving the use of derivative instruments. The company's operations, particularly oil and gas exploration and production, can be affected by changing economic, regulatory and political environments in the various countries, including the United States, in which it operates. In certain locations, host governments have imposed restrictions, controls and taxes, and in others, political conditions have existed that may threaten the safety of employees and the company's continued presence in those countries. Internal unrest or strained relations between a host government and the company or other governments may affect the company's operations. Those developments have, at times, significantly affected the company's operations and related results and are carefully considered by management when evaluating the level of current and future activity in such countries. Areas in which the company has significant operations include the United States, Canada, Australia, United Kingdom, Norway, Congo, Angola, Nigeria, Democratic Republic of Congo, Papua New Guinea, China, Indonesia, Venezuela, Thailand and Argentina. The company's Caltex affiliates have significant operations in Indonesia, Korea, Australia, Thailand, the Philippines, Singapore and South Africa. The company's Tengizchevroil affiliate operates in Kazakhstan. Note 22.EMPLOYEE TERMINATION BENEFITS AND OTHER RESTRUCTURING COSTS The company recorded before-tax charges to income of $235 in 1999 for employee termination benefits and other restructuring costs as part of a companywide staff reduction program. The charge includes severance and other termination benefits of $220 for 3,472 employees and $82 for employee and office relocation, lease termination penalties, and other items. These charges were offset partly by $67 of restructuring-related net pension settlement/curtailment gains for payments made to terminated employees. The staff reduction program affects primarily U.S.-based employees and is being implemented in all of the company's operating segments across several business functions. All identified employees will be separated by June 30, 2000. Termination benefits for 3,070 of the 3,472 employees - accrued in accordance with SFAS No. 88, "Employers' Accounting for Settlements and Curtailments of Defined Benefit Plans and for Termination Benefits" - are payable from the assets of the company's U.S. and Canadian pension plans. Payments to other employees are from company funds. Accrual and payment activity for the employee termination benefits is presented in the following table. <TABLE> <CAPTION> Restructuring Number of Liability Employees -------------------------------------------------------------- <S> <C> <C> Balance at December 31, 1998 $ - - Accruals 220 3,472 Cash Payments (135) 2,157 ---------------------------- Balance at December 31, 1999 $ 85 1,315 ============================================================== </TABLE> Of the $82 for relocations, lease termination penalties and other costs, approximately 13 percent remained unpaid at the end of 1999. These charges and the restructuring-related pension gains were classified mainly as either "operating expense" or "selling, general and administrative expense." Items are either accrued or recognized as incurred under the guidelines of EITF Issue No. 94-3, "Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring)" or SFAS No. 88, as applicable. The company's net income for 1999 also included its $25 share of a restructuring charge recorded by Caltex. 19

SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES Unaudited In accordance with Statement of Financial Accounting Standards No. 69, "Disclosures About Oil and Gas Producing Activities" (SFAS No. 69), this section provides supplemental information on oil and gas exploration and producing activities of the company in six separate tables. Tables I through III provide historical cost information pertaining to costs incurred in exploration, property acquisitions and development; capitalized costs; and results of operations. Tables IV through VI present information on the company's estimated net proved reserve quantities, standardized measure of estimated discounted future net cash flows related to proved reserves, and changes in estimated discounted future net cash flows. The Africa geographic area includes activities principally in Nigeria, Angola, Congo and Democratic Republic of Congo. The "Other" geographic category includes activities in Australia, Argentina, the United Kingdom North Sea, Canada, Papua New Guinea, Venezuela, China, Thailand and other countries. Amounts shown for affiliated companies are Chevron's 50 percent equity share in P.T. Caltex Pacific Indonesia (CPI), an exploration and production company operating in Indonesia, and its 45 percent (50 percent prior to April 1997) equity share of Tengizchevroil (TCO), an exploration and production partnership operating in the Republic of Kazakhstan. <TABLE> <CAPTION> TABLE I - COSTS INCURRED IN EXPLORATION, PROPERTY ACQUISITIONS AND DEVELOPMENT(1) Consolidated Companies Affiliated Companies Millions of dollars U.S. Africa Other Total CPI TCO Worldwide -------------------------------------------------------------------------------- <S> <C> <C> <C> <C> <C> <C> <C> YEAR ENDED DECEMBER 31, 1999 Exploration Wells $ 258 $ 40 $ 120 $ 418 $ 3 $ - $ 421 Geological and geophysical 37 25 85 147 17 - 164 Rentals and other 30 7 60 97 - - 97 ---------------------------------------------------------------------------------------------------------------------------- Total exploration 325 72 265 662 20 - 682 ---------------------------------------------------------------------------------------------------------------------------- Property acquisitions(2),(3) Proved(4) 9 - 1,070 1,079 - - 1,079 Unproved 27 11 1,202 1,240 - - 1,240 ---------------------------------------------------------------------------------------------------------------------------- Total property acquisitions 36 11 2,272 2,319 - - 2,319 ---------------------------------------------------------------------------------------------------------------------------- Development 532 518 375 1,425 182 148 1,755 ---------------------------------------------------------------------------------------------------------------------------- TOTAL COSTS INCURRED $ 893 $ 601 $2,912 $4,406 $202 $148 $4,756 ============================================================================================================================ YEAR ENDED DECEMBER 31, 1998 Exploration Wells $ 350 $ 108 $ 101 $ 559 $ 3 $ - $ 562 Geological and geophysical 49 31 112 192 16 - 208 Rentals and other 44 23 53 120 - - 120 ---------------------------------------------------------------------------------------------------------------------------- Total exploration 443 162 266 871 19 - 890 ---------------------------------------------------------------------------------------------------------------------------- Property acquisitions(2) Proved(4) 12 - - 12 - - 12 Unproved 58 - 14 72 - - 72 ---------------------------------------------------------------------------------------------------------------------------- Total property acquisitions 70 - 14 84 - - 84 ---------------------------------------------------------------------------------------------------------------------------- Development 680 561 411 1,652 156 120 1,928 ---------------------------------------------------------------------------------------------------------------------------- TOTAL COSTS INCURRED $1,193 $ 723 $ 691 $2,607 $175 $120 $2,902 ============================================================================================================================ YEAR ENDED DECEMBER 31, 1997 Exploration Wells $ 278 $ 99 $ 149 $ 526 $ 2 $ - $ 528 Geological and geophysical 39 31 59 129 16 - 145 Rentals and other 43 17 65 125 - - 125 ---------------------------------------------------------------------------------------------------------------------------- Total exploration 360 147 273 780 18 - 798 ---------------------------------------------------------------------------------------------------------------------------- Property acquisitions(2) Proved(4) 3 6 75 84 - - 84 Unproved 101 - 23 124 - - 124 ---------------------------------------------------------------------------------------------------------------------------- Total property acquisitions 104 6 98 208 - - 208 ---------------------------------------------------------------------------------------------------------------------------- Development 918 461 529 1,908 159 152 2,219 ---------------------------------------------------------------------------------------------------------------------------- TOTAL COSTS INCURRED $1,382 $ 614 $ 900 $2,896 $177 $152 $3,225 ============================================================================================================================ <FN> (1) Includes costs incurred whether capitalized or charged to earnings. Excludes support equipment expenditures. (2) Proved amounts include wells, equipment and facilities associated with proved reserves. (3) Includes acquisition costs and related deferred income taxes for purchases of Rutherford-Moran Oil Corporation and Petrolera Argentina San Jorge S.A. (4) Does not include properties acquired through property exchanges. </FN> </TABLE> 20

<TABLE> <CAPTION> TABLE II - CAPITALIZED COSTS RELATED TO OIL AND GAS PRODUCING ACTIVITIES Consolidated Companies Affiliated Companies ------------------------------------- --------------------- Millions of dollars U.S. Africa Other Total CPI TCO Worldwide --------------------------------------------------------------------------------------------------------------------------- <S> <C> <C> <C> <C> <C> <C> <C> AT DECEMBER 31, 1999 Unproved properties .......................... $ 317 $ 69 $ 1,441 $ 1,827 $ - $ 378 $ 2,205 Proved properties and related producing assets 16,662 4,034 7,318 28,014 1,158 689 29,861 Support equipment ............................ 478 268 321 1,067 902 243 2,212 Deferred exploratory wells ................... 136 172 66 374 - - 374 Other uncompleted projects ................... 354 758 664 1,776 335 405 2,516 --------------------------------------------------------------------------------------------------------------------------- GROSS CAPITALIZED COSTS ...................... 17,947 5,301 9,810 33,058 2,395 1,715 37,168 --------------------------------------------------------------------------------------------------------------------------- Unproved properties valuation ................ 133 53 157 343 - - 343 Proved producing properties - Depreciation and depletion .................. 11,953 1,993 3,071 17,017 681 99 17,797 Future abandonment and restoration .......... 835 371 208 1,414 60 10 1,484 Support equipment depreciation ............... 317 104 142 563 476 80 1,119 --------------------------------------------------------------------------------------------------------------------------- Accumulated provisions ....................... 13,238 2,521 3,578 19,337 1,217 189 20,743 --------------------------------------------------------------------------------------------------------------------------- NET CAPITALIZED COSTS ........................ $ 4,709 $ 2,780 $ 6,232 $13,721 $ 1,178 $ 1,526 $16,425 =========================================================================================================================== AT DECEMBER 31, 1998 Unproved properties .......................... $ 390 $ 58 $ 235 $ 683 $ - $ 378 $ 1,061 Proved properties and related producing assets 16,759 3,672 6,253 26,684 1,015 629 28,328 Support equipment ............................ 472 182 307 961 768 232 1,961 Deferred exploratory wells ................... 51 51 91 193 - - 193 Other uncompleted projects ................... 700 893 383 1,976 408 245 2,629 --------------------------------------------------------------------------------------------------------------------------- GROSS CAPITALIZED COSTS ...................... 18,372 4,856 7,269 30,497 2,191 1,484 34,172 --------------------------------------------------------------------------------------------------------------------------- Unproved properties valuation ................ 151 49 110 310 - - 310 Proved producing properties - Depreciation and depletion .................. 11,808 1,719 2,705 16,232 689 72 16,993 Future abandonment and restoration .......... 861 337 187 1,385 57 8 1,450 Support equipment depreciation ............... 315 90 127 532 373 67 972 --------------------------------------------------------------------------------------------------------------------------- Accumulated provisions ....................... 13,135 2,195 3,129 18,459 1,119 147 19,725 --------------------------------------------------------------------------------------------------------------------------- NET CAPITALIZED COSTS ........................ $ 5,237 $ 2,661 $ 4,140 $12,038 $ 1,072 $ 1,337 $14,447 =========================================================================================================================== AT DECEMBER 31, 1997 Unproved properties .......................... $ 370 $ 58 $ 236 $ 664 $ - $ 378 $ 1,042 Proved properties and related producing assets 16,284 3,303 5,644 25,231 1,112 491 26,834 Support equipment ............................ 503 209 310 1,022 578 209 1,809 Deferred exploratory wells ................... 120 46 58 224 - - 224 Other uncompleted projects ................... 826 549 821 2,196 338 153 2,687 --------------------------------------------------------------------------------------------------------------------------- GROSS CAPITALIZED COSTS ...................... 18,103 4,165 7,069 29,337 2,028 1,231 32,596 --------------------------------------------------------------------------------------------------------------------------- Unproved properties valuation ................ 153 42 98 293 - - 293 Proved producing properties - Depreciation and depletion .................. 11,657 1,459 2,521 15,637 626 51 16,314 Future abandonment and restoration .......... 926 304 177 1,407 44 6 1,457 Support equipment depreciation ............... 315 79 130 524 343 53 920 --------------------------------------------------------------------------------------------------------------------------- Accumulated provisions ....................... 13,051 1,884 2,926 17,861 1,013 110 18,984 --------------------------------------------------------------------------------------------------------------------------- NET CAPITALIZED COSTS ........................ $ 5,052 $ 2,281 $ 4,143 $11,476 $ 1,015 $ 1,121 $13,612 =========================================================================================================================== </TABLE> TABLE III - RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES (1) The company's results of operations from oil and gas producing activities for the years 1999, 1998 and 1997 are shown in the following table. Net income from exploration and production activities as reported on page 10 reflects income taxes computed on an effective rate basis. In accordance with SFAS No. 69, income taxes in Table III are based on statutory tax rates, reflecting allowable deductions and tax credits. Interest income and expense is excluded from the results reported in Table III and from the net income amounts on page 10. 21

<TABLE> <CAPTION> TABLE III - RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES (1) - Continued Consolidated Companies Affiliated Companies ---------------------------------------- ---------------------- Millions of dollars U.S. Africa Other Iotal CPI TCO Worldwide -------------------------------------------------------------------------------------------------------------------------------- <S> <C> <C> <C> <C> <C> <C> <C> YEAR ENDED DECEMBER 31, 1999 Revenues from net production Sales ................................... $ 1,449 $ 1,756 $ 1,415 $ 4,620 $ 24 $ 356 $ 5,000 Transfers ............................... 1,626 299 597 2,522 592 - 3,114 -------------------------------------------------------------------------------------------------------------------------------- Total ......... 3,075 2,055 2,012 7,142 616 356 8,114 Production expenses ...................... (1,005) (340) (411) (1,756) (206) (88) (2,050) Proved producing properties: depreciation, depletion and abandonment provision ..... (764) (311) (433) (1,508) (109) (47) (1,664) Exploration expenses ..................... (167) (97) (274) (538) (17) - (555) Unproved properties valuation ............ (22) (5) (36) (63) - - (63) Other income (expense)(2)................. (307) (53) 5 (355) (2) (9) (366) -------------------------------------------------------------------------------------------------------------------------------- Results before income taxes ............. 810 1,249 863 2,922 282 212 3,416 Income tax expense ....................... (275) (848) (416) (1,539) (143) (63) (1,745) -------------------------------------------------------------------------------------------------------------------------------- RESULTS OF PRODUCING OPERATIONS .......... $ 535 $ 401 $ 447 $ 1,383 $ 139 $ 149 $ 1,671 ================================================================================================================================ YEAR ENDED DECEMBER 31, 1998 Revenues from net production Sales ................................... $ 1,386 $ 1,118 $ 757 $ 3,261 $ 28 $ 176 $ 3,465 Transfers ............................... 1,185 212 458 1,855 454 - 2,309 -------------------------------------------------------------------------------------------------------------------------------- Total ......... 2,571 1,330 1,215 5,116 482 176 5,774 Production expenses ...................... (1,172) (346) (304) (1,822) (153) (76) (2,051) Proved producing properties: depreciation, depletion and abandonment provision ..... (714) (301) (316) (1,331) (106) (40) (1,477) Exploration expenses ..................... (213) (53) (212) (478) (16) - (494) Unproved properties valuation ............ (20) (8) (16) (44) - - (44) Other income (expense)(2)................. 96 48 85 229 2 (7) 224 -------------------------------------------------------------------------------------------------------------------------------- Results before income taxes ............. 548 670 452 1,670 209 53 1,932 Income tax expense ....................... (178) (328) (323) (829) (102) (16) (947) -------------------------------------------------------------------------------------------------------------------------------- RESULTS OF PRODUCING OPERATIONS .......... $ 370 $ 342 $ 129 $ 841 $ 107 $ 37 $ 985 ================================================================================================================================ YEAR ENDED DECEMBER 31, 1997 Revenues from net production Sales ................................... $ 1,931 $ 1,782 $ 899 $ 4,612 $ 43 $ 283 $ 4,938 Transfers ............................... 1,799 273 656 2,728 634 - 3,362 -------------------------------------------------------------------------------------------------------------------------------- Total ......... 3,730 2,055 1,555 7,340 677 283 8,300 Production expenses ...................... (1,272) (297) (278) (1,847) (197) (79) (2,123) Proved producing properties: depreciation, depletion and abandonment provision ..... (737) (256) (311) (1,304) (130) (37) (1,471) Exploration expenses ..................... (227) (66) (200) (493) (16) - (509) Unproved properties valuation ............ (16) (7) (10) (33) - - (33) Other income (expense)(2)................. 87 (46) 196 237 10 (13) 234 -------------------------------------------------------------------------------------------------------------------------------- Results before income taxes .............. 1,565 1,383 952 3,900 344 154 4,398 Income tax expense ...................... (555) (939) (365) (1,859) (173) (46) (2,078) -------------------------------------------------------------------------------------------------------------------------------- RESULTS OF PRODUCING OPERATIONS .......... $ 1,010 $ 444 $ 587 $ 2,041 $ 171 $ 108 $ 2,320 ================================================================================================================================ <FN> (1) The value of owned production consumed as fuel has been eliminated from revenues and production expenses, and the related volumes have been deducted from net production in calculating the unit average sales price and production cost; this has no effect on the results of producing operations. (2) Includes gas processing fees, net sulfur income, natural gas contract settlements, currency transaction gains and losses, certain significant impairment write-downs, miscellaneous expenses, etc. Also includes net income from related oil and gas activities that do not have oil and gas reserves attributed to them (e.g., equity earnings of Dynegy Inc., net income from technical and operating service agreements). </FN> </TABLE> 22

<TABLE> <CAPTION> TABLE III - RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES (1),(2) - Continued Consolidated Companies Affiliated Companies --------------------------------- ------------------- Per-unit average sales price and production cost (1),(2) U.S. Africa Other Total CPI TCO Worldwide ------------------------------------------------------------------------------------------------------------------------------ <S> <C> <C> <C> <C> <C> <C> <C> YEAR ENDED DECEMBER 31, 1999 Average sales prices Liquids, per barrel ................................... $15.73 $17.27 $17.69 $16.82 $13.40 $10.53 $15.90 Natural gas, per thousand cubic feet .................. 2.17 0.05 2.21 2.14 - 0.38 2.10 Average production costs, per barrel ................... 4.73 2.81 3.32 3.84 4.47 2.39 3.79 ============================================================================================================================== YEAR ENDED DECEMBER 31, 1998 Average sales prices Liquids, per barrel ................................... $11.27 $11.49 $11.21 $11.34 $ 9.73 $ 5.53 $10.68 Natural gas, per thousand cubic feet .................. 2.02 .07 2.26 2.04 - .57 2.01 Average production costs, per barrel ................... 5.30 2.94 2.93 4.12 3.10 2.32 3.91 ============================================================================================================================== YEAR ENDED DECEMBER 31, 1997 Average sales prices Liquids, per barrel ................................... $17.33 $18.15 $16.88 $17.53 $15.35 $10.69 $16.82 Natural gas, per thousand cubic feet .................. 2.42 - 2.35 2.40 - .51 2.35 Average production costs, per barrel ................... 5.47 2.61 2.89 4.17 4.48 2.78 4.22 ============================================================================================================================== Average sales price for liquids ($/Bbl) December 1999 ......................................... $22.25 $24.88 $24.06 $23.68 $23.68 $11.55 $22.65 December 1998 ......................................... 8.86 9.55 9.04 9.17 8.33 3.69 8.58 December 1997 ......................................... 15.63 15.60 15.09 15.48 14.16 9.40 14.91 ============================================================================================================================== Average sales price for natural gas ($/MCF) December 1999 ......................................... $ 2.20 $ 0.04 $ 2.41 $ 2.23 $ - $ 0.38 $ 2.18 December 1998 ......................................... 2.23 - 2.47 2.29 - .57 2.26 December 1997 ......................................... 2.25 - 2.76 2.31 - .63 2.26 ============================================================================================================================== <FN> (1) The value of owned production consumed as fuel has been eliminated from revenues and production expenses, and the related volumes have been deducted from net production in calculating the unit average sales price and production cost; this has no effect on the results of producing operations. (2) Natural gas converted to crude oil equivalent gas (OEG) barrels at a rate of 6 MCF=1 OEG barrel. </FN> </TABLE> TABLE IV - RESERVE QUANTITY INFORMATION The company's estimated net proved underground oil and gas reserves and changes thereto for the years 1999, 1998 and 1997 are shown in the following table. Proved reserves are estimated by company asset teams composed of earth scientists and reservoir engineers. These proved reserve estimates are reviewed annually by the corporation's Reserves Advisory Committee to ensure that rigorous professional standards and the reserves definitions prescribed by the U.S. Securities and Exchange Commission are consistently applied throughout the company. Proved reserves are the estimated quantities that geologic and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Due to the inherent uncertainties and the limited nature of reservoir data, estimates of underground reserves are subject to change as additional information becomes available. Proved reserves do not include additional quantities recoverable beyond the term of the lease or concession agreement that may result from extensions of currently proved areas or from applying secondary or tertiary recovery processes not yet tested and determined to be economic. Proved developed reserves are the quantities expected to be recovered through existing wells with existing equipment and operating methods. "Net" reserves exclude royalties and interests owned by others and reflect contractual arrangements and royalty obligations in effect at the time of the estimate. In June 1997, Chevron assumed operatorship under a risked service agreement for Venezuela's Block LL-652, located in the northeast section of Lake Maracaibo. Chevron is accounting for LL-652 as an oil and gas activity and, at December 31, 1999, had recorded 54 million barrels of proved crude oil reserves. No reserve quantities have been recorded for the company's other service agreement in Venezuela, which began in 1996, involving the Boscan Field. 23

<TABLE> <CAPTION> TABLE IV - RESERVE QUANTITY INFORMATION - Continued NET PROVED RESERVES OF CRUDE OIL, CONDENSATE NET PROVED RESERVES OF NATURAL GAS AND NATURAL GAS LIQUIDS Millions of barrels Billions of cubic feet -------------------------------------------------- -------------------------------------------------- Consolidated Companies Affiliates World- Consolidated Companies Affiliates World- ---------------------------- ----------- --------------------------- ------------ U.S. Africa Other Total CPI TCO wide U.S. Africa Other Total CPI TCO wide -------------------------------------------------------------------------------------------------------------------------------- <S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> RESERVES AT JANUARY 1, 1997 ........ 1,149 1,032 482 2,663 566 1,135 4,364 5,275 293 3,135 8,703 152 1,462 10,317 Changes attributable to: Revisions ............. 8 (16) 38 30 37 92 159 (98) (67) 211 46 19 120 185 Improved recovery 139 72 7 218 27 - 245 111 - 1 112 5 - 117 Extensions and discoveries .... 57 156 14 227 4 - 231 470 - 12 482 2 - 484 Purchases(1) .......... - - 51 51 - - 51 3 - 1 4 - - 4 Sales(2) .............. (32) - (1) (33) - (120) (153) (95) - (7) (102) - (156) (258) Production ............. (125) (113) (72) (310) (56) (25) (391) (675) (3) (166) (844) (17) (25) (886) -------------------------------------------------------------------------------------------------------------------------------- RESERVES AT DECEMBER 31, 1997 ...... 1,196 1,131 519 2,846 578 1,082 4,506 4,991 223 3,187 8,401 161 1,401 9,963 Changes attributable to: Revisions (1) 106 28 133 110(3) 7 250 (151) 77 13 (61) 7 (17) (71) Improved recovery 36 88 36 160 25 - 185 7 - - 7 12 - 19 Extensions and discoveries 43 92 7 142 2 16 160 372 - 3 375 1 21 397 Purchases(1) 5 - 30 35 - - 35 32 - 5 37 - - 37 Sales(2) (12) - (22) (34) - - (34) (119) - (50) (169) - - (169) Production (119) (117) (77) (313) (62) (30) (405) (635) (12) (175) (822) (30) (21) (873) -------------------------------------------------------------------------------------------------------------------------------- RESERVES AT DECEMBER 31, 1998 1,148 1,300 521 2,969 653 1,075 4,697 4,497 288 2,983 7,768 151 1,384 9,303 Changes attributable to: Revisions (23) 3 (24) (44) (98)(3) 115 (27) (426) 49 30 (347) 2 126 (219) Improved recovery 44 62 20 126 30 - 156 7 - 8 15 1 - 16 Extensions and discoveries 50 45 17 112 2 76 190 347 - 86 433 5 98 536 Purchases(1) 1 - 213 214 - - 214 35 - 372 407 - - 407 Sales(2) (33) - (2) (35) - - (35) (74) - - (74) - - (74) Production (115) (120) (84) (319) (59) (33) (411) (598) (15) (248) (861) (25) (27) (913) -------------------------------------------------------------------------------------------------------------------------------- RESERVES AT DECEMBER 31, 1999 1,072 1,290 661 3,023 528 1,233 4,784 3,788 322 3,231 7,341 134 1,581 9,056 ================================================================================================================================ Developed reserves -------------------------------------------------------------------------------------------------------------------------------- At January 1, 1997 1,027 658 281 1,966 448 500 2,914 4,727 293 1,634 6,654 136 643 7,433 At December 31, 1997 1,025 721 293 2,039 435 532 3,006 4,391 223 1,695 6,309 145 688 7,142 At December 31, 1998 982 891 342 2,215 436 646 3,297 3,918 263 2,074 6,255 135 832 7,222 AT DECEMBER 31, 1999 905 940 489 2,334 340 790 3,464 3,345 272 2,243 5,860 131 1,011 7,002 ================================================================================================================================ <FN> (1) Includes reserves acquired through property exchanges. (2) Includes reserves disposed of through property exchanges. (3) Mainly includes crude reserves revisions associated with CPI's cost-recovery formula. </FN> </TABLE> TABLE V - STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATED TO PROVED OIL AND GAS RESERVES The standardized measure of discounted future net cash flows, related to the above proved oil and gas reserves, is calculated in accordance with the requirements of SFAS No. 69. Estimated future cash inflows from production are computed by applying year-end prices for oil and gas to year-end quantities of estimated net proved reserves. Future price changes are limited to those provided by contractual arrangements in existence at the end of each reporting year. Future development and production costs are those estimated future expenditures necessary to develop and produce year-end estimated proved reserves based on year-end cost indices, assuming continuation of year-end economic conditions. Estimated future income taxes are calculated by applying appropriate year-end statutory tax rates. These rates reflect allowable deductions and tax credits and are applied to estimated future pretax net cash flows, less the tax basis of related assets. Discounted future net cash flows are calculated using 10 percent midperiod discount factors. Discounting requires a year-by-year estimate of when future expenditures will be incurred and when reserves will be produced. The information provided does not represent management's estimate of the company's expected future cash flows or value of proved oil and gas reserves. Estimates of proved reserve quantities are imprecise and change over time as new information becomes available. Moreover, probable and possible reserves, which may become proved in the future, are excluded from the calculations. The arbitrary valuation prescribed under SFAS No. 69 requires assumptions as to the timing and amount of future development and production costs. The calculations are made as of December 31 each year and should not be relied upon as an indication of the company's future cash flows or value of its oil and gas reserves. 24

<TABLE> <CAPTION> TABLE V - STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATED TO PROVED OIL AND GAS RESERVES - Continued Consolidated Companies Affiliated Companies ------------------------------------------------ ---------------------- Millions of dollars ................... U.S. Africa Other Total CPI TCO Worldwide --------------------------------------------------------------------------------------------------------------------------------- <S> <C> <C> <C> <C> <C> <C> <C> AT DECEMBER 31, 1999 Future cash inflows from production ... $ 31,650 $ 31,830 $ 23,690 $ 87,170 $ 11,950 $ 24,380 $ 123,500 Future production and development costs (11,350) (6,030) (5,420) (22,800) (7,830) (4,900) (35,530) Future income taxes ................... (7,050) (16,490) (6,200) (29,740) (1,820) (4,980) (36,540) --------------------------------------------------------------------------------------------------------------------------------- Undiscounted future net cash flows .... 13,250 9,310 12,070 34,630 2,300 14,500 51,430 10 percent midyear annual discount for timing of estimated cash flows ....... (5,480) (2,920) (4,590) (12,990) (900) (10,400) (24,290) --------------------------------------------------------------------------------------------------------------------------------- STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS ................. $ 7,770 $ 6,390 $ 7,480 $ 21,640 $ 1,400 $ 4,100 $ 27,140 ================================================================================================================================= AT DECEMBER 31, 1998 Future cash inflows from production ... $ 19,810 $ 12,560 $ 13,010 $ 45,380 $ 6,020 $ 8,360 $ 59,760 Future production and development costs (12,940) (6,980) (4,930) (24,850) (4,470) (5,860) (35,180) Future income taxes ................... (1,970) (2,110) (2,850) (6,930) (660) (200) (7,790) --------------------------------------------------------------------------------------------------------------------------------- Undiscounted future net cash flows .... 4,900 3,470 5,230 13,600 890 2,300 16,790 10 percent midyear annual discount for timing of estimated cash flows ....... (1,880) (1,070) (2,190) (5,140) (390) (1,990) (7,520) --------------------------------------------------------------------------------------------------------------------------------- Standardized Measure of Discounted Future Net Cash Flows ................ $ 3,020 $ 2,400 $ 3,040 $ 8,460 $ 500 $ 310 $ 9,270 ================================================================================================================================= AT DECEMBER 31, 1997 Future cash inflows from production ... $ 28,270 $ 16,560 $ 16,860 $ 61,690 $ 9,240 $ 10,890 $ 81,820 Future production and development costs (14,030) (4,810) (5,090) (23,930) (6,340) (6,550) (36,820) Future income taxes ................... (4,710) (6,630) (4,330) (15,670) (1,390) (600) (17,660) --------------------------------------------------------------------------------------------------------------------------------- Undiscounted future net cash flows .... 9,530 5,120 7,440 22,090 1,510 3,740 27,340 10 percent midyear annual discount for timing of estimated cash flows ....... (3,910) (1,780) (3,290) (8,980) (650) (2,710) (12,340) --------------------------------------------------------------------------------------------------------------------------------- Standardized Measure of Discounted Future Net Cash Flows ................ $ 5,620 $ 3,340 $ 4,150 $ 13,110 $ 860 $ 1,030 $ 15,000 ================================================================================================================================= </TABLE> <TABLE> <CAPTION> TABLE VI - CHANGES IN THE STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS FROM PROVED RESERVES Consolidated Companies Affiliated Companies Worldwide ------------------------------ -------------------------- -------------------------- Millions of dollars 1999 1998 1997 1999 1998 1997 1999 1998 1997 ------------------------------------------------------------------------------------------------------------------------ <S> <C> <C> <C> <C> <C> <C> <C> <C> <C> PRESENT VALUE AT JANUARY 1 $ 8,460 $13,110 $22,270 $ 810 $1,890 $2,850 $ 9,270 $15,000 $25,120 ------------------------------------------------------------------------------------------------------------------------ Sales and transfers of oil and gas produced, net of production costs (5,385) (3,294) (5,493) (679) (429) (684) (6,064) (3,723) (6,177) Development costs incurred 1,425 1,652 1,908 330 276 311 1,755 1,928 2,219 Purchases of reserves 2,811 208 173 - - - 2,811 208 173 Sales of reserves (344) (347) (238) - - (140) (344) (347) (378) Extensions, discoveries and improved recovery, less related costs 2,886 813 2,161 385 49 104 3,271 862 2,265 Revisions of previous quantity estimates (503) 262 535 84 280 980 (419) 542 1,515 Net changes in prices, development and production costs 25,457 (11,321) (20,440) 6,938 (2,159) (3,521) 32,395 (13,480) (23,961) Accretion of discount 1,165 2,096 3,673 135 289 516 1,300 2,385 4,189 Net change in income tax (14,332) 5,281 8,561 (2,503) 614 1,474 (16,835) 5,895 10,035 ------------------------------------------------------------------------------------------------------------------------ Net change for the year 13,180 (4,650) (9,160) 4,690 (1,080) (960) 17,870 (5,730) (10,120) ------------------------------------------------------------------------------------------------------------------------ PRESENT VALUE AT DECEMBER 31 $21,640 $ 8,460 $13,110 $5,500 $ 810 $1,890 $27,140 $ 9,270 $15,000 ======================================================================================================================== </TABLE> The changes in present values between years, which can be significant, reflect changes in estimated proved reserve quantities and prices and assumptions used in forecasting production volumes and costs. Changes in the timing of production are included with "Revisions of previous quantity estimates." 25

<TABLE> <CAPTION> QUARTERLY RESULTS AND STOCK MARKET DATA --------------------------------------- Unaudited 1999 1998 -------------------------------------- --------------------------------------- Millions of dollars, except per-share amounts 4TH Q 3RD Q 2ND Q 1ST Q 4TH Q 3RD Q 2ND Q 1ST Q -------------------------------------------------------------------------------------------------------------------------------- <S> <C> <C> <C> <C> <C> <C> <C> <C> REVENUES Sales and other operating revenues (1) ...... $10,611 $ 9,965 $ 8,473 $ 6,399 $ 7,164 $ 7,561 $ 7,754 $ 7,464 Income (loss) from equity affiliates ........ 122 127 133 144 (66) 13 155 126 Other income ................................ 246 85 135 146 184 104 60 38 ------------------------------------------------------------------------------------------------------------------------------- TOTAL REVENUES .............................. 10,979 10,177 8,741 6,689 7,282 7,678 7,969 7,628 ------------------------------------------------------------------------------------------------------------------------------- COSTS AND OTHER DEDUCTIONS Purchased crude oil and products, operating and other expenses .............. 7,307 7,006 6,275 4,426 5,978 5,100 5,314 5,195 Depreciation, depletion and amortization .... 900 767 633 566 646 563 557 554 Taxes other than on income(1) ............... 1,184 1,181 1,143 1,078 1,115 1,145 1,140 1,011 Interest and debt expense ................... 138 116 113 105 109 103 99 94 ------------------------------------------------------------------------------------------------------------------------------- TOTAL COSTS AND OTHER DEDUCTIONS ............ 9,529 9,070 8,164 6,175 7,848 6,911 7,110 6,854 ------------------------------------------------------------------------------------------------------------------------------- INCOME BEFORE INCOME TAX .................... 1,450 1,107 577 514 (566) 767 859 774 INCOME TAX (CREDIT) EXPENSE ................. 641 525 227 185 (360) 306 282 267 ------------------------------------------------------------------------------------------------------------------------------- NET INCOME (LOSS) (2) ....................... $ 809 $ 582 $ 350 $ 329 $ (206) $ 461 $ 577 $ 507 =============================================================================================================================== NET INCOME (LOSS) PER SHARE - BASIC ......... $ 1.24 $ 0.88 $ 0.54 $ 0.50 $ (0.31) $ 0.70 $ 0.88 $ 0.78 - DILUTED ....... $ 1.23 $ 0.88 $ 0.53 $ 0.50 $ (0.31) $ 0.70 $ 0.88 $ 0.77 DIVIDENDS PAID PER SHARE .................... $ 0.65 $ 0.61 $ 0.61 $ 0.61 $ 0.61 $ 0.61 $ 0.61 $ 0.61 COMMON STOCK PRICE RANGE - HIGH ............. $96 15/16 $100 13/16 $104 15/16 $90 5/16 $89 7/16 $89 $86 13/16 $90 3/16 - LOW .............. $83 3/8 $85 9/16 $86 3/8 $73 1/8 $78 3/8 $73 $ 77 3/8 $67 3/4 =============================================================================================================================== <FN> (1) Includes consumer excise taxes: $ 989 $ 1,023 $ 986 $ 912 $ 943 $ 973 $ 988 $ 852 (2) Special (charges) credits included in Net Income (Loss): $ (10) $ (120) $ (134) $ 48 $ (709) $ 75 $ (43) $ 71 The company's common stock is listed on the New York Stock Exchange (trading symbol: CHV), as well as on the Chicago, Pacific, London and Swiss stock exchanges. It also is traded on the Boston, Cincinnati, Detroit and Philadelphia stock exchanges. As of February 23, 2000, stockholders of record numbered approximately 116,062. There are no restrictions on the company's ability to pay dividends. Chevron has made dividend payments to stockholders for 88 consecutive years. </FN> </TABLE> 26