Edgar Filing: EXXON MOBIL CORP

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SCHEDULE 14A INFORMATION

Proxy Statement Pursuant to Section 14(a) of
the Securities Exchange Act of 1934 (Amendment No. )

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EXXON MOBIL CORPORATION
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NOTICE OF 2005 ANNUAL MEETING AND PROXY STATEMENT
				April 13, 2005

Dear Shareholder:

We invite you to attend the annual meeting of shareholders on Wednesday, May 25, 2005, at the Morton H. Meyerson Symphony Center, 2301 Flora Street, Dallas, Texas. The meeting will begin promptly at 9:00 a.m., Central Time. At the meeting, you will hear a report on our business and vote on the following items:

•: Election of directors
•: Ratification of independent auditors
•: 8 shareholder proposals
•: Other matters if properly raised

Only shareholders of record on April 6, 2005, or their proxy holders may vote at the meeting. Attendance at the meeting is limited to shareholders or their proxy holders and ExxonMobil guests. Only shareholders or their valid proxy holders may address the meeting.

This booklet includes the formal notice of the meeting, the proxy statement, and financial statements. The proxy statement tells you about the agenda, procedures, and rules of conduct for the meeting. It also describes how the Board operates, gives personal information about our director candidates, and provides information about the other items of business to be conducted at the meeting.

Even if you own only a few shares, we want your shares to be represented at the meeting. You can vote your shares by internet, toll-free telephone call, or proxy card.

To attend the meeting in person, please follow the instructions on page 2. A live audiocast of the meeting and a report on the meeting will be available on our website, www.exxonmobil.com.

Sincerely,


Henry H. Hubble Secretary		Lee R. Raymond Chairman of the Board

Table of Contents

		Page
General Information		1
Board of Directors		3
	Corporate Governance Guidelines	3
	Item 1 - Election of Directors	6
	Director Compensation	10
	Board Committees	10
	Director and Executive Officer Stock Ownership	12
	Compensation Committee Report	13
	Executive Compensation Tables	18
	Stock Performance Graphs	24
	Audit Committee Report	25
	Audit Committee Pre-Approval Policy and Procedure Memorandum	26
	Item 2 - Ratification of Independent Auditors	28
Shareholder Proposals		30
	Item 3 - Political Contributions	30
	Item 4 - Board Compensation	31
	Item 5 - Industry Experience	32
	Item 6 - Aceh Security Report	33
	Item 7 - Amendment of EEO Policy	34
	Item 8 - Biodiversity Impact Report	36
	Item 9 - Climate Science Report	37
	Item 10 - Kyoto Compliance Report	40
Additional Information		42
Appendix A - Financial Section		A1
Appendix B - Audit Committee Charter		B1
Directions to 2005 Annual Meeting

GENERAL INFORMATION

Who May Vote

Shareholders of ExxonMobil, as recorded in our stock register on April 6, 2005, may vote at the meeting.

How to Vote

You may vote in person at the meeting or by proxy. We recommend you vote by proxy even if you plan to attend the meeting. You can always change your vote at the meeting.

How Proxies Work

ExxonMobil's Board of Directors is asking for your proxy. Giving us your proxy means you authorize us to vote your shares at the meeting in the manner you direct. You may vote for all, some, or none of our director candidates. You may also vote for or against the other proposals, or abstain from voting.

If your shares are held in your name, you can vote by proxy in one of three convenient ways:

•: Via internet: Go to www.eproxyvote.com/xom and follow the instructions. You will need to have your proxy card in hand. At this website, you can elect to access future proxy statements and annual reports via the internet.
•: By telephone: Call toll-free 1-877-779-8683 (within the continental U.S. and Canada) or 1-201-536-8073 (outside the continental U.S. and Canada), and follow the instructions. You will need to have your proxy card in hand.
•: In writing: Complete, sign, date, and return your proxy card in the enclosed envelope.

Your proxy card covers all shares registered in your name and shares held in your EquiServe Investment Plan account. If you own shares in the ExxonMobil Savings Plan for employees and retirees, your proxy card also covers those shares.

If you give us your signed proxy but do not specify how to vote, we will vote your shares in favor of our director candidates; in favor of the ratification of the appointment of independent auditors; and against the shareholder proposals.

If you hold shares through someone else, such as a stockbroker, you will receive material from that firm asking how you want to vote. Check the voting form used by that firm to see if it offers internet or telephone voting.

Voting Shares in the ExxonMobil Savings Plan

The trustee of the ExxonMobil Savings Plan will vote Plan shares as participants direct. To the extent participants do not give instructions, the trustee will vote shares as it thinks best. The proxy card also serves to give voting instructions to the trustee.

Revoking a Proxy

You may revoke your proxy before it is voted by:

•: Submitting a new proxy with a later date, including a proxy given via the internet or by telephone;
•: Notifying ExxonMobil's Secretary in writing before the meeting; or
•: Voting in person at the meeting.

Confidential Voting

Independent inspectors count the votes. Your individual vote is kept confidential from us unless special circumstances exist. For example, a copy of your proxy card will be sent to us if you write comments on the card.

Quorum

In order to carry on the business of the meeting, we must have a quorum. This means at least a majority of the outstanding shares eligible to vote must be represented at the meeting, either by proxy or in person. Treasury shares, which are shares owned by ExxonMobil itself, are not voted and do not count for this purpose.

Votes Needed

The director candidates who receive the most votes will be elected to fill the available seats on the Board. Approval of the other proposals requires the favorable vote of a majority of the votes cast. Only votes FOR or AGAINST a proposal count. Abstentions and broker non-votes count for quorum purposes but not for voting purposes. Broker non-votes occur when a broker returns a proxy but does not have authority to vote on a particular proposal.

Annual Meeting Admission

Only shareholders or their proxy holders and ExxonMobil's guests may attend the meeting. For safety and security reasons, no cameras, recording equipment, electronic devices, large bags, briefcases or packages will be permitted in the meeting. In addition, each shareholder and guest will be asked to present a valid government-issued picture identification, such as a driver's license, before being admitted to the meeting.

For registered shareholders, an admission ticket is attached to your proxy card. Please detach and bring the admission ticket with you to the meeting.

If your shares are held in the name of your broker, bank, or other nominee, you must bring to the meeting an account statement or letter from the nominee indicating that you beneficially owned the shares on April 6, 2005, the record date for voting. You may receive an admission ticket in advance by sending a written request with proof of ownership to the address listed under "Contact Information" on page 3.

Shareholders who do not present admission tickets at the meeting will be admitted only upon verification of ownership at the admission counter.

Audiocast of the Annual Meeting

You are invited to visit our website at www.exxonmobil.com to hear the live audiocast of the meeting at 9:00 a.m., Central Time, on Wednesday, May 25, 2005. An archived copy of this audiocast will be available on our website for one year.

Conduct of the Meeting

The Chairman has broad responsibility and legal authority to conduct the annual meeting in an orderly and timely manner. This authority includes establishing rules for shareholders who wish to address the meeting. Only shareholders or their valid proxy holders may address the meeting. Copies of these rules will be available at the meeting. The Chairman may also exercise broad discretion in recognizing shareholders who wish to speak and in determining the extent of discussion on each item of business. In light of the number of business items on this year's agenda and the need to conclude the meeting

within a reasonable period of time, we cannot assure that every shareholder who wishes to speak on an item of business will be able to do so. Dialogue can better be accomplished with interested parties outside the meeting and, for this purpose, we have provided a method for raising issues and contacting the non-employee directors either in writing or electronically. The Chairman may also rely on applicable law regarding disruptions or disorderly conduct to ensure that the meeting is conducted in a manner that is fair to all shareholders. Shareholders making comments during the meeting must do so in English so that the majority of shareholders present can understand what is being said.

Contact Information

If you have questions or need more information about the annual meeting, write to:

Mr. Henry H. Hubble
Secretary
Exxon Mobil Corporation
5959 Las Colinas Boulevard
Irving, TX 75039-2298

or call us at 972-444-1157.

For information about shares registered in your name or your EquiServe Investment Plan account, call ExxonMobil Shareholder Services at 1-800-252-1800 or access your account via the website at www.exxonmobil.equiserve.com. We also invite you to visit ExxonMobil's website at www.exxonmobil.com. Website materials are not part of this proxy solicitation.

BOARD OF DIRECTORS

The Board of Directors and its committees perform a number of functions for ExxonMobil and its shareholders, including:

•: Overseeing the management of the Company on your behalf;
•: Reviewing ExxonMobil's long-term strategic plans;
•: Exercising direct decision-making authority in key areas, such as declaring dividends;
•: Selecting the CEO and evaluating the CEO's performance; and
•: Reviewing development and succession plans for ExxonMobil's top executives.

CORPORATE GOVERNANCE GUIDELINES

The Board has adopted Corporate Governance Guidelines that govern the structure and functioning of the Board and set out the Board's position on a number of governance issues. A current copy of our Corporate Governance Guidelines is posted on the Corporate Governance section, listed under Investor Information, of our website. They are also available to any shareholder on request to the Secretary at the address given under "Contact Information" above.

Director Independence

Our Corporate Governance Guidelines require that a substantial majority of the Board consist of independent directors. In general, the Guidelines require that an independent director must have no material relationship with ExxonMobil, directly or indirectly, except as a director. The Board determines

independence on the basis of the standards specified by the New York Stock Exchange (NYSE) and other facts and circumstances the Board considers relevant.

Subject to some exceptions and transition provisions, the NYSE standards generally provide that a director will not be independent if: (1) the director is, or in the past three years has been, an employee of ExxonMobil or a member of the director's immediate family is, or in the past three years has been, an executive officer of ExxonMobil; (2) the director or a member of the director's immediate family has received more than $100,000 per year in direct compensation from ExxonMobil other than for service as a director; (3) the director or a member of the director's immediate family currently is a partner of PricewaterhouseCoopers LLP (PwC), our independent auditors, or an employee in PwC's audit, assurance, or tax compliance practices, or within the past three years has been a PwC partner or employee who worked on ExxonMobil's audit; (4) the director or a member of the director's immediate family is, or in the past three years has been, employed as an executive officer of a company where an ExxonMobil executive officer serves on the compensation committee; or (5) the director or a member of the director's immediate family is an executive officer of a company that makes payments to, or receives payments from, ExxonMobil in an amount which, in any 12-month period during the past three years, exceeds the greater of $1 million or 2 percent of that other company's consolidated gross revenues.

The Board has reviewed business and charitable relationships between ExxonMobil and each non-employee director and nominee to determine compliance with the NYSE standards described above and to evaluate whether there are any other facts or circumstances that might impair a director's or nominee's independence. Based on that review, our Board has determined that all non-employee directors and nominees are independent.

Term of Office; Mandatory Retirement

All ExxonMobil directors stand for election at the annual meeting. Non-employee directors cannot stand for election after they have reached age 72.

Board Meetings and Attendance

The Board met nine times in 2004. ExxonMobil's directors, on average, attended approximately 96 percent of Board and committee meetings during 2004.

Executive Sessions

ExxonMobil's non-employee directors held five executive sessions in 2004. Normally, the Chair of the Board Affairs Committee and the Chair of the Compensation Committee preside at executive sessions on a rotational basis, but the non-employee directors may, in light of the subject matter under discussion, select another presiding director for a particular session.

Annual Meeting Attendance

As specified in our Corporate Governance Guidelines, it is ExxonMobil's policy that directors should make every effort to attend the annual meeting of shareholders. All directors attended last year's meeting.

Code of Ethics and Business Conduct

The Board maintains policies and procedures (which we refer to in this proxy statement as our Code) that represent both the code of ethics for the principal executive officer, principal financial officer, and principal accounting officer under SEC rules, and the code of business conduct and ethics for directors,

officers, and employees under NYSE listing standards. The Code applies to all directors, officers, and employees.

The Code is posted on our website and is available free of charge on request to the Secretary at the address given under "Contact Information" on page 3. The Code is also incorporated as an exhibit to our Annual Report on Form 10-K. Any amendment of the Code will be promptly posted on our website.

The Board Affairs Committee will review any issues under the Code involving an executive officer or director and will report its findings to the Board. The Board does not envision that any waivers of the Code will be granted, but should a waiver occur for an executive officer or director, it will also be promptly disclosed on our website.

Director Selection

The Board Affairs Committee has adopted Guidelines for the Selection of Non-Employee Directors that describe the qualifications the Committee looks for in director candidates. The Guidelines are posted on our website and are available free of charge on request to the Secretary at the address given under "Contact Information" on page 3.

In general, the Guidelines provide that candidates for non-employee director of ExxonMobil should be individuals who have achieved prominence in their fields, with experience and demonstrated expertise in managing large, relatively complex organizations and/or, in a professional or scientific capacity, who are accustomed to dealing with complex situations preferably with worldwide scope.

A substantial majority of the Board must meet the independence standards described in the Corporation's Corporate Governance Guidelines, and all candidates must be free from any relationship with management or the Corporation which would interfere with the exercise of independent judgment. Candidates should be committed to representing the interests of all shareholders and not any particular constituency.

The Board believes a director should be able to serve for at least several years. Candidates should bring integrity, insight, energy, and analytical skills to Board deliberations, and must have a commitment to devote the necessary time and attention to oversee the affairs of a corporation as large and complex as ExxonMobil. ExxonMobil recognizes the strength and effectiveness of the Board reflect the balance, experience, and diversity of the individual directors; their commitment; and importantly, the ability of directors to work effectively as a group in carrying out their responsibilities. ExxonMobil seeks candidates with diverse backgrounds who possess knowledge and skills in areas of importance to the Corporation. The Board must include members with particular experience required for service on key Board committees, as described in the committee charters.

The Committee identifies director candidates primarily through recommendations made by the non-employee directors. These recommendations are developed based on the directors' own knowledge and experience in a variety of fields, and research conducted by ExxonMobil staff at the Committee's direction. The Committee also considers recommendations made by the employee directors, shareholders, and others, including search firms. The Committee has the authority to engage consultants to help identify or evaluate potential director nominees but has not done so recently. All recommendations, regardless of the source, are evaluated on the same basis against the criteria contained in the Guidelines.

Shareholders may send recommendations for director candidates to the Secretary at the address given under "Contact Information" on page 3. A submission recommending a candidate should include:

•: Sufficient biographical information to allow the Committee to evaluate the candidate in light of the Guidelines;
•: Information concerning any relationships between the candidate and the shareholder recommending the candidate; and
•: Material indicating the willingness of the candidate to serve if nominated and elected.

Communications with Directors

The Board Affairs Committee has approved and implemented procedures for shareholders and other interested persons to send communications to individual directors or the non-employee directors as a group.

•: Written communications: Written correspondence should be addressed to the director or directors in care of the Secretary at the address given under "Contact Information" on page 3. All correspondence will either be forwarded to the intended recipient and to the Chair of the Board Affairs Committee, as appropriate, or held for review at the next regular Board meeting. A log of all correspondence addressed to the directors will also be kept for periodic review by the Board Affairs Committee and any other interested director.
•: Electronic communications: You may also send email to individual non-employee directors or the non-employee directors as a group by using the form provided for that purpose on our website. These communications are sent directly to the specified director's electronic mailbox. Email can be viewed by staff of the Office of the Secretary but can only be deleted by the director to whom it is addressed. More information about our procedures for handling communications to non-employee directors is posted on our website.

Additional Information

The Corporate Governance section of our website contains additional information, including our Certificate of Incorporation and By-Laws; written charters for each Board committee; and Board policy statements.

ITEM 1 – ELECTION OF DIRECTORS

The Board of Directors has nominated the director candidates named on the following pages. Personal information on each of our nominees is also provided. All of our nominees currently serve as ExxonMobil directors except for Mr. William W. George, who has been nominated by the Board for first election as a director at the annual meeting. The recommendation of Mr. George as a candidate was developed by the incumbent non-employee directors on the Board Affairs Committee. Mr. Harry J. Longwell elected to retire effective December 31, 2004, and is not standing for election.

If a director nominee becomes unavailable before the election, your proxy authorizes the people named as proxies to vote for a replacement nominee if the Board names one.

The Board recommends you vote FOR each of the following candidates:


Michael J. Boskin Age 59 Director since 1996	Principal Occupation: T. M. Friedman Professor of Economics and Senior Fellow, Hoover Institution, Stanford University Recent Business Experience: Dr. Boskin is also a Research Associate, National Bureau of Economic Research and serves on the Commerce Department's Advisory Committee on the National Income and Product Accounts. He is Chief Executive Officer and President of Boskin & Co., an economic consulting company. Public Company Directorships: Oracle Corporation; Shinsei Bank; Vodaphone Group

William W. George Age 62	Principal Occupation: Professor of Management Practice, Harvard Business School Recent Business Experience: Mr. George was elected Chairman of Medtronic in 1996, retired in 2002; Chief Executive Officer in 1991; and President and Chief Operating Officer in 1989. He is also currently Chairman of The Global Center for Leadership and Business Ethics. Public Company Directorships: Goldman Sachs, Novartis AG

James R. Houghton Age 69 Director since 1994	Principal Occupation: Chairman of the Board and Chief Executive Officer, Corning Incorporated Recent Business Experience: Mr. Houghton resumed his role as Chairman and Chief Executive Officer of Corning Incorporated in 2002, and relinquished the role of CEO in April 2005. He served as non-executive Chairman in 2001-2002 and Chairman Emeritus from 1996-2001. Elected Chairman and Chief Executive Officer of Corning Incorporated in 1983, retired in 1996. Public Company Directorships: Corning Incorporated; Metlife

William R. Howell Age 69 Director since 1982	Principal Occupation: Chairman Emeritus, J.C. Penney Company Recent Business Experience: Mr. Howell was elected Chairman and Chief Executive Officer of J.C. Penney Company in 1983, retired in 1997. Public Company Directorships: American Electric Power; Halliburton; Pfizer; The Williams Companies; Deutsche Bank Trust Corporation and Deutsche Bank Trust Company Americas, non-public wholly owned subsidiaries of Deutsche Bank AG


Reatha Clark King Age 67 Director since 1997	Principal Occupation: Former Chairman, Board of Trustees, General Mills Foundation Recent Business Experience: Elected Chairman, Board of Trustees, General Mills Foundation in 2002, retired in 2003; President and Executive Director, General Mills Foundation, and Vice President, General Mills, Inc. from 1988-2002. Prior to joining the General Mills Foundation, Dr. King held a variety of positions in chemical research, education, and academic administration. Public Company Directorships: Wells Fargo & Company; Department 56; Minnesota Mutual Companies, where she will not stand for election to the board in 2005

Philip E. Lippincott Age 69 Director since 1986	Principal Occupation: Retired Chairman of the Board and Chief Executive Officer, Scott Paper Company; Retired Chairman of the Board, Campbell Soup Company Recent Business Experience: Mr. Lippincott was elected Chairman of Campbell Soup Company in 1999, retired in 2001. Elected Chairman and Chief Executive Officer of Scott Paper Company in 1983, retired in 1994; elected Chief Executive Officer in 1982; and Director in 1978. Public Company Directorships: Campbell Soup Company; Penn Mutual Life Insurance Company

Henry A. McKinnell, Jr. Age 62 Director since 2002	Principal Occupation: Chairman of the Board and Chief Executive Officer, Pfizer Recent Business Experience: Elected Chairman and Chief Executive Officer of Pfizer in 2001; President and Chief Operating Officer in 1999; and Executive Vice President in 1992. Dr. McKinnell also served as President of Pfizer Pharmaceuticals Group from 1997-2001. Public Company Directorships: Pfizer; Moody's Corporation; John Wiley & Sons, where he will not stand for election to the board in 2005

Marilyn Carlson Nelson Age 65 Director since 1991	Principal Occupation: Chairman of the Board and Chief Executive Officer, Carlson Companies Recent Business Experience: Mrs. Nelson has held a number of management positions at Carlson Companies including Director, Senior Vice President, and Vice Chair. Public Company Directorships: Carlson Companies


Lee R. Raymond Age 66 Director since 1984	Principal Occupation: Chairman of the Board and Chief Executive Officer, Exxon Mobil Corporation Recent Business Experience: Elected Chairman and Chief Executive Officer of Exxon Corporation in 1993; President in 1987; and Senior Vice President and Director in 1984. Prior to this, Mr. Raymond held a variety of management positions in domestic and foreign operations since joining the Exxon organization in 1963. Public Company Directorships: J.P. Morgan Chase & Co.

Walter V. Shipley Age 69 Director since 1998	Principal Occupation: Retired Chairman of the Board, The Chase Manhattan Corporation and The Chase Manhattan Bank Recent Business Experience: Mr. Shipley was elected Chairman and Chief Executive Officer of Chase Manhattan upon its merger with Chemical Bank in 1996, retired in 1999. Elected Chairman and Chief Executive Officer of Chemical Bank in 1983; President and Director in 1982; and Senior Executive Vice President in 1979. Public Company Directorships: Verizon Communications; Wyeth

Rex W. Tillerson Age 52 Director since 2004	Principal Occupation: President, Exxon Mobil Corporation Recent Business Experience: Elected President and Director of ExxonMobil in 2004; Senior Vice President in 2001. Mr. Tillerson has held a variety of management positions in domestic and foreign operations since joining the Exxon organization in 1975, including President, Exxon Yemen Inc. and Esso Exploration and Production Khorat Inc.; Vice President, Exxon Ventures (CIS) Inc.; President, Exxon Neftegas Limited; and Executive Vice President, ExxonMobil Development Company. Public Company Directorships: None

Director Relationships

ExxonMobil and its affiliates have business relationships in the ordinary course of business with companies for which our non-employee directors serve as executives, but these relationships are not material by any reasonable standard.

DIRECTOR COMPENSATION

The table below shows the total compensation paid in 2004 to each of our current non-employee directors.

Director	Annual Base Fee ($)	Committee Fees ($)	Restricted Stock Awards* ($)	Total ($)
Dr. Boskin	75,000	33,827	167,240	276,067
Mr. Houghton	75,000	48,000	167,240	290,240
Mr. Howell	75,000	48,000	167,240	290,240
Dr. King	75,000	38,000	167,240	280,240
Mr. Lippincott	75,000	26,827	167,240	269,067
Dr. McKinnell	75,000	31,000	167,240	273,240
Mrs. Nelson	75,000	33,827	167,240	276,067
Mr. Shipley	75,000	32,346	167,240	274,586

*: The value shown is the number of restricted shares granted in 2004 (4,000 shares) times the closing price of ExxonMobil stock on the day of grant.

ExxonMobil employees receive no extra pay for serving as directors. Non-employee directors receive compensation consisting of cash and restricted stock. The base fee is $75,000 a year. We also pay members of the Audit and Compensation Committees a fee of $15,000 per year, and an additional fee of $10,000 per year to the Chairs of those Committees. For other Committees, non-employee directors receive $8,000 per year for each Committee on which they serve, and the Chairs receive an additional fee of $7,000 per year. No fees are paid to members of the Executive Committee. Non-employee directors are reimbursed for actual expenses to attend meetings.

Non-employee directors may elect to defer all or part of these fees either into ExxonMobil stock equivalents with dividends or into a deferred account that earns interest at the prime rate. Deferred fees are payable in one to five annual installments after the director leaves the Board.

In addition to the fees described above, we pay a significant portion of director compensation in stock. At present, each incumbent non-employee director receives an annual award of 4,000 shares of restricted stock. In addition, a new non-employee director receives a one-time grant of 8,000 shares of restricted stock upon first being elected to the Board. While on the Board, the non-employee director receives the same cash dividends on restricted shares as a holder of regular common stock, but the director is not allowed to sell the shares. The restricted shares can be forfeited if the director leaves the Board early.

BOARD COMMITTEES

The Board appoints committees to help carry out its duties. In particular, Board committees work on key issues in greater detail than would be possible at full Board meetings. Only non-employee directors may serve on the Audit, Compensation, Board Affairs, Contributions, and Public Issues Committees. Each Committee has a written charter. The charters are posted on our website and are available free of charge on request to the Secretary at the address given under "Contact Information" on page 3.

The table on the following page shows the current membership of each Board committee and the number of meetings each Committee held in 2004.

Director	Audit	Compensation	Board Affairs	Contributions	Finance	Public Issues	Executive(1)
Dr. Boskin			•		•	C
Mr. Houghton	C	•			•		•
Mr. Howell	•	C		•			•
Dr. King	•	•		•
Mr. Lippincott			•	•	•		•
Dr. McKinnell	•		•			•
Mrs. Nelson				C	•	•	•
Mr. Raymond					C		C
Mr. Shipley		•	C			•

2004 Meetings	11	9	7	3	2	3	1

C = Chair
• = Member
(1) Other directors serve as alternate members on a rotational basis.

Audit Committee

The Audit Committee met 11 times during 2004. The Committee oversees accounting and internal control matters. Its responsibilities include appointing the independent auditors to audit ExxonMobil's financial statements. The Committee's report on its activities for the fiscal year 2004 is on pages 25 and 26. The Committee's policy and procedures for pre-approving fees paid to the independent auditors are set forth on pages 26 through 28 and are posted on our website. Fees paid for 2004 and 2003 are provided on pages 28 and 29. The Committee's charter is attached as Appendix B to this proxy statement.

The Board has determined that all members of the Committee are independent within the meaning of both the SEC rules and the NYSE listing standards. The Board has further determined that all members are financially literate within the meaning of the NYSE standards, and Mr. Houghton, Mr. Howell, and Dr. McKinnell are "audit committee financial experts" as defined in the SEC rules.

Compensation Committee

The Compensation Committee met nine times during 2004. The Committee oversees compensation for ExxonMobil's senior executives, including salary, bonus, and incentive awards. The Committee also reviews succession plans for key executive positions. The Committee's report on executive compensation starts on page 13. The Board has determined that all members of the Committee are independent within the meaning of the NYSE listing standards.

Board Affairs Committee

The Board Affairs Committee met seven times during 2004. The Committee recommends director candidates; reviews non-employee director compensation; and reviews other corporate governance practices, including the Corporate Governance Guidelines available on our website. The Board has determined that all members of the Committee are independent within the meaning of the NYSE listing standards.

Advisory Committee on Contributions

The Advisory Committee on Contributions met three times during 2004. The Committee reviews the level of ExxonMobil's support for education and other public service programs, including the

Company's contributions to the ExxonMobil Foundation. The Foundation works to improve the quality of education in America at all levels, with special emphasis on math and science. The Foundation also supports the Company's other cultural and public service giving. The Board has determined that all members of the Committee are independent within the meaning of the NYSE listing standards.

Finance Committee

The Finance Committee met two times during 2004. The Committee reviews ExxonMobil's financial policies and strategies, including our capital structure, and authorizes corporate debt within limits set by the Board.

Public Issues Committee

The Public Issues Committee met three times during 2004. The Committee reviews ExxonMobil's policies and practices on relevant public issues, including their effects on safety, health, and the environment. The Committee hears reports from operating units on safety and environmental activities. The Committee also visits operating sites to observe and comment on current operating practices. The Board has determined that all members of the Committee are independent within the meaning of the NYSE listing standards.

Executive Committee

The Executive Committee met one time during 2004. The Committee has broad power to act on behalf of the Board. In practice, the Committee meets only when it is impractical to call a meeting of the full Board.

DIRECTOR AND EXECUTIVE OFFICER STOCK OWNERSHIP

These tables show the number of ExxonMobil common stock shares each executive named in the Summary Compensation Table on page 18 and each non-employee director and nominee owned on February 28, 2005. In these tables, ownership means the right to direct the voting or the sale of shares, even if those rights are shared with someone else. None of these individuals owns more than 0.12 percent of the outstanding shares.

Named Executive Officer	Shares Owned		Shares Covered by Exercisable Options*
Lee R. Raymond	3,100,466	(1)	4,604,248
Harry J. Longwell	1,016,764	(2)	2,752,375
Rex W. Tillerson	427,951	(3)	513,982
Edward G. Galante	424,413	(4)	530,996
Stuart R. McGill	526,297	(5)	877,734
J. Stephen Simon	415,859	(6)	820,000

(1): Includes 319 shares owned by spouse.
(2): Includes 110 shares owned by spouse and 82,250 shares jointly owned with spouse.
(3): Includes 1,400 shares owned by dependent child.
(4): Includes 2,250 shares owned by dependent child.
(5): Includes 3,200 shares owned by spouse.
(6): Includes 13,078 shares jointly owned with spouse.
*: Includes options that will become exercisable within 60 days.

Non-Employee Director/Nominee	Shares Owned*
Michael J. Boskin	36,300
William W. George	40,000	(1)
James R. Houghton	44,900	(2)
William R. Howell	42,700	(3)
Reatha Clark King	37,904	(4)
Philip E. Lippincott	45,900
Henry A. McKinnell, Jr.	28,400
Marilyn Carlson Nelson	58,828	(5)
Walter V. Shipley	36,540

(1): Includes 10,000 shares held as co-trustee of family foundation.
(2): Includes 5,000 shares owned by spouse.
(3): Includes 5,400 restricted shares held as constructive trustee for former spouse.
(4): Includes 1,000 shares owned by spouse.
(5): Includes 18,528 shares held as co-trustee of family trusts.
*: The non-employee directors are not granted ExxonMobil stock options.

On February 28, 2005, ExxonMobil's directors, nominees, and executive officers (28 people) together owned 8,983,848 shares of ExxonMobil stock and 14,955,311 shares covered by exercisable options, representing about 0.37 percent of the outstanding shares.

COMPENSATION COMMITTEE REPORT

Overview

The system of developing and compensating executives is critical to the achievement of business objectives at ExxonMobil. This system has been in place for several decades with ongoing refinements and constancy of purpose regarding the core principles of the system. This system is based on three key factors:

1): The competitive advantage derived from selecting, developing, and retaining the best talent in the industry;
2): The requirement for ongoing improvement in the performance of every executive to drive world-class business performance; and
3): Long lead times for capital investment in our industry, which can exceed 10 years depending on the nature of the project.

To address these factors, the Committee focuses on the process and implementation of executive performance assessments, the total remuneration program, and executive development. The integration of all three components form a system that is fundamental and has been successful in supporting long-term business and shareholder objectives. A brief overview of this integrated system follows:

•: Each executive is assessed annually through a well-defined process in which all executives worldwide are ranked based on comparative individual performance. The assessment of individual performance takes into account results and the means through which those results are achieved. A consistently applied distribution of performance assessments across the executive population worldwide is required to ensure integrity of the process and to achieve wide differentiation in

salary treatment and other forms of pay based on individual performance. This same performance assessment process applies consistently to over 44,000 managers and professionals worldwide. The process takes about three months to complete in over 80 countries and across several business and staff functions. Assessments of executive potential are conducted concurrently and implemented through a consistently applied, single process.

•: The results from this executive performance and potential assessment process provide a key input to the total remuneration program. The total remuneration program includes: salary; the incentive program; savings programs; retirement programs; and other employee benefits. Most of these forms of pay are tied directly, or affected indirectly, by the performance assessment assigned to each executive. To begin with, annual performance assessments translate into significant differentiation in salary. Salaries vary between the highest and lowest-rated performers by a wide margin. Performance-based salaries also affect the level of retirement benefits, since performance assessments determine compensation levels that are typically included in retirement benefit calculations. Finally, a key principle at work throughout this system is commonality of program application; in most countries, senior executives and lower-level executives participate in the same retirement and benefit programs. In the United States, all professionals and managers are included in the same retirement and benefit programs as senior executives.
•: The incentive program is also heavily performance-based. It is a key part of an executive's total remuneration and is comprised of three components: short-term, annual cash bonuses; mid-term awards in the form of earnings bonus units; and long-term, stock-based compensation. Eligibility to participate in all three components of the incentive program is limited to about the top 60 percent of performers in the executive population based on the performance assessment process described. The size of the annual bonus and earnings bonus units pool is determined by the annual performance of the Company, and it can vary widely year-to-year. The size of individual awards under all components of the incentive program is differentiated significantly among these participants based on individual performance and level of responsibility. Also, an executive's incentive awards may be forfeited if the executive leaves before the standard retirement age or engages in activity that is detrimental to the Company. Detrimental activity could include a violation of the Company's code of ethics.
•: Results of annual performance and potential assessment are also primary inputs to the executive development process. The executive development process ensures continuity of leadership over the long term and it forms the basis on which the company makes ongoing executive assignments. Through this process, position assignments are based on the most qualified and ready executives. The future leaders of the Company are developed at the same time through these carefully selected assignments. In addition, the organization benefits from the distribution throughout the Company of executives who understand our strong culture and underlying core values. The performance assessment of all managers in the Company is determined, in part, on how well they implement the executive development process. A career orientation and culture of promotion-from-within are key fundamentals that underpin and help sustain the process. Consistent and ongoing application of this process meets the requirements of the business and achieves competitive advantage within our industry.

Consistent with the integrated system and philosophy as described, the Committee believes that all executives should be "at will" employees of the Company. This means that our most senior executives do not have employment contracts and the Company does not maintain a senior executive severance program.

To ensure full in-depth understanding by our shareholders, the following areas of total remuneration warrant further explanation: base salaries and incentive awards which include short term and long term awards.

Base Salaries

The competition for executives of our caliber extends beyond the oil industry. Therefore, we compare our salary structure with the largest multinational companies and integrated oil companies. Because ExxonMobil is significantly larger and more diverse than most of the other comparison companies, we do not target an exact percentile at which to align salaries. We focus on a broader and more flexible target, generally a wide range around the 50th percentile. This allows us to respond better to changing business conditions, manage salaries more evenly over a career, and minimize the potential for automatic ratcheting-up of salaries due to an inflexible and narrow competitive target. This orientation also provides more flexibility to differentiate salaries to reflect a range of experience and performance levels among executives. In effect, this philosophy of competitive orientation helps us leverage more effectively the results of the performance assessment process outlined above.

Short Term Awards

As described, the size of individual awards under this program is highly dependent on the financial performance and operating results of the Company each year. It is expected that short term awards may vary significantly year-over-year, versus other forms of compensation. Short term awards help stress that results and contributions in any year affect future years.

Short term incentive awards consist of cash bonuses and earnings bonus units. (See page 20 for a description of the terms of earnings bonus units.) We grant cash bonuses to executives to reward their contributions to the business during the past year. We grant earnings bonus units as incentives for strong, mid-term corporate performance. In 2004, approximately one-half of executive short term awards were in the form of earnings bonus units. Cumulative earnings of $3.25 per share are required for each earnings bonus unit granted in 2004 to pay out, which is an increase from $3.00 in 2003.

Each year, the Committee establishes a ceiling for cash bonuses and earnings bonus units. The combined ceiling for 2004 was $184 million. This ceiling was increased from the 2003 level by about 10 percent. In reaching this decision, the Committee considered several factors. These included the record-setting financial performance of the Company in 2004, demonstrated by an 18-percent increase in net income over 2003; the record levels of operating performance in all segments of our business; strengthening of our worldwide competitive position; and progress toward long-range strategic goals, which include objectives in the areas of safety, health, and environment. The Committee does not give specific weights to these measures, nor is a particular formula applied. The entire amount was granted in awards to approximately 1,300 employees.

Long Term Awards

The petroleum business requires long-term, capital-intensive investments. These investments often take many years to generate returns to shareholders. The long term incentive program is intended to emphasize the need for executives to maintain a focus on the strategic goals of the business. It balances the emphasis on long versus short-term business objectives and reinforces that one should not be achieved at the expense of the other. Long term incentive awards are also intended to develop and retain strong management through share ownership and recognition of future performance. Long term incentives have less year-to-year variability due to these design considerations and the nature of the business as described.

Currently, restricted stock forms the basis of awards under this program. The total number of shares granted under this approach is substantially fewer than the number that would be required under an option program designed to deliver equivalent levels of compensation. However, the alternative of using options is retained under the 2003 Incentive Program approved by shareholders.

In administering the long term program, we are sensitive to the potential for dilution of future earnings per share. For this reason and other compensation design considerations, we do not administer a broad-based stock program. Instead, we focus the program on employees who will have the greatest impact on the strategic direction and long-term results of the Company by virtue of their senior roles and responsibilities. Restricted stock awards were granted to executive officers and just over 5,000 other select employees in 2004, or about 5 percent of total employees. The resulting level of share utilization in the incentive program is substantially less than share usage of other large, multinational companies of similar scope and size.

Under our current Incentive Program, the minimum restricted period for restricted stock is three years. For most recipients, 50 percent of each grant is subject to a three-year restricted period and the balance of the grant is subject to a seven-year restricted period. However, for our most senior executives, significantly longer restricted periods apply. Specifically, 50 percent of each grant to the most senior executives is subject to a five-year restricted period and the balance of each grant is restricted for 10 years or until retirement, whichever is later. These vesting provisions are among the longest of awards by comparable companies in multiple industries. They help achieve the long-term objectives of the program and ownership levels described above. Page 19 provides more information on the terms of our restricted stock, but three key points should receive further emphasis:

•: For senior executives, at least half the total amount of restricted stock may not be sold or transferred until after the executive retires.
•: The restricted period for restricted stock awards is not subject to acceleration. In many cases, shares remain restricted for years after an executive retires.
•: Restricted stock is subject to forfeiture if an executive leaves the company before standard retirement time. Restricted stock may also be forfeited if an executive engages in activity that is detrimental to the interests of the Company. Detrimental activity could include a violation of the Company's code of ethics and business standards.

Restricted stock awards must be sufficient in size to provide a strong, long-term performance and retention incentive for executives and to increase their vested interest in the business. The number of restricted shares granted to executive officers is based on Company results, individual performance, and level of responsibility as described. The number of shares held by an executive is not a factor that is used in determining subsequent grants. We believe that annual grants at a competitive level with significant vesting requirements are the most effective method of reinforcing the long-term nature of our business. In addition, annual grants of stock rather than cash reinforce ownership levels and alignment with shareholder interests.

Alignment with shareholder interests is reflected in current stock ownership among senior executives, which ranges from 22 to 44 times base salary for the named executive officers, and from 9 to 29 times for the other officers of the Company. These levels of ownership far exceed common practice across industries in the U.S., and they reflect a significant personal investment in the Company by the same executives responsible for determining the future success of the organization and the return to shareholders.

CEO Compensation

Within the framework described above, the Committee determines the salary and bonus of the CEO based on leadership, the execution of business plans, and strategic results. Key considerations include long-term returns on capital, growth in earnings per share, and the operating results of the business, which include the achievement of safety, health, and environmental objectives. The size and complexity of the business and the CEO's experience are also key factors. As explained earlier, the Committee

does not use narrow, quantitative measures or formulas in determining compensation levels, including that of the CEO.

The Committee has specifically considered the impact of the salary increase and incentive awards granted on the other elements of total remuneration, including non-cash benefits and future retirement income. The restricted stock granted to Mr. Raymond recognizes his outstanding leadership of the business, continued strengthening of our worldwide competitive position, and continuing progress toward achieving long-range strategic goals. Like the other most senior executives, 50 percent of this year's stock grant to Mr. Raymond will be restricted for five years and the remaining 50 percent will be restricted for 10 years or retirement, whichever is later. These restrictions are not accelerated upon retirement and a significant number of Mr. Raymond's shares will therefore remain restricted for a period ranging from one to over nine years after his retirement.

The Committee believes Mr. Raymond's total compensation is appropriately positioned relative to CEOs of U.S.-based, integrated oil companies and other major U.S.-based corporations, particularly in view of the long-term performance of the Company and the substantial experience and expertise that Mr. Raymond brings to the job.

U.S. Income Tax Limits on Deductibility

U.S. income tax law limits the amount ExxonMobil can deduct for compensation paid to the CEO and the other four most highly paid executives. Performance-based compensation that meets Internal Revenue Service requirements is not subject to this limit. The short term awards and restricted stock grants described above are designed to meet these requirements so that ExxonMobil can continue to deduct the related expenses. Specifically, the shareholders have approved the material terms of performance goals for awards to the top executives. These material terms limit short term and long term awards to these executives to 0.2 and 0.5 percent of operating net income, respectively. Actual award levels have been significantly less based on the factors and judgments described in the preceding sections of this report.

Salaries for senior executives may be set at levels that exceed the U.S. income tax law limitation on deductibility. While the Company seeks to take advantage of favorable tax treatment for executive compensation where appropriate, the primary drivers for determining the amount and form of executive compensation must be the retention and motivation of superior executive talent rather than the U.S. tax code.

Role of the Compensation Committee

The Compensation Committee reviews all compensation paid or awarded to senior executives and approves the salary and incentive awards of the CEO and other top executives. The Committee is made up solely of non-employee directors. The Committee meets annually with an external consultant retained by the Committee itself to gain insight into compensation trends and issues. The consultant also provides a perspective on the structure and competitive standing of the ExxonMobil compensation program for executives.

Summary

ExxonMobil continues to have an appropriate and competitive executive compensation program, which has served the Company and shareholders well. The program is part of a fully-integrated, performance-based system that provides a balanced and stable foundation for strong and effective leadership going forward.


William R. Howell, Chair James R. Houghton		Reatha Clark King Walter V. Shipley

EXECUTIVE COMPENSATION TABLES

The following tables show the compensation of ExxonMobil's Chairman, the four other most highly paid executives, and Mr. Longwell who retired at year-end. See the Compensation Committee Report beginning on page 13 for an explanation of our compensation philosophy.

Summary Compensation Table

		Annual Compensation			Long Term Compensation
					Awards		Payouts
Name and Principal Position	Year	Salary ($)	Bonus ($)	Other Annual Compensation ($)(a)	Restricted Stock Award(s) ($)(b)	Shares Underlying Options (#)	LTIP Payouts ($)(c)		All Other Compensation ($)(d)
L. R. Raymond Chairman and CEO	2004 2003 2002	3,600,000 3,250,000 3,250,000	3,920,500 3,564,000 2,160,000	179,382 161,301 161,093	28,000,500 17,910,000 17,320,000	0 0 0	2,160,000 2,700,000 2,700,005		216,000 277,550 297,960
H. J. Longwell Executive Vice President and Director (Retired – 12/31/04)	2004 2003 2002	1,923,352 1,565,000 1,415,000	1,252,500 1,138,500 690,000	27,377 13,340 13,554	10,487,460 6,680,430 6,460,360	0 0 0	690,000 862,020 862,015		160,280 145,479 131,727
R. W. Tillerson President and Director	2004 2003 2002	958,333 691,667 562,500	1,000,000 726,000 440,000	102,073 20,502 38,166	6,720,120 3,832,740 3,706,480	0 0 0	440,010 399,990 300,025		59,550 43,500 35,750
E. G. Galante Senior Vice President	2004 2003 2002	783,333 691,667 562,500	800,000 726,000 440,000	23,579 131,418 12,750	6,007,380 3,832,740 3,706,480	0 0 0	440,010 399,990 300,025		57,523 51,136 41,960
S. R. McGill Senior Vice President	2004 2003 2002	762,500 725,000 660,000	800,000 628,700 326,000	18,470 21,953 23,759	5,447,370 2,629,188 2,421,336	0 0 0	326,010 407,490 372,515		71,956 68,468 62,509
J. S. Simon Senior Vice President	2004 2003 2002	810,417 740,000 675,000	691,400 628,700 326,000	15,750 13,963 13,863	4,622,628 2,629,188 2,421,336	0 0 0	326,010 407,490 340,010	(e) (e) (e)	113,260 81,821 64,756

(a): This column shows the cost to the Company of club memberships, financial planning services, and tax assistance provided to the named executives, as well as the incremental cost of each executive's personal use of company aircraft, automobiles, and properties. SEC rules allow companies not to disclose the first $50,000 of perquisite costs, but ExxonMobil voluntarily discloses the full amount of those costs.
: For Mr. Raymond, the totals include membership fees of $46,223 in 2004, $42,301 in 2003, and $49,228 in 2002, as well as tax assistance of $33,441 in 2004, $29,880 in 2003, and $37,897 in 2002. For Mr. Tillerson, the totals include personal use of company properties of $23,095 in 2004, as well as tax assistance of $8,915 in 2004. For Mr. Galante, the totals include membership fees of $71,203 in 2003, as well as tax assistance of $47,107 in 2003.
: For security reasons, the Board requires the Chairman and President to use company aircraft for both business and personal travel. Although we consider these costs a necessary business expense rather than a perquisite, in line with SEC guidance, the table includes the amounts attributable to the Chairman and President's personal aircraft usage. The incremental costs were $89,246 in 2004, $79,711 in 2003, and $64,418 in 2002 for Mr. Raymond; and $54,559 in 2004 for Mr. Tillerson. Messrs. Raymond and Tillerson are taxed on the imputed income attributable to such personal aircraft use and do not receive tax assistance from the Company with respect to those amounts.

: The Company provides security for its employees based on an assessment of risk. The assessment includes consideration of the employee's particular focus and circumstances, including position and work location. The table does not include costs of security because we do not consider such security costs to be a personal benefit.
: The table also does not include relocation costs for transferred executives since all affected employees participate in the Company's relocation programs on the same basis.
(b): The value shown is the number of restricted shares times the market price of ExxonMobil stock on the day of grant. The table below shows the number of shares granted by year and the total number and value of restricted shares held by these executives as of December 31, 2004. Restricted shares granted in 2001 and prior years may not be sold until after retirement. Restricted shares granted in 2002 or later may not be sold (i) for half the shares, until five years after grant; and (ii) for the balance, until 10 years after grant or retirement, whichever occurs later. The values given do not reflect the transfer restrictions or the fact that, during the restricted period, the awards are subject to forfeiture in case of detrimental activity or early termination of employment. The executives receive the same cash dividends on restricted shares as holders of regular common stock, but cannot sell the shares during the restricted period. Grants in 2002 and prior years were made under the 1993 Incentive Program. Grants in 2003 and later were made under the 2003 Incentive Program. See page 15 for more details.

				Total Restricted Stock Held as of December 31, 2004
	Restricted Stock Award by Year (#)
Name	Restricted Stock Award by Year (#)
Name	2002	2003	2004	(#)	($)
L. R. Raymond	500,000	500,000	550,000	2,710,000	138,914,600
H. J. Longwell	186,500	186,500	206,000	731,000	37,471,060
R. W. Tillerson	107,000	107,000	132,000	364,000	18,658,640
E. G. Galante	107,000	107,000	118,000	350,000	17,941,000
S. R. McGill	69,900	73,400	107,000	314,300	16,111,018
J. S. Simon	69,900	73,400	90,800	268,100	13,742,806

: The stock price on date of grant was $34.64 in 2002; $35.82 in 2003; and $50.91 in 2004. The stock price on December 31, 2004, was $51.26.
(c): Settlements of earnings bonus units. See page 20 for more details.
(d): This column shows the value of company credits under ExxonMobil's tax-qualified defined contribution (401(k)) plan and the related non-qualified supplemental plan. The non-qualified supplemental plan provides higher-paid employees with the full 6-percent, company-matching contribution to which they would otherwise be entitled under the qualified plan but for limitations under the tax code. All eligible employees participate in the non-qualified supplemental plan on the same basis. The non-qualified supplemental plan is unfunded and credits accrue interest at the prime rate. Total defined contribution plan credits in 2004 were $216,000 for Mr. Raymond, $105,474 for Mr. Longwell, $59,550 for Mr. Tillerson, $48,875 for Mr. Galante, $47,800 for Mr. McGill, and $50,637 for Mr. Simon.
: This column also includes the cost of executive life insurance: $54,806 for Mr. Longwell, $8,648 for Mr. Galante, and $24,156 for Mr. McGill.
: For Mr. Simon, this amount also includes interest credits accrued on earnings bonus units for which payment is deferred until after retirement: $62,623 in 2004, $35,571 in 2003, and $22,256 in 2002.
(e): Under the terms of the award, payment is deferred until after retirement and accrues interest at the prime rate.

Aggregated Option/SAR Exercises in Last Fiscal Year and FY-End Option/SAR Values(a)

	Number of Shares Underlying Options/SARs		Number of Securities Underlying Unexercised Options/SARs at FY-End (#)		Value of Unexercised, In-the-Money Options/SARS at FY-End ($)(b)
		Value Realized
Name		Value Realized
Name	Exercised (#)	($)	Exercisable	Unexercisable	Exercisable	Unexercisable
L. R. Raymond	1,793,392	43,649,925	4,850,000	0	65,077,965	0
H. J. Longwell	455,064	12,102,593	2,844,936	0	46,795,257	0
R. W. Tillerson	65,944	1,558,297	536,744	0	6,791,498	0
E. G. Galante	72,828	1,916,076	559,252	0	7,377,921	0
S. R. McGill	103,256	2,841,746	995,432	0	16,669,764	0
J. S. Simon	76,000	2,650,500	820,000	0	13,007,349	0

(a): None of the named executives have stock appreciation rights.
(b): The difference between the option exercise price and the market price of ExxonMobil stock at year-end. The actual gain, if any, an executive realizes will depend on the market price of ExxonMobil stock at the time of exercise. "In-the-money" means the market price of the stock is greater than the exercise price of the option on the date specified.

Long Term Incentive Plans – Awards in Last Fiscal Year

Name	Number of Shares, Units or Other Rights (#)	Performance or Other Period Until Maturation or Payout	Estimated Future Payouts Under Non-Stock, Price-Based Plans Maximum ($)
L. R. Raymond	1,206,310	3 years maximum	3,920,508
H. J. Longwell	385,390	3 years maximum	1,252,518
R. W. Tillerson	307,700	3 years maximum	1,000,025
E. G. Galante	246,160	3 years maximum	800,020
S. R. McGill	246,160	3 years maximum	800,020
J. S. Simon	212,730	3 years maximum	691,373

The awards shown above are earnings bonus units. Each earnings bonus unit entitles the executive to receive an amount equal to ExxonMobil's cumulative net income per common share as announced each quarter beginning after the grant. Payout occurs on the third anniversary of the grant or when the maximum settlement value of $3.25 per unit is reached, if earlier. SEC rules classify earnings bonus units as long term incentives, but because of the long-term nature of ExxonMobil's business, we view earnings bonus units as mid-term incentive awards. See page 15 for more details.

Pension Plan Table (Yearly Benefit)

		Years of Service
Remuneration		30		35		40		45
$	500,000	$	240,000	$	280,000	$	320,000	$	360,000
	1,000,000		480,000		560,000		640,000		720,000
	1,500,000		720,000		840,000		960,000		1,080,000
	2,000,000		960,000		1,120,000		1,280,000		1,440,000
	2,500,000		1,200,000		1,400,000		1,600,000		1,800,000
	3,000,000		1,440,000		1,680,000		1,920,000		2,160,000
	4,000,000		1,920,000		2,240,000		2,560,000		2,880,000
	6,000,000		2,880,000		3,360,000		3,840,000		4,320,000
	8,000,000		3,840,000		4,480,000		5,120,000		5,760,000
	10,000,000		4,800,000		5,600,000		6,400,000		7,200,000
	12,000,000		5,760,000		6,720,000		7,680,000		8,640,000
	14,000,000		6,720,000		7,840,000		8,960,000		10,080,000

Employees who meet the age, service, and other requirements of ExxonMobil's defined benefit plans are eligible for a pension after retirement. There is no special program for senior executives. This table shows the approximate yearly benefit that would be paid to an ExxonMobil employee in the compensation and period of service categories shown. The table reflects combined benefits under ExxonMobil's tax-qualified pension plan, non-qualified supplemental pension plan, and non-qualified additional payments plan.

The qualified pension plan benefit is based on average annual salary over the highest paid consecutive 36-month period during the employee's last 10 years of employment. The supplemental pension plan provides higher-paid employees with the full salary-based pension benefit to which they would otherwise be entitled under the qualified plan but for limitations under the tax code. For employees granted a bonus under our short term incentive program, the additional payments plan provides a pension benefit based on the average of the three highest cash bonus and earnings bonus unit awards during the employee's last five years of employment if the employee attains 15 years of service and reaches age 55 before separating from the Company. Benefits accrue to all participants in these three plans on the same basis. The non-qualified plans are unfunded.

The benefit shown in the table reflects a five-year certain and life annuity form of payment for an employee retiring after age 60. For an employee who retires before age 60, the benefit would be reduced. The actual benefit is also reduced by a portion of the employee's Social Security benefits.

Under the ExxonMobil plans, covered compensation for the named executive officers includes the amount shown in the "Salary" column of the Summary Compensation Table plus the regular bonus shown in the "Bonus" column of that table and the earnings bonus unit award shown in the Long Term Incentive Plans table. However, as described above, if an executive separates from the Company before attaining 15 years of service and reaching age 55, covered compensation would include only salary. Since Messrs. Tillerson and Galante are under age 55, their covered compensation currently includes only salary.

Historically, retiring employees have had the option to receive an annuity as described above or an equivalent lump sum payment instead of an annuity. The lump sum represents the discounted net present value of the annual annuity payments to which the employee would otherwise be entitled,

based on the employee's actuarial life expectancy and the government discount rate in effect at the time. As a result of recent changes in U.S. tax law, however, starting in 2005, only lump sum distributions will be available under the two non-qualified plans. In addition, for the Company's highest ranking executives, including the executives named in the Summary Compensation Table, payment of the non-qualified lump sum must be deferred for six months after retirement. To keep these employees whole during the required deferral period, the amount payable to these executives will be the amount calculated at the date of retirement plus interest at the prime rate for six months or the amount calculated at the date of distribution, whichever is greater. The amounts could vary over the six-month deferral period due to changes in the government discount rate. As mentioned previously, these amounts are based on the same pension formula that applies to all other U.S. dollar paid employees in the ExxonMobil Pension Plan, which covers over 100,000 active and retired employees.

The chart below shows the covered compensation and years of service for each of the current executive officers named in the Summary Compensation Table. The information is shown as of February 28, 2005, for all executives except Mr. Longwell, who retired at the end of 2004. The chart also shows the discounted lump sum paid to Mr. Longwell on his retirement in lieu of an annual pension under the qualified and non-qualified pension plans, and shows an estimate of the lump sum pension benefit that would be payable to the current employees in lieu of an annual pension based on a hypothetical retirement date of February 28, 2005.

Name	Years of Service	Covered Compensation ($)	Estimated Net Present Value of Single Distribution In Lieu of Pension ($ Million)
L. R. Raymond	42 years	10,198,010	81.3
H. J. Longwell	41 years	3,739,017	31.3	(a)
R. W. Tillerson	30 years	765,282	1.3	(b)
E. G. Galante	33 years	697,503	1.4	(b)
S. R. McGill	37 years	1,949,401	14.9
J. S. Simon	38 years	1,904,347	15.2

(a): Actual discounted lump sum paid to Mr. Longwell who retired on December 31, 2004, was $31,346,389.
(b): The amounts shown for Messrs. Tillerson and Galante represent estimated lump sum distributions under the non-qualified supplemental pension plan only. Eligibility for the non-qualified supplemental pension plan is open to all participants in the ExxonMobil Pension Plan whose benefit exceeds prescribed IRS limits. Neither of these executives is yet eligible to receive a lump sum under the qualified pension plan or to receive any distribution under the non-qualified additional payments plan.

Executive Life Insurance/Death Benefit Program

The Company offers coverage for senior executives in the form of term life insurance or a company-paid death benefit. Coverage under either option equals four times base salary until age 65 and a declining multiple thereafter. For executives electing life insurance coverage, annual costs are included in the "All Other Compensation" column of the Summary Compensation Table on page 18. Messrs. Raymond, Tillerson, and Simon have elected death benefit coverage. Death benefit coverage represents an unfunded promise by the Company to pay the benefit and therefore is not reflected in the Summary Compensation Table.

Administrative Services for Retired Executives

The Company currently makes an administrative assistant available for shared use by certain senior executives, including retired chairmen and their spouses. The Company also allows certain retired employee directors, including Mr. Longwell, to use otherwise vacant office space at the Company's headquarters. The aggregate incremental cost of these services to the Company is approximately $140 thousand per year.

Equity Compensation Plan Information

	(a)		(b)		(c)
Plan Category	Number of Securities to be Issued Upon Exercise of Outstanding Options, Warrants and Rights		Weighted-Average Exercise Price of Outstanding Options, Warrants and Rights (1)		Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans [Excluding Securities Reflected in Column (a)]
Equity compensation plans approved by security holders	152,676,411	(2)(3)	$37.72	(3)	200,287,554(3)(4)(5)
Equity compensation plans not approved by security holders	0		0		0
Total	152,676,411		$37.72		200,287,554

(1): The exercise price of each option reflected in this table is equal to the fair market value of the Company's common stock on the date the option was granted. The weighted-average price reflects eight prior option grants that are still outstanding.
(2): Includes restricted stock units and deferred bonuses to be settled in shares.
(3): Does not include options that ExxonMobil assumed in the 1999 merger with Mobil. At year-end 2004, the number of securities to be issued upon exercise of outstanding options under Mobil plans was 33,996,814, and the weighted average exercise price of such options was $26.21. No additional awards may be made under those plans.
(4): Available shares can be granted in the form of restricted stock, options, or other stock-based awards.
(5): Under the 2004 Non-Employee Director Restricted Stock Plan approved by shareholders in May 2004, each non-employee director automatically receives 8,000 shares of restricted stock when first elected to the Board and, if the director remains in office, an additional 4,000 restricted shares each following year. While on the Board, each non-employee director receives the same cash dividends on restricted shares as a holder of regular common stock, but the director is not allowed to sell the shares. The restricted shares can be forfeited if the director leaves the Board early.

Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Securities and Exchange Act of 1934 requires that our executive officers and directors file reports of their ownership and changes in ownership of ExxonMobil stock on Forms 3, 4, and 5 with the Securities and Exchange Commission and New York Stock Exchange. We are not aware of any late or unfiled reports for 2004.

STOCK PERFORMANCE GRAPHS

Annual total returns to ExxonMobil shareholders were 28 percent in 2004, 20 percent in 2003, minus 9 percent in 2002, and have averaged more than 7 percent per year over the past five years. Total returns mean share price increase plus dividends paid, with dividends reinvested. The graphs below show the relative investment performance of ExxonMobil common stock, the S&P 500, and an industry competitor group over the last five and 10-year periods. The industry competitor group consists of three other international integrated oil companies: BP, ChevronTexaco, and Royal Dutch Shell.

FIVE-YEAR CUMULATIVE TOTAL RETURNS
Value of $100 Invested at Year-End 1999

TEN-YEAR CUMULATIVE TOTAL RETURNS
Value of $100 Invested at Year-End 1994

AUDIT COMMITTEE REPORT

The primary function of our Committee is oversight of the Corporation's financial reporting process, public financial reports, internal accounting and financial controls, and the independent audit of the annual consolidated financial statements. Our Committee acts under a charter attached to this proxy statement. We review the adequacy of the charter at least annually. All of our members are independent and three of our members are audit committee financial experts under Securities and Exchange Commission rules. We held 11 meetings in 2004 at which, as discussed in more detail below, we had extensive reports and discussions with the independent auditors, internal auditors, and other members of management.

In performing our oversight function, we reviewed and discussed the consolidated financial statements with management and PricewaterhouseCoopers LLP (PwC), the independent auditors. Management and PwC told us that the Corporation's consolidated financial statements were fairly stated in accordance with generally accepted accounting principles. We discussed with PwC matters covered by the Statement on Auditing Standards No. 61 (Communication with Audit Committees). In addition, we reviewed and discussed Management's report on internal control over financial reporting and the related audit performed by PwC, which confirmed the effectiveness of the Corporation's internal control over financial reporting.

We also discussed with PwC its independence from the Corporation and management, including the matters in Independence Standards Board Standard No. 1 (Independence Discussions with Audit Committees) and the letter and disclosures from PwC to us pursuant to Standard No. 1. We considered the non-audit services provided by PwC to the Corporation and concluded that the auditors' independence has been maintained.

We discussed with the Corporation's internal auditors and PwC the overall scope and plans for their respective audits. We met with the internal auditors and PwC at each meeting, both with and without management present. Discussions included the results of their examinations, their evaluations of the Corporation's internal controls, and the overall quality of the Corporation's financial reporting.

Based on the reviews and discussions referred to above, in reliance on management and PwC, and subject to the limitations of our role described below, we recommended to the Board, and the Board has approved, the inclusion of the audited financial statements in the Corporation's Annual Report on Form 10-K for the year ended December 31, 2004, for filing with the Securities and Exchange Commission.

We have also appointed PwC to audit the Corporation's financial statements for 2005, subject to shareholder ratification of that appointment.

In carrying out our responsibilities, we look to management and the independent auditors. Management is responsible for the preparation and fair presentation of the Corporation's financial statements and for maintaining effective internal control. Management is also responsible for assessing and maintaining the effectiveness of internal control over the financial reporting process in compliance with Sarbanes-Oxley Section 404 requirements. The independent auditors are responsible for auditing the Corporation's annual financial statements and expressing an opinion as to whether the statements are fairly stated in conformity with generally accepted accounting principles. In addition, the independent auditors are responsible for auditing the Corporation's internal controls over financial reporting and for expressing opinions on both the effectiveness of controls and management's assertion as to this effectiveness. The independent auditors perform their responsibilities in accordance with the standards of the Public Company Accounting Oversight Board. Our members are not

professionally engaged in the practice of accounting or auditing, and are not experts under the Securities Act of 1933 in either of those fields or in auditor independence.

James R. Houghton, Chair
William R. Howell

Reatha Clark King
Henry A. McKinnell, Jr.

AUDIT COMMITTEE PRE-APPROVAL POLICY AND PROCEDURE MEMORANDUM

Under the Sarbanes-Oxley Act of 2002, ExxonMobil's Audit Committee is responsible for the appointment, compensation and oversight of the work of the independent auditor. As part of this responsibility, the Audit Committee is required to pre-approve audit and non-audit services provided by the independent auditor in order to ensure the services do not impair the auditor's independence. The Securities and Exchange Commission (SEC) has issued rules specifying the types of services that an independent auditor may not provide to its audit client, as well as the Audit Committee's responsibility for administering the engagement of the independent auditor, including pre-approval of fees. Accordingly, ExxonMobil's Audit Committee has adopted the following Pre-Approval Policy and Procedure Memorandum for Audit, Audit-Related, and Tax services. This Memorandum sets forth procedures and conditions whereby permissible services provided by the independent auditor will be pre-approved.

The Audit Committee has adopted an approach whereby all services obtained from the independent auditor will be pre-approved. Under this approach, an annual program of work will be approved for each of the following categories of services: Audit, Audit-Related, and Tax. Engagement-by-engagement pre-approval will not be required, except for exceptional or ad hoc incremental engagements with fees resulting in the fee category exceeding the aggregate pre-approved program of work for that category. In general, a work program for each category of services can be supplemented with additional pre-approved amounts after appropriate review of the additional services with the Audit Committee. It is not envisioned that ExxonMobil will obtain non-audit services (other than Tax services) from the independent auditor; however, the Audit Committee may consider specific engagements in the All Other Services category on an engagement-by-engagement basis.

For all services obtained from the independent auditor, the Audit Committee will consider whether such services are consistent with the SEC's rules on auditor independence. The Audit Committee will consider the level of Audit and Audit-Related fees in relation to all other fees obtained from the independent auditor, and will review such level each financial year.

The remainder of this Memorandum sets forth the procedures by which the Audit Committee will fulfill its responsibilities for pre-approving services. The Audit Committee will obtain appropriate input from ExxonMobil management on the general level of fees, the process for negotiating and reporting fees from the numerous locations where ExxonMobil operates and the independent auditor provides services, and the level of Audit and Audit-Related fees compared to all other fees.

Pre-Approval Process and Delegation of Authority

The primary review and pre-approval of services to be obtained from the independent auditor and related fees will be scheduled for the Audit Committee meeting each October for the following financial year. If fees might otherwise exceed pre-approved amounts for any category of permissible services, then incremental amounts can be reviewed and pre-approved at subsequent Audit Committee meetings prior to commitment. If needed, time will be set aside in any scheduled Audit Committee meeting for review and pre-approval of additional services. No additional authority is delegated for pre-approval of services obtained from the independent auditor.

The term of any pre-approval applies to ExxonMobil's financial year. Thus Audit fees for the financial year may include work performed after the close of the calendar year. The pre-approval for Audit-Related and Tax fees is on a calendar year basis. Unused pre-approval amounts will not be carried forward to the next year. Pre-approvals will be made by category of service, and cannot be transferred between categories.

Audit Services

Engagement term, scope of service and fees for the annual examination of ExxonMobil's financial statements will be pre-approved by the Audit Committee. These Audit services include the annual financial statement audit (including required quarterly reviews), affiliate and subsidiary statutory audits, and other procedures required to be performed by the independent auditor to be able to render an opinion on ExxonMobil's consolidated financial statements. Other procedures include information systems reviews and testing performed in order to understand and place reliance on the system of internal control, and procedures to support the independent auditor's report on management's report on internal controls for financial reporting consistent with Section 404 of the Sarbanes-Oxley Act of 2002.

The Audit Committee will be responsible for direction and oversight of the engagement of the independent auditor. At its discretion, the Audit Committee will obtain input from ExxonMobil management on the terms of the engagement, the effectiveness with which the engagement is carried out, and the amount of Audit fees. The independent auditor is responsible for the cost-effective management of the engagement, and for ensuring that audit services are not provided prior to review and pre-approval by the Audit Committee.

The independent auditor and ExxonMobil management will jointly manage a process for collecting and reporting Audit fees billed by the independent auditor to ExxonMobil for each financial year.

Audit-Related Services

Audit-Related services include services that are reasonably related to the performance of the review of ExxonMobil's financial statements. These services include benefit plan and joint venture audits, attestation procedures related to cost certifications and government compliance, consultations on accounting issues, and due diligence procedures. Each year the Audit Committee will conduct a broad review of the proposed services to ensure the independence of the independent auditor is not impaired.

General pre-approval will occur in October of each year coincident with pre-approval of Audit services. Applicable operating and staff functions will be requested to assign a process-owner to monitor the engagement of the independent auditor for Audit-Related services. This will provide assurance that the aggregate dollar amount of services obtained does not exceed the pre-approval amount at any time, and that new engagements not contemplated in October are pre-approved prior to commitment.

Tax Services

The Audit Committee concurs that the independent auditor may provide certain Tax services without impairing its independence. These services include preparing local tax filings and related tax services, tax planning, preparing individual employee expatriate tax returns, and other services as permitted by SEC regulations. The Audit Committee will not permit engaging the independent auditor: (1) in connection with a transaction, the sole purpose of which may be impermissible tax avoidance; (2) for other tax services that may be prohibited by SEC rules now or in the future; or (3) to perform services under contingent fee arrangements.

The following process-owners are assigned to review the scope of major engagements, monitor the pre-approved level of all services, and ensure that fee proposals for engagements beyond the pre-approved amount, at any time, are appropriately reviewed and pre-approved prior to commitment. For Expatriate Tax services, the Manager, Global Human Resources Expatriate Services will be the process owner. These services will be subject to a periodic competitive bidding process.

Significant engagements of outside accounting firms for Tax services (other than Expatriate Tax services) require the endorsement of the Exxon Mobil Corporation General Tax Counsel. Accordingly, an Associate General Tax Counsel within the ExxonMobil Tax Department will act as primary contact on behalf of the General Tax Counsel and monitor the engagement of the independent auditor or other firms for such Tax services.

All Other Services

In general, except for the Audit, Audit-Related and Tax services described previously, ExxonMobil does not envision obtaining other services from the independent auditor. If permissible other services are requested by ExxonMobil business units, each engagement must be pre-approved by the Audit Committee. Such requests should be supported by endorsement of the Exxon Mobil Corporation Controller and the Exxon Mobil Corporation General Auditor prior to review with the Audit Committee.

Prohibited Services

Independent auditors may not provide the following prohibited services: Bookkeeping, Financial Information Systems Design and Implementation, Appraisals or Valuation (other than Tax), Fairness Opinions, Actuarial Services, Internal Audit Outsourcing, Management Functions, Human Resources such as Executive Recruiting, Broker-dealer Services, Legal Services, or Expert Services such as providing expert testimony or opinions where the purpose of the engagement is to advocate the client's position in an adversarial proceeding. ExxonMobil personnel may not under any circumstances engage the independent auditor for prohibited services. Potential engagements not clearly permissible should be referred to the Exxon Mobil Corporation Controller or the Exxon Mobil Corporation General Auditor.

ITEM 2 – RATIFICATION OF INDEPENDENT AUDITORS

The Audit Committee has appointed PricewaterhouseCoopers LLP (PwC) to audit ExxonMobil's financial statements for 2005. We are asking you to ratify that appointment.

Total Fees

The total fees paid to PwC for professional services rendered to ExxonMobil for the fiscal year ended December 31, 2004, were $47.5 million, an increase of $5.6 million from 2003. The Audit Committee reviewed and pre-approved all services in accordance with the service pre-approval policies and procedures shown above. The Audit Committee did not use the "de minimis" exception to pre-approval that is available under SEC rules. The following table summarizes the fees, which are described in more detail below.

	2004	2003
	(millions of dollars)
Audit Fees	27.6	23.5
Audit-Related Fees	3.5	3.6
Tax Fees	16.4	14.8
All Other Fees	–	–

Total	47.5	41.9

Audit Fees

The aggregate fees paid to PwC for professional services rendered for the annual audit of ExxonMobil's financial statements for the fiscal year ended December 31, 2004, and for the reviews of the financial statements included in our quarterly reports on Form 10-Q for that fiscal year were $27.6 million (versus $23.5 million for 2003). The increase of $4.1 million from 2003 is predominantly from auditing financial reporting internal controls as specified in Section 404 of Sarbanes-Oxley.

Audit-Related Fees

The aggregate fees billed by PwC for Audit-Related services rendered to ExxonMobil for the fiscal year ended December 31, 2004, were $3.5 million (versus $3.6 million for 2003). These services were mainly comprised of benefit plan and joint venture audits, and attestation procedures related to cost certifications and government compliance.

Tax Fees

The aggregate fees billed by PwC for Tax services rendered to ExxonMobil for the fiscal year ended December 31, 2004, were $16.4 million (versus $14.8 million for 2003). These services are described below.

•: PwC assisted in preparing tax returns for individual ExxonMobil expatriate employees. These fees were $14.9 million for 2004 (versus $12.8 million for 2003). The increase of $2.1 million is driven by the increase in the number of employees loaned to joint-ventures ($1.1 million) and foreign exchange effects ($0.8 million).
•: PwC also assisted various ExxonMobil affiliates with the preparation of local tax filings and related tax services. These fees were $1.5 million for 2004 (versus $2.0 million for 2003).

All Other Fees

The aggregate fees billed by PwC for services rendered to ExxonMobil, other than the services described above under "Audit Fees," "Audit-Related Fees," and "Tax Fees," for the fiscal year ended December 31, 2004, were zero (also zero in 2003).

Other than Audit-Related and Tax services of the type described above, ExxonMobil does not envision obtaining other non-audit services from PwC.

PwC has been ExxonMobil's independent auditing firm for many years, and we believe they are well qualified for the job. A PwC representative will be at the annual meeting to answer appropriate questions and to make a statement if he desires.

The Audit Committee recommends you vote FOR this proposal.

SHAREHOLDER PROPOSALS

We expect Items 3 – 10 to be presented by shareholders at the annual meeting. Following SEC rules, other than minor formatting changes, we are reprinting the proposals and supporting statements as they were submitted to us. We take no responsibility for them. On request to the Secretary at the address listed under "Contact Information" on page 3, we will provide information about the sponsors' shareholdings, as well as the names, addresses, and shareholdings of any co-sponsors.

The Board recommends you vote AGAINST Items 3 through 10 for the reasons we give after each one.

ITEM 3 – POLITICAL CONTRIBUTIONS

This proposal was submitted by Mrs. Evelyn Y. Davis, Watergate Office Building, 2600 Virginia Avenue, N.W., Suite 215, Washington, D.C. 20037.

"RESOLVED: That the stockholders of ExxonMobil assembled in Annual Meeting in person and by proxy, hereby recommend that the Corporation affirm its political nonpartisanship. To this end the following practices are to be avoided:

(a): The handing of contribution cards of a single political party to an employee by a supervisor.
(b): Requesting an employee to send a political contribution to an individual in the Corporation for a subsequent delivery as part of a group of contributions to a political party or fund raising committee.
(c): Requesting an employee to issue personal checks blank as to payee for subsequent forwarding to a political party, committee or candidate.
(d): Using supervisory meetings to announce that contribution cards of one party are available and that anyone desiring cards of a different party will be supplied one on request to his supervisor.
(e): Placing a preponderance of contribution cards of one party at mail station locations.

REASONS: The Corporation must deal with a great number of governmental units, commissions and agencies. It should maintain scrupulous political neutrality to avoid embarrassing entanglements detrimental to its business. Above all, it must avoid the appearance of coercion in encouraging its employees to make political contributions against their personal inclination. The Troy (Ohio) News has condemned partisan solicitation for political purposes by managers in a local company (not ExxonMobil). And if the Company did not engage in any of the above practices, to disclose this to ALL shareholders in each quarterly report. Last year the owners of 7.3% of shares voted FOR this resolution.

If you AGREE, please mark your proxy FOR this resolution."

The Board recommends you vote AGAINST this proposal for the following reasons:

•: U.S. federal law prohibits some of the practices listed by the proponent. The Company has not and does not engage in any of the practices listed by the proponent.
•: Directors, officers, and employees engaging in political activity do so as private citizens and not as representatives of the Corporation.

It is the Corporation's policy to communicate information and views on issues of public debate that have an important impact on our business. Registering and voting; contributing financially to the party

or candidate of one's choice; keeping informed on political matters; serving on civic bodies; and campaigning and holding office at the local, state, or national levels are highly important rights and responsibilities of the citizens of democracies and we encourage our employees to participate.

The ExxonMobil Political Action Committee (PAC) restricts solicitation for voluntary contributions to executive retirees, and senior level managers and professionals. Decisions on whether or not to contribute are left to the discretion of those individuals and are strictly confidential. Contribution cards are not collected at Company meetings nor are they sent to Company managers. Contributions go directly to an outside vendor that collects and manages the funds available to the ExxonMobil PAC. Neither names of contributors nor the amounts of any contributions are released to ExxonMobil management.

ITEM 4 – BOARD COMPENSATION

This proposal was submitted by Mr. Chris Rossi, P. O. Box 249, Boonville, CA 95415.

"The shareholders of ExxonMobil request the board of directors take the necessary steps to amend the company's governing instruments to adopt the following: Beginning in the 2006 fiscal year at least 50% of the compensation of each board member shall be restricted common stock of ExxonMobil. This restricted stock shall be held until that board member retires from our board of directors.

SUPPORTING STATEMENT

There is no better way to align management's compensation with the shareholder's interest than to have to own the common stock."

The Board recommends you vote AGAINST this proposal for the following reasons:

•: Currently more than 60 percent of each board member's compensation is in restricted stock and must be held until the non-employee director leaves the Board. Consequently, this proposal would have no impact on our non-employee director compensation program.
•: For many years, the objective has been to structure director compensation to be on average, over time, approximately equal amounts of cash and stock. This proposal would potentially require that a different number of restricted stock shares be granted each year in order to comply.
•: ExxonMobil's Corporate Governance Guidelines require that a substantial portion of non-employee director compensation be paid in stock, which must be held until the director retires from the Board.

ExxonMobil's non-employee director compensation program is designed to help attract and retain highly qualified individuals to serve as non-employee directors and to align their interests with those of shareholders. This compensation program balances short-term and long-term features and is monitored through regular surveys of other large firms.

Implementing arbitrary quotas on short-term or long-term features of the non-employee director compensation program could put the Company at a competitive disadvantage in attracting and retaining the best-qualified director candidates through loss of flexibility. The Board believes that ExxonMobil's non-employee director compensation program would not be impacted with this shareholder proposal and that changes to governing instruments are not currently required.

ITEM 5 – INDUSTRY EXPERIENCE

This proposal was submitted by the Community of the Sisters of St. Dominic of Caldwell, New Jersey, 52 Old Swartswood Station Road, Newton, NJ 07860, as lead proponent of a filing group.

"Whereas

Exxon Mobil Corporation is one of the largest companies in the world in investment capitalization, revenue and in profit. It is also the world's largest energy company.

Although the independent members of the Board of Directors have the responsibility of protecting the interests of the shareholders, none of our outside directors have any day-to-day expertise in the core part of the company's business.

Many of our independent directors are active CEOs of large companies, and sit on many large cap corporate boards and non-profit organizations, all of which involve large commitments of time.

We believe that evaluation of the performance of the corporation, and effectiveness in improving the performance of the company, necessitates both a serious time commitment and an in-depth understanding of the energy business.

We believe that the oversight function of Board Members would be lacking if Board Members were to be uninformed about or misunderstand the core operations of the business, e.g. oil and gas availability, exploration and production, opportunities for investment in renewable energy resources and environmental impacts.

The proponents of this resolution contend that the oversight function of the outside directors would be enhanced if some had personal experience with the specialized problems of the industry.

Other publicly owned oil companies, such as ConocoPhillips, have outside directors with industry expertise.

Although the share price of ExxonMobil stock has thus far done well, the energy industry is changing rapidly. The proponents of this resolution believe that having outside board members with solid expertise in the industry could enhance the company's ability to adapt to changing circumstances and thus improve its fiscal performance and reputation.

Be it Resolved that the shareholders of ExxonMobil request the Nominating Committee of the Board of Directors to adopt a policy of annually nominating, whenever possible, at least two independent Directors who, without any conflicts of interest vis a vis ExxonMobil, hold expertise in the oil, gas or energy industry, and who have significant availability of time to devote to the oversight of ExxonMobil management."

The Board recommends you vote AGAINST this proposal for the following reasons:

•: Due to the large number of joint ventures in this industry and the many contractors and suppliers used by the Company, it would be difficult, if not impossible, to find eligible non-employee directors within the oil industry who are qualified and who meet the antitrust and conflicts of interest rules.
•: ExxonMobil's Guidelines for the Selection of Non-Employee Directors state that the Corporation seeks candidates with diverse backgrounds who possess knowledge and skills in areas of importance to the Corporation. Non-employee directors make up a substantial majority of the Board and only non-employee directors serve on the Board's key committees.

Non-employee directors are well informed on the oil and gas business beginning with a comprehensive orientation program regarding ExxonMobil's business and affairs for all new

non-employee directors. In addition, Company executives present regular and detailed reviews of all aspects of ExxonMobil's operations as part of the agenda of regular Board meetings. Also, the non-employee directors attend meetings with the CEO and other members of management in Board and committee meetings and other formal and informal settings. Finally, the Board makes on-site visits to ExxonMobil facilities.

The Board believes it is not practical to implement this proposal.

ITEM 6 – ACEH SECURITY REPORT

This proposal was submitted by the New York City Teachers' Retirement System, 1 Centre Street, New York, N.Y. 10007.

"WHEREAS, we believe that transnational corporations operating in countries with repressive governments, ethnic conflict, weak rule of law, endemic corruption, or poor labor and environmental standards face serious risks to their reputation and share value if they are, in any way, seen to be responsible for, or complicit in, human rights violations; and,

WHEREAS, ExxonMobil has extensive natural gas operations in the Aceh region of the island of Sumatra in Indonesia; and,

WHEREAS, there have been numerous reports of human rights abuses against the local population by the Indonesian military in connection with security operations conducted in the area of ExxonMobil's operations; and,

WHEREAS, due to its relationship with the Indonesian military, the corporation has been named as lead defendant in a pending lawsuit, John Doe 1,et al., vs. Exxon Mobil Corporation, et al., filed in the Federal District Court for the District of Columbia, on behalf of Indonesian citizens who allegedly were victims of human rights abuses by military forces guarding ExxonMobil's facilities; and,

WHEREAS, it has been reported that ExxonMobil has provided logistical as well as financial support for Indonesian military forces stationed in the area; and,

WHEREAS, since 2002, ExxonMobil has been a participant in the dialogue on the U.S.-U.K. Voluntary Principles on Security and Human Rights, which call on companies operating internationally to urge local security forces to provide security in a manner consistent with human rights and ethical conduct; and

WHEREAS, ExxonMobil's Corporate Citizenship policy states that the provision of security should be 'consistent with the law and respect for human rights',

THEREFORE, BE IT RESOLVED, that shareholders request that management review and report to shareholders, by September, 2005, on the corporation's security arrangements with the Indonesian government and private security forces, including support, both monetary and in kind, to the Indonesian government and military. Furthermore, it is requested that this review and report to shareholders should be conducted with a particular reference to potential financial and reputational risks incurred by the company as a result of these relationships.

SUPPORTING STATEMENT

The New York City Teachers' Retirement System and the New York City Board of Education Retirement System believe that it is time for management to seriously review its policies in this area. Significant commercial advantages can accrue to our company by the rigorous implementation in its overseas operations of human rights policies based upon the Universal Declaration of Human Rights. These benefits can include enhanced corporate reputation, improved employee recruitment and retention,

improved community and stakeholder relations, and a reduced risk of adverse publicity, divestment campaigns, and lawsuits. We therefore urge you to vote FOR this proposal."

The Board recommends you vote AGAINST this proposal for the following reasons:

•: The Aceh region has been experiencing challenging economic, social, and political times, underscored by civil conflict, for many years. The Company and its employees are deeply troubled and concerned about the violence in the region.
•: The referenced field and facilities in the Aceh province of Indonesia belong to the government of Indonesia. Under our Production Sharing Agreement with the government, ExxonMobil's affiliate is a contractor whose role is to develop and operate the Arun field and facilities. Under the agreement, the government of Indonesia provides the security to protect those physical assets in a manner determined appropriate by the Indonesian Mining Authority, BPMIGAS.
•: We condemn human rights violations in any form and have actively expressed our views to governments and others around the world. In accordance with the Voluntary Principles on Security and Human Rights, we have specifically communicated to the government of Indonesia our opposition to human rights abuse in any form by any organization or individual.

ExxonMobil's operations and activities have actively contributed to the quality of life in the Aceh province through employment of local workers, use of small businesses that provide services for our operations, provision of health services, and extensive community investment. We have been a stabilizing force in the region. For example, ExxonMobil's affiliate in Indonesia donated much-needed assistance, including (in addition to millions of dollars of financial aid) air transportation for medical personnel and medical supplies, for the relief efforts arising from the devastating earthquake and tsunami that hit the Aceh province in December 2004.

The Board hopes that the political turmoil and violence in the Aceh province can be peacefully resolved. Since ExxonMobil's position and policies on human rights in our workplaces are broadly communicated and reports on our activities are available to shareholders and the public on our website, the Board does not believe a standalone Aceh security report is warranted.

ITEM 7 – AMENDMENT OF EEO POLICY

This proposal was submitted by the New York City Employees' Retirement System, 1 Centre Street, New York, NY 10007, as lead proponent of a filing group.

"WHEREAS: ExxonMobil does not explicitly prohibit discrimination based on sexual orientation in its written employment policy;

Many of our peers, including Amerada Hess, BP, ChevronTexaco, ConocoPhillips, Marathon Oil, Occidental Petroleum, Shell Oil, Sunoco and Unocal explicitly prohibit this form of discrimination in their written policies, according to the Human Rights Campaign.

Over 80% of the Fortune 500 companies have adopted written nondiscrimination policies prohibiting harassment and discrimination on the basis of sexual orientation, as have more than 95% of Fortune 100 companies, according to the Human Rights Campaign;

We believe that corporations that prohibit discrimination on the basis of sexual orientation have a competitive advantage in recruiting and retaining employees from the widest talent pool;

According to a September 2002 survey by Harris Interactive and Witeck-Combs, 41% of gay and lesbian workers in the United States reported an experience with some form of job discrimination related to sexual orientation; almost one out of every 10 gay or lesbian adults also stated that they had

been fired or dismissed unfairly from a previous job, or pressured to quit a job because of their sexual orientation;

Minneapolis, San Francisco, Seattle and Los Angeles have adopted legislation restricting business with companies that do not guarantee equal treatment for lesbian and gay employees;

Fourteen states, the District of Columbia and more than 150 cities and counties, including the city of Dallas, have laws prohibiting employment discrimination based on sexual orientation;

Our company has operations in, and makes sales to institutions in states and cities that prohibit discrimination on the basis of sexual orientation;

National public opinion polls consistently find more than three quarters of the American people support equal rights in the workplace for gay men, lesbians and bisexuals; for example, in a Gallup poll conducted in March, 2003, 88% of respondents favored equal opportunity in employment for gays and lesbians;

RESOLVED: The Shareholders request that ExxonMobil amend its written equal employment opportunity policy to explicitly prohibit discrimination based on sexual orientation and to substantially implement the policy.

SUPPORTING STATEMENT: Employment discrimination on the basis of sexual orientation diminishes employee morale and productivity. Because state and local laws are inconsistent with respect to employment discrimination, our company would benefit from a consistent, corporate wide policy to enhance efforts to prevent discrimination, resolve complaints internally, and ensure a respectful and supportive atmosphere for all employees. ExxonMobil will enhance its competitive edge by joining the growing ranks of companies guaranteeing equal opportunity for all employees."

The Board recommends you vote AGAINST this proposal for the following reasons:

•: ExxonMobil has zero-tolerance discrimination and harassment policies which are comprehensive in nature, rigorously enforced, and applicable to all employees wherever we operate in the world. These written policies prohibit discrimination or harassment for any reason, including sexual orientation.
•: Our all-inclusive global policies, supported by comprehensive ongoing training, eliminate any doubt among employees, supervisors, contractors, or anyone else in our worldwide operations that discrimination and harassment for any reason, including sexual orientation, are prohibited. Country-specific policies are established only to recognize and honor the specific legal requirements in countries where required.

In responding to this proposal for the seventh consecutive year, the Board reaffirms its strong position that the Company's policies are both comprehensive to address our worldwide operations, and explicit to meet country-specific laws and regulations.

The Board believes the request to amend the Company's policies on discrimination and harassment is unwarranted and unnecessary. Discrimination and harassment of any form, including sexual orientation, in the Company are not tolerated and the Company's steadfast adherence to these policies ensures that employees worldwide understand and enforce them.

ITEM 8 – BIODIVERSITY IMPACT REPORT

This proposal was submitted by Mr. David Cunningham, 5039 Route 22A, Benson, VT 05743, as lead proponent of a filing group.

"WHEREAS, biodiversity is being lost at an alarming rate and that there is a need to preserve the Earth's remaining species of plants and animals.

WHEREAS, protected and sensitive areas are essential for supporting biodiversity. Oil and gas drilling and development in these areas are likely to have negative impacts on biodiversity. For example, the U.S. Department of the Interior estimates that oil and gas drilling in the coastal plain of the Arctic National Wildlife Refuge will displace or damage up to 40 percent of the Porcupine River Caribou herd, threaten denning areas for polar bears, and disturb ecosystems that support more than 120 species of migratory birds. The company has already started drilling off of Sakhalin Island in eastern Russia. The Sakhalin I project, which is being developed by Exxon Neftegas Limited, will adversely impact the world's last remaining Western Pacific grey whales and important fisheries including Pacific salmon;

WHEREAS, as shareholders, we believe there is a need to study and report on the impact on our company's value from decisions to do business in sensitive areas or areas of high conservation value (ecologically sensitive, biologically rich or environmentally sensitive cultural areas).

WHEREAS, preserving sensitive ecosystems will enhance our company's image and reputation with consumers, elected officials, current and potential employees, and investors;

WHEREAS, some of our major competitors have already enacted such a policy and are members of the Energy Biodiversity Initiative,

RESOLVED, shareholders request that the independent directors of the Board of ExxonMobil prepare a report, at reasonable cost and omitting proprietary information, on the potential environmental damage that would result from the company drilling for oil and gas in protected areas such as IUCN Management Categories I-IV and Marine Management Categories I-V, national parks, monuments, and wildlife refuges (such as the Arctic National Wildlife Refuge), and World Heritage Sites. The report should consider the implications of a policy of refraining from drilling in such areas and should be available to investors by the 2006 annual meeting.

Supporting Statement

We agree with the company when it states 'ExxonMobil recognizes the protection of biodiversity – the variety and complexity of life – as an important conservation issue that presents broad challenges to society.'

We welcome this interest in biodiversity, and as shareholders we strongly believe, in addition to recognizing the issue, there is a need to study and disclose the impact on our company's value from decisions to do business in protected and sensitive areas. This would allow shareholders to assess the risks created by the company's activity in these areas as well as the company's strategy for managing these risks.

Vote YES for this proposal, which will improve our company's reputation and make ExxonMobil a leader in promoting biodiversity."

The Board recommends you vote AGAINST this proposal for the following reasons:

•: ExxonMobil recognizes the protection of biodiversity – the variety and complexity of life – as an important conservation issue that presents broad challenges to society. We believe that we have consistently demonstrated our ability to operate responsibly in sensitive areas by implementing scientific, practical, and sustainable solutions. Protecting biodiversity is part of our environmental management system and is considered during business planning across all aspects of our operations.
•: Biodiversity assessments and decisions regarding the conduct of our operations in environmentally sensitive areas must be location and ecosystem-specific to be meaningful rather than in the generalized approach suggested by this proposal. Each prospective exploration and development area has unique characteristics and sensitivities requiring site-specific scientific evaluation and risk assessment. ExxonMobil's approach requires a thorough and systematic assessment of environmental and other impacts prior to conducting drilling or other operations. In many cases, these assessments are available in the public domain as part of submittals to governments and international organizations.
•: ExxonMobil's Environment Policy appropriately and adequately addresses the potential issues raised by this proposal. The Environment Policy confirms ExxonMobil's commitment to continuous efforts to improve environmental performance and provides definitive standards for the conduct of all our activities. Further, our Operations Integrity Management System provides the systematic and disciplined framework to manage safety, health, environment, and security risks in our operations and to promote exemplary execution of our policies and standards.

Biodiversity conservation remains a focus area for the Corporation. Over the last two years, an internal work group has identified several actions to strengthen awareness of conservation requirements, including further integration of our practices in ecosystem protection into our management system discipline. Our approach is closely aligned with the 12 recommendations highlighted in the "Energy and Biodiversity Initiative." ExxonMobil remains an active participant in the Biodiversity Working Group sponsored jointly by the International Petroleum Industry Environmental Conservation Association (IPIECA) and the International Association of Oil and Gas Producers.

ExxonMobil will continue to communicate with shareholders and the public about our environmental conservation work through our Corporate Citizenship Report and on the Company's website. The Board believes the additional report requested by this proposal would be duplicative to the assessments already prepared.

ITEM 9 – CLIMATE SCIENCE REPORT

This proposal was submitted by Christian Brothers Investment Services, Inc., 90 Park Avenue, 29th Floor, New York, NY 10016, as lead proponent of a filing group.

"Whereas:

Corporations have a responsibility to create value for shareholders and benefits for society. However, companies acting to maximize shareholder value may impose costs on the public, including environmental degradation and climate change. It is in the long-term interest of society to minimize these 'externalities,' partly because they may hamper economic growth.

Government is responsible for creating standards for business conduct that will ensure respect for the environment and the public welfare. It is in the interest of shareholders for companies to act within a legal and regulatory framework that is consistent, predictable and effective.

Successful policymaking requires the best possible information. Without the cooperation of business, policymakers may lack crucial information necessary for effective regulation. Companies have a responsibility to be as transparent as possible in providing information to the public and the government.

Whereas:

The Intergovernmental Panel on Climate Change (IPCC), the international body of experts charged with climate change research, stated in its 2001 Third Assessment Report:

'There is new and stronger evidence that most of the warming observed over the last 50 years is attributable to human activity...Human influences will continue to change atmospheric composition throughout the 21st century.'

The study describes climate impacts, such as higher global temperatures and increased precipitation, as 'very likely.'

A 2004 report by the Bush Administration's Climate Change Science Program states that increases in human-derived GHG emissions are the only likely explanation for global warming over the past three decades.

ExxonMobil has funded scientific studies and made public statements that appear to conflict with these conclusions. According to the June 2002 edition of ExxonMobil Perspectives:

'There continue to be substantial and well-documented gaps in climate science. These gaps limit scientists' ability to assess the extent of any human influence on climate...'

In November 2003, Andrew Swiger, Chairman and Production Director of ExxonMobil International Ltd, testified before the British House of Lords: 'We say the science is unsettled.'

Whereas:

A worldwide movement towards greater regulation to mitigate climate change has resulted from the IPCC reports. Consistent with its own position, ExxonMobil opposes most such regulation. Yet, it has not released primary research or an analysis of data supporting its conclusions. The lack of such information prevents shareholders, policymakers, and the public from being able to make decisions based on the facts the company claims to have.

Resolved: That, by the 2006 annual shareholder meeting, the Board of Directors make available to shareholders the research data relevant to ExxonMobil's stated position on the science of climate change, omitting proprietary information and at reasonable cost.

Supporting Statement:

These data should:

1.: Explain the specific differences between the company's position and that of the IPCC.
2.: Describe company claims about 'gaps in climate science.'
3.: Project the estimated costs of mitigating climate change compared to the costs of failing to do so.
4.: Discuss relevant peer-reviewed research data leading to the company's conclusions, including data that do not support the company's position."

The Board recommends you vote AGAINST this proposal for the following reasons:

•: ExxonMobil's position on climate change is the result of our direct engagement for many years in the ongoing scientific process, and our cumulative analysis and consideration of the tens of thousands of papers and research results published in this area.
•: ExxonMobil's A Report on Energy Trends, Greenhouse Gas Emissions and Alternative Energy provides a brief synopsis of the complex, inter-related set of issues and disciplines relevant to climate change. This report can be viewed and printed from our website.

The science of climate change is immense, complex, and evolving with new information emerging every month. Research has been well-funded by the U.S. government for many years, with recent budgets in the neighborhood of two billion dollars per year. Relevant research covers natural science, technology, economics, and policy analysis.

ExxonMobil has been an industry leader in climate science since 1980. Our scientists interact with researchers at universities, national laboratories, and other institutions, as well as participate in and help to organize research seminars, symposia, and workshops in which results and ideas are disseminated. Our scientists have authored 66 papers in scientific and technical publications on climate change (with over 41 published in peer-reviewed journals). A list of these papers is available on our website. Our scientists have also been nominated to serve on numerous review boards and assessments, including acting as lead authors with the Intergovernmental Panel on Climate Change (IPCC). We have supported, and in some cases helped to create, cutting-edge, climate-related research at leading institutions, including Carnegie Mellon University, Lamont-Doherty Earth Observatory at Columbia University, MIT, Princeton, Yale, and Stanford.

ExxonMobil's views on climate science are available to the public in A Report on Energy Trends, Greenhouse Gas Emissions and Alternative Energy, scientific journals, and on our website. As explained in this response, these views are not based on any particular set of climate data or papers, from among the thousands of lengthy publications that might be compiled in a report as requested by the proponents. Rather our views are based on long-term, direct participation in, and support for, climate science research.

ExxonMobil recognizes that although scientific evidence remains inconclusive, the potential impacts of controllable greenhouse gas emissions on society and ecosystems may prove to be significant. To address these risks, we have for many years taken actions to improve efficiency and reduce emissions in our operations and in customer use of our products. We are capturing significant efficiency improvements with our Global Energy Management System (GEMS) and the Company is an industry leader in the use of cogeneration, a much more efficient way to make steam and power than by conventional processes.

We are also working with the scientific and business communities to undertake research to create economically competitive and affordable future options to reduce long-term global emissions. For example, we initiated the largest privately funded academic technology initiative in history – the Global Climate and Energy Project (GCEP) led by Stanford University.

ExxonMobil's views on climate science are based on a broad consideration of all available information on climate data and research. The Board believes that it is not practical to produce the report requested by this proposal and such an effort would do little to advance the science or address important climate change issues.

ITEM 10 – KYOTO COMPLIANCE REPORT

This proposal was submitted by the Province of St. Joseph of the Capuchin Order, 1015 North Ninth Street, Milwaukee, WI 53233, as lead proponent of a filing group.

"WHEREAS, international energy companies face unprecedented pressure to reduce greenhouse gas (GHG) emissions. Nations implementing the Kyoto Protocol are committed to significant reductions.

This resolution's proponents believe ExxonMobil is poorly positioned to meet increasing mandates to reduce GHG emissions in a cost-effective way.

The Guardian (10/07/04) reported: 'Exxon... saw its greenhouse gas emissions jump 2% last year to 135.6m tones' and that 'an Exxon spokesman admitted that the company had no targets for reductions in CO₂ emissions although he insisted that it was working hard on 'energy efficiency' gains.' It said ExxonMobil's 'emissions are more than 50% higher than those of rival Britain's BP despite the US firm's oil and gas production being only slightly larger.'

At the World Energy Congress (09/07/04), ExxonMobil's Science Strategy and Programs Manager, Brian Flannery, said the company depends on new technology to address the issue, 'not emissions abatement goals' (Asia Pulse Pte Limited, 09/07/04).

Flannery also noted the bulk of new energy demand 'would come from developing countries which were outside the Kyoto Protocol.' However, presently ExxonMobil is significantly exposed to climate regulations. In 2003 at least 37% of our Company's revenue came from just five nations (Canada, Japan, UK, Germany, Italy) that have signed the Kyoto Protocol.

ExxonMobil's commitment toward 'technological solutions for energy supply and use with much lower greenhouse gas emissions' seems limited to the $10 million a year it's given Stanford University's Global Climate and Energy Project.

Competitors (i.e., Shell, BP, ConocoPhillips, Statoil, Amerada Hess and Suncor) have taken early actions to reduce their exposure to climate related risks, including assuming costs for carbon in their strategic planning, reporting on and reducing their GHG emissions, engaging in emissions trading, and investing in renewable energy. BP's emissions reduction activities have generated savings with an NPV of $650 million.

ExxonMobil's own data show its total spending on research and development from 1997-2003 decreased between 2002-2003; meanwhile two of its three main competitors' expenditures increased (WSJ 07/17/04).

Such conflicting data and statements create confusion about whether and how the company is prepared to cost-effectively meet GHG reduction requirements, exposing it to unnecessary risks. Pressure from pension funds to examine climate change risks raises the possibility that industry segments like our own 'could be viewed as inherently risky because of their exposure to climate-change regulations' (WSJ 10/27/04).

RESOLVED: shareholders request the Board undertake a comprehensive review and publish within six months of the annual meeting a report on how ExxonMobil will meet the greenhouse gas reduction targets of those countries in which it operates which have adopted the Kyoto Protocol.

Supporting Statement

The proponents hope the report will include:

+: Projections of costs.
+: Timelines for meeting mandatory reduction targets.

+: An evaluation of whether earlier action to reduce emissions, as undertaken by key ExxonMobil competitors, would have reduced these costs.
+: A study of the feasibility of reducing emissions in the US, which does not have restrictions on GHG emissions at the federal level but might implement them in the future."

The Board recommends you vote AGAINST this proposal for the following reasons:

•: ExxonMobil is well positioned to meet the challenges and opportunities associated with likely energy trends and greenhouse gas emissions. In February 2004, A Report on Energy Trends, Greenhouse Gas Emissions and Alternative Energy was published and posted on the Company's website. The report, which contains a specific section on the subject of greenhouse gas emissions, describes actions we are taking now to address this important issue.
•: Currently, some governments have made commitments to reduce national greenhouse gas emissions under the provisions of the Kyoto Treaty. In several countries, regulations are in the process of being developed to meet these commitments, and ExxonMobil is fully prepared and competitively positioned to comply with all laws and regulations in countries where we operate.
•: For example, in November 2004, the Dutch Environment Ministry recognized ExxonMobil for our work to develop the first accepted measuring and reporting protocol for a petroleum refinery as required in their national implementation of the European Union's Emissions Trading Directive.

It is our intention to comply in the most cost-effective manner with whatever regulations and mandates that issue from these discussions. Our operations are well positioned versus competitors to comply with these regulations.

ExxonMobil also participates in the independent Carbon Disclosure Project (CDP). Our 2004 report to the CDP discusses in detail the commercial implications (including both obligations and opportunities) for us of proposed climate change policies, regulations, and trading schemes; extensive information on our efforts to measure, report, and reduce greenhouse gas emissions; and our consideration of scenarios beyond existing national, regional, and international targets. ExxonMobil's response to the CDP is available on the CDP website at www.cdproject.net and is also posted on ExxonMobil's website.

The proponent makes reference to our greenhouse gas emissions increasing 2 percent in 2003. This was primarily due to higher power demand in Hong Kong and a return to prior levels of oil production in Nigeria, which had reduced oil output in 2002 to comply with OPEC quotas.

ExxonMobil's Board is monitoring the Company's approach to meeting greenhouse gas emissions. As part of our preparatory work, we and others are working to resolve a number of practical issues related to accomplishing the reduction goals, including measurement of overall greenhouse gases, and reductions achieved. We are engaged in discussions with industry groups and with governments to ensure broader understanding of compliance issues and potential carbon-control measures, including carbon trading.

Since the Company is prepared to comply with all laws and regulations regarding greenhouse gas emissions and is addressing this important issue, the Board believes this proposal has been substantially implemented, and an additional report is not warranted at this time.

ADDITIONAL INFORMATION

Other Business

We are not currently aware of any other business to be acted on at the meeting. Under the laws of New Jersey, where ExxonMobil is incorporated, no business other than procedural matters may be raised at the meeting unless proper notice has been given to the shareholders. If other business is properly raised, your proxies have authority to vote as they think best, including to adjourn the meeting.

People with Disabilities

We can provide reasonable assistance to help you participate in the meeting if you tell us about your disability and your plans to attend. Please call or write the Secretary at least two weeks before the meeting at the telephone number or address listed under "Contact Information" on page 3.

Outstanding Shares

On February 28, 2005, there were 6,389,362,325 shares of common stock outstanding. Each common share has one vote.

How We Solicit Proxies

In addition to this mailing, ExxonMobil officers and employees may solicit proxies personally, electronically, by telephone, or with additional mailings. ExxonMobil pays the costs of soliciting this proxy. We are paying D. F. King & Co. a fee of $27,500 plus expenses to help with the solicitation. We also reimburse brokers and other nominees for their expenses in sending these materials to you and getting your voting instructions.

Shareholder Proposals for Next Year

Any shareholder proposal for the annual meeting in 2006 must be sent to the Secretary at the address of ExxonMobil's principal executive office listed under "Contact Information" on page 3. The deadline for receipt of a proposal to be considered for inclusion in the proxy statement is 5:00 p.m., Central Time, on December 14, 2005. The deadline for notice of a proposal for which a shareholder will conduct his or her own solicitation is February 27, 2006. On request, the Secretary will provide instructions for submitting proposals.

Duplicate Annual Reports

Registered shareholders with multiple accounts may authorize ExxonMobil to discontinue mailing extra summary annual reports by marking the "discontinue annual report mailing for this account" box on the proxy card. If you vote via the internet or by telephone, you will also have the opportunity to indicate that you wish to discontinue receiving extra annual reports. At least one account must continue to receive an annual report. Eliminating these duplicate mailings will not affect receipt of future proxy statements and proxy cards.

Also, you may call ExxonMobil Shareholder Services at the toll-free telephone number listed under "Contact Information" on page 3 at any time during the year to discontinue duplicate mailings.

Shareholders with the Same Address

If you share an address with one or more ExxonMobil shareholders, you may elect to "household" your proxy mailing. This means you will receive only one annual report and proxy statement to that address unless one or more shareholders at that address specifically elect to receive separate mailings. Shareholders who participate in householding will continue to receive separate proxy cards. Also, householding will not affect dividend check mailings. We will promptly send a separate annual report and proxy statement to a shareholder at a shared address on request. Shareholders with a shared address may also request us to send separate annual reports and proxy statements in the future, or to send a single copy in the future if we are currently sending multiple copies to the same address.

Requests related to householding should be made by calling ExxonMobil Shareholder Services at the telephone number listed under "Contact Information" on page 3. Beneficial shareholders can request information about householding from their banks, brokers, or other holders of record.

Electronic Delivery of Proxy Statement and Annual Report

The Proxy Statement and the 2004 Summary Annual Report (the proxy materials) are available on our website at www.exxonmobil.com. Instead of receiving future copies of these documents by mail, shareholders can elect to receive an email that will provide electronic links to them. Opting to receive your proxy materials online will save the Company the cost of producing and mailing documents to your home or business, and also will give you an electronic link to the proxy voting site.

•: Shareholders of Record: If you vote on the internet at www.eproxyvote.com/xom, simply follow the prompts for enrolling in the electronic proxy delivery service. You also may enroll in the electronic proxy delivery service at any time in the future by going directly to www.exxonmobil.equiserve.com. You may also revoke an electronic delivery election at this site at any time.
•: Beneficial Shareholders: If you hold your shares in a brokerage account, you also may have the opportunity to receive copies of the proxy materials electronically. Please check the information provided in the proxy materials mailed to you by your bank or broker regarding the availability of this service.

Financial Statements

The year 2004 consolidated financial statements and auditor's report; management's discussion and analysis of financial condition and results of operations; information concerning the quarterly financial data for the past two fiscal years; and other information are provided in Appendix A.

SEC Form 10-K

Shareholders may obtain a copy of the Company's Annual Report to the Securities and Exchange Commission on Form 10-K without charge by writing to the Secretary at the address listed under "Contact Information" on page 3 or by visiting ExxonMobil's website at www.exxonmobil.com.

APPENDIX A
FINANCIAL SECTION

TABLE OF CONTENTS

Business Profile		A2
Financial Summary		A3
Frequently Used Terms		A4
Management's Discussion and Analysis of Financial Condition and Results of Operations
	Functional Earnings	A6
	Forward-Looking Statements	A7
	Overview	A7
	Business Environment and Outlook	A7
	Review of 2004 and 2003 Results	A8
	Liquidity and Capital Resources	A10
	Capital and Exploration Expenditures	A14
	Taxes	A14
	Merger Expenses and Reorganization Reserves	A14
	Asset Retirement Obligations and Environmental Costs	A15
	Market Risks, Inflation and Other Uncertainties	A15
	Recently Issued Statements of Financial Accounting Standards	A16
	Emerging Accounting and Reporting Issues	A17
	Critical Accounting Policies	A17
Management's Report on Internal Control Over Financial Reporting		A24
Report of Independent Registered Public Accounting Firm		A24
Consolidated Financial Statements
	Statement of Income	A26
	Balance Sheet	A27
	Statement of Shareholders' Equity	A28
	Statement of Cash Flows	A29
Notes to Consolidated Financial Statements
	1. Summary of Accounting Policies	A30
	2. Discontinued Operations	A32
	3. Merger Expenses and Reorganization Reserves	A33
	4. Miscellaneous Financial Information	A33
	5. Cash Flow Information	A33
	6. Additional Working Capital Information	A33
	7. Equity Company Information	A34
	8. Investments and Advances	A35
	9. Property, Plant and Equipment and Asset Retirement Obligations	A35
	10. Leased Facilities	A37
	11. Employee Stock Ownership Plans	A37
	12. Capital	A38
	13. Financial Instruments and Derivatives	A39
	14. Long-Term Debt	A39
	15. Incentive Program	A44
	16. Litigation and Other Contingencies	A46
	17. Annuity Benefits and Other Postretirement Benefits	A48
	18. Disclosures about Segments and Related Information	A51
	19. Income, Excise and Other Taxes	A53
Supplemental Information on Oil and Gas Exploration and Production Activities		A54
Quarterly Information		A64
Operating Summary		A65

BUSINESS PROFILE

			Earnings After Income Taxes					Average Capital Employed				Return on Average Capital Employed		Capital and Exploration Expenditures
Financial			Earnings After Income Taxes					Average Capital Employed				Return on Average Capital Employed		Capital and Exploration Expenditures
Financial			2004			2003		2004		2003		2004	2003	2004		2003
			(millions of dollars)									(percent)		(millions of dollars)
Upstream
	United States		$	4,948		$	3,905	$	13,355	$	13,508	37.0	28.9	$	1,922	$	2,125
	Non-U.S.			11,727			10,597		37,287		34,164	31.5	31.0		9,793		9,863

		Total	$	16,675		$	14,502	$	50,642	$	47,672	32.9	30.4	$	11,715	$	11,988

Downstream
	United States		$	2,186		$	1,348	$	7,632	$	8,090	28.6	16.7	$	775	$	1,244
	Non-U.S.			3,520			2,168		19,541		18,875	18.0	11.5		1,630		1,537

		Total	$	5,706		$	3,516	$	27,173	$	26,965	21.0	13.0	$	2,405	$	2,781

Chemical
	United States		$	1,020		$	381	$	5,246	$	5,194	19.4	7.3	$	262	$	333
	Non-U.S.			2,408			1,051		9,362		8,905	25.7	11.8		428		359

		Total	$	3,428		$	1,432	$	14,608	$	14,099	23.5	10.2	$	690	$	692

Corporate and financing				(479	)		1,510		14,916		6,637	—	—		75		64
Accounting change				—			550		—		—	—	—		—		—

	Total		$	25,330		$	21,510	$	107,339	$	95,373	23.8	20.9	$	14,885	$	15,525

See Frequently Used Terms on pages A4 and A5 for a definition and calculation of capital employed and return on average capital employed.

Operating			2004	2003		2004	2003
			(thousands of barrels daily)			(thousands of barrels daily)
Net liquids production					Petroleum product sales
	United States		557	610	United States	2,872	2,729
	Non-U.S.		2,014	1,906	Non-U.S.	5,338	5,228

		Total	2,571	2,516	Total	8,210	7,957
			(millions of cubic feet daily)			(thousands of barrels daily)
Natural gas production available for sale					Refinery throughput
	United States		1,947	2,246	United States	1,850	1,806
	Non-U.S.		7,917	7,873	Non-U.S.	3,863	3,704

		Total	9,864	10,119	Total	5,713	5,510
			(thousands of oil-equivalent barrels daily)			(thousands of metric tons)
Oil-equivalent production (1)			4,215	4,203	Chemical prime product sales
					United States	11,521	10,740
					Non-U.S.	16,267	15,827

					Total	27,788	26,567

(1): Gas converted to oil-equivalent at 6 million cubic feet = 1 thousand barrels.

FINANCIAL SUMMARY

		2004			2003			2002			2001			2000
		(millions of dollars, except per share amounts)
Sales and other operating revenue (1)
	Upstream	$	23,033		$	21,330		$	16,484		$	18,567		$	21,509
	Downstream		240,413			195,511			168,032			174,185			188,563
	Chemical		27,781			20,190			16,408			15,943			17,501
	Other		25			23			25			20			23

	Total	$	291,252		$	237,054		$	200,949		$	208,715		$	227,596

Earnings
	Upstream	$	16,675		$	14,502		$	9,598		$	10,736		$	12,685
	Downstream		5,706			3,516			1,300			4,227			3,418
	Chemical		3,428			1,432			830			707			1,161
	Corporate and financing		(479	)		1,510			(442	)		(142	)		(538	)
	Merger-related expenses		—			—			(275	)		(525	)		(920	)

Income from continuing operations		$	25,330		$	20,960		$	11,011		$	15,003		$	15,806
	Discontinued operations		—			—			449			102			184
	Extraordinary gain		—			—			—			215			1,730
	Accounting change		—			550			—			—			—

	Net income	$	25,330		$	21,510		$	11,460		$	15,320		$	17,720

Net income per common share		$	3.91		$	3.24		$	1.69		$	2.23		$	2.55
Net income per common share—assuming dilution		$	3.89		$	3.23		$	1.68		$	2.21		$	2.52
Cash dividends per common share		$	1.06		$	0.98		$	0.92		$	0.91		$	0.88
Net income to average shareholders' equity (percent)			26.4			26.2			15.5			21.3			26.4
Working capital		$	17,396		$	7,574		$	5,116		$	5,567		$	2,208
Ratio of current assets to current liabilities			1.40			1.20			1.15			1.18			1.06
Additions to property, plant and equipment		$	11,986		$	12,859		$	11,437		$	9,989		$	8,446
Property, plant and equipment, less allowances		$	108,639		$	104,965		$	94,940		$	89,602		$	89,829
Total assets		$	195,256		$	174,278		$	152,644		$	143,174		$	149,000
Exploration expenses, including dry holes		$	1,098		$	1,010		$	920		$	1,175		$	936
Research and development costs		$	649		$	618		$	631		$	603		$	564
Long-term debt		$	5,013		$	4,756		$	6,655		$	7,099		$	7,280
Total debt		$	8,293		$	9,545		$	10,748		$	10,802		$	13,441
Fixed-charge coverage ratio (times)			36.1			30.8			13.8			17.7			15.6
Debt to capital (percent)			7.3			9.3			12.2			12.4			15.4
Net debt to capital (percent) (2)			(10.7	)		(1.2	)		4.4			5.3			7.9
Shareholders' equity at year end		$	101,756		$	89,915		$	74,597		$	73,161		$	70,757
Shareholders' equity per common share		$	15.90		$	13.69		$	11.13		$	10.74		$	10.21
Weighted average number of common shares outstanding (millions)			6,482			6,634			6,753			6,868			6,953
Number of regular employees at year end (thousands) (3)			85.9			88.3			92.5			97.9			99.6
CORS employees not included above (thousands) (4)			19.3			17.4			16.8			19.9			18.7

(1): Sales and other operating revenue includes excise taxes of $27,263 million for 2004, $23,855 million for 2003, $22,040 million for 2002, $21,907 million for 2001 and $22,356 million for 2000.
(2): Debt net of cash, excluding restricted cash. The ratio of net debt to capital including restricted cash is (16.3) percent for 2004.
(3): Regular employees are defined as active executive, management, professional, technical and wage employees who work full time or part time for the Corporation and are covered by the Corporation's benefit plans and programs.
(4): CORS employees are employees of company-operated retail sites.

FREQUENTLY USED TERMS

Listed below are definitions of several of ExxonMobil's key business financial performance measures. These definitions are provided to facilitate understanding of the terms and their calculation.

CASH FLOW FROM OPERATIONS AND ASSET SALES

Cash flow from operations and asset sales is the sum of the net cash provided by operating activities and proceeds from sales of subsidiaries, investments and property, plant and equipment from the Consolidated Statement of Cash Flows. This cash flow is the total sources of cash from both operating the Corporation's assets and from the divesting of assets. The Corporation employs a long-standing disciplined regular review process to ensure that all assets are contributing to the Corporation's strategic and financial objectives. Assets are divested when they are no longer meeting these objectives or are worth considerably more to others. Because of the regular nature of this activity, we believe it is useful for investors to consider sales proceeds together with cash provided by operating activities when evaluating cash available for investment in the business and financing activities, including shareholder distributions.

Cash flow from operations and asset sales		2004		2003		2002
		(millions of dollars)
Net cash provided by operating activities		$	40,551	$	28,498	$	21,268
Sales of subsidiaries, investments and property, plant and equipment			2,754		2,290		2,793

	Cash flow from operations and asset sales	$	43,305	$	30,788	$	24,061

CAPITAL EMPLOYED

Capital employed is a measure of net investment. When viewed from the perspective of how the capital is used by the businesses, it includes ExxonMobil's net share of property, plant and equipment and other assets less liabilities, excluding both short-term and long-term debt. When viewed from the perspective of the sources of capital employed in total for the Corporation, it includes ExxonMobil's share of total debt and shareholders' equity. Both of these views include ExxonMobil's share of amounts applicable to equity companies, which the Corporation believes should be included to provide a more comprehensive measure of capital employed.

Capital employed		2004			2003			2002
		(millions of dollars)
Business uses: asset and liability perspective
Total assets		$	195,256		$	174,278		$	152,644
Less liabilities and minority share of assets and liabilities
	Total current liabilities excluding notes and loans payable		(39,701	)		(33,597	)		(29,082	)
	Total long-term liabilities excluding long-term debt and equity of minority and preferred shareholders in affiliated companies		(41,554	)		(37,839	)		(35,449	)
	Minority share of assets and liabilities		(5,285	)		(4,945	)		(4,210	)
Add ExxonMobil share of debt-financed equity company net assets			3,914			4,151			4,795

	Total capital employed	$	112,630		$	102,048		$	88,698

Total corporate sources: debt and equity perspective
Notes and loans payable		$	3,280		$	4,789		$	4,093
Long-term debt			5,013			4,756			6,655
Shareholders' equity			101,756			89,915			74,597
Less minority share of total debt			(1,333	)		(1,563	)		(1,442	)
Add ExxonMobil share of equity company debt			3,914			4,151			4,795

	Total capital employed	$	112,630		$	102,048		$	88,698

RETURN ON AVERAGE CAPITAL EMPLOYED

Return on average capital employed (ROCE) is a performance measure ratio. From the perspective of the business segments, ROCE is annual business segment earnings divided by average business segment capital employed (average of beginning and end-of-year amounts). These segment earnings include ExxonMobil's share of segment earnings of equity companies, consistent with our capital employed definition, and exclude the cost of financing. The Corporation's total ROCE is net income excluding the after-tax cost of financing, divided by total corporate average capital employed. The Corporation has consistently applied its ROCE definition for many years and views it as the best measure of historical capital productivity in our capital-intensive, long-term industry, both to evaluate management's performance and to demonstrate to shareholders that capital has been used wisely over the long term. Additional measures, which tend to be more cash flow based, are used for future investment decisions.

Return on average capital employed			2004			2003			2002
			(millions of dollars)
Net income			$	25,330		$	21,510		$	11,460
Financing costs (after tax)
	Third-party debt			(137	)		(69	)		(81	)
	ExxonMobil share of equity companies			(185	)		(172	)		(227	)
	All other financing costs—net (1)			54			1,775			(127	)

		Total financing costs		(268	)		1,534			(435	)

Earnings excluding financing costs			$	25,598		$	19,976		$	11,895

Average capital employed			$	107,339		$	95,373		$	88,342
Return on average capital employed—corporate total				23.8	%		20.9	%		13.5	%

(1): "All other financing costs—net" in 2003 includes interest income (after tax) associated with the settlement of a U.S. tax dispute.

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

FUNCTIONAL EARNINGS			2004			2003		2002
			(millions of dollars, except per share amounts)
Net income (U.S. GAAP)
Upstream
	United States		$	4,948		$	3,905	$	2,524
	Non-U.S.			11,727			10,597		7,074
Downstream
	United States			2,186			1,348		693
	Non-U.S.			3,520			2,168		607
Chemical
	United States			1,020			381		384
	Non-U.S.			2,408			1,051		446
Corporate and financing				(479	)		1,510		(442	)
Merger-related expenses				—			—		(275	)

Income from continuing operations			$	25,330		$	20,960	$	11,011
Discontinued operations				—			—		449
Accounting change				—			550		—

		Net income	$	25,330		$	21,510	$	11,460

Net income per common share			$	3.91		$	3.24	$	1.69
Net income per common share—assuming dilution			$	3.89		$	3.23	$	1.68
Special items included in net income
Non-U.S. Upstream
	Gain on transfer of Ruhrgas shares		$	—		$	1,700	$	—
	U.K. deferred income tax adjustment		$	—		$	—	$	(215	)
U.S. Downstream
	Allapattah lawsuit provision		$	(550	)	$	—	$	—
Corporate and financing
	U.S. tax settlement		$	—		$	2,230	$	—

FORWARD-LOOKING STATEMENTS

Statements in this discussion regarding expectations, plans and future events or conditions are forward-looking statements. Actual future results, including production growth; financing sources; the resolution of contingencies; the effect of changes in prices; interest rates and other market conditions; and environmental and capital expenditures could differ materially depending on a number of factors, such as the outcome of commercial negotiations; changes in the supply of and demand for crude oil, natural gas, and petroleum and petrochemical products; and other factors discussed herein and under the caption "Factors Affecting Future Results" in Item 1 of ExxonMobil's 2004 Form 10-K.

OVERVIEW

The following discussion and analysis of ExxonMobil's financial results, as well as the accompanying financial statements and related notes to consolidated financial statements to which they refer, are the responsibility of the management of Exxon Mobil Corporation. The Corporation's accounting and financial reporting fairly reflect its straightforward business model involving the extracting, refining and marketing of hydrocarbons and hydrocarbon-based products. The Corporation's business model involves the production (or purchase), manufacture and sale of physical products, and all commercial activities are directly in support of the underlying physical movement of goods.

This straightforward approach extends to the financing of the business. In evaluating business or investment opportunities, the Corporation views as economically equivalent any debt obligation, whether included on the face of the consolidated balance sheet, or disclosed as other debt-like obligations in notes to the financial statements, such as ExxonMobil's share of equity company debt and noncancelable, long-term operating leases. This consistent, conservative approach to financing the capital-intensive needs of the Corporation has helped ExxonMobil to sustain the "triple-A" status of its long-term debt securities for 86 years.

ExxonMobil, with its resource base, financial strength, disciplined investment approach and technology portfolio, is well positioned to participate in substantial investments to develop new energy supplies. While commodity prices remain volatile on a short-term basis depending on supply and demand, ExxonMobil's investment decisions are based on our long-term outlook, using a disciplined approach in selecting and pursuing the most attractive investment opportunities. The corporate plan is a fundamental annual management process that is the basis for setting near-term operating and capital objectives in addition to providing the longer-term economic assumptions used for investment evaluation purposes. Annual volumes are based on individual field production profiles, which are also updated annually. Prices for natural gas and other products are based on corporate plan assumptions developed annually by major region and used for investment evaluation purposes. Potential investment opportunities are tested over a wide range of economic scenarios to establish the resiliency of each opportunity. Once investments are made, a reappraisal process is completed to ensure relevant lessons are learned and improvements are incorporated into future projects. ExxonMobil views return on capital employed as the best measure of historical capital productivity.

BUSINESS ENVIRONMENT AND OUTLOOK

Upstream

The Corporation expects worldwide economic growth to average just under 3 percent per year through 2030. This growth, and rising personal incomes notably in developing nations, should increase global energy demand by 1.7 percent per year, reaching 50 percent more than today by 2030. Oil, natural gas and coal are expected to remain the predominant fuels through the middle of the century. The share of oil and gas in the world's energy supply, close to 60 percent today, should remain relatively stable, and total fossil fuels, including coal, will account for about 80 percent of the energy mix. In the very long term, the energy mix will likely become more diversified. However, for the foreseeable future, fossil fuels are the only energy forms with the scale and versatility to meet the challenge of growing world energy demand.

Oil demand should grow at 1.5 percent per year, with increasing use of oil in the transportation sector. However, natural gas is expected to be the fastest-growing primary energy source, capturing about 30 percent of the growth in total energy demand, and reaching one quarter of the total energy supply. About half of the growth in gas demand will likely be to meet worldwide electricity demand that is expected to double by 2030. The Corporation expects the liquefied natural gas (LNG) market to quadruple, helping to meet rising import dependency in Europe, North America and Asia. With equity positions in many of the largest remote gas accumulations in the world, the Corporation is positioned to benefit from its technology advances in gas liquefaction, transportation and regasification that enable distant gas supplies to reach markets economically.

On average, the world's oil and gas fields are declining in production at between 4 percent and 6 percent per year. While large resources exist, technology advances remain critical to increasing future oil and gas supplies. Emerging technologies promise to further advance our capability to extend recoverable resources worldwide. The cost to develop these resources is also very large. According to the International Energy Agency, the investment required to meet total oil and gas energy needs worldwide through 2030 will be about $200 billion per year.

ExxonMobil maintains the largest portfolio of exploration and development opportunities among the international oil companies, which enables the selectivity required to optimize total profitability and mitigate overall political and technical risks. As future development projects bring new resources on line, the Corporation expects a shift in the geographic mix of production volumes between now and 2010. For example, oil and natural gas output from West Africa, the Caspian, the Middle East and Russia will more than double during the next six years based on current capital project execution plans. Currently, these growth areas account for less than 20 percent of the Corporation's production. By the end of the decade, they are expected to generate about 40 percent of total volumes. Production from established areas, including Europe and North America, will decline as a percentage of the Corporation's total production but still is expected to represent over half of 2010 volumes.

In addition to a changing geographic mix, there will also be a change in the type of opportunities from which volumes are produced. Production using arctic technology, deepwater drilling and production systems, heavy oil recovery processes and LNG is expected to grow from 20 percent to 40 percent of the Corporation's output between now and 2010. The Corporation's overall volume capacity outlook, based on projects coming on stream as anticipated, is for production capacity

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

increases to average 3 percent annually through 2010. However, actual volume increases will vary from year to year due to timing of individual project start-ups, operational outages, reservoir performance, regulatory changes, price effects on production sharing contracts and other factors described under the caption "Factors Affecting Future Results" in Item 1 of ExxonMobil's 2004 Form l0-K.

Restructuring of our European gas marketing operations has progressed in anticipation of the impact of the European Gas Directives. Part of this effort includes a Heads of Agreement (HOA) whereby Esso Nederland B.V. and Shell Nederland B.V. will agree to transfer their ownership share of 25 percent each in Gasunie's gas transportation business to the State of the Netherlands. As specified in the HOA, the State of the Netherlands will pay a total net compensation in the amount of 2.78 billion Euros to the Dutch company Nederlandse Aardolie Maatschappij B.V., jointly owned by ExxonMobil and Shell. The parties intend to finalize the restructuring by mid-2005, and it is anticipated that, at that time, this step will have a positive impact on the Corporation's results. The restructuring will position ExxonMobil to compete effectively in the future European gas market and enable us to directly sell more of our equity production.

Downstream

The downstream industry environment remains very competitive. Long-term real refining margins have historically declined at a rate of about 2 percent per year and the intense competition in the retail fuels market has driven long-term real margins down by 4 percent per year. The outlook is for modest industry growth in mature markets with increasing requirements for regulatory investments.

Refining margins are a function of the difference between what a refinery pays for its raw materials (primarily crude oil) and the market prices for the range of products produced (primarily gasoline, heating oil, jet fuel and fuel oil). Crude oil and many products are widely traded with published prices, including those quoted on multiple exchanges around the world (e.g., New York Mercantile Exchange and International Petroleum Exchange). Prices for these commodities (crude and various products) are determined by the global marketplace and are impacted by many industry factors, including global and regional supply/demand balances, inventory levels, refinery operations, import/export balances, seasonality and weather. These prices and factors are continuously monitored and serve as input to decisions about which raw materials to buy, facilities to operate and products to make. However, there are no reliable indicators of future market factors that accurately predict changes in margins from period to period.

The objectives of ExxonMobil's Downstream strategies are to position the Corporation to be the industry leader and outperform competition under a variety of market conditions. These strategies include maintaining best-in-class operations in all respects, maximizing value from leading-edge technology, capitalizing on integration with other ExxonMobil businesses and providing quality, valued products and services to the Corporation's customers. ExxonMobil has an ownership interest in 45 refineries, located in 25 countries, with distillation capacity of 6.4 million barrels per day and lubricant basestock manufacturing capacity of about 145 thousand barrels per day. ExxonMobil's fuels marketing business portfolio includes operations in over 100 countries on six continents, serving a globally diverse customer base. World-class scale and integration, industry-leading efficiency, leading-edge technology and globally respected brands enable ExxonMobil to take advantage of attractive emerging-growth opportunities around the globe. For example, our assets are well-positioned and configured to supply demand growth in Asia Pacific, which we estimate will be 3 percent annually through 2020.

Chemical

The strength of the global economy supported strong demand growth for petrochemical products in 2004. Demand growth in Asia benefited from continued economic and industrial production growth, and the North American market recovered from weak conditions in 2003. Growth in Europe was moderate, consistent with the less favorable economic environment. As a result of strong demand growth and limited new capacity additions, regional and global supply demand balances tightened, supporting higher prices and margins despite increased feedstock costs. ExxonMobil's portfolio includes many of the largest-volume and highest-growth petrochemicals in the global economy. In addition to being a worldwide supplier of primary petrochemical products, the Corporation also has a diverse portfolio of less cyclical business lines. The Corporation's competitive advantages are achieved through its business mix, investment discipline, integration of chemical capacity with large refining complexes or upstream gas processing, operational excellence, including leading proprietary technology, and product application expertise.

REVIEW OF 2004 AND 2003 RESULTS

		2004		2003		2002
		(millions of dollars)
Income from continuing operations		$	25,330	$	20,960	$	11,011
	Discontinued operations		—		—		449
	Accounting change		—		550		—

Net income (U.S. GAAP)		$	25,330	$	21,510	$	11,460

2004

Net income in 2004 of $25,330 million was the highest ever for the Corporation, up $3,820 million from 2003. Net income in 2004 included a one-time special charge of $550 million relating to the Allapattah lawsuit provision. Interest expense in 2004 increased to $638 million compared to $207 million in 2003, reflecting the interest component of the Allapattah lawsuit provision.

Total assets at December 31, 2004, of $195 billion increased by approximately $21 billion from 2003, reflecting strong earnings and the Corporation's active investment program, particularly in the Upstream.

2003

Net income in 2003 was $21,510 million, an increase of $10,050 million from 2002. Excluding a $550 million positive impact for the required adoption of Statement of Financial Accounting Standards No. 143 (FAS 143) relating to accounting for asset retirement obligations, income from continuing operations was $20,960 million. 2003 net income also included one-time special items of $2,230 million relating to the positive settlement of a long-running U.S. tax dispute and $1,700 million from a gain on the transfer of shares in Ruhrgas AG, a German gas transmission company. Interest expense in 2003 was $207 million compared to $398 million in 2002, reflecting lower debt levels and nondebt-related items.

Total assets at December 31, 2003, of $174 billion increased by approximately $22 billion from 2002, reflecting the Corporation's active investment program and the effect of the weaker U.S. dollar.

Upstream

			2004		2003		2002
			(millions of dollars)
Upstream
	United States		$	4,948	$	3,905	$	2,524
	Non-U.S.			11,727		10,597		7,074

		Total	$	16,675	$	14,502	$	9,598

2004

Upstream earnings of $16,675 million increased $2,173 million due to higher liquids and natural gas realizations. Upstream earnings for 2003 included a $1,700 million special item from a gain on the transfer of shares in Ruhrgas AG. Absent this, Upstream earnings increased $3,873 million in 2004. Oil-equivalent production was up 3 percent versus 2003 excluding price-related entitlement effects and divestment impacts. Including these impacts, total oil-equivalent production was flat with 2003. Liquids production of 2,571 Kbd (thousands of barrels daily) increased 55 Kbd from 2003. Production increases in West Africa and Norway were partly offset by natural field decline in mature areas, entitlement effects and divestment impacts. Natural gas production of 9,864 mcfd (millions of cubic feet daily) in 2004 compared with 10,119 mcfd in 2003. The start-up of an additional LNG train in Qatar and contributions from projects and work programs were more than offset by natural field decline, divestment impacts and entitlement effects. Earnings from U.S. Upstream operations for 2004 of $4,948 million were $1,043 million higher than 2003 due to higher realizations partly offset by lower production volumes. Earnings outside the U.S. for 2004 of $11,727 million were $1,130 million higher than 2003 due to improved realizations and higher production volumes. Earnings outside the U.S. for 2003 included a $1,700 million special item from a gain on the transfer of shares in Ruhrgas AG.

2003

Upstream earnings totaled $14,502 million, including $1,700 million from a gain on the transfer of shares in Ruhrgas AG. Absent this, Upstream earnings increased by $3,204 million from 2002 due to higher liquids and natural gas realizations. Total oil-equivalent production was down 1 percent. Liquids production of 2,516 Kbd increased 20 Kbd from 2002. Production increases from new projects in West Africa, Norway and Canada, and lower OPEC-driven quota constraints, were partly offset by natural field decline, operational problems in the North Sea and West Africa and the impact of the national strike in Venezuela. Natural gas production of 10,119 mcfd in 2003 compared with 10,452 mcfd in 2002. Higher demand in the first half of the year in Europe and contributions from new projects and work programs were more than offset by natural field decline, reduced entitlements and operational outages in the North Sea. Improved earnings from both U.S. and non-U.S. Upstream operations were driven by higher liquids and natural gas realizations. Earnings from U.S. Upstream operations for 2003 were $3,905 million, an increase of $1,381 million. Earnings outside the U.S. for 2003, including $1,700 million from a gain on the transfer of shares in Ruhrgas AG, were $10,597 million. Earnings outside the U.S. for 2002, including a special charge of $215 million relating to a United Kingdom tax rate change, were $7,074 million.

Downstream

			2004		2003		2002
			(millions of dollars)
Downstream
	United States		$	2,186	$	1,348	$	693
	Non-U.S.			3,520		2,168		607

		Total	$	5,706	$	3,516	$	1,300

2004

Downstream earnings totaled $5,706 million, including a special charge of $550 million relating to the Allapattah lawsuit provision. Absent this, Downstream earnings increased $2,740 million due to stronger worldwide refining margins and higher refinery throughput partly offset by weaker marketing margins. Earnings also benefited from a planned reduction in inventories as a result of optimizing operations around the world. Petroleum product sales of 8,210 Kbd were 253 Kbd higher than 2003, largely related to increased refinery runs due to strong margins and more efficient operations. Refinery throughput was 5,713 Kbd compared with 5,510 Kbd in 2003. U.S. Downstream earnings of $2,186 million, including the one-time special charge relating to the Allapattah lawsuit provision, increased by $838 million. Non-U.S. Downstream earnings of $3,520 million were $1,352 million higher than 2003.

2003

Downstream earnings of $3,516 million increased by $2,216 million from 2002, reflecting higher worldwide refining and marketing margins. Earnings also benefited from a planned reduction in inventories as a result of optimizing operations around the world. Petroleum product sales of 7,957 Kbd were 200 Kbd higher than 2002, largely related to increased refinery runs due to strong margins and higher demand for distillates. Refinery throughput was 5,510 Kbd compared with 5,443 Kbd in 2002. U.S. Downstream earnings of $1,348 million increased by $655 million, reflecting higher refining and marketing margins partly offset by increased refinery turnaround activity in the year. Non-U.S. Downstream earnings of $2,168 million were $1,561 million higher than 2002 due to higher refining and marketing margins, increased refinery runs and positive inventory impacts.

Chemical

			2004		2003		2002
			(millions of dollars)
Chemical
	United States		$	1,020	$	381	$	384
	Non-U.S.			2,408		1,051		446

		Total	$	3,428	$	1,432	$	830

2004

Chemical earnings of $3,428 million were up $1,996 million from 2003. Earnings benefited from improved worldwide margins, higher volumes and favorable foreign exchange effects. Prime product sales were a record 27,788 kt (thousands of metric tons), an increase of 1,221 kt from 2003, reflecting improved worldwide demand. Prime product sales are total chemical product sales including ExxonMobil's share of equity company volumes and finished-product transfers to

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

the Downstream business. Carbon black oil and sulfur volumes are excluded. U.S. Chemical earnings of $1,020 million were $639 million higher than 2003 with higher margins and increased volumes on improved demand. Non-U.S. Chemical earnings of $2,408 million were $1,357 million higher than 2003 due to higher margins, strong demand in Asia and favorable foreign exchange effects.

2003

Chemical earnings of $1,432 million were up $602 million from 2002. Earnings benefited from improved worldwide margins and favorable foreign exchange effects. Prime product sales of 26,567 kt were in line with sales of 26,606 kt in 2002. U.S. Chemical earnings of $381 million were $3 million lower than 2002 with higher margins offset by lower volumes on weaker demand. Non-U.S. Chemical earnings of $1,051 million were $605 million higher than 2002 due to higher margins, strong demand in Asia and favorable foreign exchange effects.

All Other Segments

			2004			2003		2002
			(millions of dollars)
All other segments
	Corporate and financing		$	(479	)	$	1,510	$	(442	)
	Merger-related expenses			—			—		(275	)
	Discontinued operations			—			—		449
	Accounting change			—			550		—

		Total	$	(479	)	$	2,060	$	(268	)

2004

Corporate and financing expenses in 2004 were $479 million. The corporate and financing segment contributed $1,510 million to earnings in 2003, including a special item of $2,230 million relating to the settlement of a long-running U.S. tax dispute. Excluding this special item, corporate and financing expenses were down $241 million mainly due to lower U.S. pension expense.

2003

All other segments totaled a gain of $2,060 million in 2003 compared to a loss of $268 million in 2002.

Corporate and financing in 2003, including $2,230 million relating to the settlement of a long-running U.S. tax dispute, contributed $1,510 million to earnings. Excluding this settlement, corporate and financing expenses increased by $278 million mainly due to higher U.S. pension expense.

Net income in 2003 included a $550 million positive impact for the required adoption of FAS 143 relating to accounting for asset retirement obligations.

Merger-related activities were completed in 2002 and net income included $275 million of merger-related expenses. Net income in 2002 also included discontinued operations earnings of $449 million, including a gain associated with the sale of the Chilean copper business.

LIQUIDITY AND CAPITAL RESOURCES

Sources and Uses of Cash

		2004			2003
		(millions of dollars)
Net cash provided by/(used in)
	Operating activities	$	40,551		$	28,498
	Investing activities		(14,910	)		(10,842	)
	Financing activities		(18,268	)		(14,763	)
Effect of exchange rate changes			532			504

Increase/(decrease) in cash and cash equivalents		$	7,905		$	3,397

			(Dec. 31)
Cash and cash equivalents		$	18,531		$	10,626
Cash and cash equivalents—restricted			4,604			—

	Total cash and cash equivalents	$	23,135		$	10,626

Cash and cash equivalents were $18,531 million at the end of 2004, an increase of $7,905 million, including $532 million of foreign exchange rate effects from the generally weaker U.S. dollar. Including restricted cash and cash equivalents of $4,604 million (see note 4 on page A33 and note 16 on page A46), total cash and cash equivalents of $23,135 million at the end of 2004 increased $12,509 million during the year. Cash and cash equivalents were $10,626 million at the end of 2003, an increase of $3,397 million, including $504 million of foreign exchange rate effects. Cash flows from operating, investing and financing activities are discussed below. For additional details, see the Consolidated Statement of Cash Flows on page A29.

Although the Corporation issues long-term debt from time to time and maintains a revolving commercial paper program, internally generated funds cover the majority of its financial requirements. The management of cash that may be temporarily available as surplus to the Corporation's immediate needs is carefully controlled, both to optimize returns on cash balances, and to ensure that it is secure and readily available to meet the Corporation's cash requirements as they arise.

Production from existing oil and gas fields has declined about 6 percent on average over the past two years and is expected to continue to decline in the future at approximately the same rate. The impact on cash flows from production is highly dependent on crude oil and natural gas prices. Decline rates vary widely by individual field and the overall decline rate for a geographical area will be heavily influenced by the type of reservoir and age of the fields in that region.

The Corporation will need to continually find and develop new fields, and continue to develop and apply new technologies and recovery processes to existing fields, in order to maintain or increase production and resulting cash flows in future periods. The Corporation has been successful in offsetting the effects of field decline through these measures and anticipates similar results in the future. Projects are in place or under way to increase production capacity. However, these volume increases are subject to a variety of risks including project execution, operational outages, reservoir performance, price effects on production sharing contracts and regulatory changes.

A10

The Corporation's financial strength, as evidenced by its AAA/Aaa debt rating, enables it to make large, long-term capital expenditures. ExxonMobil currently expects to spend approximately $12 billion annually through the end of the decade on Upstream capital and exploration expenditures. The Corporation has a large and diverse portfolio of development projects and exploration opportunities, which helps mitigate the overall political and technical risks of the Corporation's Upstream segment and associated cash flow. Further, due to its financial strength, debt capacity and diverse portfolio of opportunities, the risk associated with failure or delay of any single project would not have a significant impact on the Corporation's liquidity or ability to generate sufficient cash flows for operations and its fixed commitments. The purchase and sale of oil and gas properties have not had a significant impact on the amount or timing of operating cash flows.

Cash Flow from Operating Activities

2004

Cash provided by operating activities totaled $40.6 billion in 2004, a $12.1 billion increase from 2003. Major sources of funds were net income of $25.3 billion, which increased $3.8 billion, and noncash provisions of $9.8 billion for depreciation and depletion. Contributing to the increased level of cash provided by operating activities in 2004 was $2.4 billion of lower company contributions to pension plans and $3.0 billion of cash received related to the U.S. tax settlement recognized in earnings in 2003.

2003

Cash provided by operating activities totaled $28.5 billion in 2003, a $7.2 billion increase from 2002 influenced by higher net income. Major sources of funds were net income of $21.5 billion and noncash provisions of $9.0 billion for depreciation and depletion.

In 2003, ExxonMobil completed a divestment of interests in shares of Ruhrgas AG, a German gas transmission company. These shares were held in part by BEB Erdgas und Erdoel GmbH (BEB), an investment accounted for by the equity method, and in part by a consolidated affiliate in Germany. In 2002, cash in the amount of $1,466 million was received from BEB, an equity company, and included in cash flows from operating activities (see Ruhrgas transaction line on Consolidated Statement of Cash Flows, page A29). This cash from BEB was a loan and was part of a restructuring that enabled BEB to transfer its holdings in Ruhrgas AG provided regulatory approval was received. No income was recorded in 2002.

In 2003, upon receipt of regulatory approvals, the Ruhrgas AG shares held by BEB were transferred, cash was received for the shares held by the consolidated affiliate and a one-time gain of $1,700 million after tax was recognized in net income. The $2,240 million reduction in 2003 cash flow from operating activities reflects the pretax gains from the transaction. The cash generated from these gains for the BEB portion of the transaction was reported in 2002. For the shares held by the consolidated affiliate, the cash received was reported in cash flows from investing activities in 2003.

Cash Flow from Investing Activities

2004

Cash used in investing activities totaled $14.9 billion in 2004, $4.1 billion higher than 2003. Spending for property, plant and equipment decreased $0.9 billion. Proceeds from the sales of subsidiaries, investments and property, plant and equipment in 2004 increased $0.5 billion to $2.8 billion. As discussed in note 16 on page A46, investing activities in 2004 included a pledge by the Corporation of $4.6 billion of collateral consisting of cash and short-term, high-quality securities to the issuer of a litigation-related appeal bond. This collateral was reported as restricted cash and cash equivalents on the balance sheet.

2003

Cash used in investing activities totaled $10.8 billion in 2003, $1.0 billion higher than 2002. Spending for property, plant and equipment increased $1.4 billion, reflecting the Corporation's active investment program. Proceeds from the sales of subsidiaries, investments and property, plant and equipment in 2003 were $2.3 billion, including $1.2 billion from the sale of an interest in Ruhrgas AG partly held by a consolidated affiliate.

Cash Flow from Financing Activities

2004

Cash used in financing activities was $18.3 billion, an increase of $3.5 billion from 2003, reflecting a higher level of purchases of ExxonMobil shares. Dividend payments on common shares increased to $1.06 per share from $0.98 per share and totaled $6.9 billion, a payout of 27 percent. Total consolidated short-term and long-term debt declined $1.2 billion to $8.3 billion at year-end 2004. Shareholders' equity increased $11.8 billion in 2004 to $101.7 billion, reflecting $25.3 billion of net income partly offset by distributions to ExxonMobil shareholders of $6.9 billion of dividends and $9.0 billion of net purchases of shares of ExxonMobil stock. Shareholders' equity, and net assets and liabilities, also increased $2.2 billion, representing the foreign exchange translation effects of stronger foreign currencies on ExxonMobil's operations outside the U.S.

During 2004, Exxon Mobil Corporation purchased 218 million shares of its common stock for the treasury at a gross cost of $10.0 billion. These purchases were to offset shares issued in conjunction with company benefit plans and programs and to reduce the number of shares outstanding. Shares outstanding were reduced from 6,568 million at the end of 2003 to 6,401 million at the end of 2004. Purchases were made in both the open market and through negotiated transactions. Purchases may be increased, decreased or discontinued at any time without prior notice.

2003

Cash used in financing activities was $14.8 billion, an increase of $3.4 billion from 2002, reflecting higher levels of debt reductions and purchases of ExxonMobil shares. Dividend payments on common shares increased to $0.98 per share from $0.92 per share and totaled $6.5 billion, a payout of 30 percent. Total consolidated short-term and long-term debt declined $1.2 billion to $9.5 billion at year-end 2003. Shareholders' equity increased $15.3 billion in 2003 to $89.9 billion, reflecting $21.5 billion of net income partly offset by $6.5 billion of dividends paid to ExxonMobil shareholders and $5.4 billion of net

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

purchases of shares of ExxonMobil stock. Shareholders' equity, and net assets and liabilities, also increased $4.4 billion, representing the foreign exchange translation effects of stronger foreign currencies on ExxonMobil's operations outside the U.S.

During 2003, Exxon Mobil Corporation purchased 163 million shares of its common stock for the treasury at a gross cost of $5.9 billion. These purchases were to offset shares issued in conjunction with company benefit plans and programs and to reduce the number of shares outstanding. Shares outstanding were reduced from 6,700 million at the end of 2002 to 6,568 million at the end of 2003. Purchases were made in both the open market and through negotiated transactions. Purchases may be increased, decreased or discontinued at any time without prior notice.

Commitments

Set forth below is information about the Corporation's commitments outstanding at December 31, 2004. It provides data for easy reference from the consolidated balance sheet and from individual notes to the consolidated financial statements.

			Payments Due by Period
Commitments		Note Reference Number	2005		2006-2009		2010 and Beyond		Total
			(millions of dollars)
Long-term debt (1)		14	$	—	$	666	$	4,347	$	5,013
	—Due in one year (2)			608		—		—		608
Asset retirement obligations (3)		9		142		784		2,684		3,610
Pension obligations (4)		17		1,703		1,576		5,531		8,810
Operating leases (5)		10		1,323		2,813		1,855		5,991
Unconditional purchase obligations (6)		16		602		1,918		2,125		4,645
Take-or-pay obligations (7)				907		1,994		2,087		4,988
Firm capital commitments (8)				3,823		2,069		529		6,421

This table excludes commodity purchase obligations (volumetric commitments but no fixed or minimum price) for which an active, highly liquid market exists and which are expected to be resold shortly after purchase. Examples include long-term, noncancelable upstream commitments with equity companies to purchase Qatar LNG production and downstream offtake commitments with equity companies and third parties to purchase refinery products at market prices. Inclusion of such amounts would not be meaningful in assessing liquidity and cash flow, since such market-based purchases will be offset in the same periods by cash received from sales.

Notes:

(1): Includes capitalized lease obligations of $354 million. Long-term debt amounts exclude the Corporation's share of equity company debt, which is included in the calculation of return on average capital employed as shown on page A5.
(2): The amount due in one year is included in notes and loans payable of $3,280 million (note 6 on page A33).
(3): The discounted present value of upstream asset retirement obligations, primarily asset removal costs at the completion of field life.
(4): The amount by which accumulated benefit obligations (ABOs) exceeded the fair value of fund assets for certain U.S. and non-U.S. plans at year end (note 17 on page A48). For funded pension plans, this difference was $3.5 billion at December 31, 2004 (U.S. $0.9 billion, non-U.S. $2.6 billion). For unfunded plans, this was the ABO amount of $5.3 billion (U.S. $1.0 billion, non-U.S. $4.3 billion). The payments by period include expected contributions to funded pension plans in 2005 and estimated benefit payments for unfunded plans in all years.
(5): Minimum commitments for operating leases, shown on an undiscounted basis, cover drilling equipment, tankers, service stations and other properties.
(6): Unconditional purchase obligations (UPOs) are those long-term commitments that are noncancelable and that third parties have used to secure financing for the facilities that will provide the contracted goods or services. The undiscounted obligations of $4,645 million mainly pertain to pipeline throughput agreements and include $2,513 million of obligations to equity companies. The present value of the total commitments, excluding imputed interest of $1,386 million, was $3,259 million.
(7): Take-or-pay obligations are noncancelable, long-term commitments for goods and services other than UPOs. The undiscounted obligations of $4,988 million mainly pertain to transportation, refining and natural gas purchases and include $503 million of obligations to equity companies. The present value of the total commitments, excluding imputed interest of $1,046 million, totaled $3,942 million.
(8): Firm commitments related to capital projects, shown on an undiscounted basis, totaled approximately $6.4 billion. These commitments were predominantly associated with upstream projects outside the U.S., of which the largest single commitment outstanding at the end of 2004 was $1.6 billion associated with the development of crude oil and natural gas resources in Malaysia. The Corporation expects to fund the majority of these commitments through internal cash flow.

Guarantees

		Dec. 31, 2004
		Equity Company Obligations		Other Third-Party Obligations		Total
		(millions of dollars)
Guarantees of excise taxes/customs duties under reciprocal arrangements		$	—	$	1,122	$	1,122
Other guarantees			2,428		344		2,772

	Total	$	2,428	$	1,466	$	3,894

The Corporation and certain of its consolidated subsidiaries were contingently liable at December 31, 2004, for $3,894 million, primarily relating to guarantees for notes, loans and performance under contracts (note 16 on page A47). This included $1,122 million representing guarantees of non-U.S. excise taxes and customs duties of other companies, entered into as a normal business practice, under reciprocal arrangements. Also included in this amount were guarantees by consolidated affiliates of $2,428 million, representing ExxonMobil's share of obligations of certain equity companies. The above-mentioned guarantees are not reasonably likely to have a material current or future effect on the Corporation's financial condition, changes in financial condition,

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revenues or expenses, results of operations, liquidity, capital expenditures or capital resources.

Financial Strength

On December 31, 2004, unused credit lines for short-term financing totaled approximately $5.2 billion (note 6 on page A33).

The table below shows the Corporation's fixed-charge coverage and consolidated debt-to-capital ratios. The data demonstrate the Corporation's creditworthiness. Throughout this period, the Corporation's long-term debt securities maintained the top credit rating from both Standard and Poor's (AAA) and Moody's (Aaa), a rating it has sustained for 86 years.

	2004		2003		2002
	(millions of dollars)
Fixed-charge coverage ratio (times)	36.1		30.8		13.8
Debt to capital (percent)	7.3		9.3		12.2
Net debt to capital (percent) (1)	(10.7	)	(1.2	)	4.4
Credit rating	AAA/Aaa		AAA/Aaa		AAA/Aaa

(1): Debt net of cash, excluding restricted cash. The ratio of net debt to capital including restricted cash is (16.3) percent for 2004.

Management views the Corporation's financial strength, as evidenced by the above financial ratios and other similar measures, to be a competitive advantage of strategic importance. The Corporation's sound financial position gives it the opportunity to access the world's capital markets in the full range of market conditions, and enables the Corporation to take on large, long-term capital commitments in the pursuit of maximizing shareholder value.

In addition to the above commitments, the Corporation makes limited use of derivative instruments, which are discussed in Risk Management on page A16 and note 13 on page A39.

Litigation and Other Contingencies

As discussed in note 16 to the consolidated financial statements, a number of lawsuits, including class actions, were brought in various courts against Exxon Mobil Corporation and certain of its subsidiaries relating to the accidental release of crude oil from the tanker Exxon Valdez in 1989. The vast majority of the compensatory claims have been resolved. All of the punitive damage claims were consolidated in the civil trial that began in May 1994.

In that trial, on September 24, 1996, the United States District Court for the District of Alaska entered a judgment in the amount of $5 billion in punitive damages to a class composed of all persons and entities who asserted claims for punitive damages from the Corporation as a result of the Exxon Valdez grounding. ExxonMobil appealed the judgment. On November 7, 2001, the United States Court of Appeals for the Ninth Circuit vacated the punitive damage award as being excessive under the Constitution and remanded the case to the District Court for it to determine the amount of the punitive damage award consistent with the Ninth Circuit's holding. The Ninth Circuit upheld the compensatory damage award, which has been paid. On December 6, 2002, the District Court reduced the punitive damage award from $5 billion to $4 billion. Both the plaintiffs and ExxonMobil appealed that decision to the Ninth Circuit. The Ninth Circuit panel vacated the District Court's $4 billion punitive damage award without argument and sent the case back for the District Court to reconsider in light of the recent U.S. Supreme Court decision in Campbell v. State Farm. On January 28, 2004, the District Court reinstated the punitive damage award at $4.5 billion plus interest. ExxonMobil and the plaintiffs appealed the decision to the Ninth Circuit. The Corporation has posted a $5.4 billion letter of credit. Management believes that the likelihood of the judgment being upheld is remote. While it is reasonably possible that a liability may have been incurred arising from the Exxon Valdez grounding, it is not possible to predict the ultimate outcome or to reasonably estimate any such potential liability.

On December 19, 2000, a jury in Montgomery County, Alabama, returned a verdict against the Corporation in a dispute over royalties in the amount of $88 million in compensatory damages and $3.4 billion in punitive damages in the case of Exxon Corporation v. State of Alabama, et al. The verdict was upheld by the trial court on May 4, 2001. On December 20, 2002, the Alabama Supreme Court vacated the $3.5 billion jury verdict. The case was retried and on November 14, 2003, a state district court jury in Montgomery, Alabama, returned a verdict against Exxon Mobil Corporation. The verdict included $63.5 million in compensatory damages and $11.8 billion in punitive damages. On March 29, 2004, the district court judge reduced the amount of punitive damages to $3.5 billion. ExxonMobil believes the judgment is not justified by the evidence, that any punitive damage award is not justified by either the facts or the law, and that the amount of the award is grossly excessive and unconstitutional. ExxonMobil has appealed the decision. Management believes that the likelihood of the judgment being upheld is remote. While it is reasonably possible that a liability may have been incurred by ExxonMobil from this dispute over royalties, it is not possible to predict the ultimate outcome or to reasonably estimate any such potential liability. On May 4, 2004, the Corporation posted a $4.5 billion supersedeas bond as required by Alabama law to stay execution of the judgment pending appeal. The Corporation has pledged to the issuer of the bond collateral consisting of cash and short-term, high-quality securities with an aggregate value of approximately $4.6 billion. This collateral is reported as restricted cash and cash equivalents on the Consolidated Balance Sheet on page A27. Under the terms of the pledge agreement, the Corporation is entitled to receive the income generated from the cash and securities and to make investment decisions, but is restricted from using the pledged cash and securities for any other purpose until such time the bond is canceled.

On May 22, 2001, a state court jury in New Orleans, Louisiana, returned a verdict against the Corporation and three other entities in a case brought by a landowner claiming damage to his property. The property had been leased by the landowner to a company that performed pipe cleaning and storage services for customers, including the Corporation. The jury awarded the plaintiff $56 million in compensatory damages (90 percent to be paid by the Corporation) and $1 billion in punitive damages (all to be paid by the Corporation). The damage related to the presence of naturally occurring radioactive material (NORM) on the site resulting from pipe cleaning operations. The award has been upheld at the trial court. ExxonMobil has appealed the judgment to the Louisiana Fourth Circuit Court of Appeals and believes that the judgment should be set aside or substantially reduced on factual and constitutional grounds. Management believes that the likelihood of the judgment being upheld is remote. While it is reasonably possible that a liability may have been incurred by ExxonMobil from this

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

dispute over property damages, it is not possible to predict the ultimate outcome or to reasonably estimate any such potential liability.

In Allapattah v. Exxon, a jury in the United States District Court for the Southern District of Florida determined in January 2001 that a class of all Exxon dealers between March 1983 and August 1994 had been overcharged between 1.03 and 1.4 cents per gallon for gasoline. Exxon sold a total of 39.8 billion gallons of gasoline to its dealers during this period. The estimated value of the potential claims associated with the 39.8 billion gallons of gasoline is $494 million. Including related interest, the total is approximately $1.3 billion. On June 11, 2003, the Eleventh Circuit Court of Appeals affirmed the judgment and on March 15, 2004, denied a petition for Rehearing En Banc. On October 12, 2004, the U.S. Supreme Court granted review of an issue raised by ExxonMobil as to whether the class in the District Court judgment should include members that individually do not satisfy the $50,000 minimum amount-in-controversy requirement in federal court. Members of the class could file claims through December 1, 2004. Claims representing over 90 percent of the gallons have been filed. In light of the Supreme Court's decision to grant review of only part of ExxonMobil's appeal, ExxonMobil took an after-tax charge of $550 million in the third quarter reflecting the estimated liability, including interest and after considering potential set-offs and defenses, for the claims in excess of $50,000.

Tax issues for 1983 to 1993 remain pending before the U.S. Tax Court. The ultimate resolution of these issues is not expected to have a materially adverse effect upon the Corporation's operations or financial condition.

Based on a consideration of all relevant facts and circumstances, the Corporation does not believe the ultimate outcome of any currently pending lawsuit against ExxonMobil will have a materially adverse effect upon the Corporation's operations or financial condition. There are no events or uncertainties known to management beyond those already included in reported financial information that would indicate a material change in future operating results or financial condition.

CAPITAL AND EXPLORATION EXPENDITURES

		2004				2003
		U.S.		Non-U.S.		U.S.		Non-U.S.
		(millions of dollars)
Upstream (1)		$	1,922	$	9,793	$	2,125	$	9,863
Downstream			775		1,630		1,244		1,537
Chemical			262		428		333		359
Other			66		9		64		—

	Total	$	3,025	$	11,860	$	3,766	$	11,759

(1): Exploration expenses included.

Capital and exploration expenditures in 2004 were $14.9 billion, reflecting the Corporation's continued active investment program. Upstream spending was down 2 percent to $11.7 billion in 2004, from $12.0 billion in 2003, as a result of lower spending on major projects in the North Sea and the U.S. These decreases were partly offset by higher development drilling in Qatar, the Caspian and Russia. Capital and exploration expenditures are not tracked by the undeveloped and developed proved reserve categories. During the past three years, Upstream capital and exploration expenditures averaged $11.4 billion, and the Corporation currently expects to spend approximately $12 billion annually through the end of the decade. The majority of these expenditures are on major development projects, which typically take two to four years from the time of recording proved undeveloped reserves to the start of production from those reserves. The percentage of proved developed reserves has remained relatively stable over the past five years at over 60 percent of total proved reserves, indicating that proved reserves are consistently moved from undeveloped to developed status. Capital investments in the Downstream totaled $2.4 billion in 2004, down $0.4 billion from 2003, primarily reflecting reduced spending on low-sulfur motor fuels projects in North America. Total Chemical capital expenditures were essentially unchanged from 2003.

TAXES

		2004			2003			2002
		(millions of dollars)
Income taxes		$	15,911		$	11,006		$	6,499
Excise taxes			27,263			23,855			22,040
All other taxes and duties			43,605			40,107			35,746

	Total	$	86,779		$	74,968		$	64,285

Total effective tax rate			40.3	%		36.4	%		39.8	%

2004

Income, excise and all other taxes totaled $86.8 billion in 2004, an increase of $11.8 billion, or 16 percent, from 2003. Income tax expense, both current and deferred, was $15.9 billion, $4.9 billion higher than 2003, reflecting higher pretax income in 2004. The effective tax rate was 40.3 percent in 2004, compared to 36.4 percent in 2003. Excluding the income tax effects in 2003 of the gain on the Ruhrgas AG share transfer and the settlement of a U.S. tax dispute, the effective rate in 2004 was similar to the prior year. During both periods, the Corporation continued to benefit from the favorable resolution of other tax-related issues. Excise and all other taxes and duties of $70.9 billion in 2004 increased $6.9 billion from 2003, reflecting higher prices and foreign exchange effects.

2003

Income, excise and all other taxes totaled $75.0 billion in 2003, an increase of $10.7 billion, or 17 percent, from 2002. Income tax expense, both current and deferred, was $11.0 billion, $4.5 billion higher than 2002, reflecting higher pretax income in 2003. The effective tax rate was 36.4 percent in 2003. Excluding the income tax effects of the 2003 gain on the Ruhrgas AG share transfer and settlement of a U.S. tax dispute, the effective rate in 2003 was similar to the prior year. During both periods, the Corporation continued to benefit from the favorable resolution of other tax-related issues. Excise and all other taxes and duties of $64.0 billion in 2003 increased $6.2 billion from 2002, reflecting higher prices and foreign exchange effects.

MERGER EXPENSES AND REORGANIZATION RESERVES

In association with the merger between Exxon and Mobil, $410 million pretax ($275 million after tax) of costs were recorded as merger-related expenses in 2002. Charges included separation expenses related to workforce reductions (approximately 8,200 employees at year-end 2002), plus implementation and merger closing costs. Merger-related expenses for the period 1999 to 2002 cumulatively totaled approximately $3.2 billion pretax. Reflecting the completion of merger-related activities, merger expenses were not reported in either 2003 or 2004.

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The following table summarizes the activity in the reorganization reserves. The 2002 opening balance represents accruals for provisions taken in prior years.

	Opening Balance		Additions		Deductions		Balance at Year End
	(millions of dollars)
2002	$	197	$	93	$	189	$	101
2003		101		—		53		48
2004		48		—		21		27

ASSET RETIREMENT OBLIGATIONS AND ENVIRONMENTAL COSTS

Asset Retirement Obligations

The methodology of accounting for asset retirement obligations was modified as of January 1, 2003, per FAS 143. The fair values of asset retirement obligations are recorded as liabilities on a discounted basis when they are incurred, which is typically at the time assets are installed, with an offsetting amount booked as additions to property, plant and equipment ($143 million for 2004). Over time, the liabilities are accreted for the increase in their present value, with this effect included in expenses ($136 million in 2004). Payments made for asset retirement obligations in 2004 were $201 million, and the ending balance of the obligations recorded on the balance sheet at December 31, 2004, totaled $3,610 million.

Environmental Costs

		2004		2003
		(millions of dollars)
Capital expenditures		$	1,073	$	1,306
Included in expenses			1,781		1,497

	Total	$	2,854	$	2,803

Throughout ExxonMobil's businesses, new and ongoing measures are taken to prevent and minimize the impact of our operations on the air, water and ground. This includes a significant investment in refining technology to manufacture low-sulfur motor fuels and projects to reduce nitrogen oxide and sulfur oxide emissions. ExxonMobil's 2004 worldwide environmental costs for all such preventative and remediation steps were about $2.9 billion, of which $1.1 billion were capital expenditures and $1.8 billion were included in expenses. The total cost for such activities is expected to be about $3.0 billion in 2005 (with capital expenditures representing just over 40 percent of the total), and a similar amount is expected for 2006.

The Corporation accrues liabilities for environmental liabilities when it is probable that obligations have been incurred and the amounts can be reasonably estimated. This policy applies to assets or businesses currently owned or previously disposed. ExxonMobil has accrued liabilities for probable environmental remediation obligations at various sites, including multiparty sites where the U.S. Environmental Protection Agency has identified ExxonMobil as one of the potentially responsible parties. The involvement of other financially responsible companies at these multiparty sites mitigates ExxonMobil's actual joint and several liability exposure. At present, no individual site is expected to have losses material to ExxonMobil's operations, financial condition or liquidity. Provisions made in 2004 for new environmental liabilities were $340 million ($275 million in 2003), included in the $1.8 billion of 2004 expenses noted above, and the balance sheet reflects accumulated liabilities of $643 million as of December 31, 2004, and $528 million as of December 31, 2003.

MARKET RISKS, INFLATION AND OTHER UNCERTAINTIES

	2004		2003		2002
Worldwide Average Realizations (1)
Crude oil and NGL ($/barrel)	$	34.76	$	26.66	$	22.30
Natural gas ($/kcf)		4.48		3.98		2.65

(1): Consolidated subsidiaries.

Crude oil, natural gas, petroleum product and chemical prices have fluctuated in response to changing market forces. The impacts of these price fluctuations on earnings from Upstream, Downstream and Chemical operations have been varied, tending at times to be offsetting. In the Upstream, based on the 2004 worldwide production levels, a $1 per barrel change in the weighted-average realized price of oil would have approximately a $400 million annual after-tax effect on Upstream consolidated plus equity company earnings. Similarly, a $0.10 per kcf change in the worldwide average gas realization would have approximately a $200 million annual after-tax effect on Upstream consolidated plus equity company earnings. For any given period, the extent of actual benefit or detriment will be dependent on the price movements of individual types of crude oil, taxes and other government take impacts, price adjustment lags in long-term gas contracts, and crude and gas production volumes. Accordingly, changes in benchmark prices for crude oil and natural gas only provide a broad indicator of changes in the earnings experienced in any particular period.

In the very competitive downstream and chemical environments, earnings are primarily determined by margin capture rather than absolute price levels of products sold. Refining margins are a function of the difference between what a refiner pays for its raw materials (primarily crude oil) and the market prices for the range of products produced. These prices in turn depend on global and regional supply/demand balances, inventory levels, refinery operations, import/export balances and weather.

The global energy markets can give rise to extended periods in which market conditions are adverse to one or more of the Corporation's businesses. Such conditions, along with the capital-intensive nature of the industry and very long lead times associated with many of our projects, underscore the importance of maintaining a strong financial position. Management views the Corporation's financial strength, including the AAA and Aaa ratings of its long-term debt securities by Standard and Poor's and Moody's, as a competitive advantage.

In general, segment results are not dependent on the ability to sell and/or purchase products to/from other segments. Instead, where such sales take place, they are the result of efficiencies and competitive advantages of integrated refinery/chemical complexes. Additionally, intersegment sales are market-related. The products bought and sold between segments can also be acquired in worldwide markets that have substantial liquidity, capacity and transportation capabilities. About 40 percent of the Corporation's intersegment sales are crude oil produced by the Upstream and sold to the Downstream. Other intersegment sales include those between refineries and chemical plants related to raw materials, feedstocks and finished products.

Although price levels of crude oil and natural gas may rise or fall significantly over the short to medium term due to political events, OPEC actions and other factors, industry economics over the long term

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

will continue to be driven by market supply and demand. Accordingly, the Corporation tests the viability of all of its assets based on long-term price projections. The Corporation's assessment is that its operations will continue to be successful in a variety of market conditions. This is the outcome of disciplined investment and asset management programs. Investment opportunities are tested against a variety of market conditions, including low-price scenarios. As a result, investments that would succeed only in highly favorable price environments are screened out of the investment plan.

The Corporation has had an active asset management program in which underperforming assets are either improved to acceptable levels or considered for divestment. The asset management program involves a disciplined, regular review to ensure that all assets are contributing to the Corporation's strategic and financial objectives. The result has been the creation of a very efficient capital base and has meant that the Corporation has seldom been required to write down the carrying value of assets, even during periods of low commodity prices.

Risk Management

The Corporation's size, geographic diversity and the complementary nature of the Upstream, Downstream and Chemical businesses mitigate the Corporation's risk from changes in interest rates, currency rates and commodity prices. The Corporation relies on these operating attributes and strengths to reduce enterprise-wide risk. As a result, the Corporation makes limited use of derivatives to offset exposures arising from existing transactions.

The Corporation does not trade in derivatives nor does it use derivatives with leverage features. The Corporation maintains a system of controls that includes a policy covering the authorization, reporting and monitoring of derivative activity. The Corporation's derivative activities pose no material credit or market risks to ExxonMobil's operations, financial condition or liquidity. Interest rate, foreign exchange rate and commodity price exposures arising from derivative contracts undertaken in accordance with the Corporation's policies have not been significant.

Derivatives	2004		2003			2002
	(millions of dollars)
Net receivable/(payable)	$	6	$	(17	)	$	20
Net gain/(loss), before tax		38		4			(35	)

The fair values of derivatives outstanding and recorded on the balance sheet are shown in the table above. This is the amount that the Corporation would have paid to or received from third parties if these derivatives had been settled. These derivative fair values were substantially offset by the fair values of the underlying exposures being hedged. The gains/losses before tax include the offsetting amounts from the changes in fair value of the items being hedged by the derivatives. The fair value of derivatives outstanding at year-end 2004 and gain recognized during the year are immaterial in relation to the Corporation's year-end cash balance of $18.5 billion, total assets of $195.3 billion or net income for the year of $25.3 billion.

Debt-Related Instruments

The Corporation is exposed to changes in interest rates, primarily as a result of its short-term debt and long-term debt carrying floating interest rates. The Corporation makes limited use of interest rate swap agreements to adjust the ratio of fixed and floating rates in the debt portfolio. The impact of a 100-basis-point change in interest rates affecting the Corporation's debt would not be material to earnings, cash flow or fair value.

Foreign Currency Exchange Rate Instruments

The Corporation conducts business in many foreign currencies and is subject to foreign currency exchange rate risk on cash flows related to sales, expenses, financing and investment transactions. The impacts of fluctuations in foreign currency exchange rates on ExxonMobil's geographically diverse operations are varied and often offsetting in amount. The Corporation makes limited use of currency exchange contracts to reduce the risk of adverse foreign currency movements related to certain foreign currency debt obligations. Exposure from market-rate fluctuations related to these contracts is not material. Aggregate foreign exchange transaction gains and losses included in net income are discussed in note 4 on page A33.

Commodity Instruments

The Corporation makes limited use of commodity forwards, swaps and futures contracts of short duration to mitigate the risk of unfavorable price movements on certain crude, natural gas and petroleum product purchases and sales. Commodity price exposure related to these contracts is not material.

Inflation and Other Uncertainties

The general rate of inflation in most major countries of operation has been relatively low in recent years, and the associated impact on costs has been countered by cost reductions from efficiency and productivity improvements.

The operations and earnings of the Corporation and its affiliates throughout the world have been, and may in the future be, affected from time to time in varying degree by political developments and laws and regulations, such as forced divestiture of assets; restrictions on production, imports and exports; price controls; tax increases and retroactive tax claims; expropriation of property; cancellation of contract rights; and environmental regulations. Both the likelihood of such occurrences and their overall effect upon the Corporation vary greatly from country to country and are not predictable.

RECENTLY ISSUED STATEMENTS OF FINANCIAL ACCOUNTING STANDARDS

In December 2004, the Financial Accounting Standards Board (FASB) issued a revised Statement of Financial Accounting Standards No. 123 (FAS 123R), "Share-based Payment." FAS 123R requires compensation costs related to share-based payments to be recognized in the income statement over the vesting period. The amount of the compensation cost will be measured based on the grant-date fair value of the instrument issued. FAS 123R is effective as of July 1, 2005, for all awards granted or modified after that date and for those awards granted prior to that date that have not vested. FAS 123R will have no earnings impact on the Corporation because in 2003 the Corporation adopted a policy of expensing all share-based payments that is consistent with the provisions of FAS 123R, and all prior year outstanding awards have vested.

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EMERGING ACCOUNTING AND REPORTING ISSUES

Accounting for Suspended Well Costs

At its September 2004 meeting, the Emerging Issues Task Force (EITF) discussed Issue No. 04-9, "Accounting for Suspended Well Costs." Statement of Financial Accounting Standards No. 19 (FAS 19), "Financial Accounting and Reporting by Oil and Gas Producing Companies," requires costs of drilling exploratory wells to be capitalized pending determination of whether the well has found proved reserves. If the well has found proved reserves, the capitalized costs are included in wells, equipment and facilities. If, however, the well has not found proved reserves, the capitalized costs of drilling the well are expensed, net of any salvage value, within one year except under certain specific circumstances. Questions have arisen in practice about the application of this guidance. The EITF agreed to remove this issue from the EITF agenda and requested that the FASB consider an amendment to FAS 19 to address this issue. On February 4, 2005, the FASB issued a proposed FASB Staff Position (FSP) that would amend FAS 19 to permit the continued capitalization of exploratory well costs beyond one year if (a) the well found a sufficient quantity of reserves to justify its completion as a producing well and (b) the entity is making sufficient progress assessing the reserves and the economic and operating viability of the project. Comments on the FSP are due back to the FASB in March 2005, and the guidance in the FSP would be applied prospectively in the first reporting period beginning after the FSP is finalized.

ExxonMobil continues to carry as an asset the cost of drilling exploratory wells that find sufficient quantities of reserves to justify their completion as producing wells if the required capital expenditure is made and drilling of additional exploratory wells is under way or firmly planned for the near future. Once exploration activities demonstrate that sufficient quantities of commercially producible reserves have been discovered, continued capitalization is dependent on project reviews, which take place at least annually, to ensure that sufficient progress toward ultimate development of the reserves is being achieved. Exploratory well costs not meeting these criteria are charged to expense. ExxonMobil does not believe that this issue will have a material impact on its financial statements.

The following table shows the amount of suspended wells on the year-end balance sheet that were greater than one year old with no firm exploratory drilling planned.

	Dec. 31 2004		Dec. 31 2003
	(millions of dollars)
Projects greater than one year old with no firm exploratory drilling planned	$	718	$	693
Total suspended well cost		1,070		1,093

Accounting for Purchases and Sales of Inventory with the Same Counterparty

At its November 2004 meeting, the EITF began discussion of Issue No. 04-13, "Accounting for Purchases and Sales of Inventory with the Same Counterparty." This Issue addresses the question of when it is appropriate to measure purchases and sales of inventory at fair value and record them in cost of sales and revenues and when they should be recorded as an exchange measured at the book value of the item sold. The EITF did not reach a consensus on this issue, but requested the FASB staff to further explore the alternative views.

ExxonMobil records certain crude oil, natural gas, petroleum product, and chemical purchases and sales of inventory entered into contemporaneously with the same counterparty as cost of sales and revenues, measured at fair value as agreed upon by a willing buyer and a willing seller. These transactions occur under contractual arrangements that establish the agreement terms either jointly, in a single contract, or separately, in individual contracts. This accounting treatment is consistent with long-term, predominant industry practice based on the Corporation's knowledge of the industry (although the Corporation understands that some companies in the oil and gas industry may be accounting for these transactions differently as nonmonetary exchanges). Should the EITF reach a consensus on this Issue requiring these transactions to be recorded as exchanges measured at book value, the Corporation's accounts "Sales and other operating revenue" and "Crude oil and product purchases" on the Consolidated Statement of Income would be lower by equal amounts with no impact on net income. All operating segments would be impacted by this change, but the largest effects are in the Downstream. The Corporation has not yet determined the amount by which "Sales and other operating revenue" and "Crude oil and product purchases" would be lower under this interpretation. A special effort is needed to accumulate this information manually since heretofore it has never been necessary to identify these monetary transactions separately from other monetary purchases and monetary sales. A best efforts estimate based on this undertaking is expected to be available in the second quarter of 2005. The Corporation does not believe this estimate will be material, but if it is, the information will be disclosed once it is available together with material changes in trends and uncertainties, if any.

CRITICAL ACCOUNTING POLICIES

The Corporation's accounting and financial reporting fairly reflect its straightforward business model involving the extracting, refining and marketing of hydrocarbons and hydrocarbon-based products. The preparation of financial statements in conformity with U.S. Generally Accepted Accounting Principles (GAAP) requires management to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. The following summary provides further information about the critical accounting policies and the judgments that are made by the Corporation in the application of those policies.

Oil and Gas Reserves

Evaluations of oil and gas reserves are important to the effective management of upstream assets. They are integral to making investment decisions about oil and gas properties such as whether development should proceed or enhanced recovery methods should be undertaken. Oil and gas reserve quantities are also used as the basis of calculating the unit-of-production rates for depreciation and evaluating for impairment. Oil and gas reserves are divided between proved and unproved reserves. Proved reserves are the estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions; i.e., prices and costs as of the date the estimate is made. Unproved reserves are those with less than reasonable certainty of recoverability and are classified as either probable or possible. Probable

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

reserves are reserves that are more likely to be recovered than not, and possible reserves are less likely to be recovered than not.

The estimation of proved reserves, which is based on the requirement of reasonable certainty, is an ongoing process based on rigorous technical evaluations and extrapolations of well information such as flow rates and reservoir pressure declines. In certain deepwater fields, proved reserves are recorded in a limited number of cases before flow tests are conducted because of the safety and cost implications of conducting the tests. In those situations, other industry-accepted analyses are used such as information from well logs, a thorough pressure and fluid sampling program, conventional core data obtained across the entire reservoir interval and nearby analog data. Historically, proved reserves recorded using these methods have been immaterial when compared to the Corporation's total proved reserves and have also been validated by subsequent flow tests or actual production levels. Furthermore, the Corporation only records proved reserves for projects that have received significant funding commitments by management made toward the development of the reserves.

The estimation of proved reserves is controlled by the Corporation through long-standing approval guidelines. Reserve changes are made within a well-established, disciplined process driven by senior level geoscience and engineering professionals (assisted by a central reserves group with significant technical experience) culminating in reviews with and approval by senior management. Notably, no employee is compensated based on the level of proved reserve bookings.

Key features of the reserves estimation process include:

•: rigorous peer-reviewed technical evaluations and analysis of well and field performance information (such as flow rates and reservoir pressure declines), and
•: a requirement that management make significant funding commitments toward the development of the reserves prior to booking.

Although the Corporation is reasonably certain that proved reserves will be produced, the timing and amount recovered can be affected by a number of factors including completion of development projects, reservoir performance, regulatory approvals and significant changes in long-term oil and gas price levels.

Proved reserves can be further subdivided into developed and undeveloped reserves. The percentage of proved developed reserves has remained relatively stable over the past five years at over 60 percent of total proved reserves (including both consolidated and equity reserves), indicating that proved reserves are consistently moved from undeveloped to developed status. Management is not aware of any factors that would significantly change this historical relationship in the next several years. Over time, these undeveloped reserves will be reclassified to the developed category as new wells are drilled, existing wells are recompleted and/or facilities to collect and deliver the production from existing and future wells are installed. Major development projects typically take two to four years from the time of recording proved reserves to the start of production from these reserves.

Based on regulatory guidance, the Corporation has reported 2004 reserves on the basis of December 31, 2004, prices and costs ("year-end prices"). Resultant changes from the year-end 2003 reserve estimates, which were based on long-term projections of oil and gas prices consistent with those used in the Corporation's investment decision-making process, are shown in the line titled "Year-end price/cost revisions" on pages A59 and A60.

The use of year-end prices for reserves estimation introduces short-term price volatility into the process since annual adjustments will be required based on prices occurring on a single day. The Corporation believes that this approach is inconsistent with the long-term nature of the upstream business where production from individual projects often spans multiple decades. The use of prices from a single date is not relevant to the investment decisions made by the Corporation and annual variations in reserves based on such year-end prices are not of consequence to how the business is actually managed.

Performance-related revisions can include upward or downward changes in previously estimated volumes of proved reserves for existing fields due to the evaluation or re-evaluation of (1) already available geologic, reservoir or production data or (2) new geologic, reservoir or production data. This category can also include changes associated with the performance of improved recovery projects and significant changes in either development strategy or production equipment/facility capacity.

The Corporation uses the "successful efforts" method to account for its exploration and production activities. Under this method, costs are accumulated on a field-by-field basis with certain exploratory expenditures and exploratory dry holes being expensed as incurred. Costs of productive wells and development dry holes are capitalized and amortized on the unit-of-production method for each field. The Corporation uses this accounting policy instead of the "full cost" method because it provides a more timely accounting of the success or failure of the Corporation's exploration and production activities. If the full cost method were used, all costs would be capitalized and depreciated on a country-by-country basis. The capitalized costs would be subject to an impairment test by country. The full cost method would tend to delay the expense recognition of unsuccessful projects.

Impact of Oil and Gas Reserves on Depreciation. The calculation of unit-of-production depreciation is a critical accounting estimate that measures the depreciation of upstream assets. It is the ratio of (1) actual volumes produced to (2) total proved developed reserves (those proved reserves recoverable through existing wells with existing equipment and operating methods) applied to the (3) asset cost. The volumes produced and asset cost are known and, while proved developed reserves have a high probability of recoverability, they are based on estimates that are subject to some variability. This variability has generally resulted in net upward revisions of proved reserves in existing fields, as more information becomes available through research and actual production levels. While the upward revisions the Corporation has made in the past are an indicator of variability, they have had a very small impact on the unit-of-production rates because they have been small compared to the large reserves base.

Impact of Oil and Gas Reserves and Prices on Testing for Impairment. Proved oil and gas properties held and used by the Corporation are reviewed for impairment whenever events or circumstances indicate that the carrying amounts may not be recoverable. Assets are grouped at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets.

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The Corporation estimates the future undiscounted cash flows of the affected properties to judge the recoverability of carrying amounts. In general, analyses are based on proved reserves. Where probable reserves exist, an appropriately risk-adjusted amount of these reserves may be included in the impairment evaluation. An asset would be impaired if the undiscounted cash flows were less than its carrying value. Impairments are measured by the amount by which the carrying value exceeds its fair value.

The Corporation performs asset valuation analyses on an ongoing basis as a part of its asset management program. These analyses monitor the performance of assets against corporate objectives. They also assist the Corporation in assessing whether the carrying amounts of any of its assets may not be recoverable. In addition to estimating oil and gas reserve volumes in conducting these analyses, it is also necessary to estimate future oil and gas prices. The impairment evaluation triggers include a significant decrease in current and projected prices or reserve volumes, an accumulation of project costs significantly in excess of the amount originally expected, and historical and current negative operating losses.

In general, the Corporation does not view temporarily low oil prices as a triggering event for conducting the impairment tests. The markets for crude oil and natural gas have a history of significant price volatility. Although prices will occasionally drop precipitously, industry prices over the long term will continue to be driven by market supply and demand. On the supply side, industry production from mature fields is declining, but this is being offset by production from new discoveries and field developments. OPEC production policies also have an impact on world oil supplies. The demand side is largely a function of global economic growth. The relative growth/decline in supply versus demand will determine industry prices over the long term and these cannot be accurately predicted. Accordingly, any impairment tests that the Corporation performs make use of the Corporation's long-term price assumptions for the crude oil and natural gas markets, petroleum products and chemicals. These are the same price assumptions that are used in the Corporation's annual planning and budgeting processes and are also used for capital investment decisions. The corporate plan is a fundamental annual management process that is the basis for setting near-term operating and capital objectives in addition to providing the longer-term economic assumptions used for investment evaluation purposes. Annual volumes are based on individual field production profiles, which are also updated annually. Prices for natural gas and other products are based on corporate plan assumptions developed annually by major region and used for investment evaluation purposes. Cash flow estimates for impairment testing exclude the use of derivative instruments.

Supplemental information regarding oil and gas results of operations, capitalized costs and reserves can be found on pages A54 to A61. The standardized measure of discounted future cash flows on pages A62 and A63 is based on the year-end 2004 price applied for all future years, as required under Statement of Financial Accounting Standards No. 69 (FAS 69). Future prices used for any impairment tests will vary from the one used in the FAS 69 disclosure, and could be lower or higher for any given year.

Suspended Exploratory Well Costs

The Corporation carries as an asset the cost of drilling exploratory wells that find sufficient quantities of reserves to justify their completion as producing wells if the required capital expenditure is made and drilling of additional exploratory wells is under way or firmly planned for the near future. Once exploration activities demonstrate that sufficient quantities of commercially producible reserves have been discovered, continued capitalization is dependent on project reviews, which take place at least annually, to ensure that sufficient progress toward ultimate development of the reserves is being achieved. Exploratory well costs not meeting these criteria are charged to expense.

The following table summarizes the year-end suspended exploratory well balances:

Exploration Suspended Drilling Costs		2004		2003
		(millions of dollars)
Projects with drilling in past 12 months (1)		$	207	$	324
Projects with future exploratory drilling planned			145		76
Other exploratory activities planned			16		34

	Subtotal—Projects with recent drilling or planned exploratory activity		368		434

Projects requiring major capital expenditures			621		519
Other projects progressing toward commercialization			81		140

	Subtotal—Projects with completed exploratory activity		702		659

	Total	$	1,070	$	1,093

Number of wells at year end			142		189

(1): Includes $68 million for 2004 and $107 million for 2003 for wells older than one year on projects with additional exploratory drilling in the past 12 months as part of an overall exploration program to evaluate the property.

The category "Other exploratory activities planned" includes wells whose continuing commercialization is dependent upon the results of additional seismic work that is either under way or planned. Significant advances in subsurface evaluation technologies have eliminated the need to drill as many exploratory wells as were required when FAS 19 was adopted in the late 1970s. The use of high-resolution 3-D seismic is a cost-effective technology that can eliminate the need for additional drilling in further defining the resource potential of a property.

The "Projects requiring major capital expenditures" category represents wells that require large capital projects (the Corporation's share of development costs typically greater than $50 million, excluding developmental drilling) to develop significant amounts of hydrocarbon

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

resources discovered by these wells. Sufficient quantities of hydrocarbons have been discovered to justify a project. The timing for progressing these major projects to development is dependent upon factors such as lengthy negotiations with host governments, distance from markets and existing infrastructure, the effective deployment of existing technology, negotiations with joint venture partners on development plans and negotiations of long-term sales contracts, particularly if the reserves are in natural gas. These development activities are necessary to confirm whether the wells have found reserves that can be classified as proved, and often involve interfaces with a wide variety of regulatory bodies at the local, state and/or national level. In many cases required government approvals of proposed development plans have already been obtained, while in other cases development plan approvals are pending while the Corporation satisfies other regulatory requirements to maintain our rights to the resources.

The "Other projects progressing to commercialization" category includes both discoveries made near existing or already planned infrastructure, where the timing of development is driven by pipeline or facility capacity limitations, and smaller developments whose project timing is driven by negotiations with governments and co-venturers or the structuring of volume commitments under long-term sales contracts. In both cases, the existence of sufficient quantities of hydrocarbons to justify a project has been established, and deferral of well costs is a function of development timing.

The Corporation has a long history of converting exploration discoveries into successful projects and continued to progress activity on the suspended wells in 2004. Timing of proved reserve bookings will vary by individual project but the active, ongoing engagement of the Corporation's Upstream organization to progress these opportunities is our standard practice. The following table provides further detail on wells included in the "Projects requiring major capital expenditures" and "Other projects progressing toward commercialization" categories:

Country/Project		2004		Year-End 2004 Wells	Years Wells Drilled	Anticipated Year of Proved Reserve Booking	Comment
		(millions of dollars)
Angola
	—Clochas/Tchihumba	$	20	2	2003	2008-2009	Development awaiting capacity in existing infrastructure.
	—Marimba		11	1	2001	2009-2010	Development in progress on first phase of Marimba deepwater project with proved reserves booked; development of second phase awaiting capacity in existing/planned infrastructure.
	—Mavacola		12	2	2001-2002	2007-2008	Development awaiting capacity in existing/planned infrastructure; planned subsea tieback to floating production system; submission of Declaration of Commerciality anticipated in 2005.
	—Mondo/Saxi/Batuque		26	4	2000-2002	2005-2006	Planned subsea tieback to floating production system; initial project funding in 2003.
	—Orquidea/Violeta		6	2	1999-2001	2007-2008	Planned subsea tieback to floating production system; high-resolution 3-D seismic survey in 2004; submission of Declaration of Commerciality anticipated in 2005.
Australia
	—Gorgon/Jansz		73	17	1980-2003	2006-2007	Gorgon and Jansz resources to be developed as integrated LNG project; land access rights for onshore plant secured; negotiations with partners on unitized development plan are in progress.
	—Kipper/Other		10	3	1986-2001	2005-2006	Bass Strait project in design phase and progressing toward funding; planned tie-in to existing platform.
Bolivia
	—Itau		38	2	1999-2001	2008-2009	Changes in hydrocarbon law that would impact development of the Itau resource have been proposed and are being debated in Bolivian legislature; resolution required before a development plan can be finalized.
Canada
	—Hebron		32	2	1999-2000	2007-2008	Actively working development concept with co-venturer; recent efforts focused on further technical evaluation of wells and reservoir using seismic reprocessing and well core analysis.
	—Terra Nova		4	1	2001	2005-2006	Finalizing drilling plans to develop far east area of field in 2005.

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Indonesia
	—Cepu		46	6	1998-2001	2005-2006	Negotiations with government to extend license term are in progress; initial project funding and engineering began in 2001 with timely development anticipated upon conclusion of negotiations.
	—Natuna		118	4	1981-1983	2009-2010	Intent to proceed to the next phase of development communicated to government in 2004; discussions with government on near-term development work plans are in progress.
Nigeria
	—Etoro-Isobo		9	2	2002	2010-2011	Satellite development offshore Nigeria which will tie back to an existing production facility.
	—Other		16	5	2001-2002	2007-2012	Actively pursuing development of several smaller offshore satellite discoveries, which will tie back to existing production facilities.
Norway
	—Fram		22	3	1991-1997	2005-2006	Initial project funding began in 2003 and initial design work was completed in 2004; first production anticipated in 2006.
	—Lavrans		22	3	1995-1999	2016-2017	Development awaiting capacity in existing/planned infrastructure; planned subsea tieback to existing floating production system.
	—Skarv/Snadd		24	5	1998-2001	2007-2008	Assessment of export infrastructure alternatives and negotiations with partners on development plan are in progress; submission of Plan of Development anticipated in 2005.
	—Other		10	5	1992-2002	2005-2008	Progressing several smaller developments expected to result in proved reserve additions over next few years.
Papua New Guinea
	—Hides		35	2	1993-1998	2006-2007	Early engineering studies complete; negotiations with customers on sales terms are in progress; initial project funding and front-end engineering and design began in 2004.
Russia
	—Sakhalin 1, Phase 3		26	4	1996-1998	2010-2011	Actively progressing the third phase of the Sakhalin 1 project to utilize capacity in facilities and infrastructure in Phase 1. Phase 1 development under way with first production anticipated in 2005.
United Kingdom
	—Merganser		13	3	1995	2005-2006	Development awaiting capacity in existing infrastructure; planned subsea tieback to existing U.K. North Sea facilities.
	—Puffin		42	4	1981-1986	2007-2008	Development awaiting capacity in existing infrastructure; planned tieback to existing U.K. North Sea production facility.
	—Other		24	4	2001-2003	2005-2007	Several smaller projects whose development timing is governed by capacity availability in existing infrastructure.
United States
	—Point Thomson		28	2	1977-1980	2006-2007	Annual Plan of Development work program approved by state; initial engineering design for gas cycling option complete; also progressing alternate development options including tie-in to proposed Alaska gas pipeline.
Other
	—Various		35	10	1979-2003	2005-2015

Total		$	702	98

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The timing of when proved reserves will be booked on the projects noted above is an estimate and subject to the uncertainties discussed under the heading "Factors Affecting Future Results" in Item 1 of ExxonMobil's 2004 Form 10-K. Actual results could differ from estimates due to the factors noted in Item 1.

The following table shows the amount of suspended well costs that were written off in the past three years after the Corporation made the decision that projects were not commercially viable and proved reserves would not be booked. Total exploration expenses, including nonconsolidated interests, are also shown to provide context on the suspended well write-offs.

	2004		2003		2002
	(millions of dollars)
Suspended well write-offs	$	98	$	238	$	22
Total exploration expense		1,133		1,033		957

Consolidations

The consolidated financial statements include the accounts of those significant subsidiaries that the Corporation controls. They also include the Corporation's undivided interests in upstream assets and liabilities. Amounts representing the Corporation's percentage interest in the underlying net assets of other significant affiliates that it does not control, but exercises significant influence, are included in "Investments and advances"; the Corporation's share of the net income of these companies is included in the consolidated statement of income caption "Income from equity affiliates." The accounting for these nonconsolidated companies is referred to as the equity method of accounting.

Majority ownership is normally the indicator of control that is the basis on which subsidiaries are consolidated. However, certain factors may indicate that a majority-owned investment is not controlled and therefore should be accounted for using the equity method of accounting. These factors occur where the minority shareholders are granted by law or by contract substantive participating rights. These include the right to approve operating policies, expense budgets, financing and investment plans and management compensation and succession plans.

The Corporation consolidates certain affiliates identified as variable-interest entities in which it has less than a majority ownership, because of guarantees or other arrangements that create majority economic interests in those affiliates that are greater than the Corporation's voting interests.

Additional disclosures of summary balance sheet and income information for those subsidiaries accounted for under the equity method of accounting can be found in note 7 on page A34. The Corporation believes this to be important information necessary to a full understanding of the Corporation's financial statements.

Investments in companies that are partially owned by the Corporation are integral to the Corporation's operations. In some cases they serve to balance worldwide risks and in others they provide the only available means of entry into a particular market or area of interest. The other parties who also have an equity interest in these companies are either independent third parties or host governments that share in the business results according to their percentage ownership. The Corporation does not invest in these companies in order to remove liabilities from its balance sheet. In fact, the Corporation has long been on record supporting an alternative accounting method that would require each investor to consolidate its percentage share of all assets and liabilities in these partially owned companies rather than only the percentage in the net equity. This method of accounting for investments in partially owned companies is not permitted by GAAP except where the investments are in the direct ownership of a share in the upstream assets and liabilities. However, for purposes of calculating return on average capital employed, which is not covered by GAAP standards, the Corporation includes its share of debt of these partially owned companies in the determination of average capital employed.

Annuity Benefits

The Corporation and its affiliates sponsor approximately 100 defined-benefit (pension) plans in about 50 countries. The funding arrangement for each plan depends on the prevailing practices and regulations of the countries where the Corporation operates. Note 17, pages A48 to A51, provides details on pension obligations, fund assets and pension expense.

Some of these plans (primarily non-U.S.) provide pension benefits that are paid directly by their sponsoring affiliates out of corporate cash flow rather than a separate pension fund. Book reserves are established for these plans because tax conventions and regulatory practices do not encourage advance funding. The portion of the pension cost attributable to employee service is expensed as services are rendered. The portion attributable to the increase in pension obligations due to the passage of time is expensed over the term of the obligations, which ends when all benefits are paid. The primary difference in pension expense for unfunded versus funded plans is that pension expense for funded plans also includes a credit for the expected long-term return on fund assets.

For funded plans, including many in the U.S., pension obligations are financed in advance through segregated assets or insurance arrangements. These plans are managed in compliance with the requirements of governmental authorities, and meet or exceed required funding levels as measured by relevant actuarial and government standards at the mandated measurement dates. In determining liabilities and required contributions, these standards often require approaches and assumptions that differ from those used for accounting purposes. Contributions to funded plans totaled $473 million in 2004 (all non-U.S.).

The Corporation will continue to make contributions to these funded plans as necessary. All defined-benefit pension obligations, regardless of the funding status of the underlying plans, are fully supported by the financial strength of the Corporation or the respective sponsoring affiliate.

Pension accounting requires explicit assumptions regarding, among others, the long-term expected earnings rate on fund assets, the discount rate for the benefit obligations, and the long-term rate for future salary increases. All the pension assumptions are reviewed annually by outside actuaries and senior management. These assumptions are adjusted only as appropriate to reflect changes in market rates and outlook. For example, the long-term expected earnings rate on U.S. pension plan assets in 2004 was 9.0 percent. This compares to an actual rate of return over the past decade of 12.5 percent. The Corporation establishes the long-term expected rate of return by developing a forward-looking, long-term return assumption for each asset class, taking into account factors such as the expected

A22

real return for the specific asset class and inflation. A single, long-term rate of return is then calculated as the weighted average of the target asset allocation and the long-term return assumption for each asset class. A worldwide reduction of 0.5 percent in the pension fund earnings rate would increase annual pension expense by approximately $85 million before tax.

Under GAAP, differences between actual returns on fund assets versus the long-term expected return are not recorded in the year that the difference occurs, but rather are amortized in pension expense, along with other actuarial gains and losses, over the expected remaining service life of employees.

Due to the general increase in the market value of pension assets, pension expense declined from $1,938 million in 2003 (U.S. $1,015 million, non-U.S. $923 million) to $1,630 million in 2004 (U.S. $764 million, non-U.S. $866 million).

Litigation and Other Contingencies

A variety of claims have been made against ExxonMobil and certain of its consolidated subsidiaries in a number of pending lawsuits and tax disputes. These are summarized on pages A13 and A14, with a more extensive discussion included in note 16 on pages A46 and A47.

GAAP requires that liabilities for contingencies be recorded when it is probable that a liability has been incurred by the date of the balance sheet and that the amount can be reasonably estimated. These amounts are not reduced by amounts that may be recovered under insurance or claims against third parties, but undiscounted receivables from insurers or other third parties may be accrued separately. The Corporation revises such accruals in light of new information.

Significant management judgment is required related to contingent liabilities and the outcome of litigation because both are difficult to predict. However, the Corporation has been successful in defending litigation in the past, and actual payments have not been material. In the Corporation's experience, large claims often do not result in large awards. Large awards are often reversed or substantially reduced as a result of appeal or settlement.

Foreign Currency Translation

The method of translating the foreign currency financial statements of the Corporation's international subsidiaries into U.S. dollars is prescribed by GAAP. Under these principles, it is necessary to select the functional currency of these subsidiaries. The functional currency is the currency of the primary economic environment in which the subsidiary operates. Management selects the functional currency after evaluating this economic environment. Downstream and chemical operations normally use the local currency, except in highly inflationary countries, primarily Latin America, as well as in Singapore, which uses the U.S. dollar, because it predominantly sells into the U.S. dollar export market. Upstream operations also use the local currency as the functional currency, except where crude and natural gas production is predominantly sold in the export market in U.S. dollars. These operations, which use the U.S. dollar as their functional currency, are in Malaysia, Indonesia, Angola, Nigeria, Equatorial Guinea and the Middle East.

Factors considered by management when determining the functional currency for a subsidiary include: the currency used for cash flows related to individual assets and liabilities; the responsiveness of sales prices to changes in exchange rates; whether sales are into local markets or exported; the currency used to acquire raw materials, labor, services and supplies; sources of financing; and significance of intercompany transactions.

A23

MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Management, including the Corporation's chief executive officer, principal accounting officer and principal financial officer, is responsible for establishing and maintaining adequate internal control over the Corporation's financial reporting. Management conducted an evaluation of the effectiveness of internal control over financial reporting based on the Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that Exxon Mobil Corporation's internal control over financial reporting was effective as of December 31, 2004.

Management's assessment of the effectiveness of internal control over financial reporting as of December 31, 2004, was audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which is included herein.



Lee R. Raymond Chief Executive Officer	Patrick T. Mulva Vice President and Controller (Principal Accounting Officer)	Donald D. Humphreys Vice President and Treasurer (Principal Financial Officer)

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Shareholders of Exxon Mobil Corporation:

We have completed an integrated audit of Exxon Mobil Corporation's 2004 consolidated financial statements and of its internal control over financial reporting as of December 31, 2004, and audits of its 2003 and 2002 consolidated financial statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Our opinions, based on our audits, are presented below.

Consolidated financial statements

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, shareholders' equity and cash flows appearing on pages A26 to A53 present fairly, in all material respects, the financial position of Exxon Mobil Corporation and its subsidiaries at December 31, 2004, and 2003, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2004, in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Corporation'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 the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit of financial statements 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 our opinion.

As discussed in note 9 to the consolidated financial statements, the Corporation changed its method of accounting for asset retirement obligations in 2003.

A24

Internal control over financial reporting

Also, in our opinion, management's assessment, included in the accompanying Management's Report on Internal Control Over Financial Reporting, that the Corporation maintained effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), is fairly stated, in all material respects, based on those criteria. Furthermore, in our opinion, the Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control—Integrated Framework issued by the COSO. The Corporation's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express opinions on management's assessment and on the effectiveness of the Corporation's internal control over financial reporting based on our audit. We conducted our audit of internal control over financial reporting in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. An audit of internal control over financial reporting includes obtaining an understanding of internal control over financial reporting, evaluating management's assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we consider necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.

A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the company's assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Dallas, Texas
February 28, 2005

A25

CONSOLIDATED STATEMENT OF INCOME

			Note Reference Number	2004		2003		2002
				(millions of dollars)
Revenues and other income
	Sales and other operating revenue (1)			$	291,252	$	237,054	$	200,949
	Income from equity affiliates		7		4,961		4,373		2,066
	Other income				1,822		5,311		1,491

		Total revenues and other income		$	298,035	$	246,738	$	204,506

Costs and other deductions
	Crude oil and product purchases			$	139,224	$	107,658	$	90,950
	Production and manufacturing expenses				23,225		21,260		17,831
	Selling, general and administrative expenses				13,849		13,396		12,356
	Depreciation and depletion				9,767		9,047		8,310
	Exploration expenses, including dry holes				1,098		1,010		920
	Merger-related expenses		3		—		—		410
	Interest expense				638		207		398
	Excise taxes (1)		19		27,263		23,855		22,040
	Other taxes and duties		19		40,954		37,645		33,572
	Income applicable to minority and preferred interests				776		694		209

		Total costs and other deductions		$	256,794	$	214,772	$	186,996

Income before income taxes				$	41,241	$	31,966	$	17,510
	Income taxes		19		15,911		11,006		6,499

Income from continuing operations				$	25,330	$	20,960	$	11,011
	Discontinued operations, net of income tax		2		—		—		449
	Cumulative effect of accounting change, net of income tax				—		550		—

Net income				$	25,330	$	21,510	$	11,460

Net income per common share (dollars)			12
	Income from continuing operations			$	3.91	$	3.16	$	1.62
	Discontinued operations, net of income tax				—		—		0.07
	Cumulative effect of accounting change, net of income tax				—		0.08		—

	Net income			$	3.91	$	3.24	$	1.69

Net income per common share—assuming dilution (dollars)			12
	Income from continuing operations			$	3.89	$	3.15	$	1.61
	Discontinued operations, net of income tax				—		—		0.07
	Cumulative effect of accounting change, net of income tax				—		0.08		—

	Net income			$	3.89	$	3.23	$	1.68

(1): Sales and other operating revenue includes excise taxes of $27,263 million for 2004, $23,855 million for 2003 and $22,040 million for 2002.

The information on pages A30 through A53 is an integral part of these statements.

A26

CONSOLIDATED BALANCE SHEET

					Note Reference Number	Dec. 31 2004			Dec. 31 2003
						(millions of dollars)
Assets
	Current assets
		Cash and cash equivalents				$	18,531		$	10,626
		Cash and cash equivalents—restricted			4, 16		4,604			—
		Notes and accounts receivable, less estimated doubtful amounts			6		25,359			24,309
		Inventories
			Crude oil, products and merchandise		1		8,136			7,665
			Materials and supplies				1,351			1,292
		Prepaid taxes and expenses					2,396			2,068

				Total current assets		$	60,377		$	45,960
Investments and advances					8		18,404			15,535
Property, plant and equipment, at cost, less accumulated depreciation and depletion					9		108,639			104,965
Other assets, including intangibles, net							7,836			7,818

				Total assets		$	195,256		$	174,278

Liabilities
	Current liabilities
		Notes and loans payable			6	$	3,280		$	4,789
		Accounts payable and accrued liabilities			6		31,763			28,445
		Income taxes payable					7,938			5,152

				Total current liabilities		$	42,981		$	38,386
	Long-term debt				14		5,013			4,756
	Annuity reserves				17		10,850			9,609
	Accrued liabilities						6,279			5,283
	Deferred income tax liabilities				19		21,092			20,118
	Deferred credits and other long-term obligations						3,333			2,829
	Equity of minority and preferred shareholders in affiliated companies						3,952			3,382

				Total liabilities		$	93,500		$	84,363

Commitments and contingencies					16
Shareholders' equity
	Benefit plan related balances					$	(1,014	)	$	(634	)
	Common stock without par value (9,000 million shares authorized)						5,067			4,468
	Earnings reinvested						134,390			115,956
	Accumulated other nonowner changes in equity
		Cumulative foreign exchange translation adjustment					3,598			1,421
		Minimum pension liability adjustment					(2,499	)		(2,446	)
		Unrealized gains/(losses) on stock investments					428			511
	Common stock held in treasury (1,618 million shares in 2004 and 1,451 million shares in 2003)						(38,214	)		(29,361	)

				Total shareholders' equity		$	101,756		$	89,915

				Total liabilities and shareholders' equity		$	195,256		$	174,278

The information on pages A30 through A53 is an integral part of these statements.

A27

CONSOLIDATED STATEMENT OF SHAREHOLDERS' EQUITY

				2004						2003					2002
			Note Reference Number	Shareholders' Equity			Nonowner Changes in Equity			Shareholders' Equity			Nonowner Changes in Equity		Shareholders' Equity			Nonowner Changes in Equity
				(millions of dollars)
Benefit plan related balances
	At beginning of year			$	(634	)				$	(450	)			$	(159	)
		Restricted stock award			(555	)					(358	)				(361	)
		Amortization			173						107					11
		Other			2						67					59

	At end of year			$	(1,014	)				$	(634	)			$	(450	)

Common stock			12
	At beginning of year				4,468						4,217					3,789
		Issued			—						—					—
		Other			599						251					428

	At end of year			$	5,067					$	4,468				$	4,217

Earnings reinvested
	At beginning of year				115,956						100,961					95,718
		Net income for the year			25,330		$	25,330			21,510		$	21,510		11,460		$	11,460
		Dividends—common shares			(6,896	)					(6,515	)				(6,217	)

	At end of year			$	134,390					$	115,956				$	100,961

Accumulated other nonowner changes in equity
	At beginning of year				(514	)					(6,054	)				(6,590	)
		Foreign exchange translation adjustment			2,177			2,177			4,436			4,436		2,932			2,932
		Minimum pension liability adjustment	17		(53	)		(53	)		514			514		(2,425	)		(2,425	)
		Unrealized gains/(losses) on stock investments			(83	)		(83	)		590			590		29			29

	At end of year			$	1,527					$	(514	)			$	(6,054	)

		Total					$	27,371					$	27,050				$	11,996

Common stock held in treasury
	At beginning of year				(29,361	)					(24,077	)				(19,597	)
		Acquisitions, at cost			(9,951	)					(5,881	)				(4,798	)
		Dispositions			1,098						597					318

	At end of year			$	(38,214	)				$	(29,361	)			$	(24,077	)

Shareholders' equity at end of year				$	101,756					$	89,915				$	74,597


				Share Activity
				2004						2003					2002
				(millions of shares)
Common stock
	Issued		12
	At beginning of year				8,019						8,019					8,019
		Issued			—						—					—

	At end of year				8,019						8,019					8,019

Held in treasury			12
	At beginning of year				(1,451	)					(1,319	)				(1,210	)
		Acquisitions			(218	)					(163	)				(127	)
		Dispositions			51						31					18

	At end of year				(1,618	)					(1,451	)				(1,319	)

Common shares outstanding at end of year					6,401						6,568					6,700

The information on pages A30 through A53 is an integral part of these statements.

A28

CONSOLIDATED STATEMENT OF CASH FLOWS

				Note Reference Number	2004			2003			2002
					(millions of dollars)
Cash flows from operating activities
	Net income
		Accruing to ExxonMobil shareholders			$	25,330		$	21,510		$	11,460
		Accruing to minority and preferred interests				776			694			209
	Cumulative effect of accounting change, net of income tax					—			(550	)		—
	Adjustments for noncash transactions
		Depreciation and depletion				9,767			9,047			8,310
		Deferred income tax charges/(credits)				(1,134	)		1,827			297
		Annuity provisions				886			(1,489	)		(500	)
		Accrued liability provisions				806			264			(90	)
	Dividends received greater than/(less than) equity in current earnings of equity companies					(1,643	)		(402	)		(170	)
	Changes in operational working capital, excluding cash and debt
		Reduction/(increase)	—Notes and accounts receivable			(472	)		(1,286	)		(305	)
			—Inventories			(223	)		(100	)		353
			—Prepaid taxes and expenses			11			42			32
		Increase/(reduction)	—Accounts and other payables			6,333			1,130			365
	Ruhrgas transaction			5		—			(2,240	)		1,466
	All other items—net					114			51			(159	)

		Net cash provided by operating activities			$	40,551		$	28,498		$	21,268

Cash flows from investing activities
	Additions to property, plant and equipment				$	(11,986	)	$	(12,859	)	$	(11,437	)
	Sales of subsidiaries, investments and property, plant and equipment			5		2,754			2,290			2,793
	Increase in restricted cash and cash equivalents			4, 16		(4,604	)		—			—
	Additional investments and advances					(2,287	)		(809	)		(2,012	)
	Collection of advances					1,213			536			898

		Net cash used in investing activities			$	(14,910	)	$	(10,842	)	$	(9,758	)

Cash flows from financing activities
	Additions to long-term debt				$	470		$	127		$	396
	Reductions in long-term debt					(562	)		(914	)		(246	)
	Additions to short-term debt					450			715			751
	Reductions in short-term debt					(2,243	)		(1,730	)		(927	)
	Additions/(reductions) in debt with less than 90-day maturity					(66	)		(322	)		(281	)
	Cash dividends to ExxonMobil shareholders					(6,896	)		(6,515	)		(6,217	)
	Cash dividends to minority interests					(215	)		(430	)		(169	)
	Changes in minority interests and sales/(purchases) of affiliate stock					(215	)		(247	)		(161	)
	Common stock acquired					(9,951	)		(5,881	)		(4,798	)
	Common stock sold					960			434			299

		Net cash used in financing activities			$	(18,268	)	$	(14,763	)	$	(11,353	)

Effects of exchange rate changes on cash					$	532		$	504		$	525

Increase/(decrease) in cash and cash equivalents					$	7,905		$	3,397		$	682
Cash and cash equivalents at beginning of year						10,626			7,229			6,547

Cash and cash equivalents at end of year					$	18,531		$	10,626		$	7,229

The information on pages A30 through A53 is an integral part of these statements.

A29

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The accompanying consolidated financial statements and the supporting and supplemental material are the responsibility of the management of Exxon Mobil Corporation.

The Corporation's principal business is energy, involving the worldwide exploration, production, transportation and sale of crude oil and natural gas (Upstream) and the manufacture, transportation and sale of petroleum products (Downstream). The Corporation is also a major worldwide manufacturer and marketer of petrochemicals (Chemical), and participates in electric power generation (Upstream).

The preparation of financial statements in conformity with U.S. Generally Accepted Accounting Principles (GAAP) requires management to make estimates that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. Actual results could differ from these estimates. Certain reclassifications to prior years have been made to conform to the 2004 presentation.

1. Summary of Accounting Policies

Principles of Consolidation. The consolidated financial statements include the accounts of those significant subsidiaries owned directly or indirectly with more than 50 percent of the voting rights held by the Corporation, and for which other shareholders do not possess the right to participate in significant management decisions. They also include the Corporation's share of the undivided interest in upstream assets and liabilities. Additionally, the Corporation consolidates certain affiliates identified as variable-interest entities in which it has less than a majority ownership, because of guarantees or other arrangements that create majority economic interests in those affiliates that are greater than the Corporation's voting interests.

Amounts representing the Corporation's percentage interest in the underlying net assets of other significant subsidiaries and less-than-majority-owned companies in which a significant equity ownership interest is held, are included in "Investments and advances"; the Corporation's share of the net income of these companies is included in the consolidated statement of income caption "Income from equity affiliates." The Corporation's share of the cumulative foreign exchange translation adjustment for equity method investments is reported in consolidated shareholder's equity. Evidence of loss in value that might indicate impairment of investments in companies accounted for on the equity method is assessed to determine if such evidence represents a loss in value of the Corporation's investment that is other than temporary. Examples of key indicators include a history of operating losses, a negative earnings and cash flow outlook, significant downward revisions to oil and gas reserves, and the financial condition and prospects for the investee's business segment or geographic region. If evidence of an other than temporary loss in fair value below carrying amount is determined, an impairment is recognized. In the absence of market prices for the investment, discounted cash flows are used to assess fair value.

Revenue Recognition. The Corporation generally sells crude oil, natural gas and petroleum and chemical products under short-term agreements at prevailing market prices. In some cases (e.g., natural gas), products may be sold under long-term agreements, with periodic price adjustments. In all cases, revenues are recognized when the products are delivered, which occurs when the customer has taken title and has assumed the risks and rewards of ownership, prices are fixed or determinable and collectibility is reasonably assured.

Revenues include the sales portion of certain crude oil, natural gas, petroleum product, and chemical transactions settled in cash where the Corporation contemporaneously negotiates purchases with the same counterparty under contractual arrangements that establish the agreement terms either jointly, in a single contract, or separately, in individual contracts. The purchases are recorded in crude oil and product purchases. These transactions are commonly called buy/sell transactions. Together with nonmonetary exchanges as well as independently transacted purchases and sales of crude oil and petroleum products, buy/sell transactions are used to ensure that the right crude oil is at the appropriate refineries at the right time and that the appropriate products are available to meet consumer demands. This activity is called balancing the supply system.

Each buy/sell transaction is composed of a separate purchase and a separate sale transaction and therefore is accounted for as any other independently transacted monetary purchase or sale. These monetary transactions are accounted for as cost of sales and revenues, measured at fair value as agreed upon by a willing buyer and a willing seller. They are entered into with our normal suppliers and customers for substantive business purposes and invoiced for the full fair value of the transaction. Physical delivery is required and each counterparty is legally liable for the full value of the shipment. Each separate transaction transfers title to the crude oil or petroleum product, and delivery is not conditioned on any other transaction. Each separate transaction is subject to the risk of loss, credit risk, environmental risk, and counterparty nonperformance risk. These transactions are undertaken by all operating segments, but the majority occur in the Downstream.

Accounting for the sales portion of buy/sell transactions in revenues, measured at fair value, has been the predominant industry practice for decades, based on the Corporation's knowledge of the industry. The characteristics of these transactions are indistinguishable from those of any other monetary sales transaction. This accounting practice has recently been addressed in Emerging Issues Task Force (EITF) Issue No. 03-11, "Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133 and Not Held for Trading Purposes as Defined in Issue No. 02-3." While Issue 03-11 addresses the issue of gross versus net classification for derivative instruments, it also provides guidance for buy/sell transactions that are not accounted for as derivative instruments. In Issue 03-11, the EITF concluded that the determination of whether contracts not held for trading purposes should be reported in the income statement on a gross or net basis is a matter of judgment that depends on the relevant facts and circumstances. In addition, indicators for gross revenue reporting provided in EITF Issue No. 99-19, "Reporting Revenue Gross as a Principal versus Net as an Agent" are consistent with many of the characteristics found in buy/sell transactions. These indicators are useful in providing guidance to assist in the determination of the appropriate accounting policy. In the judgment of management, the relevant facts and circumstances support accounting for these transactions in revenues, measured at fair value. The Corporation does not believe that these buy/sell transactions fall under the scope of APB Opinion 29, "Accounting for Nonmonetary Transactions" because they are monetary transactions.

A30

Revenues from the production of natural gas properties in which the Corporation has an interest with other producers are recognized on the basis of the Corporation's net working interest. Differences between actual production and net working interest volumes are not significant.

Derivative Instruments. The Corporation makes limited use of derivatives. Derivative instruments are not held for trading purposes nor do they have leverage features. When the Corporation does enter into derivative transactions, it is to offset exposures associated with interest rates, foreign currency exchange rates and hydrocarbon prices. The gains and losses resulting from the changes in fair value of these instruments are recorded in income, except when the instruments are designated as hedging the currency exposure of net investments in foreign subsidiaries, in which case they are recorded in the cumulative foreign exchange translation account, as part of shareholders' equity.

The gains and losses on derivative instruments that are designated as fair value hedges (i.e., those hedging the exposure to changes in the fair value of an asset or a liability or the changes in the fair value of a firm commitment) are offset by the gains and losses from the changes in fair value of the hedged items, which are also recognized in income. Most of these designated hedges are entered into at the same time that the hedged items are transacted; they are fully effective and in combination with the offsetting hedged items result in no net impact on income. In some situations, the Corporation has chosen not to designate certain immaterial derivatives used for hedging economic exposure as hedges for accounting purposes due to the excessive administrative effort that would be required to account for these items as hedging transactions. These derivatives are recorded on the balance sheet at fair value and the gains and losses arising from changes in fair value are recognized in income. All derivatives activity is immaterial.

Inventories. Crude oil, products and merchandise inventories are carried at the lower of current market value or cost (generally determined under the last-in, first-out method—LIFO). Inventory costs include expenditures and other charges (including depreciation) directly and indirectly incurred in bringing the inventory to its existing condition and location. Selling expenses and general and administrative expenses are reported as period costs and excluded from inventory cost. Inventories of materials and supplies are valued at cost or less.

Crude oil, products and merchandise as of year-end 2004 and 2003 consist of the following:

		2004		2003
		(billions of dollars)
Petroleum products		$	3.4	$	3.2
Crude oil			2.3		2.2
Chemical products			2.1		1.9
Gas/other			0.3		0.4

	Total	$	8.1	$	7.7

Property, Plant and Equipment. Depreciation, depletion and amortization, based on cost less estimated salvage value of the asset, are primarily determined under either the unit-of-production method or the straight-line method, which is based on estimated asset service life taking obsolescence into consideration. Maintenance and repairs, including planned major maintenance, are expensed as incurred. Major renewals and improvements are capitalized and the assets replaced are retired.

The Corporation continues to carry as an asset the cost of drilling exploratory wells that find sufficient quantities of reserves to justify their completion as producing wells if the required capital expenditure is made and drilling of additional exploratory wells is under way or firmly planned for the near future. Once exploration activities demonstrate that sufficient quantities of commercially producible reserves have been discovered, continued capitalization is dependent on project reviews, which take place at least annually, to ensure that sufficient progress toward ultimate development of the reserves is being achieved. Exploratory well costs not meeting these criteria are charged to expense.

Acquisition costs of proved properties are amortized using a unit-of-production method, computed on the basis of total proved oil and gas reserves. Significant unproved properties are assessed for impairment individually and valuation allowances against the capitalized costs are recorded based on the estimated economic chance of success and the length of time that the Corporation expects to hold the properties. The cost of properties that are not individually significant are aggregated by groups and amortized over the average holding period of the properties of the groups. The valuation allowances are reviewed at least annually. Other exploratory expenditures, including geophysical costs, other dry hole costs and annual lease rentals, are expensed as incurred.

Unit-of-production depreciation is applied to property, plant and equipment, including capitalized exploratory drilling and development costs, associated with productive depletable extractive properties, all in the Upstream segment. Unit-of-production rates are based on proved developed reserves, which are oil, gas and other mineral reserves estimated to be recoverable from existing facilities using current operating methods. Additional oil and gas to be obtained through the application of improved recovery techniques is included when, or to the extent that, the requisite commercial-scale facilities have been installed and the required wells have been drilled.

Under the unit-of-production method, oil and gas volumes are considered produced once they have been measured through meters at custody transfer or sales transaction points at the outlet valve on the lease or field storage tank.

Production costs are expensed as incurred. Production involves lifting the oil and gas to the surface and gathering, treating, field processing and field storage of the oil and gas. The production function normally terminates at the outlet valve on the lease or field production storage tank. Production costs are those incurred to operate and maintain the Corporation's wells and related equipment and facilities. They become part of the cost of oil and gas produced. These costs, sometimes referred to as lifting costs, include such items as labor costs to operate the wells and related equipment; repair and maintenance costs on the wells and equipment; materials, supplies and energy costs required to operate the wells and related equipment; and administrative expenses related to the production activity.

Gains on sales of proved and unproved properties are only recognized when there is no uncertainty about the recovery of costs applicable

A31

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

to any interest retained or where there is no substantial obligation for future performance by the Corporation. Losses on properties sold are recognized when incurred or when the properties are held for sale and the fair value of the properties is less than the carrying value.

Proved oil and gas properties held and used by the Corporation are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amounts may not be recoverable. Assets are grouped at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets.

The Corporation estimates the future undiscounted cash flows of the affected properties to judge the recoverability of carrying amounts. Cash flows used in impairment evaluations are developed using annually updated corporate plan investment evaluation assumptions for crude oil commodity prices and foreign currency exchange rates. Annual volumes are based on individual field production profiles, which are also updated annually. Prices for natural gas and other products are based on corporate plan assumptions developed annually by major region and also for investment evaluation purposes. Cash flow estimates for impairment testing exclude derivative instruments.

Impairment analyses are generally based on proved reserves. Where probable reserves exist, an appropriately risk-adjusted amount of these reserves may be included in the impairment evaluation. Impairments are measured by the amount the carrying value exceeds the fair value.

Asset Retirement Obligations and Environmental Costs. The Corporation incurs retirement obligations for its upstream assets. The fair values of these obligations are recorded as liabilities on a discounted basis, which is typically at the time the assets are installed. The costs associated with these liabilities are capitalized as part of the related assets and depreciated as the reserves are produced. Over time, the liabilities are accreted for the change in present value. Asset retirement obligations are not recorded for downstream and chemical facilities, because such potential obligations cannot be measured since it is not possible to estimate the settlement dates.

Liabilities for environmental costs are recorded when it is probable that obligations have been incurred and the amounts can be reasonably estimated. These liabilities are not reduced by possible recoveries from third parties, and projected cash expenditures are not discounted.

Foreign Currency Translation. The "functional currency" for translating the accounts of the majority of downstream and chemical operations outside the U.S. is the local currency. Local currency is also used for upstream operations that are relatively self-contained and integrated within a particular country, such as in Canada, the United Kingdom, Norway and continental Europe. The U.S. dollar is used for operations in highly inflationary economies, in Singapore, which is predominantly export-oriented, and for some upstream operations, primarily in Malaysia, Indonesia, Angola, Nigeria, Equatorial Guinea and the Middle East. For all operations, gains or losses on remeasuring foreign currency transactions into functional currency are included in income.

Stock-Based Awards. Effective January 1, 2003, the Corporation adopted for all employee stock-based awards granted after that date, the recognition provisions of Statement of Financial Accounting Standards No. 123 (FAS 123), "Accounting for Stock-Based Compensation." In accordance with FAS 123, compensation expense for awards granted on or after January 1, 2003, will be measured by the fair value of the award at the date of grant and recognized over the vesting period. The fair value of awards in the form of restricted stock is the market price of the stock. The fair value of awards in the form of stock options is estimated using an option-pricing model.

The Corporation has retained its prior method of accounting for stock-based awards granted before January 1, 2003. Under this method, compensation expense for awards granted in the form of stock options is measured at the intrinsic value of the options (the difference between the market price of stock and the exercise price of the options) on the date of grant. Since these two prices are the same on the date of grant, no compensation expense was recognized in income for these awards. Additionally, compensation expense for awards granted in the form of restricted stock is based on the price of the stock when it is granted and is recognized over the vesting period, which is the same method of accounting as under FAS 123.

If the provisions of FAS 123 had been adopted for all prior years, the impact on compensation expense, net income, and net income per share would have been as follows:

		2004			2003			2002
		(millions of dollars)
Net income, as reported		$	25,330		$	21,510		$	11,460
Add: Stock-based compensation, net of tax included in reported net income			144			86			19
Deduct: Stock-based compensation, net of tax determined under fair-value-based method			(146	)		(93	)		(180	)

Pro forma net income		$	25,328		$	21,503		$	11,299

		(dollars per share)
Net income per share:
	Basic—as reported	$	3.91		$	3.24		$	1.69
	Basic—pro forma		3.91			3.24			1.67
	Diluted—as reported		3.89			3.23			1.68
	Diluted—pro forma		3.89			3.23			1.66

The pro forma amounts that would have been reported if FAS 123 had been in effect for all years are based on the fair value of stock-based awards granted for each of those years and recognized over the vesting period. In 2004, 2003 and 2002, the stock-based awards were in the form of restricted common stock and restricted stock units, and the fair value is based on the price of the stock at the date of grant, which was $51.07, $36.11 and $34.64 in 2004, 2003 and 2002, respectively. No stock option awards were made in these years.

2. Discontinued Operations

In 2002, the copper business in Chile and the coal operations in Colombia were sold. Earnings of these businesses are reported as discontinued operations for 2002 as presented in the consolidated statement of income. Income taxes related to discontinued operations were $41 million in 2002. Included in discontinued operations for 2002 are gains on the dispositions of $400 million, net of tax. The assets sold were primarily property, plant and equipment in the amount of $1.3 billion. Revenues of these operations were not material. These

A32

businesses were historically reported in the "All Other" column in the segment disclosures located in note 18 on pages A51 and A52.

3. Merger Expenses and Reorganization Reserves

In association with the merger between Exxon and Mobil, $410 million pretax ($275 million after tax) of costs were recorded as merger-related expenses in 2002. Cumulative charges for the period 1999 to 2002 of $3,189 million included separation expenses of approximately $1,460 million related to workforce reductions (approximately 8,200 employees at year-end 2002), plus implementation costs and merger closing costs. Reflecting the completion of merger-related activities, merger expenses were not reported in 2003 or 2004.

The following table summarizes the activity in the reorganization reserves. The 2002 opening balance represents accruals for provisions taken in prior years.

	Opening Balance		Additions		Deductions		Balance at Year End
	(millions of dollars)
2002	$	197	$	93	$	189	$	101
2003		101		—		53		48
2004		48		—		21		27

4. Miscellaneous Financial Information

Research and development costs totaled $649 million in 2004, $618 million in 2003 and $631 million in 2002.

Net income included aggregate foreign exchange transaction gains of $69 million in 2004 and $11 million in 2003, and losses of $106 million in 2002.

In 2004, 2003 and 2002, net income included gains of $227 million, $255 million and $159 million, respectively, attributable to the combined effects of LIFO inventory accumulations and draw-downs. The aggregate replacement cost of inventories was estimated to exceed their LIFO carrying values by $9.8 billion and $6.8 billion at December 31, 2004, and 2003, respectively.

Restricted cash and cash equivalents were $4,604 million at December 31, 2004, attributable to cash and short-term, high-quality securities the Corporation pledged as collateral to the issuer of a $4.5 billion litigation-related bond. The Corporation posted this bond to stay execution of the judgment pending appeal in the case of Exxon Corporation v. State of Alabama, et al. (refer to page A13 and note 16 on page A46 for discussion of this lawsuit). Under the terms of the pledge agreement, the Corporation is entitled to receive the income generated from the cash and securities and to make investment decisions, but is restricted from using the pledged cash and securities for any other purpose until such time the bond is canceled.

5. Cash Flow Information

The consolidated statement of cash flows provides information about changes in cash and cash equivalents. Highly liquid investments with maturities of three months or less when acquired are classified as cash equivalents.

In 2003, ExxonMobil completed a divestment of interests in shares of Ruhrgas AG, a German gas transmission company. These shares were held in part by BEB Erdgas und Erdoel GmbH (BEB), an investment accounted for by the equity method, and in part by a consolidated affiliate in Germany. In 2002, cash in the amount of $1,466 million was received from BEB, an equity company, and included in cash flows from operating activities (see Ruhrgas transaction line on Consolidated Statement of Cash Flows, page A29). This cash from BEB was a loan and was part of a restructuring that enabled BEB to transfer its holdings in Ruhrgas AG, provided regulatory approval was received. No income was recorded in 2002.

Cash payments for interest were: 2004—$328 million, 2003—$429 million and 2002—$437 million. Cash payments for income taxes were: 2004—$13,510 million, 2003—$8,149 million and 2002—$6,106 million.

6. Additional Working Capital Information

		Dec. 31 2004		Dec. 31 2003
		(millions of dollars)
Notes and accounts receivable
	Trade, less reserves of $332 million and $358 million	$	20,712	$	16,766
	Other, less reserves of $40 million and $38 million		4,647		7,543

	Total	$	25,359	$	24,309

Notes and loans payable
	Bank loans	$	839	$	972
	Commercial paper		1,491		1,579
	Long-term debt due within one year		608		1,903
	Other		342		335

	Total	$	3,280	$	4,789

Accounts payable and accrued liabilities
	Trade payables	$	18,186	$	15,334
	Payables to equity companies		1,871		1,584
	Accrued taxes other than income taxes		6,055		5,374
	Other		5,651		6,153

	Total	$	31,763	$	28,445

On December 31, 2004, unused credit lines for short-term financing totaled approximately $5.2 billion. Of this total, $3.3 billion support commercial paper programs under terms negotiated when drawn. The weighted-average interest rate on short-term borrowings outstanding at December 31, 2004, and 2003 was 3.5 percent and 2.9 percent, respectively.

A33

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

7. Equity Company Information

The summarized financial information below includes amounts related to certain less-than-majority-owned companies and majority-owned subsidiaries where minority shareholders possess the right to participate in significant management decisions (see note 1 on page A30). These companies are primarily engaged in crude production, natural gas marketing and refining operations in North America; natural gas production, natural gas distribution and downstream operations in Europe; crude production in Kazakhstan and Abu Dhabi; and liquefied natural gas (LNG) operations in Qatar. Also included are several power generation, petrochemical/lubes manufacturing and chemical ventures. The Corporation's ownership in these ventures is in the form of shares in corporate joint ventures as well as interests in partnerships. The share of total revenues in the table below representing sales to ExxonMobil consolidated companies was 22 percent, 18 percent and 19 percent in the years 2004, 2003 and 2002, respectively.

		2004				2003				2002
Equity Company Financial Summary		Total		ExxonMobil Share		Total		ExxonMobil Share		Total		ExxonMobil Share
		(millions of dollars)
Total revenues		$	72,872	$	26,359	$	63,651	$	23,667	$	47,204	$	17,230

Income before income taxes		$	15,278	$	6,141	$	11,432	$	5,356	$	6,028	$	2,844
Income taxes			3,257		1,180		1,871		983		1,461		778

Income from continuing operations		$	12,021	$	4,961		9,561	$	4,373	$	4,567	$	2,066
Cumulative effect of accounting change, net of income tax			—		—		74		35		—		—

	Net income	$	12,021	$	4,961	$	9,635	$	4,408	$	4,567	$	2,066

Current assets		$	21,835	$	7,803	$	19,334	$	7,386	$	20,162	$	7,658
Property, plant and equipment, less accumulated depreciation			46,236		15,793		40,895		15,034		39,351		14,254
Other long-term assets			6,600		4,166		5,820		2,694		5,524		2,614

	Total assets	$	74,671	$	27,762	$	66,049	$	25,114	$	65,037	$	24,526

Short-term debt		$	4,109	$	1,348	$	3,402	$	1,336	$	3,561	$	1,443
Other current liabilities			14,463		5,397		13,394		5,112		15,529		5,991
Long-term debt			10,477		2,566		7,997		2,815		9,236		3,352
Other long-term liabilities			6,489		2,910		6,738		3,215		8,248		3,881
Advances from shareholders			12,339		3,799		11,092		3,091		10,721		2,927

	Net assets	$	26,794	$	11,742	$	23,426	$	9,545	$	17,742	$	6,932

A list of significant equity companies as of December 31, 2004, together with the Corporation's percentage ownership interest, is detailed below:

		Percentage Ownership Interest
Upstream
Aera Energy LLC		48
BEB Erdgas und Erdoel GmbH		50
Cameroon Oil Transportation Company S.A.		41
Castle Peak Power Company Limited		60
Nederlandse Aardolie Maatschappij B.V.		50
Qatar Liquefied Gas Company Limited		10
Ras Laffan Liquefied Natural Gas Company Limited		27
Ras Laffan Liquefied Natural Gas Company Limited II		30
Tengizchevroil, LLP		25
Downstream
Chalmette Refining, LLC		50
Mineraloelraffinerie Oberrhein GmbH & Co. KG		25
Saudi Aramco Mobil Refinery Company Ltd.		50
Chemical
Al-Jubail Petrochemical Company		50
Infineum Holdings B.V.		50
Saudi Yanbu Petrochemical Co.		50

A34

8. Investments and Advances

		Dec. 31 2004		Dec. 31 2003
		(millions of dollars)
Companies carried at equity in underlying assets
	Investments	$	11,742	$	9,545
	Advances		3,799		3,091

		$	15,541	$	12,636
Companies carried at cost or less and stock investments carried at fair value			1,931		1,795

		$	17,472	$	14,431
Long-term receivables and miscellaneous investments at cost or less			932		1,104

	Total	$	18,404	$	15,535

9. Property, Plant and Equipment and Asset Retirement Obligations

		Dec. 31, 2004				Dec. 31, 2003
Property, Plant and Equipment		Dec. 31, 2004				Dec. 31, 2003
Property, Plant and Equipment		Cost		Net		Cost		Net
		(millions of dollars)
Upstream		$	148,024	$	62,013	$	138,701	$	58,727
Downstream			62,014		29,810		59,939		29,566
Chemical			21,777		10,049		20,623		10,115
Other			10,607		6,767		10,052		6,557

	Total	$	242,422	$	108,639	$	229,315	$	104,965

In the Upstream segment, depreciation is on a unit-of-production basis, so depreciable life will vary by field. In the Downstream segment, investments in refinery and lubes basestock manufacturing facilities are generally depreciated on a straight-line basis over a 25-year life and service station buildings and fixed improvements over a 20-year life. In the Chemical segment, investments in process equipment are generally depreciated on a straight-line basis over a 20-year life.

Accumulated depreciation and depletion totaled $133,783 million at the end of 2004 and $124,350 million at the end of 2003. Interest capitalized in 2004, 2003 and 2002 was $500 million, $490 million and $426 million, respectively.

The following table provides the year-end balances and movements for suspended exploratory well costs:

		2004			2003			2002
		(millions of dollars)
Beginning balance at January 1		$	1,093		$	1,193		$	1,066
	Additions to capitalized exploratory well costs pending the determination of proved reserves		139			217			195
	Capitalized exploratory well costs charged to expense		(98	)		(238	)		(22	)
	Reclassifications to wells, facilities and equipment based on the determination of proved reserves		(92	)		(123	)		(90	)
	Foreign exchange changes		28			44			44

Ending balance at December 31		$	1,070		$	1,093		$	1,193

Number of wells at year end			142			189			204

A35

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

An aging of suspended well costs is shown below (Amounts—millions of dollars):

	2004			2003			2002
Age	2004			2003			2002
Age	Amount		Wells	Amount		Wells	Amount		Wells
<1 Year	$	139	14	$	217	27	$	195	42
1-5 Years		510	72		453	82		660	96
6-10 Years		172	32		162	49		102	36
>10 Years		249	24		261	31		236	30

	$	1,070	142	$	1,093	189	$	1,193	204

Asset Retirement Obligations (AROs)

As of January 1, 2003, the Corporation adopted Financial Accounting Standards Board Statement of Financial Accounting Standards No. 143 (FAS 143), "Accounting for Asset Retirement Obligations." The primary impact of FAS 143 was to change the method for accruing for upstream site restoration costs. Asset retirement obligations are not recorded for downstream and chemical facilities because such potential obligations cannot be measured since it is not possible to estimate the settlement dates.

Upstream costs were previously accrued ratably over the productive lives of the assets in accordance with Statement of Financial Accounting Standards No. 19 (FAS 19), "Financial Accounting and Reporting by Oil and Gas Producing Companies." Under FAS 143, the fair values of asset retirement obligations are recorded as liabilities on a discounted basis when they are incurred, which is typically at the time the assets are installed. Amounts recorded for the related assets will be increased by the amount of these obligations. Over time, the liabilities will be accreted for the change in their present value and the initial capitalized costs will be depreciated over the useful lives of the related assets.

The cumulative adjustment for the change in accounting principle reported in the first quarter of 2003 was after-tax income of $550 million (net of $442 million of income tax effects, including ExxonMobil's share of related equity company income taxes of $51 million), or $0.08 per common share. The effect of this accounting change on the 2003 balance sheet was a $0.3 billion increase to property, plant and equipment, a $0.6 billion reduction to the accrued liability and a $0.4 billion increase in deferred income tax liabilities.

The following table summarizes the activity in the liability for asset retirement obligations:

		2004			2003
		(millions of dollars)
Beginning balance		$	3,440		$	3,454
	Cumulative effect of accounting change (1)		—			(622	)
	Accretion expense and other provisions		136			174
	Payments made		(201	)		(113	)
	Liabilities incurred		143			253
	Foreign currency translation/other		92			294

Ending balance		$	3,610		$	3,440

		(millions of dollars)
(1) Cumulative Effect of 2003 Accounting Change		2003
Increase in net PP&E		$	284
Decrease in ARO liability			622
Increase in deferred tax liability			(391	)
Increase in investments in equity companies			35

	Total after-tax earnings	$	550

A36

10. Leased Facilities

At December 31, 2004, the Corporation and its consolidated subsidiaries held noncancelable operating charters and leases covering drilling equipment, tankers, service stations and other properties with minimum lease commitments as indicated in the table.

Net rental expenditures for 2004, 2003 and 2002 totaled $2,491 million, $2,298 million and $2,322 million, respectively, after being reduced by related rental income of $136 million, $141 million and $140 million, respectively. Minimum rental expenditures totaled $2,501 million in 2004, $2,319 million in 2003 and $2,378 million in 2002.

		Minimum Commitment		Related Rental Income
		(millions of dollars)
2005		$	1,323	$	52
2006			1,025		42
2007			762		37
2008			562		32
2009			464		29
2010 and beyond			1,855		30

	Total	$	5,991	$	222

11. Employee Stock Ownership Plans

In 1989, the Exxon and Mobil employee stock ownership plan trusts borrowed $1,000 million and $800 million, respectively, to finance the purchase of shares of Exxon and Mobil stock. The trusts were merged in late 1999 to create the ExxonMobil leveraged employee stock ownership trust (ExxonMobil ESOP). The ExxonMobil ESOP is a constituent part of the ExxonMobil Savings Plan, which, effective February 8, 2002, is an employee stock ownership plan in its entirety.

Employees eligible to participate in the ExxonMobil Savings Plan may elect to participate in the ExxonMobil ESOP. Corporate contributions to the plan and dividends were used to make principal and interest payments on the ExxonMobil ESOP notes ($65 million outstanding as of December 31, 2002, which was fully paid in 2003). As corporate contributions and dividends were credited, common shares were allocated to participants' plan accounts. The Corporation's contribution to the ExxonMobil ESOP, representing the amount by which debt service exceeded dividends on shares held by the ExxonMobil ESOP, was $59 million and $86 million in 2003 and 2002, respectively. No contributions were made in 2004.

Accounting for the plans has followed the principles that were in effect for the respective plans when they were established. During the time that the guaranteed ESOP borrowing was outstanding, the borrowing was included in ExxonMobil's debt. The future compensation to be earned by employees was classified in shareholders' equity. No guaranteed debt was outstanding at year-end 2004, and there was no future compensation classified in shareholders' equity as all compensation was earned. Expense, net of the dividends used for debt service, was recognized as the debt was repaid and shares were earned by employees. The amount of compensation expense related to the plans and recorded by the Corporation was $32 million in 2003 and $122 million in 2002. No expense was incurred in 2004.

A37

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

12. Capital

The authorized common stock of the Corporation is 9 billion shares without par value. The table below summarizes the earnings per share calculations:

		2004		2003		2002
Net income per common share
Income from continuing operations (millions of dollars)		$	25,330	$	20,960	$	11,011
Weighted average number of common shares outstanding (millions of shares)			6,482		6,634		6,753
Net income per common share (dollars)
	Income from continuing operations	$	3.91	$	3.16	$	1.62
	Discontinued operations, net of income tax		—		—		0.07
	Cumulative effect of accounting change, net of income tax		—		0.08		—

	Net income	$	3.91	$	3.24	$	1.69

Net income per common share—assuming dilution
Income from continuing operations (millions of dollars)		$	25,330	$	20,960	$	11,011
Weighted average number of common shares outstanding (millions of shares)			6,482		6,634		6,753
	Effect of employee stock-based awards		37		28		50

Weighted average number of common shares outstanding—assuming dilution			6,519		6,662		6,803

Net income per common share (dollars)
	Income from continuing operations	$	3.89	$	3.15	$	1.61
	Discontinued operations, net of income tax		—		—		0.07
	Cumulative effect of accounting change, net of income tax		—		0.08		—

	Net Income	$	3.89	$	3.23	$	1.68

Dividends paid per common share (dollars)		$	1.06	$	0.98	$	0.92

A38

13. Financial Instruments and Derivatives

The fair value of financial instruments is determined by reference to various market data and other valuation techniques as appropriate. Long-term debt is the only category of financial instruments whose fair value differs materially from the recorded book value. The estimated fair value of total long-term debt, including capitalized lease obligations, at December 31, 2004, and 2003, was $5.9 billion and $5.6 billion, respectively, as compared to recorded book values of $5.0 billion and $4.8 billion.

The Corporation does not trade in derivatives nor does it use derivatives with leveraged features. The Corporation maintains a system of controls that includes a policy covering the authorization, reporting and monitoring of derivative activity. The Corporation's derivative activities pose no material credit or market risks to ExxonMobil's operations, financial condition or liquidity. Interest rate, foreign exchange rate and commodity price exposures arising from derivative contracts undertaken in accordance with the Corporation's policies have not been significant.

The fair value of derivatives outstanding and recorded on the balance sheet was a net receivable of $6 million and a net payable of $17 million at year-end 2004 and 2003, respectively. This is the amount that the Corporation would have paid to or received from third parties if these derivatives had been settled. These derivative fair values were substantially offset by the fair values of the underlying exposures being hedged. The Corporation recognized a gain of $38 million, a gain of $4 million and a loss of $35 million related to derivative activity during 2004, 2003 and 2002, respectively. The gains/losses included the offsetting amounts from the changes in fair value of the items being hedged by the derivatives.

14. Long-Term Debt

At December 31, 2004, long-term debt consisted of $4,671 million due in U.S. dollars and $342 million representing the U.S. dollar equivalent at year-end exchange rates of amounts payable in foreign currencies. These amounts exclude that portion of long-term debt, totaling $608 million, which matures within one year and is included in current liabilities. The amounts of long-term debt maturing, together with sinking fund payments required, in each of the four years after December 31, 2005, in millions of dollars, are: 2006—$120, 2007—$127, 2008—$284 and 2009—$135. Certain of the borrowings described may from time to time be assigned to other ExxonMobil affiliates. At December 31, 2004, the Corporation's unused long-term credit lines were not material.

Summarized long-term borrowings at year-end 2004 and 2003 were as shown in the adjacent table:

			2004		2003
			(millions of dollars)
Exxon Capital Corporation (1)
6.0% Guaranteed notes due 2005			$	—	$	106
6.125% Guaranteed notes due 2008				160		160
SeaRiver Maritime Financial Holdings, Inc. (1)
Guaranteed debt securities due 2006-2011 (2)				75		85
Guaranteed deferred interest debentures due 2012
	—Face value net of unamortized discount plus accrued interest			1,249		1,121
Mobil Producing Nigeria Unlimited
8.625% notes due 2006				—		63
Mobil Corporation
8.625% debentures due 2021				248		248
Mobil Services (Bahamas) Ltd.
Variable notes due 2034 (3)				311		—
Industrial revenue bonds due 2007-2033 (4)				1,702		1,688
Other U.S. dollar obligations (5)				719		640
Other foreign currency obligations				195		275
Capitalized lease obligations (6)				354		370

		Total long-term debt	$	5,013	$	4,756

(1): Additional information is provided for these subsidiaries on pages A40 to A44.
(2): Average effective interest rate of 1.5% in 2004 and 1.2% in 2003.
(3): Average effective interest rate of 2.0% in 2004.
(4): Average effective interest rate of 1.8% in 2004 and 1.7% in 2003.
(5): Average effective interest rate of 6.0% in 2004 and 6.3% in 2003.
(6): Average imputed interest rate of 7.4% in 2004 and 7.0% in 2003.

A39

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Condensed consolidating financial information related to guaranteed securities issued by subsidiaries

Exxon Mobil Corporation has fully and unconditionally guaranteed the 6.125% notes due 2008 ($160 million of long-term debt at December 31, 2004) of Exxon Capital Corporation and the deferred interest debentures due 2012 ($1,249 million long-term) and the debt securities due 2006 to 2011 ($75 million long-term and $10 million short-term) of SeaRiver Maritime Financial Holdings, Inc.

Exxon Capital Corporation and SeaRiver Maritime Financial Holdings, Inc. are 100-percent-owned subsidiaries of Exxon Mobil Corporation.

The following condensed consolidating financial information is provided for Exxon Mobil Corporation, as guarantor, and for Exxon Capital Corporation and SeaRiver Maritime Financial Holdings, Inc., as issuers, as an alternative to providing separate financial statements for the issuers. The accounts of Exxon Mobil Corporation, Exxon Capital Corporation and SeaRiver Maritime Financial Holdings, Inc. are presented utilizing the equity method of accounting for investments in subsidiaries.

			Exxon Mobil Corporation Parent Guarantor		Exxon Capital Corporation			SeaRiver Maritime Financial Holdings, Inc.			All Other Subsidiaries		Consolidating and Eliminating Adjustments			Consolidated
			(millions of dollars)
Condensed consolidated statement of income for 12 months ended December 31, 2004
Revenues and other income
	Sales and other operating revenue, including excise taxes		$	13,617	$	—		$	—		$	277,635	$	—		$	291,252
	Income from equity affiliates			23,115		—			15			4,966		(23,135	)		4,961
	Other income			521		—			—			1,301		—			1,822
	Intercompany revenue			24,147		33			22			196,653		(220,855	)		—

		Total revenues and other income		61,400		33			37			480,555		(243,990	)		298,035

Costs and other deductions
	Crude oil and product purchases			23,217		—			—			324,920		(208,913	)		139,224
	Production and manufacturing expenses			6,642		3			—			21,945		(5,365	)		23,225
	Selling, general and administrative expenses			2,099		4			—			12,056		(310	)		13,849
	Depreciation and depletion			1,424		4			1			8,338		—			9,767
	Exploration expenses, including dry holes			187		—			—			911		—			1,098
	Merger-related expenses			—		—			—			—		—			—
	Interest expense			1,381		21			135			5,339		(6,238	)		638
	Excise taxes			—		—			—			27,263		—			27,263
	Other taxes and duties			14		—			—			40,940		—			40,954
	Income applicable to minority and preferred interests			—		—			—			776		—			776

		Total costs and other deductions		34,964		32			136			442,488		(220,826	)		256,794

Income before income taxes				26,436		1			(99	)		38,067		(23,164	)		41,241
	Income taxes			1,106		(1	)		(40	)		14,846		—			15,911

Income from continuing operations				25,330		2			(59	)		23,221		(23,164	)		25,330
	Discontinued operations, net of income tax			—		—			—			—		—			—
	Accounting change, net of income tax			—		—			—			—		—			—

Net income			$	25,330	$	2		$	(59	)	$	23,221	$	(23,164	)	$	25,330

A40

			Exxon Mobil Corporation Parent Guarantor		Exxon Capital Corporation			SeaRiver Maritime Financial Holdings, Inc.			All Other Subsidiaries		Consolidating and Eliminating Adjustments			Consolidated
			(millions of dollars)
Condensed consolidated statement of income for 12 months ended December 31, 2003
Revenues and other income
	Sales and other operating revenue, including excise taxes		$	11,328	$	—		$	—		$	225,726	$	—		$	237,054
	Income from equity affiliates			18,163		—			1			4,363		(18,154	)		4,373
	Other income			3,229		—			—			2,082		—			5,311
	Intercompany revenue			17,918		33			19			142,930		(160,900	)		—

		Total revenues and other income		50,638		33			20			375,101		(179,054	)		246,738

Costs and other deductions
	Crude oil and product purchases			17,342		—			—			240,908		(150,592	)		107,658
	Production and manufacturing expenses			6,492		2			1			19,691		(4,926	)		21,260
	Selling, general and administrative expenses			2,037		2			—			11,526		(169	)		13,396
	Depreciation and depletion			1,535		5			2			7,505		—			9,047
	Exploration expenses, including dry holes			247		—			—			763		—			1,010
	Merger-related expenses			—		—			—			—		—			—
	Interest expense			648		21			121			4,629		(5,212	)		207
	Excise taxes			1		—			—			23,854		—			23,855
	Other taxes and duties			9		—			—			37,636		—			37,645
	Income applicable to minority and preferred interests			—		—			—			694		—			694

		Total costs and other deductions		28,311		30			124			347,206		(160,899	)		214,772

Income before income taxes				22,327		3			(104	)		27,895		(18,155	)		31,966
	Income taxes			1,367		(1	)		(37	)		9,677		—			11,006

Income from continuing operations				20,960		4			(67	)		18,218		(18,155	)		20,960
	Discontinued operations, net of income tax			—		—			—			—		—			—
	Accounting change, net of income tax			550		—			—			481		(481	)		550

Net income			$	21,510	$	4		$	(67	)	$	18,699	$	(18,636	)	$	21,510

Condensed consolidated statement of income for 12 months ended December 31, 2002
Revenues and other income
	Sales and other operating revenue, including excise taxes		$	8,711	$	—		$	—		$	192,238	$	—		$	200,949
	Income from equity affiliates			10,177		—			(16	)		2,048		(10,143	)		2,066
	Other income			580		5			—			906		—			1,491
	Intercompany revenue			15,711		41			27			120,836		(136,615	)		—

		Total revenues and other income		35,179		46			11			316,028		(146,758	)		204,506

Costs and other deductions
	Crude oil and product purchases			14,687		—			—			207,709		(131,446	)		90,950
	Production and manufacturing expenses			5,312		2			1			16,839		(4,323	)		17,831
	Selling, general and administrative expenses			1,592		2			—			10,898		(136	)		12,356
	Depreciation and depletion			1,572		5			3			6,730		—			8,310
	Exploration expenses, including dry holes			147		—			—			773		—			920
	Merger-related expenses			70		—			—			356		(16	)		410
	Interest expense			655		22			112			4,634		(5,025	)		398
	Excise taxes			—		—			—			22,040		—			22,040
	Other taxes and duties			12		—			—			33,560		—			33,572
	Income applicable to minority and preferred interests			—		—			—			209		—			209

		Total costs and other deductions		24,047		31			116			303,748		(140,946	)		186,996

Income before income taxes				11,132		15			(105	)		12,280		(5,812	)		17,510
	Income taxes			121		6			(31	)		6,403		—			6,499

Income from continuing operations				11,011		9			(74	)		5,877		(5,812	)		11,011
	Discontinued operations, net of income tax			449		—			—			456		(456	)		449
	Accounting change, net of income tax			—		—			—			—		—			—

Net income			$	11,460	$	9		$	(74	)	$	6,333	$	(6,268	)	$	11,460

A41

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Condensed consolidating financial information related to guaranteed securities issued by subsidiaries

		Exxon Mobil Corporation Parent Guarantor			Exxon Capital Corporation		SeaRiver Maritime Financial Holdings, Inc.			All Other Subsidiaries		Consolidating and Eliminating Adjustments			Consolidated
		(millions of dollars)
Condensed consolidated balance sheet for year ended December 31, 2004
Cash and cash equivalents		$	10,055		$	4	$	—		$	8,472	$	—		$	18,531
Cash and cash equivalents—restricted			4,604			—		—			—		—			4,604
Notes and accounts receivable—net			3,262			—		—			22,097		—			25,359
Inventories			1,117			—		—			8,370		—			9,487
Prepaid taxes and expenses			79			—		—			2,317		—			2,396

	Total current assets		19,117			4		—			41,256		—			60,377
Investments and advances			138,395			—		416			369,455		(489,862	)		18,404
Property, plant and equipment—net			15,601			95		—			92,943		—			108,639
Other long-term assets			1,512			—		90			6,234		—			7,836
Intercompany receivables			9,728			1,090		1,594			322,469		(334,881	)		—

	Total assets	$	184,353		$	1,189	$	2,100		$	832,357	$	(824,743	)	$	195,256

Notes and loans payable		$	—		$	—	$	10		$	3,270	$	—		$	3,280
Accounts payable and accrued liabilities			2,934			3		—			28,826		—			31,763
Income taxes payable			1,348			—		1			6,589		—			7,938

	Total current liabilities		4,282			3		11			38,685		—			42,981
Long-term debt			261			160		1,324			3,268		—			5,013
Deferred income tax liabilities			3,152			28		268			17,644		—			21,092
Other long-term liabilities			5,461			22		—			18,931		—			24,414
Intercompany payables			69,441			185		403			264,852		(334,881	)		—

	Total liabilities		82,597			398		2,006			343,380		(334,881	)		93,500
Earnings reinvested			134,390			6		(300	)		81,380		(81,086	)		134,390
Other shareholders' equity			(32,634	)		785		394			407,597		(408,776	)		(32,634	)

	Total shareholders' equity		101,756			791		94			488,977		(489,862	)		101,756

	Total liabilities and shareholders' equity	$	184,353		$	1,189	$	2,100		$	832,357	$	(824,743	)	$	195,256

Condensed consolidated balance sheet for year ended December 31, 2003
Cash and cash equivalents		$	5,647		$	—	$	—		$	4,979	$	—		$	10,626
Cash and cash equivalents—restricted			—			—		—			—		—			—
Notes and accounts receivable—net			5,781			—		—			18,528		—			24,309
Inventories			1,027			—		—			7,930		—			8,957
Prepaid taxes and expenses			91			—		—			1,977		—			2,068

	Total current assets		12,546			—		—			33,414		—			45,960
Investments and advances			126,568			—		401			357,104		(468,538	)		15,535
Property, plant and equipment—net			16,733			98		1			88,133		—			104,965
Other long-term assets			1,714			—		105			5,999		—			7,818
Intercompany receivables			9,463			1,114		1,540			381,683		(393,800	)		—

	Total assets	$	167,024		$	1,212	$	2,047		$	866,333	$	(862,338	)	$	174,278

Notes and loans payable		$	1,104		$	—	$	10		$	3,675	$	—		$	4,789
Accounts payable and accrued liabilities			3,538			6		—			24,901		—			28,445
Income taxes payable			1,457			—		—			3,695		—			5,152

	Total current liabilities		6,099			6		10			32,271		—			38,386
Long-term debt			261			266		1,206			3,023		—			4,756
Deferred income tax liabilities			3,643			29		296			16,150		—			20,118
Other long-term liabilities			3,991			16		—			17,096		—			21,103
Intercompany payables			63,115			106		382			330,197		(393,800	)		—

	Total liabilities		77,109			423		1,894			398,737		(393,800	)		84,363
Earnings reinvested			115,956			4		(241	)		72,012		(71,775	)		115,956
Other shareholders' equity			(26,041	)		785		394			395,584		(396,763	)		(26,041	)

	Total shareholders' equity		89,915			789		153			467,596		(468,538	)		89,915

	Total liabilities and shareholders' equity	$	167,024		$	1,212	$	2,047		$	866,333	$	(862,338	)	$	174,278

A42

			Exxon Mobil Corporation Parent Guarantor			Exxon Capital Corporation			SeaRiver Maritime Financial Holdings, Inc.			All Other Subsidiaries			Consolidating and Eliminating Adjustments			Consolidated
			(millions of dollars)
Condensed consolidated statement of cash flows for 12 months ended December 31, 2004
Cash provided by/(used in) operating activities			$	21,515		$	8		$	44		$	32,837		$	(13,853	)	$	40,551

Cash flows from investing activities
	Additions to property, plant and equipment			(1,101	)		—			—			(10,885	)		—			(11,986	)
	Sales of long-term assets			521			—			—			2,233			—			2,754
	Increase in restricted cash and cash equivalents			(4,604	)		—			—			—			—			(4,604	)
	Net intercompany investing			5,109			24			(55	)		(5,224	)		146			—
	All other investing, net			2			—			—			(1,076	)		—			(1,074	)

		Net cash provided by/(used in) investing activities		(73	)		24			(55	)		(14,952	)		146			(14,910	)

Cash flows from financing activities
	Additions to short- and long-term debt			—			—			—			920			—			920
	Reductions in short- and long-term debt			(1,146	)		(106	)		(10	)		(1,543	)		—			(2,805	)
	Additions/(reductions) in debt with less than 90-day maturity			—			—			—			(66	)		—			(66	)
	Cash dividends			(6,896	)		—			—			(13,853	)		13,853			(6,896	)
	Common stock acquired			(9,951	)		—			—			—			—			(9,951	)
	Net intercompany financing activity			—			78			21			47			(146	)		—
	All other financing, net			959			—			—			(429	)		—			530

		Net cash provided by/(used in) financing activities		(17,034	)		(28	)		11			(14,924	)		13,707			(18,268	)

Effects of exchange rate changes on cash				—			—			—			532			—			532

Increase/(decrease) in cash and cash equivalents			$	4,408		$	4		$	—		$	3,493		$	—		$	7,905

Condensed consolidated statement of cash flows for 12 months ended December 31, 2003
Cash provided by/(used in) operating activities			$	4,797		$	23		$	60		$	24,945		$	(1,327	)	$	28,498

Cash flows from investing activities
	Additions to property, plant and equipment			(1,691	)		—			—			(11,168	)		—			(12,859	)
	Sales of long-term assets			238			—			—			2,052			—			2,290
	Increase in restricted cash and cash equivalents			—			—			—			—			—			—
	Net intercompany investing			13,555			281			(50	)		(13,523	)		(263	)		—
	All other investing, net			—			—			—			(273	)		—			(273	)

		Net cash provided by/(used in) investing activities		12,102			281			(50	)		(22,912	)		(263	)		(10,842	)

Cash flows from financing activities
	Additions to short- and long-term debt			—			—			—			842			—			842
	Reductions in short- and long-term debt			—			—			—			(2,644	)		—			(2,644	)
	Additions/(reductions) in debt with less than 90-day maturity			—			(6	)		(10	)		(306	)		—			(322	)
	Cash dividends			(6,515	)		(93	)		—			(1,234	)		1,327			(6,515	)
	Common stock acquired			(5,881	)		—			—			—			—			(5,881	)
	Net intercompany financing activity			—			(184	)		—			(58	)		242			—
	All other financing, net			434			(21	)		—			(677	)		21			(243	)

		Net cash provided by/(used in) financing activities		(11,962	)		(304	)		(10	)		(4,077	)		1,590			(14,763	)

Effects of exchange rate changes on cash				—			—			—			504			—			504

Increase/(decrease) in cash and cash equivalents			$	4,937		$	—		$	—		$	(1,540	)	$	—		$	3,397

A43

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Condensed consolidating financial information related to guaranteed securities issued by subsidiaries

			Exxon Mobil Corporation Parent Guarantor			Exxon Capital Corporation			SeaRiver Maritime Financial Holdings, Inc.			All Other Subsidiaries			Consolidating and Eliminating Adjustments			Consolidated
			(millions of dollars)
Condensed consolidated statement of cash flows for 12 months ended December 31, 2002
Cash provided by/(used in) operating activities			$	1,970		$	17		$	69		$	19,905		$	(693	)	$	21,268

Cash flows from investing activities
	Additions to property, plant and equipment			(1,727	)		—			—			(9,710	)		—			(11,437	)
	Sales of long-term assets			168			—			—			2,625			—			2,793
	Increase in restricted cash and cash equivalents			—			—			—			—			—			—
	Net intercompany investing			9,640			(30	)		(59	)		(9,646	)		95			—
	All other investing, net			—			—			—			(1,114	)		—			(1,114	)

		Net cash provided by/(used in) investing activities		8,081			(30	)		(59	)		(17,845	)		95			(9,758	)

Cash flows from financing activities
	Additions to short- and long-term debt			—			—			—			1,147			—			1,147
	Reductions in short- and long-term debt			—			—			(10	)		(1,163	)		—			(1,173	)
	Additions/(reductions) in debt with less than 90-day maturity			—			(29	)		—			(252	)		—			(281	)
	Cash dividends			(6,217	)		—			—			(693	)		693			(6,217	)
	Common stock acquired			(4,798	)		—			—			—			—			(4,798	)
	Net intercompany financing activity			—			42			—			53			(95	)		—
	All other financing, net			299			—			—			(330	)		—			(31	)

		Net cash provided by/(used in) financing activities		(10,716	)		13			(10	)		(1,238	)		598			(11,353	)

Effects of exchange rate changes on cash				—			—			—			525			—			525

Increase/(decrease) in cash and cash equivalents			$	(665	)	$	—		$	—		$	1,347		$	—		$	682

15. Incentive Program

The 2003 Incentive Program provides for grants of stock options, stock appreciation rights (SARs), restricted stock and other forms of award. Awards may be granted to eligible employees of the Corporation and those affiliates at least 50 percent owned. The maximum number of shares of stock that may be issued under the 2003 Incentive Program is 220 million. Awards that are forfeited or expire, or are settled in cash, do not count against this maximum limit. The 2003 Incentive Program does not have a specified term. New awards may be made until the available shares are depleted, unless the Board terminates the plan early. Outstanding awards are subject to certain forfeiture provisions contained in the program or award instrument. Shares available for granting under the 2003 Incentive Program were 199,300 thousand at the end of 2004.

As under earlier programs, options and SARs may be granted at prices not less than 100 percent of market value on the date of grant and have a maximum life of 10 years. Most of the options and SARs normally first become exercisable one year following the date of grant. All remaining stock options and SARs outstanding were granted prior to 2002.

Long-term incentive awards totaling 11,374 thousand, 10,381 thousand and 11,072 thousand shares of restricted (nonvested) common stock and restricted (nonvested) common stock units were granted in 2004, 2003 and 2002, respectively. These shares with a value of $554 million, $357 million and $361 million at the grant date in 2004, 2003 and 2002, respectively, will be issued to employees from treasury stock. The price of the stock on the date of grant was $51.07, $36.11 and $34.64 in 2004, 2003 and 2002, respectively. The total compensation expense of $581 million for 2004 grants (including units with a value of $27 million that will be settled in cash), of $375 million for 2003 grants (including units with a value of $18 million that will be settled in cash) and of $384 million for 2002 grants (including units with a value of $23 million that will be settled in cash) will be recognized over the vesting period. The units that are settled in cash are recorded as liabilities and their changes in fair value are recognized over the vesting period. During the applicable restricted periods, the shares may not be sold or transferred and are subject to forfeiture. The majority of the awards have graded vesting periods, with 50 percent of the shares in each award vesting after three years and the remaining 50 percent vesting after seven years. A small number of awards granted to certain employees have longer vesting periods.

A44

The following table summarizes information about restricted stock and restricted stock units, including those shares from former Mobil plans (shares in thousands):

Restricted Stock and Units		2004		2003		2002
Granted		11,374		10,381		11,072
Issued and outstanding at end of year		23,159		13,089		2,382

Changes that occurred in stock options in 2004, 2003 and 2002 are summarized below (shares in thousands):

	2004				2003				2002
Stock Options	Shares		Avg. Exercise Price		Shares		Avg. Exercise Price		Shares		Avg. Exercise Price
Outstanding at beginning of year	223,750		$	33.09	246,995		$	31.59	265,695		$	30.54
Exercised	(42,588	)		22.57	(22,757	)		16.80	(18,334	)		16.18
Expired/canceled	(250	)		39.91	(488	)		35.86	(366	)		40.47

Outstanding at end of year	180,912			35.55	223,750			33.09	246,995			31.59

Exercisable at end of year	180,912			35.55	222,054			33.06	243,548			31.46

The following table summarizes information about stock options outstanding at December 31, 2004 (shares in thousands):

Options Outstanding and Exercisable
Exercise Price Range	Shares	Avg. Remaining Contractual Life	Avg. Exercise Price
$16.53 - 23.54	29,051	1.9 years	$	22.12
25.36 - 37.12	86,782	5.0 years		34.00
40.07 - 45.22	65,079	5.4 years		43.62

Total	180,912	4.7 years		35.55

A45

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

16. Litigation and Other Contingencies

Litigation

A variety of claims have been made against ExxonMobil and certain of its consolidated subsidiaries in a number of pending lawsuits and tax disputes. The Corporation accrues an undiscounted liability for those contingencies where the incurrence of a loss is probable and the amount can be reasonably estimated. The Corporation does not record liabilities when the likelihood that the liability has been incurred is probable but the amount cannot be reasonably estimated, or when the liability is believed to be only reasonably possible or remote. ExxonMobil will continue to defend itself vigorously in these matters. Based on a consideration of all relevant facts and circumstances, the Corporation does not believe the ultimate outcome of any currently pending lawsuit against ExxonMobil will have a materially adverse effect upon the Corporation's operations or financial condition.

A number of lawsuits, including class actions, were brought in various courts against Exxon Mobil Corporation and certain of its subsidiaries relating to the accidental release of crude oil from the tanker Exxon Valdez in 1989. The vast majority of the compensatory claims have been resolved. All of the punitive damage claims were consolidated in the civil trial that began in May 1994.

In that trial, on September 24, 1996, the United States District Court for the District of Alaska entered a judgment in the amount of $5 billion in punitive damages to a class composed of all persons and entities who asserted claims for punitive damages from the Corporation as a result of the Exxon Valdez grounding. ExxonMobil appealed the judgment. On November 7, 2001, the United States Court of Appeals for the Ninth Circuit vacated the punitive damage award as being excessive under the Constitution and remanded the case to the District Court for it to determine the amount of the punitive damage award consistent with the Ninth Circuit's holding. The Ninth Circuit upheld the compensatory damage award, which has been paid. On December 6, 2002, the District Court reduced the punitive damage award from $5 billion to $4 billion. Both the plaintiffs and ExxonMobil appealed that decision to the Ninth Circuit. The Ninth Circuit panel vacated the District Court's $4 billion punitive damage award without argument and sent the case back for the District Court to reconsider in light of the recent U.S. Supreme Court decision in Campbell v. State Farm. On January 28, 2004, the District Court reinstated the punitive damage award at $4.5 billion plus interest. ExxonMobil and the plaintiffs have appealed the decision to the Ninth Circuit. The Corporation has posted a $5.4 billion letter of credit.

On January 29, 1997, a settlement agreement was concluded resolving all remaining matters between the Corporation and various insurers arising from the Valdez accident. Under terms of this settlement, ExxonMobil received $480 million. Final income statement recognition of this settlement continues to be deferred in view of uncertainty regarding the ultimate cost to the Corporation of the Valdez accident. Management believes that the likelihood of the judgment being upheld is remote. While it is reasonably possible that a liability may have been incurred arising from the Exxon Valdez grounding, it is not possible to predict the ultimate outcome or to reasonably estimate any such potential liability.

On December 19, 2000, a jury in the 15th Judicial Circuit Court of Montgomery County, Alabama, returned a verdict against the Corporation in a dispute over royalties in the amount of $88 million in compensatory damages and $3.4 billion in punitive damages in the case of Exxon Corporation v. State of Alabama, et al. The verdict was upheld by the trial court on May 4, 2001. On December 20, 2002, the Alabama Supreme Court vacated the $3.5 billion jury verdict. The case was retried and on November 14, 2003, a state district court jury in Montgomery, Alabama, returned a verdict against Exxon Mobil Corporation. The verdict included $63.5 million in compensatory damages and $11.8 billion in punitive damages. On March 29, 2004, the district court judge reduced the amount of punitive damages to $3.5 billion. ExxonMobil believes the judgment is not justified by the evidence, that any punitive damage award is not justified by either the facts or the law, and that the amount of the award is grossly excessive and unconstitutional. ExxonMobil has appealed the decision. Management believes that the likelihood of the judgment being upheld is remote. While it is reasonably possible that a liability may have been incurred by ExxonMobil from this dispute over royalties, it is not possible to predict the ultimate outcome or to reasonably estimate any such potential liability. On May 4, 2004, the Corporation posted a $4.5 billion supersedeas bond as required by Alabama law to stay execution of the judgment pending appeal. The Corporation has pledged to the issuer of the bond collateral consisting of cash and short-term, high-quality securities with an aggregate value of approximately $4.6 billion. This collateral is reported as restricted cash and cash equivalents on the Consolidated Balance Sheet on page A27. Under the terms of the pledge agreement, the Corporation is entitled to receive the income generated from the cash and securities and to make investment decisions, but is restricted from using the pledged cash and securities for any other purpose until such time the bond is canceled.

In Allapattah v. Exxon, a jury in the United States District Court for the Southern District of Florida determined in January 2001 that a class of all Exxon dealers between March 1983 and August 1994 had been overcharged between 1.03 and 1.4 cents per gallon for gasoline. Exxon

A46

sold a total of 39.8 billion gallons of gasoline to its dealers during this period. The estimated value of the potential claims associated with the 39.8 billion gallons of gasoline is $494 million. Including related interest, the total is approximately $1.3 billion. On June 11, 2003, the Eleventh Circuit Court of Appeals affirmed the judgment and on March 15, 2004, denied a petition for Rehearing En Banc. On October 12, 2004, the U.S. Supreme Court granted review of an issue raised by ExxonMobil as to whether the class in the District Court judgment should include members that individually do not satisfy the $50,000 minimum amount-in-controversy requirement in federal court. Members of the class could file claims through December 1, 2004. Claims representing over 90 percent of the gallons have been filed. In light of the Supreme Court's decision to grant review of only part of ExxonMobil's appeal, ExxonMobil took an after-tax charge of $550 million in the third quarter reflecting the estimated liability, including interest and after considering potential set-offs and defenses, for the claims in excess of $50,000.

Other Contingencies

		Dec. 31, 2004
		Equity Company Obligations		Other Third-Party Obligations		Total
		(millions of dollars)
Guarantees of excise taxes/customs duties under reciprocal arrangements		$	—	$	1,122	$	1,122
Other guarantees			2,428		344		2,772

	Total	$	2,428	$	1,466	$	3,894

The Corporation and certain of its consolidated subsidiaries were contingently liable at December 31, 2004, for $3,894 million, primarily relating to guarantees for notes, loans and performance under contracts. This included $1,122 million representing guarantees of non-U.S. excise taxes and customs duties of other companies, entered into as a normal business practice, under reciprocal arrangements. Also included in this amount were guarantees by consolidated affiliates of $2,428 million, representing ExxonMobil's share of obligations of certain equity companies.

Additionally, the Corporation and its consolidated subsidiaries have numerous long-term sales and purchase commitments in their various business activities, all of which are expected to be fulfilled with no adverse consequences material to the Corporation's operations or financial condition. Unconditional purchase obligations, as defined by accounting standards, are those long-term commitments that are noncancelable or cancelable only under certain conditions, and that third parties have used to secure financing for the facilities that will provide the contracted goods or services.

	Payments Due by Period
	2005		2006- 2009		2010 and Beyond		Total
	(millions of dollars)
Unconditional purchase obligations (1)	$	602	$	1,918	$	2,125	$	4,645

(1): Undiscounted obligations of $4,645 million mainly pertain to pipeline throughput agreements and include $2,513 million of obligations to equity companies. The present value of these commitments, excluding imputed interest of $1,386 million, totaled $3,259 million.

A47

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

17. Annuity Benefits and Other Postretirement Benefits

		Annuity Benefits
		Annuity Benefits																		Other Postretirement Benefits
		U.S.									Non-U.S.									Other Postretirement Benefits
		2004			2003			2002			2004			2003			2002			2004			2003			2002
		(millions of dollars)
Components of net benefit cost
	Service cost	$	308		$	284		$	224		$	357		$	326		$	257		$	62		$	36		$	30
	Interest cost		611			624			577			812			728			621			295			234			220
	Expected return on plan assets		(618	)		(418	)		(501	)		(684	)		(552	)		(561	)		(36	)		(31	)		(38	)
	Amortization of actuarial loss/(gain) and prior service cost		286			321			121			378			384			190			191			96			57
	Net pension enhancement and curtailment/settlement expense		177			204			49			3			37			18			—			—			—

Net benefit cost		$	764		$	1,015		$	470		$	866		$	923		$	525		$	512		$	335		$	269

Weighted-average assumptions used to determine net benefit cost for years ended December 31			(percent)
	Discount rate		6.00			6.75			7.25			5.2			5.2			5.6			6.00			6.75			7.25
	Long-term rate of return on funded assets		9.00			9.00			9.50			7.7			7.7			8.0			9.00			9.00			9.50
	Long-term rate of compensation increase		3.50			3.50			3.50			3.8			3.9			4.0			3.50			3.50			3.50

Costs for defined contribution plans were $245 million, $253 million and $191 million in 2004, 2003 and 2002, respectively.

The benefit obligations and plan assets associated with the Corporation's principal benefit plans are measured on December 31.

		Annuity Benefits
		Annuity Benefits												Other Postretirement Benefits
		U.S.						Non-U.S.						Other Postretirement Benefits
		2004			2003			2004			2003			2004			2003
		(millions of dollars)
Change in benefit obligation (1)
	Benefit obligation at January 1	$	10,280		$	9,139		$	16,313		$	13,543		$	4,960		$	3,496
	Service cost		308			284			357			326			62			36
	Interest cost		611			624			812			728			295			234
	Actuarial loss/(gain)		700			1,060			874			295			330			1,192
	Benefits paid		(1,127	)		(829	)		(1,020	)		(929	)		(350	)		(338	)
	Foreign exchange rate changes		—			—			1,182			2,184			29			53
	Other		(2	)		2			186			166			62			287

Projected benefit obligation at December 31		$	10,770		$	10,280		$	18,704		$	16,313		$	5,388		$	4,960

Accumulated benefit obligation at December 31		$	9,193		$	8,764		$	17,003		$	14,904			—			—
Weighted-average assumptions used to determine benefit obligations at December 31			(percent)
	Discount rate		5.75			6.00			4.9			5.2			5.75			6.00
	Long-term rate of compensation increase		3.50			3.50			3.8			3.8			3.50			3.50

(1): The term benefit obligation means "projected benefit obligation" as defined by Statement of Financial Accounting Standards No. 87 (FAS 87), "Employers' Accounting for Pensions," for annuity benefits and "accumulated postretirement benefit obligation" as defined by FAS 106, "Employers' Accounting for Postretirement Benefits Other than Pensions," for other postretirement benefits.

The measurement of the accumulated postretirement benefit obligation assumes a health care cost trend rate of 6 percent for 2005 that declines to 2.5 percent by 2011. The 2003 actuarial loss for other postretirement benefits reflects a change in the health care cost trend rate assumption at year-end 2003. A one-percentage-point increase in the health care cost trend rate would increase service and interest cost by $33 million and the postretirement benefit obligation by $373 million. A one-percentage-point decrease in the health care cost trend rate would decrease service and interest cost by $27 million and the postretirement benefit obligation by $316 million.

A48

The Corporation offers a Medicare supplement plan to Medicare-eligible retirees that provides prescription drug benefits. On December 8, 2003, the President of the United States signed into law the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the "Act"). The Act provides a federal subsidy to employers sponsoring retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to Medicare Part D. The Corporation believes that its Medicare supplement plan is at least actuarially equivalent to Medicare Part D but that it is not a significant event for the plan. Accordingly, the Corporation recognized the effects of the Act at the December 31, 2004, measurement date.

		Annuity Benefits
		Annuity Benefits												Other Postretirement Benefits
		U.S.						Non-U.S.						Other Postretirement Benefits
		2004			2003			2004			2003			2004			2003
		(millions of dollars)
Change in plan assets
	Fair value at January 1	$	7,301		$	4,616		$	9,185		$	6,735		$	412		$	345
	Actual return on plan assets		967			1,327			1,086			1,114			50			86
	Foreign exchange rate changes		—			—			691			1,202			—			—
	Payments directly to participants		157			133			303			297			236			213
	Company contribution		—			2,054			473			779			34			34
	Benefits paid		(1,127	)		(829	)		(1,020	)		(929	)		(350	)		(338	)
	Other		1			—			(45	)		(13	)		62			72

Fair value at December 31		$	7,299		$	7,301		$	10,673		$	9,185		$	444		$	412

The data on the preceding page conform with current accounting standards that specify use of a discount rate at which postretirement liabilities could be effectively settled. The discount rate for calculating year-end postretirement liabilities is based on the year-end rate of interest on a portfolio of high-quality bonds. The return on the annuity fund's actual portfolio of assets has historically been higher than bonds as the majority of pension assets are invested in equities, as illustrated in the table below, which shows asset allocation. The U.S. long-term expected rate of return of 9.0 percent used in 2004 compares to an actual rate of return for the U.S. annuity fund over the past decade of 12.5 percent. The Corporation establishes the long-term expected rate of return for each plan by developing a forward-looking, long-term return assumption for each asset class, taking into account factors such as the expected real return for the specific asset class and inflation. A single, long-term rate of return is then calculated as the weighted average of the target asset allocation and the long-term return assumption for each asset class.

		Annuity Benefits
		Annuity Benefits								Other Postretirement Benefits
		U.S.				Non-U.S.				Other Postretirement Benefits
		2004		2003		2004		2003		2004		2003
		(percent)
Funded benefit plan asset allocation
	Equity securities	75	%	71	%	69	%	67	%	76	%	76	%
	Debt securities	25		25		29		31		24		24
	Other	—		4		2		2		—		—

Total		100	%	100	%	100	%	100	%	100	%	100	%

The Corporation's investment strategy for benefit plan assets reflects a long-term view, a careful assessment of the risks inherent in various asset classes and broad diversification to reduce the risk of the portfolio. The Corporation primarily invests in funds that follow an index-based strategy to achieve its objectives of diversifying risk while minimizing costs. The funds hold ExxonMobil stock only to the extent necessary to replicate the relevant equity index. Asset-liability studies, or simulations of the interaction of cash flows associated with both assets and liabilities, are periodically used to establish the preferred target asset allocation. The target asset allocation for equity securities of 75 percent for the U.S. benefit plans and 67 percent for non-U.S. plans reflects the long-term nature of the liability. The balance of the funds is largely targeted to debt securities.

A49

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The funding levels of all qualified plans are in compliance with standards set by applicable law or regulation. Certain smaller U.S. plans and a number of non-U.S. plans are not funded because local tax conventions and regulatory practices do not encourage funding of these plans. All defined-benefit pension obligations, regardless of the funding status of the underlying plans, are fully supported by the financial strength of the Corporation or the respective sponsoring affiliate.

A summary comparing the total plan assets to the total projected benefit obligation is shown in the table below:

		Annuity Benefits
		Annuity Benefits												Other Postretirement Benefits
		U.S.						Non-U.S.						Other Postretirement Benefits
		2004			2003			2004			2003			2004			2003
		(millions of dollars)
Assets in excess of/(less than) projected benefit obligation
	Balance at December 31 (1)	$	(3,471	)	$	(2,979	)	$	(8,031	)	$	(7,128	)	$	(4,944	)	$	(4,548	)
	Unrecognized net transition liability/(asset)		—			—			2			48			—			—
	Unrecognized net actuarial loss/(gain)		2,638			2,723			4,859			4,330			1,696			1,485
	Unrecognized prior service cost		172			199			512			363			567			645

Net amount recognized		$	(661	)	$	(57	)	$	(2,658	)	$	(2,387	)	$	(2,681	)	$	(2,418	)

Amounts recognized in the consolidated balance sheet consist of:
	Prepaid benefit cost (2)	$	71		$	64		$	713		$	794		$	—		$	—
	Accrued benefit cost (3)		(1,951	)		(1,512	)		(7,081	)		(6,498	)		(2,681	)		(2,418	)
	Intangible assets		244			281			712			429			—			—
	Equity of minority shareholders		—			—			117			146			—			—
	Accumulated other nonowner changes in equity, minimum pension liability adjustment		975			1,110			2,881			2,742			—			—

Net amount recognized		$	(661	)	$	(57	)	$	(2,658	)	$	(2,387	)	$	(2,681	)	$	(2,418	)

(1): Fair value of assets less projected benefit obligation shown in the preceding tables.
(2): Included in "Other assets, including intangibles, net" on the Consolidated Balance Sheet.
(3): Long-term portion in "Annuity Reserves" and short-term portion in "Accounts payable and accrued liabilities" on the Consolidated Balance Sheet.

		Annuity Benefits
		Annuity Benefits				Other Postretirement Benefits
		U.S.		Non-U.S.		Other Postretirement Benefits
		(millions of dollars)
Contributions expected in 2005		$	—	$	1,300	$	35
Benefit payments expected in:
	2005		649		938		359
	2006		675		952		347
	2007		732		981		353
	2008		776		1,000		358
	2009		829		1,018		366
	2010-2014		4,846		5,643		1,906

A summary of the change in other nonowner changes in equity related to the minimum pension liability adjustment is shown in the table below:

		Annuity Benefits
		Total (U.S. and Non-U.S.)
		2004			2003
		(millions of dollars)
Increase/(decrease) in accumulated other nonowner changes in equity, before tax		$	(4	)	$	895
Deferred income tax (charge)/credit (see note 19, page A53)			(49	)		(381	)

Increase/(decrease) in accumulated other nonowner changes in equity, after tax		$	(53	)	$	514

	(see Consolidated Statement of Shareholders' Equity, page A28)

A50

A summary of pension plans with an accumulated benefit obligation in excess of plan assets is shown in the table below:

		Annuity Benefits
		U.S.				Non-U.S.
		2004		2003		2004		2003
		(millions of dollars)
For funded pension plans with accumulated benefit obligations in excess of plan assets:
	Projected benefit obligation	$	9,397	$	8,999	$	11,552	$	9,886
	Accumulated benefit obligation		8,038		7,643		10,681		9,172
	Fair value of plan assets		7,127		7,141		8,128		6,719
	Accumulated benefit obligation less fair value of plan assets		911		502		2,553		2,453
For unfunded plans covered by book reserves:
	Projected benefit obligation		1,260		1,168		4,827		4,342
	Accumulated benefit obligation		1,041		1,010		4,305		3,872

18. Disclosures about Segments and Related Information

The Upstream, Downstream and Chemical functions best define the operating segments of the business that are reported separately. The factors used to identify these reportable segments are based on the nature of the operations that are undertaken by each segment. The Upstream segment is organized and operates to explore for and produce crude oil and natural gas. The Downstream segment is organized and operates to manufacture and sell petroleum products, and the Chemical segment is organized and operates to manufacture and sell petrochemicals. These segments are broadly understood across the petroleum and petrochemical industries.

These functions have been defined as the operating segments of the Corporation because they are the segments (a) that engage in business activities from which revenues are earned and expenses are incurred; (b) whose operating results are regularly reviewed by the Corporation's chief operating decision maker to make decisions about resources to be allocated to the segment and assess its performance; and (c) for which discrete financial information is available.

Earnings include special items and transfers are at estimated market prices. Consistent with a change in internal organization in 2002, earnings from the electric power business, previously reported in the Other segment, are now shown within non-U.S. Upstream. Earnings from the divested coal and minerals businesses are shown as discontinued operations and are included within the Other segment. In addition to discontinued operations, the Other segment includes corporate and financing activities and merger-related expenses. The interest revenue amount relates to interest earned on cash deposits and marketable securities. Interest expense includes nondebt-related interest expense of $529 million, $106 million and $207 million in 2004, 2003 and 2002, respectively. The increase in 2004 reflects the interest component of the Allapattah lawsuit provision. U.S. Downstream after-tax earnings in 2004 include a special charge of $550 million relating to the Allapattah lawsuit provision. Non-U.S. Upstream after-tax earnings in 2003 include $1,700 million from a gain on the transfer of shares in Ruhrgas AG, a German gas transmission company. All Other after-tax earnings in 2003 include $2,230 million relating to the positive settlement of a long-running U.S. tax dispute. All Other after-tax earnings in 2003 also include a $550 million positive impact for the required adoption of FAS 143 relating to accounting for asset retirement obligations. Non-U.S. Upstream after-tax earnings in 2002 include a special charge of $215 million reflecting the impact on deferred taxes from the 10 percent supplementary tax enacted in the United Kingdom in 2002.

A51

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

	Upstream				Downstream					Chemical
	Upstream				Downstream					Chemical				All Other			Corporate Total
	U.S.		Non-U.S.		U.S.			Non-U.S.		U.S.		Non-U.S.		All Other			Corporate Total
	(millions of dollars)
As of December 31, 2004
Earnings after income tax	$	4,948	$	11,727	$	2,186		$	3,520	$	1,020	$	2,408	$	(479	)	$	25,330
Earnings of equity companies included above		904		2,709		138			466		31		914		(201	)		4,961
Sales and other operating revenue		5,990		17,043		71,645			168,768		10,729		17,052		25			291,252
Intersegment revenue		6,547		21,800		8,047			26,577		4,937		4,278		306			—
Depreciation and depletion expense		1,453		4,758		618			1,646		408		400		484			9,767
Interest revenue		—		—		—			—		—		—		361			361
Interest expense		—		—		—			—		—		—		638			638
Income taxes		2,733		10,168		1,371			1,073		450		731		(615	)		15,911
Additions to property, plant and equipment		1,465		7,358		668			1,472		247		201		575			11,986
Investments in equity companies		1,347		6,595		401			1,047		276		2,079		(3	)		11,742
Total assets		19,330		62,204		14,685			49,688		8,102		13,052		28,195			195,256

As of December 31, 2003
Earnings after income tax	$	3,905	$	10,597	$	1,348		$	2,168	$	381	$	1,051	$	2,060		$	21,510
Earnings of equity companies included above		525		3,335		36			240		16		409		(188	)		4,373
Sales and other operating revenue		5,942		15,388		56,373			139,138		7,792		12,398		23			237,054
Intersegment revenue		5,479		15,782		5,627			18,752		3,403		3,237		310			—
Depreciation and depletion expense		1,571		4,072		601			1,548		410		368		477			9,047
Interest revenue		—		—		—			—		—		—		229			229
Interest expense		—		—		—			—		—		—		207			207
Income taxes		2,175		7,237		757			795		67		325		(350	)		11,006
Additions to property, plant and equipment		1,701		7,529		1,159			1,416		313		186		555			12,859
Investments in equity companies		1,266		5,176		316			909		266		1,612		—			9,545
Total assets		19,196		56,237		14,436			46,060		7,722		11,786		18,841			174,278

As of December 31, 2002
Earnings after income tax	$	2,524	$	7,074	$	693		$	607	$	384	$	446	$	(268	)	$	11,460
Earnings of equity companies included above		391		1,761		(40	)		27		24		175		(272	)		2,066
Sales and other operating revenue		3,896		12,588		48,865			119,167		6,891		9,517		25			200,949
Intersegment revenue		5,020		12,144		4,540			15,157		2,666		2,486		269			—
Depreciation and depletion expense		1,597		3,551		583			1,399		414		348		418			8,310
Interest revenue		—		—		—			—		—		—		297			297
Interest expense		—		—		—			—		—		—		398			398
Income taxes		1,321		5,162		359			44		165		189		(741	)		6,499
Additions to property, plant and equipment		1,902		6,122		884			1,357		448		181		543			11,437
Investments in equity companies		1,360		2,867		246			795		265		1,399		—			6,932
Total assets		19,385		47,040		13,562			41,530		7,543		10,581		13,003			152,644

Geographic Sales and other operating revenue		2004		2003		2002		Long-lived assets	2004		2003		2002
		(millions of dollars)							(millions of dollars)
United States		$	88,382	$	70,128	$	59,675	United States	$	33,569	$	34,585	$	34,138
Non-U.S.			202,870		166,926		141,274	Non-U.S.		75,070		70,380		60,802

	Total	$	291,252	$	237,054	$	200,949	Total	$	108,639	$	104,965	$	94,940

Significant non-U.S. revenue sources include:								Significant non-U.S. long-lived assets include:
	Japan	$	25,485	$	22,360	$	19,300	Canada	$	11,806	$	10,849	$	8,469
	United Kingdom		22,549		19,946		17,701	United Kingdom		9,545		9,615		9,030
	Canada		21,689		17,897		14,087	Norway		7,561		7,047		6,449
	Germany		17,649		15,764		14,101	Nigeria		4,923		3,833		2,633
	Italy		15,096		13,074		10,727	Japan		4,784		4,931		4,637
	France		12,231		9,725		8,416	Angola		3,544		2,666		1,678
								Singapore		3,089		3,252		3,407

A52

19. Income, Excise and Other Taxes

				2004								2003						2002
				U.S.			Non-U.S.		Total			U.S.		Non-U.S.		Total		U.S.		Non-U.S.			Total
				(millions of dollars)
Income taxes
	Federal or non-U.S.
		Current		$	4,410		$	12,030	$	16,440		$	1,522	$	7,426	$	8,948	$	351	$	5,618		$	5,969
		Deferred—net			(1,113	)		122		(991	)		996		645		1,641		635		(288	)		347
	U.S. tax on non-U.S. operations				56			—		56			71		—		71		62		—			62

					3,353			12,152		15,505			2,589		8,071		10,660		1,048		5,330			6,378
	State				406			—		406			346		—		346		121		—			121

			Total income taxes		3,759			12,152		15,911			2,935		8,071		11,006		1,169		5,330			6,499
Excise taxes					6,833			20,430		27,263			6,323		17,532		23,855		7,174		14,866			22,040
All other taxes and duties
	Other taxes and duties				26			40,928		40,954			22		37,623		37,645		35		33,537			33,572
	Included in production and manufacturing expenses				982			951		1,933			976		812		1,788		914		674			1,588
	Included in SG&A expenses				215			503		718			211		463		674		171		415			586

		Total other taxes and duties			1,223			42,382		43,605			1,209		38,898		40,107		1,120		34,626			35,746

			Total	$	11,815		$	74,964	$	86,779		$	10,467	$	64,501	$	74,968	$	9,463	$	54,822		$	64,285

All other taxes and duties include taxes reported in production and manufacturing and selling, general and administrative (SG&A) expenses. The above provisions for deferred income taxes include net (charges)/credits for the effect of changes in tax laws and rates of $318 million in 2004, $124 million in 2003 and $(194) million in 2002. Income taxes (charged)/credited directly to shareholders' equity were:

	2004			2003			2002
	(millions of dollars)
Cumulative foreign exchange translation adjustment	$	(180	)	$	(233	)	$	(331	)
Minimum pension liability adjustment		(49	)		(381	)		1,373
Unrealized gains and losses on stock investments		53			(331	)		(8	)
Other components of shareholders' equity		183			107			86

The reconciliation between income tax expense and a theoretical U.S. tax computed by applying a rate of 35 percent for 2004, 2003 and 2002, is as follows:

			2004			2003			2002
			(millions of dollars)
Earnings before federal and non-U.S. income taxes
	United States		$	11,067		$	9,438		$	4,340
	Non-U.S.			29,768			22,182			13,049

		Total	$	40,835		$	31,620		$	17,389

Theoretical tax			$	14,292		$	11,067		$	6,086
Effect of equity method accounting				(1,736	)		(1,531	)		(723	)
Non-U.S. taxes in excess of theoretical U.S. tax				3,093			1,635			1,355
U.S. tax on non-U.S. operations				56			71			62
U.S. tax settlement				—			(541	)		—
Other U.S.				(200	)		(41	)		(402	)

Federal and non-U.S. income tax expense			$	15,505		$	10,660		$	6,378

		Total effective tax rate		40.3	%		36.4	%		39.8	%

The effective income tax rate includes state income taxes and the Corporation's share of income taxes of equity companies. Equity company taxes totaled $1,180 million in 2004, $983 million in 2003 and $778 million in 2002, primarily outside the U.S.

Deferred income taxes reflect the impact of temporary differences between the amount of assets and liabilities recognized for financial reporting purposes and such amounts recognized for tax purposes.

Deferred tax liabilities/(assets) are comprised of the following at December 31:

Tax effects of temporary differences for:		2004			2003
		(millions of dollars)
Depreciation		$	16,732		$	16,284
Intangible development costs			4,733			3,821
Capitalized interest			2,279			2,109
Other liabilities			3,295			4,521

	Total deferred tax liabilities	$	27,039		$	26,735

Pension and other postretirement benefits		$	(2,613	)	$	(2,365	)
Tax loss carryforwards			(2,399	)		(2,500	)
Other assets			(3,761	)		(3,453	)

	Total deferred tax assets	$	(8,773	)	$	(8,318	)

Asset valuation allowances			686			854

	Net deferred tax liabilities	$	18,952		$	19,271

Deferred income tax (assets) and liabilities are included in the balance sheet as shown below. Deferred income tax (assets) and liabilities are classified as current or long term consistent with the classification of the related temporary difference—separately by tax jurisdiction.

Balance sheet classification		2004			2003
		(millions of dollars)
Prepaid taxes and expenses		$	(1,221	)	$	(919	)
Other assets, including intangibles, net			(1,406	)		(1,647	)
Accounts payable and accrued liabilities			487			1,719
Deferred income tax liabilities			21,092			20,118

	Net deferred tax liabilities	$	18,952		$	19,271

The Corporation had $25 billion of indefinitely reinvested, undistributed earnings from subsidiary companies outside the U.S. Unrecognized deferred taxes on remittance of these funds are not expected to be material.

A53

SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES (unaudited)

The results of operations for producing activities shown below are presented in accordance with Statement of Financial Accounting Standards No. 69. As such, it does not include earnings from other activities that ExxonMobil includes in the Upstream function such as oil and gas transportation operations, tar sands operations, LNG liquefaction and transportation operations, coal and power operations, technical services agreements, other nonoperating activities and adjustments for minority interests. These excluded amounts for both consolidated and equity companies totaled $1,340 million in 2004, $2,300 million in 2003 and $638 million in 2002.

Results of Operations			United States		Canada		Europe		Asia Pacific			Africa		Middle East		Other *(1)*			Total
			(millions of dollars)
2004—Revenue
		Sales to third parties	$	4,203	$	2,460	$	6,714	$	2,200		$	29	$	91	$	554		$	16,251
		Transfers		5,555		2,680		5,347		2,615			7,272		155		179			23,803

			$	9,758	$	5,140	$	12,061	$	4,815		$	7,301	$	246	$	733		$	40,054
	Production costs excluding taxes			1,442		1,085		1,932		622			719		41		164			6,005
	Exploration expenses			193		92		112		108			321		32		228			1,086
	Depreciation and depletion			1,335		969		2,082		667			839		35		95			6,022
	Taxes other than income			550		49		582		633			722		1		3			2,540
	Related income tax			2,546		1,015		4,417		1,022			2,789		78		102			11,969

	Results of producing activities for consolidated subsidiaries		$	3,692	$	1,930	$	2,936	$	1,763		$	1,911	$	59	$	141		$	12,432

	Proportional interest in results of producing activities of equity companies		$	810	$	—	$	993	$	—		$	—	$	635	$	465		$	2,903

2003—Revenue
		Sales to third parties	$	4,257	$	2,221	$	5,267	$	2,287		$	56	$	81	$	378		$	14,547
		Transfers		4,619		2,090		4,397		2,066			4,443		145		161			17,921

			$	8,876	$	4,311	$	9,664	$	4,353		$	4,499	$	226	$	539		$	32,468
	Production costs excluding taxes			1,435		1,054		1,688		558			564		48		146			5,493
	Exploration expenses			257		92		144		146			217		33		119			1,008
	Depreciation and depletion			1,456		782		1,833		727			459		43		95			5,395
	Taxes other than income			540		39		658		447			528		1		3			2,216
	Related income tax			2,017		738		2,902		1,046			1,496		50		44			8,293

	Results of producing activities for consolidated subsidiaries		$	3,171	$	1,606	$	2,439	$	1,429		$	1,235	$	51	$	132		$	10,063

	Proportional interest in results of producing activities of equity companies		$	584	$	—	$	836	$	—		$	—	$	424	$	295		$	2,139

2002—Revenue
		Sales to third parties	$	2,499	$	1,441	$	4,856	$	1,994		$	18	$	88	$	255		$	11,151
		Transfers		4,176		1,617		3,334		2,022			3,046		133		140			14,468

			$	6,675	$	3,058	$	8,190	$	4,016		$	3,064	$	221	$	395		$	25,619
	Production costs excluding taxes			1,405		766		1,493		592			455		49		143			4,903
	Exploration expenses			222		66		109		88			177		21		236			919
	Depreciation and depletion			1,512		681		1,737		651			354		40		110			5,085
	Taxes other than income			459		31		360		403			345		1		3			1,602
	Related income tax			1,153		486		2,399		939			972		80		(202	)		5,827

	Results of producing activities for consolidated subsidiaries		$	1,924	$	1,028	$	2,092	$	1,343		$	761	$	30	$	105		$	7,283

	Proportional interest in results of producing activities of equity companies		$	428	$	—	$	680	$	(13	)	$	—	$	341	$	241		$	1,677

(1): The Caspian region and South America.

A54

Average sales prices have been calculated by using sales quantities from the Corporation's own production as the divisor. Average production costs have been computed by using net production quantities for the divisor. The volumes of crude oil and natural gas liquids (NGL) production used for this computation are shown in the reserves table on page A59 of this report. The volumes for natural gas for this calculation are the production volumes of natural gas available for sale and thus are different than those shown in the reserves table on page A60 of this report due to volumes consumed or flared. The volumes of natural gas were converted to oil-equivalent barrels based on a conversion factor of six thousand cubic feet per barrel.

Average sales prices and production costs per unit of production—consolidated subsidiaries			United States		Canada		Europe		Asia Pacific		Africa		Middle East		Other *(1)*		Total
			(millions of dollars)
During 2004
	Average sales prices
		Crude oil and NGL, per barrel	$	34.84	$	30.26	$	35.71	$	39.09	$	35.04	$	38.49	$	29.14	$	34.76
		Natural gas, per thousand cubic feet		5.53		5.23		4.20		3.41		—		—		1.13		4.48
	Average production costs, per barrel (2)			5.05		6.47		4.95		3.74		3.44		6.22		5.20		4.78
During 2003
	Average sales prices
		Crude oil and NGL, per barrel	$	25.74	$	23.84	$	27.15	$	29.03	$	28.29	$	28.80	$	22.55	$	26.66
		Natural gas, per thousand cubic feet		5.06		4.61		3.76		2.84		—		—		1.04		3.98
	Average production costs, per barrel (2)			4.48		6.17		4.34		2.84		3.49		5.96		4.97		4.31
During 2002
	Average sales prices
		Crude oil and NGL, per barrel	$	20.80	$	20.73	$	22.95	$	24.26	$	24.19	$	24.62	$	17.31	$	22.30
		Natural gas, per thousand cubic feet		2.67		2.34		3.08		2.26		—		—		0.48		2.65
	Average production costs, per barrel (2)			3.97		4.53		3.82		2.72		3.57		5.31		4.94		3.78

(1): The Caspian region and South America.
(2): Production costs exclude depreciation and depletion and all taxes. Natural gas included by conversion to crude oil-equivalent.

A55

SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES (unaudited)

Oil and Gas Exploration and Production Costs (unaudited)

The amounts shown for net capitalized costs of consolidated subsidiaries are $4,769 million less at year-end 2004 and $3,961 million less at year-end 2003 than the amounts reported as investments in property, plant and equipment for the Upstream in note 9, page A35. This is due to the exclusion from capitalized costs of certain transportation and research assets and assets relating to the tar sands and LNG operations, all as required in Statement of Financial Accounting Standards No. 19. Part of the increase in net capitalized costs at year-end 2003 reflected the adoption of Statement of Financial Accounting Standards No. 143.

Capitalized Costs			United States		Canada		Europe		Asia Pacific		Africa		Middle East		Other *(1)*		Total
			(millions of dollars)
As of December 31, 2004
	Property (acreage) costs—Proved		$	3,739	$	3,414	$	235	$	339	$	253	$	659	$	523	$	9,162
		—Unproved		623		244		35		863		552		—		326		2,643

		Total property costs	$	4,362	$	3,658	$	270	$	1,202	$	805	$	659	$	849	$	11,805
	Producing assets			34,875		11,318		43,899		14,175		8,537		862		1,220		114,886
	Support facilities			617		119		530		1,113		383		10		95		2,867
	Incomplete construction			1,637		419		1,136		1,495		4,782		239		1,682		11,390

		Total capitalized costs	$	41,491	$	15,514	$	45,835	$	17,985	$	14,507	$	1,770	$	3,846	$	140,948
	Accumulated depreciation and depletion			26,508		8,905		30,943		11,489		3,801		1,474		584		83,704

	Net capitalized costs for consolidated subsidiaries		$	14,983	$	6,609	$	14,892	$	6,496	$	10,706	$	296	$	3,262	$	57,244

	Proportional interest of net capitalized costs of equity companies		$	1,234	$	—	$	1,277	$	—	$	—	$	767	$	2,427	$	5,705

As of December 31, 2003
	Property (acreage) costs—Proved		$	4,188	$	3,174	$	219	$	918	$	116	$	659	$	359	$	9,633
		—Unproved		663		251		46		1,025		545		—		475		3,005

		Total property costs	$	4,851	$	3,425	$	265	$	1,943	$	661	$	659	$	834	$	12,638
	Producing assets			35,737		9,925		39,371		14,478		6,158		850		1,207		107,726
	Support facilities			614		113		476		1,083		290		11		60		2,647
	Incomplete construction			1,201		381		1,174		1,133		4,477		63		1,010		9,439

		Total capitalized costs	$	42,403	$	13,844	$	41,286	$	18,637	$	11,586	$	1,583	$	3,111	$	132,450
	Accumulated depreciation and depletion			26,903		7,401		26,719		11,749		2,980		1,437		495		77,684

	Net capitalized costs for consolidated subsidiaries		$	15,500	$	6,443	$	14,567	$	6,888	$	8,606	$	146	$	2,616	$	54,766

	Proportional interest of net capitalized costs of equity companies		$	1,211	$	—	$	1,263	$	—	$	—	$	592	$	2,043	$	5,109

(1): The Caspian region and South America.

A56

Oil and Gas Exploration and Production Costs (unaudited) (continued)

The amounts reported as costs incurred include both capitalized costs and costs charged to expense during the year. Costs incurred also include new asset retirement obligations established in the current year, as well as increases or decreases to the asset retirement obligation resulting from changes in cost estimates or abandonment date. Total consolidated costs incurred in 2004 were $9,017 million, down $819 million from 2003, due primarily to lower development costs. 2003 costs were $9,836 million, up $1,421 million from 2002, due primarily to higher development costs.

Costs incurred in property acquisitions, exploration and development activities			United States		Canada		Europe		Asia Pacific		Africa		Middle East		Other *(1)*		Total
			(millions of dollars)
During 2004
	Property acquisition costs—Proved		$	—	$	—	$	—	$	—	$	68	$	—	$	25	$	93
		—Unproved		14		1		—		2		24		—		—		41
	Exploration costs			232		68		123		113		382		33		239		1,190
	Development costs			1,427		694		1,232		660		2,788		188		704		7,693

	Total costs incurred for consolidated subsidiaries		$	1,673	$	763	$	1,355	$	775	$	3,262	$	221	$	968	$	9,017

	Proportional interest of costs incurred of equity companies		$	155	$	—	$	169	$	—	$	—	$	205	$	451	$	980

During 2003
	Property acquisition costs—Proved		$	—	$	—	$	—	$	—	$	—	$	—	$	—	$	—
		—Unproved		17		7		4		—		17		—		—		45
	Exploration costs			252		102		153		138		264		33		210		1,152
	Development costs			1,636		644		1,755		929		3,117		69		489		8,639

	Total costs incurred for consolidated subsidiaries		$	1,905	$	753	$	1,912	$	1,067	$	3,398	$	102	$	699	$	9,836

	Proportional interest of costs incurred of equity companies		$	145	$	—	$	231	$	—	$	—	$	146	$	289	$	811

During 2002
	Property acquisition costs—Proved		$	18	$	8	$	—	$	—	$	—	$	—	$	—	$	26
		—Unproved		13		12		—		—		10		—		125		160
	Exploration costs			276		109		127		82		301		18		198		1,111
	Development costs			1,676		653		1,785		936		1,708		44		316		7,118

	Total costs incurred for consolidated subsidiaries		$	1,983	$	782	$	1,912	$	1,018	$	2,019	$	62	$	639	$	8,415

	Proportional interest of costs incurred of equity companies		$	173	$	—	$	223	$	13	$	—	$	100	$	231	$	740

(1): The Caspian region and South America.

A57

SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES (unaudited)

Oil and Gas Reserves (unaudited)

The following information describes changes during the years and balances of proved oil and gas reserves at year-end 2002, 2003 and 2004.

The definitions used are in accordance with the Securities and Exchange Commission's Rule 4-10 (a) of Regulation S-X, paragraphs (2) through (2)iii, (3) and (4).

Proved oil and gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements but not on escalations based upon future conditions. In some cases, substantial new investments in additional wells and related facilities will be required to recover these proved reserves. In certain deepwater fields, proved reserves are recorded in a limited number of cases before flow tests are conducted because of the safety and cost implications of conducting the tests. In those situations, other industry-accepted analyses are used. Historically, proved reserves recorded using these methods have been immaterial when compared to the Corporation's total proved reserves and have also been validated by subsequent flow tests or actual production levels.

Based on regulatory guidance, the Corporation has reported 2004 reserves on the basis of December 31, 2004, prices and costs ("year-end prices").

The impact of year-end prices on reserve estimation is most graphically shown at the Cold Lake field (heavy oil-bitumen steam project) in Canada where proved reserves were reduced by approximately 0.5 billion oil-equivalent barrels as a result of employing December 31 prices, which were unusually low for bitumen. However, bitumen prices in western Canada increased substantially after December 31 and resulted in the rebooking of approximately 0.5 billion oil-equivalent barrels at the Cold Lake field in 2005.

Proved reserves include 100 percent of each majority-owned affiliate's participation in proved reserves and ExxonMobil's ownership percentage of the proved reserves of equity companies, but exclude royalties and quantities due others. Gas reserves exclude the gaseous equivalent of liquids expected to be removed from the gas on leases, at field facilities and at gas processing plants. These liquids are included in net proved reserves of crude oil and natural gas liquids.

In the reserves tables on pages A59 to A61, consolidated reserves and equity reserves are reported separately. However, the Corporation does not view equity reserves any differently than those from consolidated companies.

Reserves reported under production sharing and other nonconcessionary agreements are based on the economic interest as defined by the specific fiscal terms in the agreement. The percentage of conventional liquids and natural gas proved reserves (consolidated subsidiaries plus equity companies) at year-end 2004 that were associated with production sharing contract arrangements was 17 percent of liquids, 9 percent of natural gas and 13 percent on an oil-equivalent basis (gas converted to oil-equivalent at 6 billion cubic feet = 1 million barrels).

Net proved developed reserves are those volumes that are expected to be recovered through existing wells with existing equipment and operating methods. Undeveloped reserves are those volumes that are expected to be recovered as a result of future investments to drill new wells, to recomplete existing wells and/or to install facilities to collect and deliver the production from existing and future wells.

Crude oil and natural gas liquids and natural gas production quantities shown are the net volumes withdrawn from ExxonMobil's oil and gas reserves. The natural gas quantities differ from the quantities of gas delivered for sale by the producing function as reported on page A65 due to volumes consumed or flared and inventory changes.

A58

(unaudited)

Crude Oil and Natural Gas Liquids				United States		Canada *(1)*		Europe		Asia Pacific		Africa		Middle East *(2)*		Other *(3)*		Total
				(millions of barrels)
Net proved developed and undeveloped reserves of consolidated subsidiaries
	January 1, 2002			3,028		1,277		1,476		622		2,461		30		658		9,552
		Revisions		31		74		59		40		73		3		23		303
		Purchases		—		—		—		—		—		—		—		—
		Sales		(13	)	—		—		—		—		—		—		(13	)
		Improved recovery		3		—		—		—		75		—		—		78
		Extensions and discoveries		60		40		11		124		145		—		100		480
		Production		(200	)	(106	)	(213	)	(95	)	(128	)	(9	)	(24	)	(775	)

	December 31, 2002			2,909		1,285		1,333		691		2,626		24		757		9,625
		Revisions		31		14		50		67		176		1		2		341
		Purchases		1		—		—		—		—		—		—		1
		Sales		(14	)	—		(2	)	—		—		—		—		(16	)
		Improved recovery		16		3		1		—		66		—		—		86
		Extensions and discoveries		27		6		10		12		36		49		491		631
		Production		(178	)	(114	)	(208	)	(86	)	(162	)	(8	)	(23	)	(779	)

	December 31, 2003			2,792		1,194		1,184		684		2,742		66		1,227		9,889
		Performance-related revisions		(46	)	4		35		17		(39	)	(4	)	77		44
		Purchases		—		—		—		—		10		—		—		10
		Sales		(113	)	(3	)	—		(16	)	—		—		—		(132	)
		Improved recovery		5		—		—		—		—		—		—		5
		Extensions and discoveries		15		4		3		2		150		—		—		174
		Production		(161	)	(108	)	(210	)	(74	)	(209	)	(7	)	(26	)	(795	)

			Total before year-end price/cost revisions	2,492		1,091		1,012		613		2,654		55		1,278		9,195
		Year-end price/cost revisions		101		(464	)	2		(12	)	(210	)	(6	)	(211	)	(800	)

	December 31, 2004			2,593		627		1,014		601		2,444		49		1,067		8,395

Proportional interest in proved reserves of equity companies
		End of year 2002		443		—		26		—		—		779		950		2,198
		End of year 2003		426		—		20		—		—		767		973		2,186
		End of year 2004 (4)		402		—		17		—		—		1,169		911		2,499

Proved developed reserves, included above, as of
	December 31, 2002
		Consolidated subsidiaries		2,461		685		797		487		1,057		23		185		5,695
		Equity companies		374		—		20		—		—		652		459		1,505
Proved developed reserves, included above, as of
	December 31, 2003
		Consolidated subsidiaries		2,348		750		805		473		1,107		16		165		5,664
		Equity companies		363		—		16		—		—		616		513		1,508
Proved developed reserves, included above, as of
	December 31, 2004
		Consolidated subsidiaries		2,204		561		763		394		1,117		9		163		5,211
		Equity companies		347		—		15		—		—		642		600		1,604

(1): Includes total proved reserves attributable to Imperial Oil Limited of 947 million barrels in 2002, 889 million barrels in 2003 and 347 million barrels in 2004, as well as proved developed reserves of 447 million barrels in 2002, 519 million barrels in 2003 and 343 million barrels in 2004, in which there is a 30.4 percent minority interest.
(2): 2003 reserves were adjusted to reflect the movement of equity company volumes to consolidated company reserves.
(3): The Caspian region and South America.
(4): Year-end 2004 equity company total reserves of 2,499 million barrels included a negative revision of 62 million barrels due to the use of year-end prices and costs.

A59

SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES (unaudited)

Oil and Gas Reserves (continued)

Natural Gas				United States		Canada *(1)*		Europe		Asia Pacific		Africa		Middle East *(2)*		Other *(3)*		Total
						(billions of cubic feet)
Net proved developed and undeveloped reserves of consolidated subsidiaries
	January 1, 2002			12,732		3,183		10,931		8,301		379		38		690		36,254
		Revisions		206		30		600		258		17		—		42		1,153
		Purchases		—		2		—		—		—		—		—		2
		Sales		(43	)	—		—		—		—		—		—		(43	)
		Improved recovery		1		3		—		—		—		—		—		4
		Extensions and discoveries		209		83		115		212		52		—		9		680
		Production		(1,043	)	(419	)	(1,138	)	(813	)	(12	)	(8	)	(36	)	(3,469	)

	December 31, 2002			12,062		2,882		10,508		7,958		436		30		705		34,581
		Revisions		124		(199	)	411		23		157		(4	)	(2	)	510
		Purchases		10		—		—		—		—		—		—		10
		Sales		(90	)	—		(3	)	—		—		—		—		(93	)
		Improved recovery		9		1		—		—		—		—		—		10
		Extensions and discoveries		156		45		333		22		1		849		239		1,645
		Production		(999	)	(388	)	(1,103	)	(718	)	(11	)	(9	)	(40	)	(3,268	)

	December 31, 2003			11,272		2,341		10,146		7,285		583		866		902		33,395
		Performance-related revisions		31		19		(65	)	(375	)	165		(75	)	211		(89	)
		Purchases		—		—		—		—		9		—		—		9
		Sales		(142	)	(18	)	(16	)	(301	)	—		—		—		(477	)
		Improved recovery		2		—		31		—		—		—		—		33
		Extensions and discoveries		121		36		39		44		39		—		—		279
		Production		(846	)	(399	)	(1,092	)	(624	)	(25	)	(9	)	(40	)	(3,035	)

			Total before year-end price/cost revisions	10,438		1,979		9,043		6,029		771		782		1,073		30,115
		Year-end price/cost revisions		1,891		(96	)	142		(110	)	—		(98	)	(1	)	1,728

	December 31, 2004			12,329		1,883		9,185		5,919		771		684		1,072		31,843

Proportional interest in proved reserves of equity companies
	End of year 2002			177		—		13,828		—		—		5,692		1,440		21,137
	End of year 2003			152		—		13,703		—		—		6,055		1,464		21,374
	End of year 2004 (4)			140		—		13,557		—		—		13,455		1,367		28,519

(1): Includes total proved reserves attributable to Imperial Oil Limited of 1,224 billion cubic feet in 2002, 1,023 billion cubic feet in 2003 and 791 billion cubic feet in 2004, in which there is a 30.4 percent minority interest.
(2): 2003 reserves were adjusted to reflect the movement of equity company volumes to consolidated company reserves.
(3): The Caspian region and South America.
(4): Year-end 2004 equity company total reserves of 28,519 billion cubic feet included a positive revision of 694 billion cubic feet due to the use of year-end prices and costs.

A60

(unaudited)

Natural Gas (continued)			United States	Canada *(1)*	Europe	Asia Pacific	Africa	Middle East	Other *(2)*	Total
			(billions of cubic feet)
Proved developed reserves, included above, as of
	December 31, 2002
		Consolidated subsidiaries	9,991	2,294	7,326	5,887	112	30	372	26,012
		Equity companies	137	—	5,602	—	—	2,358	634	8,731
Proved developed reserves, included above, as of
	December 31, 2003
		Consolidated subsidiaries	9,513	1,962	7,196	5,764	155	21	331	24,942
		Equity companies	124	—	7,770	—	—	2,689	709	11,292
Proved developed reserves, included above, as of
	December 31, 2004
		Consolidated subsidiaries	9,134	1,647	7,076	4,428	279	12	283	22,859
		Equity companies	120	—	9,805	—	—	4,578	837	15,340

(1): Includes proved developed reserves attributable to Imperial Oil Limited of 959 billion cubic feet in 2002, 859 billion cubic feet in 2003 and 704 billion cubic feet in 2004, in which there is a 30.4 percent minority interest.
(2): The Caspian region and South America.

INFORMATION ON CANADIAN TAR SANDS PROVEN RESERVES NOT INCLUDED ABOVE

In addition to conventional liquids and natural gas proved reserves, ExxonMobil has significant interests in proven tar sands reserves in Canada associated with the Syncrude project. For internal management purposes, ExxonMobil views these reserves and their development as an integral part of total upstream operations. However, for financial reporting purposes, these reserves are required to be reported separately from the oil and gas reserves.

The tar sands reserves are not considered in the standardized measure of discounted future cash flows for conventional oil and gas reserves, which is found on page A62.

Tar Sands Reserves		Canada
		(millions of barrels)
At December 31, 2002		800
At December 31, 2003		781
At December 31, 2004		757

A61

SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES (unaudited)

Standardized Measure of Discounted Future Cash Flows

As required by the Financial Accounting Standards Board, the standardized measure of discounted future net cash flows is computed by applying year-end prices, costs and legislated tax rates and a discount factor of 10 percent to net proved reserves. The standardized measure includes costs for future dismantlement, abandonment and rehabilitation obligations. The Corporation believes the standardized measure does not provide a reliable estimate of the Corporation's expected future cash flows to be obtained from the development and production of its oil and gas properties or of the value of its proved oil and gas reserves. The standardized measure is prepared on the basis of certain prescribed assumptions including year-end prices, which represent a single point in time and therefore may cause significant variability in cash flows from year to year as prices change.

Standardized Measure of Discounted Future Cash Flows			United States		Canada *(1)*		Europe		Asia Pacific		Africa		Middle East *(2)*		Other *(3)*		Total
			(millions of dollars)
Consolidated subsidiaries
	As of December 31, 2002
		Future cash inflows from sales of oil and gas	$	118,905	$	38,528	$	68,111	$	36,917	$	76,407	$	695	$	17,626	$	357,189
		Future production costs		26,601		7,910		14,781		9,889		13,673		113		3,325		76,292
		Future development costs		5,545		3,157		5,983		3,433		10,454		—		1,789		30,361
		Future income tax expenses		34,289		10,261		23,580		8,254		28,190		315		3,606		108,495

		Future net cash flows	$	52,470	$	17,200	$	23,767	$	15,341	$	24,090	$	267	$	8,906	$	142,041
		Effect of discounting net cash flows at 10%		28,930		6,792		7,788		5,857		11,658		42		5,592		66,659

		Discounted future net cash flows	$	23,540	$	10,408	$	15,979	$	9,484	$	12,432	$	225	$	3,314	$	75,382

	Proportional interest in standardized measure of discounted future net cash flows related to proved reserves of equity companies		$	3,930	$	—	$	7,140	$	—	$	—	$	6,218	$	3,889	$	21,177

Consolidated subsidiaries
	As of December 31, 2003
		Future cash inflows from sales of oil and gas	$	127,459	$	35,637	$	71,937	$	37,006	$	76,969	$	1,784	$	27,735	$	378,527
		Future production costs		26,777		11,451		16,090		10,860		15,017		145		4,324		84,664
		Future development costs		4,537		3,659		6,966		3,740		7,576		76		3,787		30,341
		Future income tax expenses		38,690		7,835		25,080		8,819		29,808		714		5,418		116,364

		Future net cash flows	$	57,455	$	12,692	$	23,801	$	13,587	$	24,568	$	849	$	14,206	$	147,158
		Effect of discounting net cash flows at 10%		31,107		4,688		7,970		5,290		10,868		436		9,862		70,221

		Discounted future net cash flows	$	26,348	$	8,004	$	15,831	$	8,297	$	13,700	$	413	$	4,344	$	76,937

Proportional interest in standardized measure of discounted future net cash flows related to proved reserves of equity companies			$	4,007	$	—	$	9,826	$	—	$	—	$	4,627	$	3,849	$	22,309

Consolidated subsidiaries
	As of December 31, 2004
		Future cash inflows from sales of oil and gas	$	141,261	$	25,008	$	79,698	$	34,921	$	87,687	$	1,850	$	31,935	$	402,360
		Future production costs		30,096		5,686		17,847		10,691		17,929		183		4,125		86,557
		Future development costs		6,181		2,743		7,670		3,682		7,822		59		3,923		32,080
		Future income tax expenses		42,928		5,662		28,883		7,066		33,945		840		6,707		126,031

		Future net cash flows	$	62,056	$	10,917	$	25,298	$	13,482	$	27,991	$	768	$	17,180	$	157,692
		Effect of discounting net cash flows at 10%		36,078		3,598		8,485		5,342		11,287		362		11,456		76,608

		Discounted future net cash flows	$	25,978	$	7,319	$	16,813	$	8,140	$	16,704	$	406	$	5,724	$	81,084

Proportional interest in standardized measure of discounted future net cash flows related to proved reserves of equity companies			$	4,079	$	—	$	9,612	$	—	$	—	$	11,137	$	4,784	$	29,612

(1): Includes discounted future net cash flows attributable to Imperial Oil Limited of $5,210 million in 2002, $3,667 million in 2003 and $2,773 million in 2004, in which there is a 30.4 percent minority interest.
(2): 2003 cash flows were adjusted to reflect the movement of equity company cash flows to consolidated company cash flows.
(3): The Caspian region and South America.

A62

(unaudited)

Change in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves

Consolidated Subsidiaries			2004			2003 *(1)*			2002
			(millions of dollars)
Value of reserves added during the year due to extensions, discoveries, improved recovery and net purchases less related costs			$	588		$	4,431		$	5,481
Changes in value of previous-year reserves due to:
	Sales and transfers of oil and gas produced during the year, net of production (lifting) costs			(31,726	)		(25,012	)		(19,242	)
	Development costs incurred during the year			7,660			8,350			6,994
	Net change in prices, lifting and development costs			21,267			4,014			57,506
	Revisions of previous reserves estimates			(766	)		2,234			4,665
	Accretion of discount			10,645			10,513			5,837
Net change in income taxes				(3,521	)		(2,975	)		(26,973	)

		Total change in the standardized measure during the year	$	4,147		$	1,555		$	34,268

(1): 2003 change in standardized measure was adjusted to reflect the movement of equity company cash flows to consolidated company cash flows.

A63

QUARTERLY INFORMATION

		2004						2003
		First Quarter		Second Quarter	Third Quarter	Fourth Quarter	Year	First Quarter		Second Quarter	Third Quarter	Fourth Quarter	Year
		(thousands of barrels daily)
Volumes
Production of crude oil and natural gas liquids			2,635	2,581	2,505	2,565	2,571		2,504	2,477	2,485	2,595	2,516
Refinery throughput			5,596	5,589	5,809	5,852	5,713		5,390	5,491	5,555	5,603	5,510
Petroleum product sales			8,126	8,023	8,242	8,446	8,210		7,859	7,795	7,931	8,237	7,957

		(millions of cubic feet daily)
Natural gas production available for sale			11,488	9,061	8,488	10,430	9,864		12,046	9,283	8,323	10,858	10,119

		(thousands of oil-equivalent barrels daily)
Oil-equivalent production (1)			4,550	4,091	3,920	4,303	4,215		4,512	4,024	3,872	4,405	4,203

		(thousands of metric tons)
Chemical prime product sales			6,792	6,930	7,117	6,949	27,788		6,880	6,335	6,660	6,692	26,567

		(millions of dollars)
Summarized financial data
Sales and other operating revenue		$	66,060	69,220	74,854	81,118	291,252	$	60,188	56,167	58,760	61,939	237,054
Gross profit (2)		$	27,619	28,202	29,655	33,560	119,036	$	24,588	24,451	24,007	26,043	99,089
Income from continuing operations		$	5,440	5,790	5,680	8,420	25,330	$	6,490	4,170	3,650	6,650	20,960
Accounting change, net of income tax		$	—	—	—	—	—	$	550	—	—	—	550

Net income		$	5,440	5,790	5,680	8,420	25,330	$	7,040	4,170	3,650	6,650	21,510


		(dollars per share)
Per share data
Income from continuing operations		$	0.83	0.89	0.88	1.31	3.91	$	0.97	0.63	0.55	1.01	3.16
Accounting change, net of income tax		$	—	—	—	—	—	$	0.08	—	—	—	0.08

Net income per common share		$	0.83	0.89	0.88	1.31	3.91	$	1.05	0.63	0.55	1.01	3.24

Net income per common share—assuming dilution		$	0.83	0.88	0.88	1.30	3.89	$	1.05	0.62	0.55	1.01	3.23
Dividends per common share		$	0.25	0.27	0.27	0.27	1.06	$	0.23	0.25	0.25	0.25	0.98
Common stock prices
	High	$	43.40	45.53	49.79	52.05	52.05	$	36.60	38.45	38.50	41.13	41.13
	Low	$	39.91	41.43	44.20	48.18	39.91	$	31.58	34.20	34.90	35.05	31.58

(1): Gas converted to oil-equivalent at 6 million cubic feet = 1 thousand barrels.
(2): Gross profit equals sales and other operating revenue less estimated costs associated with products sold.

The price range of ExxonMobil common stock is as reported on the composite tape of the several U.S. exchanges where ExxonMobil common stock is traded. The principal market where ExxonMobil common stock (XOM) is traded is the New York Stock Exchange, although the stock is traded on other exchanges in and outside the United States.

There were 637,416 registered shareholders of ExxonMobil common stock at December 31, 2004. At January 31, 2005, the registered shareholders of ExxonMobil common stock numbered 636,250.

On January 26, 2005, the Corporation declared a $0.27 dividend per common share, payable March 10, 2005.

A64

OPERATING SUMMARY

			2004	2003	2002	2001	2000
			(thousands of barrels daily)
Production of crude oil and natural gas liquids
	Net production
		United States	557	610	681	712	733
		Canada	355	363	349	331	304
		Europe	583	579	592	653	704
		Asia Pacific	202	237	260	247	253
		Africa	572	442	349	342	323
		Other Non-U.S.	302	285	265	257	236

	Worldwide		2,571	2,516	2,496	2,542	2,553

			(millions of cubic feet daily)
Natural gas production available for sale
	Net production
		United States	1,947	2,246	2,375	2,598	2,856
		Canada	972	943	1,024	1,006	844
		Europe	4,614	4,498	4,463	4,595	4,463
		Asia Pacific	1,519	1,803	2,019	1,547	1,755
		Other Non-U.S.	812	629	571	533	425

	Worldwide		9,864	10,119	10,452	10,279	10,343

			(thousands of oil-equivalent barrels daily)
Oil-equivalent production (1)			4,215	4,203	4,238	4,255	4,277

			(thousands of barrels daily)
Refinery throughput
		United States	1,850	1,806	1,834	1,811	1,862
		Canada	468	450	447	449	451
		Europe	1,663	1,566	1,539	1,563	1,578
		Asia Pacific	1,423	1,390	1,379	1,436	1,462
		Other Non-U.S.	309	298	244	283	289

	Worldwide		5,713	5,510	5,443	5,542	5,642

Petroleum product sales
		United States	2,872	2,729	2,731	2,751	2,669
		Canada	615	602	593	585	577
		Europe	2,139	2,061	2,042	2,079	2,129
		Asia Pacific and other Eastern Hemisphere	2,080	2,075	1,889	2,024	2,090
		Latin America	504	490	502	532	528

	Worldwide		8,210	7,957	7,757	7,971	7,993

		Gasoline, naphthas	3,301	3,238	3,176	3,165	3,122
		Heating oils, kerosene, diesel oils	2,517	2,432	2,292	2,389	2,373
		Aviation fuels	698	662	691	721	749
		Heavy fuels	659	638	604	668	694
		Specialty petroleum products	1,035	987	994	1,028	1,055

	Worldwide		8,210	7,957	7,757	7,971	7,993

			(thousands of metric tons)
Chemical prime product sales
		United States	11,521	10,740	11,386	11,078	11,736
		Non-U.S.	16,267	15,827	15,220	14,702	13,901

	Worldwide		27,788	26,567	26,606	25,780	25,637

Operating statistics include 100 percent of operations of majority-owned subsidiaries; for other companies, crude production, gas, petroleum product and chemical prime product sales include ExxonMobil's ownership percentage, and refining throughput includes quantities processed for ExxonMobil. Net production excludes royalties and quantities due others when produced, whether payment is made in kind or cash.

(1): Gas converted to oil-equivalent at 6 million cubic feet = 1 thousand barrels.

A65

APPENDIX B
AUDIT COMMITTEE CHARTER

I. Purposes of the Committee

The primary purpose of the Audit Committee (the "Committee") is oversight. The Committee shall assist the Board of Directors (the "Board") in fulfilling its responsibility to oversee:

•: Management's conduct of the Corporation's financial reporting process;
•: The integrity of the financial statements and other financial information provided by the Corporation to the Securities and Exchange Commission (the "SEC") and the public;
•: The Corporation's system of internal accounting and financial controls;
•: The Corporation's compliance with legal and regulatory requirements;
•: The performance of the Corporation's internal audit function;
•: The independent auditors' qualifications, performance, and independence; and
•: The annual independent audit of the Corporation's financial statements.

The Committee shall have direct authority and responsibility to appoint (subject to shareholder ratification), compensate, retain, and oversee the independent auditors.

The Committee shall also prepare the report that the SEC rules require be included in the Corporation's annual proxy statement.

The Corporation's management is responsible for preparing the Corporation's financial statements. The independent auditors are responsible for auditing those financial statements. Management, including the internal audit function, and the independent auditors, have more time, knowledge, and detailed information about the Corporation than do Committee members. Consequently, in carrying out its oversight responsibilities, the Committee is not providing any expert or special assurance as to the Corporation's financial statements, or any professional certification as to the independent auditors' work, including with respect to auditor independence. Each member of the Committee shall be entitled to rely on the integrity of people and organizations from whom the Committee receives information and the accuracy of such information, including representations by management and the independent auditors regarding non-audit services provided by the independent auditors.

II. Committee Membership

The Committee shall have at least three members. Committee members shall be appointed by the Board from among its members and may be removed by the Board at any time. Each member of the Committee must satisfy such criteria of independence as the Board may establish and such additional regulatory or listing requirements as the Board may determine to be applicable or appropriate.

Accordingly, each member of the Committee shall be financially literate within a reasonable period of time after appointment to the Committee; must be "independent" within the meaning of Rule 10A-3 under the Securities Exchange Act of 1934; and may not serve on more than two other public company audit committees unless the Board determines that such simultaneous service would not impair the ability of the member to serve effectively on the Committee. In addition, at least one member of the Committee shall be an "audit committee financial expert" as defined by the SEC.

The actual number of members shall be determined from time to time by resolution of the Board. Two members of the Committee shall constitute a quorum thereof.

III. Committee Structure and Operations

The Chair of the Committee shall be designated by the Board. The Committee shall fix its own rules of procedure and shall meet where and as provided by such rules or by resolution of the Committee. In addition to the regular meeting schedule established by the Committee, the Chair of the Committee may call a special meeting at any time.

The Secretary of the Corporation shall be the Secretary of the Audit Committee, unless the Committee designates otherwise.

In the absence of the Chair during any Committee meeting, the Committee may designate a Chair pro tempore.

The Committee shall act only on the affirmative vote of a majority of the members at a meeting or by unanimous written consent.

The Committee may establish sub-committees to carry out such duties as the Committee may assign.

IV. Committee Activities

The following shall be the common recurring activities of the Committee in carrying out its purposes. These activities are set forth as a guide with the understanding that the Committee may diverge from this guide as appropriate given the circumstances.

1.: Appoint the independent auditors to audit the consolidated financial statements of the Corporation and its subsidiaries for the coming year; approve the engagement fees and terms; and recommend ratification of that appointment by the shareholders.
2.: Pre-approve all audit and non-audit services to be provided by the independent auditors to the Corporation in accordance with the Committee's policies and procedures, and regularly review: (a) the adequacy of the Committee's policies and procedures for pre-approving the use of the independent auditors for audit and non-audit services with a view to auditor independence; (b) the audit and non-audit services pre-approved in accordance with the Committee's policies and procedures; and (c) fees paid to the independent auditors for pre-approved audit and non-audit services.
3.: Regularly review with the independent auditors: (a) the arrangements for and the scope of the independent auditors' audit of the Corporation's consolidated financial statements; (b) the results of the audit by the Corporation's independent auditors of the Corporation's consolidated financial statements; (c) any audit problems or difficulties encountered by the independent auditors and management's response; (d) any significant deficiency in the design or the operation of the Corporation's internal accounting controls identified by the independent auditors and any resulting recommendations; (e) all critical accounting policies and practices used by the Corporation; (f) all alternative accounting treatments of financial information within generally accepted accounting principles that have been discussed with management, including the ramifications of the use of such alternative treatments and disclosures, and the treatment preferred by the independent auditors; and (g) other material written communications between the independent auditors and management. The Committee shall have ultimate authority to resolve any disagreement between management and the independent auditors regarding financial reporting.
4.: Review major changes to the Corporation's auditing and accounting principles and practices based on advice of the independent auditors, the Controller, the General Auditor, or management.

5.: At least annually, obtain and review a report by the independent auditors describing: (a) the firm's internal quality-control procedures; (b) any material issues raised by the most recent internal quality-control review, or peer review, of the firm, or by any inquiry or investigation by governmental or professional authorities, within the preceding five years, respecting one or more independent audits carried out by the firm, and any steps taken to deal with any such issues; and (c) all relationships between the independent auditors and the Corporation consistent with Independence Standards Board Standard Number 1. The Committee shall discuss such report with the independent auditors, which may include issues that impact the independent auditors' qualifications, performance, or independence.
6.: Evaluate, along with the other members of the Board, management, the Controller, and the General Auditor, the qualifications, performance, and independence of the independent auditors, including the performance of the lead audit partner.
7.: Monitor regular rotation of audit partners by the independent auditors as required by law.
8.: The Committee, along with the other members of the Board, shall discuss with management and the independent auditors the audited financial statements to be included in the Corporation's Annual Report on Form 10-K, including the Corporation's disclosures under "Management's Discussion and Analysis of Financial Condition and Results of Operations." The Committee shall review and consider with the independent auditors the matters required to be discussed by Statement of Auditing Standards No. 61 ("SAS No. 61"), including deficiencies in internal controls, fraud, illegal acts, management judgments and estimates, audit adjustments, audit difficulties, and the independent auditors' judgments about the quality of the Corporation's accounting practices.
9.: Discuss with the independent auditors and management the Corporation's interim financial results to be included in each quarterly report on Form 10-Q, including the Corporation's disclosures under "Management's Discussion and Analysis of Financial Condition and Results of Operations." Each such review shall include any matters required to be discussed by SAS No. 61, and shall occur prior to the Corporation's filing of the related Form 10-Q with the SEC.
10.: Maintain and periodically review the Corporation's procedures for the receipt, retention, and treatment of complaints regarding accounting, internal accounting controls or auditing matters, including procedures for the confidential, anonymous submission by employees of the Corporation, of concerns regarding questionable accounting or auditing matters.
11.: Confer with the Controller, the General Auditor, the General Counsel, management, and the independent auditors as requested by any of them or by the Committee, at least annually, and review their reports with respect to the functioning, quality, and adequacy of programs for compliance with the Corporation's policies and procedures regarding business ethics, financial controls, internal auditing, and compliance with legal and regulatory requirements, including information regarding violations or probable violations of such policies.
12.: Discuss from time to time the Corporation's earnings press releases, as well as financial information and earnings guidance provided to analysts and rating agencies.
13.: Discuss from time to time the Corporation's policies with respect to risk assessment and risk management.
14.: Maintain hiring policies for employees and former employees of the independent auditors.
15.: Review the expenses of officers of the Corporation who are also members of the Board and such other officers as it may deem appropriate.

16.: Review with the Controller and the General Auditor, at least annually, the activities, budget, staffing, and structure of the internal auditing function of the Corporation and its subsidiaries, including their evaluations of the performance of that function and any recommendations with respect to improving the performance of or strengthening of that function. As appropriate, the Committee shall review the reports of any internal auditor on a financial safeguard problem that has not resulted in corrective action or has not otherwise been resolved to the auditors' satisfaction at any intermediate level of audit management.
17.: From time to time, meet separately with management, the internal auditors, and the independent auditors to discuss issues warranting attention by the Committee.
18.: Prepare any report or other disclosure by the Committee required to be included in any proxy statement for the election of the Corporation's directors under the rules of the SEC.
19.: Take other such actions and do other such things as may be referred to it from time to time by the Board.

V. Committee Evaluation

The Committee will annually complete a self-evaluation of the Committee's own performance and effectiveness and will consider whether any changes to the Committee's charter are appropriate.

VI. Committee Reports

The Chair of the Committee will report regularly to the full Board on the Committee's activities, findings, and recommendations, including the results of the Committee's self-evaluation and any recommended changes to the Committee's charter.

VII. Resources and Authority of the Committee

The Committee has exclusive authority with respect to the retention of the independent auditors described in Section IV of this charter. In discharging its oversight role, the Committee is empowered to investigate any matter brought to its attention with full access to all books, records, facilities, and personnel of the Corporation. The Committee also has the authority to retain outside advisors, including legal counsel, auditors, or other experts, as it deems appropriate; to approve the fees and expenses of such advisors; and to incur such other ordinary administrative expenses as are necessary or appropriate in carrying out its duties.

Directions
ExxonMobil 2005 Annual Meeting
Morton H. Meyerson Symphony Center
2301 Flora Street
Dallas, Texas

•: Free parking is available at the Arts District Garage. Traffic in the area may cause a delay; please allow extra time for parking.
•: From I-45/Hwy. 75 – Take I-35E exit (Woodall Rodgers Frwy.) to Pearl Street exit or St. Paul exit (follow frontage road east to Pearl Street), turn south and continue to Ross Avenue, turn left to Arts District Garage.
•: From I-35E – Take I-45/Hwy. 75 exit (Woodall Rodgers Frwy.) to Pearl Street exit, continue to Ross Avenue, turn left to Arts District Garage.
•: From DFW Airport – Take South exit to Hwy. 183 East (merges with I-35E), follow directions from I-35E (above).
•: From Love Field – Exit airport on Mockingbird Lane west to I-35E South, follow directions from I-35E (above).


		*Printed on recycled paper*		3300-PS-2005

		2005 ANNUAL MEETING
		ADMISSION TICKET
c/o EquiServe Trust Company, N.A. P.O. Box 8694 Edison, NJ 08818-8694		This ticket will admit shareholder and one guest.

ANNUAL MEETING OF SHAREHOLDERS

TIME:	Wednesday, May 25, 2005, 9:00 a.m., Central Time
PLACE:	Morton H. Meyerson Symphony Center Dallas, Texas (map on back)
AUDIOCAST:	Live on the internet at www.exxonmobil.com. Instructions appear on the internet site one week prior to the event.
ADMISSION:	Valid admission ticket and government-issued picture identification required.

Your vote is important. Please vote immediately.


	Vote by Internet			Vote by Telephone
1.	Log on to the internet and go to www.eproxyvote.com/xom.		1.	Call toll-free 1-877-779-8683 (within the U.S. and Canada) or 1-201-536-8073 (outside the U.S. and Canada).
		OR
2.	Follow the easy steps outlined on the secure internet site.		2.	Follow the easy recorded instructions.

If you vote over the internet or by telephone, please do not mail your card.

-------------------------------------------------------------------------------------------------------------------------------------
DETACH HERE IF YOU ARE RETURNING YOUR PROXY CARD BY MAIL

Please mark
votes as in
this example.

3300

	The Directors recommend a vote FOR items 1 and 2.

1.	Election of directors (page 6).	FOR o		WITHHELD o
	For all nominees except as noted above
2.	Ratification of independent auditors (page 28).	FOR o	AGAINST o	ABSTAIN o

	The Directors recommend a vote AGAINST shareholder proposal items 3 through 10.
		FOR	AGAINST	ABSTAIN			FOR	AGAINST	ABSTAIN
3.	Political contributions (page 30).	o	o	o	7.	Amendment of EEO policy (page 34).	o	o	o
4.	Board compensation (page 31).	o	o	o	8.	Biodiversity impact report (page 36).	o	o	o
5.	Industry experience (page 32).	o	o	o	9.	Climate science report (page 37).	o	o	o
6.	Aceh security report (page 33).	o	o	o	10.	Kyoto compliance report (page 40).	o	o	o



		Mark box to discontinue annual report mailing for this account.			o		Mark box if comments appear on this card or an attachment.		o

Signature: ________________________ Date: ______________ 2005 Signature: ________________________ Date: ______________ 2005

Please sign exactly as name appears hereon. If stock is held jointly, each holder should sign. When signing as attorney, executor, administrator, trustee, or guardian, please give full name as such.

ExxonMobil 2005 Annual Meeting
Morton H. Meyerson Symphony Center
2301 Flora Street
Dallas, Texas 75201

Free parking is available in the Arts District Garage. Traffic in the area may cause a delay; please allow
extra time for parking.

c/o EquiServe Trust Company, N.A.
P.O. Box 8587
Edison, NJ 08818-8587

PROXY/VOTING INSTRUCTION
SOLICITED BY BOARD OF DIRECTORS

ANNUAL MEETING, MAY 25, 2005
DALLAS, TEXAS

The undersigned hereby appoints, and instructs the appropriate account trustee(s), if any, to appoint, J.R. Houghton, W.R. Howell, P.E. Lippincott, M.C. Nelson, and L.R. Raymond, or each or any of them, with power of substitution, proxies to act and vote shares of common stock of the undersigned at the 2005 annual meeting of shareholders of Exxon Mobil Corporation and at any adjournments thereof, as indicated, upon all matters referred to on the reverse side and described in the proxy statement for the meeting and, at their discretion, upon any other matters that may properly come before the meeting.

Election of Directors ¹ Nominees:
(01) M.J. Boskin (02) W.W. George (03) J.R. Houghton		(04) W.R. Howell (05) R.C. King (06) P.E. Lippincott		(07) H.A. McKinnell, Jr. (08) M.C. Nelson (09) L.R. Raymond		(10) W.V. Shipley (11) R.W. Tillerson

This proxy covers shares of ExxonMobil common stock registered in the name of the undersigned (whether certificated or book-entry). This proxy also covers shares held in the name of the undersigned in the EquiServe Investment Plan and provides voting instructions for any shares held in the name of the undersigned in the ExxonMobil Savings Plan and/or an EquiServe Investment Plan IRA.

If no other indication is made, the proxies/trustees shall vote: (a) for the election of the director nominees; and (b) in accordance with the recommendations of the Board of Directors on the other matters referred to on the reverse side.

¹ See item 1 on reverse side. The numbers in front of the nominees' names are provided to assist in telephone voting.

(OVER)