Final Accounting Project

10‐K 1 xom10k2013.htm FORM 10‐K  

2013

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF

THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 2013

or

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission File Number 1-2256

(Exact name of registrant as specified in its charter)

NEW JERSEY 13-5409005 (State or other jurisdiction of incorporation or organization)

(I.R.S. Employer Identification Number)

5959 LAS COLINAS BOULEVARD, IRVING, TEXAS 75039-2298 (Address of principal executive offices) (Zip Code)

(972) 444-1000 (Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:

Title of Each Class Name of Each Exchange

on Which Registered

Common Stock, without par value (4,321,238,544 shares outstanding at January 31, 2014) New York Stock Exchange

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes x No ¨ 

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨ No x 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 dur preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the p days. Yes x No ¨ 

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be sub and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and po files). Yes x No ¨ 

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the b registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ¨ 

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

Large accelerated filer x Accelerated filer ¨ 

Non-accelerated filer ¨ Smaller reporting company ¨ 

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

The aggregate market value of the voting stock held by non-affiliates of the registrant on June 28, 2013, the last business day of the registrant’s most recently com second fiscal quarter, based on the closing price on that date of $90.35 on the New York Stock Exchange composite tape, was in excess of $397 billion.

Documents Incorporated by Reference: Proxy Statement for the 2014 Annual Meeting of Shareholders (Part III)

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EXXON MOBIL CORPORATION FORM 10-K

FOR THE FISCAL YEAR ENDED DECEMBER 31, 2013

TABLE OF CONTENTS

PART I Item 1. Business

Item 1A. Risk Factors

Item 1B. Unresolved Staff Comments

Item 2. Properties

Item 3. Legal Proceedings

Item 4. Mine Safety Disclosures

Executive Officers of the Registrant [pursuant to Instruction 3 to Regulation S-K, Item 401(b)]

PART II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Item 6. Selected Financial Data

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Item 8. Financial Statements and Supplementary Data

Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

Item 9A. Controls and Procedures

Item 9B. Other Information

PART III

Item 10. Directors, Executive Officers and Corporate Governance

Item 11. Executive Compensation

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

Item 13. Certain Relationships and Related Transactions, and Director Independence

Item 14. Principal Accounting Fees and Services

PART IV

Item 15. Exhibits, Financial Statement Schedules Financial Section

Signatures

Index to Exhibits

Exhibit 12 — Computation of Ratio of Earnings to Fixed Charges

Exhibits 31 and 32 — Certifications

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PART I ITEM 1. BUSINESS

Exxon Mobil Corporation was incorporated in the State of New Jersey in 1882. Divisions and affiliated companies of ExxonMobil operate or m products in the United States and most other countries of the world. Their principal business is energy, involving exploration for, and production of, cru and natural gas, manufacture of petroleum products and transportation and sale of crude oil, natural gas and petroleum products. ExxonMobil is a manufacturer and marketer of commodity petrochemicals, including olefins, aromatics, polyethylene and polypropylene plastics and a wide vari specialty products. ExxonMobil also has interests in electric power generation facilities. Affiliates of ExxonMobil conduct extensive research progra support of these businesses.

Exxon Mobil Corporation has several divisions and hundreds of affiliates, many with names that include ExxonMobil, Exxon, Esso, Mobil or XTO convenience and simplicity, in this report the terms ExxonMobil, Exxon, Esso, Mobil and XTO, as well as terms like Corporation, Company, our, we a are sometimes used as abbreviated references to specific affiliates or groups of affiliates. The precise meaning depends on the context in question.

Throughout ExxonMobil’s businesses, new and ongoing measures are taken to prevent and minimize the impact of our operations on air, wate ground. These include a significant investment in refining infrastructure and technology to manufacture clean fuels as well as projects to monitor and r nitrogen oxide, sulfur oxide, and greenhouse gas emissions and expenditures for asset retirement obligations. Using definitions and guidelines establish the American Petroleum Institute, ExxonMobil’s 2013 worldwide environmental expenditures for all such preventative and remediation steps, inc ExxonMobil’s share of equity company expenditures, were $6.0 billion, of which $3.5 billion were included in expenses with the remainder in c expenditures. The total cost for such activities is expected to remain in this range in 2014 and 2015 (with capital expenditures approximately 45 perc the total).

The energy and petrochemical industries are highly competitive. There is competition within the industries and also with other industries in supplyi energy, fuel and chemical needs of both industrial and individual consumers. The Corporation competes with other firms in the sale or purchase of n goods and services in many national and international markets and employs all methods of competition which are lawful and appropriate for such purpo

Operating data and industry segment information for the Corporation are contained in the Financial Section of this report under the following: “Qua Information”, “Note 18: Disclosures about Segments and Related Information” and “Operating Summary”. Information on oil and gas reserves is con in the “Oil and Gas Reserves” part of the “Supplemental Information on Oil and Gas Exploration and Production Activities” portion of the Financial S of this report.

ExxonMobil has a long-standing commitment to the development of proprietary technology. We have a wide array of research programs designed to the needs identified in each of our business segments. Information on Company-sponsored research and development spending is contained in “N Miscellaneous Financial Information” of the Financial Section of this report. ExxonMobil held approximately 11 thousand active patents worldwide end of 2013. For technology licensed to third parties, revenues totaled approximately $195 million in 2013. Although technology is an important contr to the overall operations and results of our Company, the profitability of each business segment is not dependent on any individual patent, trade trademark, license, franchise or concession.

The number of regular employees was 75.0 thousand, 76.9 thousand and 82.1 thousand at years ended 2013, 2012 and 2011, respectively. R employees are defined as active executive, management, professional, technical and wage employees who work full time or part time for the Corporatio are covered by the Corporation’s benefit plans and programs. Regular employees do not include employees of the company-operated retail sites (CORS number of CORS employees was 9.8 thousand, 11.1 thousand and 17.0 thousand at years ended 2013, 2012 and 2011, respectively.

Information concerning the source and availability of raw materials used in the Corporation’s business, the extent of seasonality in the busines possibility of renegotiation of profits or termination of contracts at the election of governments and risks attendant to foreign operations may be fou “Item 1A–Risk Factors” and “Item 2–Properties” in this report.

ExxonMobil maintains a website at exxonmobil.com. Our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8- any amendments to those reports filed or furnished pursuant to Section 13(a) of the Securities Exchange Act of 1934 are made available through our w as soon as reasonably practical after we electronically file or furnish the reports to the Securities and Exchange Commission. Also available o Corporation’s website are the Company’s Corporate Governance Guidelines and Code of Ethics and Business Conduct, as well as the charters of the compensation and nominating committees of the Board of Directors. Information on our website is not incorporated into this report.

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  ITEM 1A. RISK FACTORS

ExxonMobil’s financial and operating results are subject to a variety of risks inherent in the global oil, gas, and petrochemical businesses. Many of the factors are not within the Company’s control and could adversely affect our business, our financial and operating results or our financial condition. The factors include:

Supply and Demand

The oil, gas, and petrochemical businesses are fundamentally commodity businesses. This means ExxonMobil’s operations and earnings may be signifi affected by changes in oil, gas and petrochemical prices and by changes in margins on refined products. Oil, gas, petrochemical and product price margins in turn depend on local, regional and global events or conditions that affect supply and demand for the relevant commodity.

Economic conditions. The demand for energy and petrochemicals correlates closely with general economic growth rates. The occurrence of recessi other periods of low or negative economic growth will typically have a direct adverse impact on our results. Other factors that affect general eco conditions in the world or in a major region, such as changes in population growth rates, periods of civil unrest, government austerity programs, or cu exchange rate fluctuations, can also impact the demand for energy and petrochemicals. Sovereign debt downgrades, defaults, inability to access debt m due to credit or legal constraints, liquidity crises, the breakup or restructuring of fiscal, monetary, or political systems such as the European Union, and events or conditions that impair the functioning of financial markets and institutions also pose risks to ExxonMobil, including risks to the safety financial assets and to the ability of our partners and customers to fulfill their commitments to ExxonMobil.

Other demand-related factors. Other factors that may affect the demand for oil, gas and petrochemicals, and therefore impact our results, in technological improvements in energy efficiency; seasonal weather patterns, which affect the demand for energy associated with heating and co increased competitiveness of alternative energy sources that have so far generally not been competitive with oil and gas without the benefit of gover subsidies or mandates; and changes in technology or consumer preferences that alter fuel choices, such as toward alternative fueled vehicles.

Other supply-related factors. Commodity prices and margins also vary depending on a number of factors affecting supply. For example, increased s from the development of new oil and gas supply sources and technologies to enhance recovery from existing sources tend to reduce commodity prices extent such supply increases are not offset by commensurate growth in demand. Similarly, increases in industry refining or petrochemical manufac capacity tend to reduce margins on the affected products. World oil, gas, and petrochemical supply levels can also be affected by factors that reduce ava supplies, such as adherence by member countries to OPEC production quotas and the occurrence of wars, hostile actions, natural disasters, disrupti competitors’ operations, or unexpected unavailability of distribution channels that may disrupt supplies. Technological change can also alter the relative for competitors to find, produce, and refine oil and gas and to manufacture petrochemicals.

Other market factors. ExxonMobil’s business results are also exposed to potential negative impacts due to changes in interest rates, inflation, cu exchange rates, and other local or regional market conditions. We generally do not use financial instruments to hedge market exposures.

Government and Political Factors

ExxonMobil’s results can be adversely affected by political or regulatory developments affecting our operations.

Access limitations. A number of countries limit access to their oil and gas resources, or may place resources off-limits from development altog Restrictions on foreign investment in the oil and gas sector tend to increase in times of high commodity prices, when national governments may hav need of outside sources of private capital. Many countries also restrict the import or export of certain products based on point of origin.

Restrictions on doing business. As a U.S. company, ExxonMobil is subject to laws prohibiting U.S. companies from doing business in certain countr restricting the kind of business that may be conducted. Such restrictions may provide a competitive advantage to our non-U.S. competitors unless thei home countries impose comparable restrictions.

Lack of legal certainty. Some countries in which we do business lack well-developed legal systems, or have not yet adopted clear regulatory framewor oil and gas development. Lack of legal certainty exposes our operations to increased risk of adverse or unpredictable actions by government official also makes it more difficult for us to enforce our contracts. In some cases these risks can be partially offset by agreements to arbitrate disputes international forum, but the adequacy of this remedy may still depend on the local legal system to enforce an award.

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  Regulatory and litigation risks. Even in countries with well-developed legal systems where ExxonMobil does business, we remain exposed to chan law (including changes that result from international treaties and accords) that could adversely affect our results, such as:

∙

increases in taxes or government royalty rates (including retroactive claims);

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price controls;

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changes in environmental regulations or other laws that increase our cost of compliance or reduce or delay available business opportu (including changes in laws related to offshore drilling operations, water use, or hydraulic fracturing);

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adoption of regulations mandating the use of alternative fuels or uncompetitive fuel components;

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adoption of government payment transparency regulations that could require us to disclose competitively sensitive commercial informati that could cause us to violate the non-disclosure laws of other countries; and

∙

government actions to cancel contracts, re-denominate the official currency, renounce or default on obligations, renegotiate terms unilatera expropriate assets.

Legal remedies available to compensate us for expropriation or other takings may be inadequate.

We also may be adversely affected by the outcome of litigation, especially in countries such as the United States in which very large and unpredi punitive damage awards may occur, or by government enforcement proceedings alleging non-compliance with applicable laws or regulations.

Security concerns. Successful operation of particular facilities or projects may be disrupted by civil unrest, acts of sabotage or terrorism, and other security concerns. Such concerns may require us to incur greater costs for security or to shut down operations for a period of time.

Climate change and greenhouse gas restrictions. Due to concern over the risk of climate change, a number of countries have adopted, or are consi the adoption of, regulatory frameworks to reduce greenhouse gas emissions. These include adoption of cap and trade regimes, carbon taxes, rest permitting, increased efficiency standards, and incentives or mandates for renewable energy. These requirements could make our products more expe lengthen project implementation times, and reduce demand for hydrocarbons, as well as shift hydrocarbon demand toward relatively lower-carbon so such as natural gas. Current and pending greenhouse gas regulations may also increase our compliance costs, such as for monitoring or seques emissions.

Government sponsorship of alternative energy. Many governments are providing tax advantages and other subsidies to support alternative energy so or are mandating the use of specific fuels or technologies. Governments are also promoting research into new technologies to reduce the cost and increa scalability of alternative energy sources. We are conducting our own research efforts into alternative energy, such as through sponsorship of the G Climate and Energy Project at Stanford University and research into liquid products from algae and biomass that can be further converted to transpor fuels. Our future results may depend in part on the success of our research efforts and on our ability to adapt and apply the strengths of our current bu model to providing the energy products of the future in a cost-competitive manner. See “Management Effectiveness” below.

Management Effectiveness

In addition to external economic and political factors, our future business results also depend on our ability to manage successfully those factors that least in part within our control. The extent to which we manage these factors will impact our performance relative to competition. For projects in whi are not the operator, we depend on the management effectiveness of one or more co-venturers whom we do not control.

Exploration and development program. Our ability to maintain and grow our oil and gas production depends on the success of our exploratio development efforts. Among other factors, we must continuously improve our ability to identify the most promising resource prospects and apply our p management expertise to bring discovered resources on line on schedule and within budget.

Project management. The success of ExxonMobil’s Upstream, Downstream, and Chemical businesses depends on complex, long-term, capital int projects. These projects in turn require a high degree of project management expertise to maximize efficiency. Specific factors that can affect the perform of major projects include our ability to: negotiate successfully with joint venturers, partners, governments, suppliers, customers, or others; mod optimize reservoir performance; develop markets for project outputs, whether through long-term contracts or the development of effective spot ma manage changes in operating conditions and costs, including costs of third party equipment or services such as drilling rigs and shipping; prevent, extent possible, and respond effectively to unforeseen technical difficulties that could delay project startup or cause unscheduled project downtim influence the performance of project operators where ExxonMobil does not perform that role.

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The term “project” as used in this report can refer to a variety of different activities and does not necessarily have the same meaning as in any gover payment transparency reports.

Operational efficiency. An important component of ExxonMobil’s competitive performance, especially given the commodity-based nature of many businesses, is our ability to operate efficiently, including our ability to manage expenses and improve production yields on an ongoing basis. This re continuous management focus, including technology improvements, cost control, productivity enhancements, regular reappraisal of our asset portfoli the recruitment, development and retention of high caliber employees.

Research and development. To maintain our competitive position, especially in light of the technological nature of our businesses and the ne continuous efficiency improvement, ExxonMobil’s research and development organizations must be successful and able to adapt to a changing mark policy environment.

Safety, business controls, and environmental risk management. Our results depend on management’s ability to minimize the inherent risks of oil, ga petrochemical operations, to control effectively our business activities and to minimize the potential for human error. We apply rigorous management sy and continuous focus to workplace safety and to avoiding spills or other adverse environmental events. For example, we work to minimize spills thro combined program of effective operations integrity management, ongoing upgrades, key equipment replacements, and comprehensive inspectio surveillance. Similarly, we are implementing cost-effective new technologies and adopting new operating practices to reduce air emissions, not o response to government requirements but also to address community priorities. We also maintain a disciplined framework of internal controls and a controls management system for monitoring compliance with this framework. Substantial liabilities and other adverse impacts could result management systems and controls do not function as intended. The ability to insure against such risks is limited by the capacity of the applicable insu markets, which may not be sufficient.

Business risks also include the risk of cybersecurity breaches. If our systems for protecting against cybersecurity risks prove not to be suff ExxonMobil could be adversely affected such as by having its business systems compromised, its proprietary information altered, lost or stolen, business operations disrupted.

Preparedness. Our operations may be disrupted by severe weather events, natural disasters, human error, and similar events. For example, hurricane damage our offshore production facilities or coastal refining and petrochemical plants in vulnerable areas. Our ability to mitigate the adverse impacts of events depends in part upon the effectiveness of our rigorous disaster preparedness and response planning, as well as business continuity planning.

Projections, estimates and descriptions of ExxonMobil’s plans and objectives included or incorporated in Items 1, 1A, 2, 7 and 7A of this repo forward-looking statements. Actual future results, including project completion dates, production rates, capital expenditures, costs and business plans differ materially due to, among other things, the factors discussed above and elsewhere in this report.  

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

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  ITEM 2. PROPERTIES

Information with regard to oil and gas producing activities follows:

1. Disclosure of Reserves

A. Summary of Oil and Gas Reserves at Year-End 2013

The table below summarizes the oil-equivalent proved reserves in each geographic area and by product type for consolidated subsidiaries and companies. The Corporation has reported proved reserves on the basis of the average of the first-day-of-the-month price for each month during th 12-month period. Gas is converted to an oil-equivalent basis at six million cubic feet per one thousand barrels. No major discovery or other favora adverse event has occurred since December 31, 2013, that would cause a significant change in the estimated proved reserves as of that date. Crude Natural Gas Synthetic Natural Oil-Equiva

Oil Liquids Bitumen Oil Gas Basis (million bbls) (million bbls) (million bbls) (million bbls) (billion cubic ft) (million bb Proved Reserves Developed Consolidated Subsidiaries United States 1,212 257 - - 14,655 Canada/South America (1) 111 15 1,810 579 664 Europe 210 39 - - 2,189 Africa 765 180 - - 779 Asia 1,525 138 - - 5,241 Australia/Oceania 56 49 - - 969 Total Consolidated 3,879 678 1,810 579 24,497 1 Equity Companies United States 258 10 - - 197 Europe 27 - - - 6,852 Asia 902 390 - - 17,288 Total Equity Company 1,187 400 - - 24,337 Total Developed 5,066 1,078 1,810 579 48,834 1 Undeveloped Consolidated Subsidiaries United States 796 272 - - 11,365 Canada/South America (1) 173 4 1,820 - 571 Europe 35 16 - - 621 Africa 428 21 - - 88 Asia 638 - - - 493 Australia/Oceania 99 32 - - 6,546 Total Consolidated 2,169 345 1,820 - 19,684 Equity Companies United States 72 5 - - 84 Europe 1 - - - 2,032 Asia 243 51 - - 1,226 Total Equity Company 316 56 - - 3,342 Total Undeveloped 2,485 401 1,820 - 23,026 Total Proved Reserves 7,551 1,479 3,630 579 71,860 2

(1) South America includes proved developed reserves of 0.2 million barrels of crude oil and natural gas liquids and 44 billion cubic feet of natural ga proved undeveloped reserves of 0.1 million barrels of crude oil and natural gas liquids and 10 billion cubic feet of natural gas.

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  In the preceding reserves information, consolidated subsidiary and equity company reserves are reported separately. However, the Corporation opera business with the same view of equity company reserves as it has for reserves from consolidated subsidiaries.

The Corporation’s overall volume capacity outlook, based on projects coming on stream as anticipated, is for production capacity to grow over the 2014-2018. However, actual volumes will vary from year to year due to the timing of individual project start-ups, operational outages, reservoir perform regulatory changes, asset sales, weather events, price effects on production sharing contracts and other factors as described in Item 1A—Risk Factors report.

The estimation of proved reserves, which is based on the requirement of reasonable certainty, is an ongoing process based on rigorous tec evaluations, commercial and market assessments and detailed analysis of well and reservoir information such as flow rates and reservoir pressure de Furthermore, the Corporation only records proved reserves for projects which have received significant funding commitments by management made t the development of the reserves. Although the Corporation is reasonably certain that proved reserves will be produced, the timing and amount recovere be affected by a number of factors including completion of development projects, reservoir performance, regulatory approvals and significant chan projections of long-term oil and gas price levels.

B. Technologies Used in Establishing Proved Reserves Additions in 2013

Additions to ExxonMobil’s proved reserves in 2013 were based on estimates generated through the integration of available and appropriate geolo engineering and production data, utilizing well-established technologies that have been demonstrated in the field to yield repeatable and consistent resul

Data used in these integrated assessments included information obtained directly from the subsurface via wellbores, such as well logs, reservoi samples, fluid samples, static and dynamic pressure information, production test data, and surveillance and performance information. The data utilize included subsurface information obtained through indirect measurements including high-quality 2-D and 3-D seismic data, calibrated with availabl control information. The tools used to interpret the data included proprietary seismic processing software, proprietary reservoir modeling and simu software, and commercially available data analysis packages.

In some circumstances, where appropriate analog reservoirs were available, reservoir parameters from these analogs were used to increase the qua and confidence in the reserves estimates.

C. Qualifications of Reserves Technical Oversight Group and Internal Controls over Proved Reserves

ExxonMobil has a dedicated Global Reserves group that provides technical oversight and is separate from the operating organization. Primary responsib of this group include oversight of the reserves estimation process for compliance with Securities and Exchange Commission (SEC) rules and regula review of annual changes in reserves estimates, and the reporting of ExxonMobil’s proved reserves. This group also maintains the official company re estimates for ExxonMobil’s proved reserves of crude and natural gas liquids, bitumen, synthetic oil and natural gas. In addition, the group provides tr to personnel involved in the reserves estimation and reporting process within ExxonMobil and its affiliates. The Manager of the Global Reserves grou more than 30 years of experience in reservoir engineering and reserves assessment and has a degree in Engineering. He is an active member of the Soc Petroleum Engineers (SPE) and previously served on the SPE Oil and Gas Reserves Committee. The group is managed by and staffed with individua have an average of more than 20 years of technical experience in the petroleum industry, including expertise in the classification and categorizat reserves under the SEC guidelines. This group includes individuals who hold advanced degrees in either Engineering or Geology. Several members group hold professional registrations in their field of expertise, and members have served on the SPE Oil and Gas Reserves Committee.

The Global Reserves group maintains a central database containing the official company reserves estimates. Appropriate controls, including limitatio database access and update capabilities, are in place to ensure data integrity within this central database. An annual review of the system’s cont performed by internal audit. Key components of the reserves estimation process include technical evaluations and analysis of well and field performanc a rigorous peer review. No changes may be made to the reserves estimates in the central database, including additions of any new initial reserves estima subsequent revisions, unless these changes have been thoroughly reviewed and evaluated by duly authorized personnel within the operating organizati addition, changes to reserves estimates that exceed certain thresholds require further review and approval of the appropriate level of management with operating organization before the changes may be made in the central database. Endorsement by the Global Reserves group for all proved reserves chan a mandatory component of this review process. After all changes are made, reviews are held with senior management for final endorsement.

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   2. Proved Undeveloped Reserves

At year-end 2013, approximately 8.5 billion oil-equivalent barrels (GOEB) of ExxonMobil’s proved reserves were classified as proved undeveloped represents 34 percent of the 25.2 GOEB reported in proved reserves. This compares to the 9.9 GOEB of proved undeveloped reserves reported at the 2012. The net decrease is primarily due to project startups in Canada and Kazakhstan. During the year, ExxonMobil conducted development activities i 100 fields that resulted in the transfer of approximately 1.9 GOEB from proved undeveloped to proved developed reserves by year-end. The largest tra were related to Kearl Initial Development startup and new pad steam injection in the Cold Lake field in Canada, Kashagan field startup in Kazakhsta the Groningen compression assessment in the Netherlands.

One of ExxonMobil’s requirements for reporting proved reserves is that management has made significant funding commitments toward the develo of the reserves. ExxonMobil has a disciplined investment strategy and many major fields require long lead-time in order to be developed. Develo projects typically take two to four years from the time of first recording of proved reserves to the start of production of these reserves. Howeve development time for large and complex projects can exceed five years. During 2013, discoveries and extensions related to new projects approximately 0.7 GOEB of proved undeveloped reserves. The largest of these additions were related to planned drilling in the United States and Zakum field expansion in Abu Dhabi. Overall, investments of $25.3 billion were made by the Corporation during 2013 to progress the developm reported proved undeveloped reserves, including $22.7 billion for oil and gas producing activities and an additional $2.6 billion for other non-oil an producing activities such as the construction of support infrastructure and other related facilities that were undertaken to progress the development of p undeveloped reserves. These investments represented 66 percent of the $38.2 billion in total reported Upstream capital and exploration expenditures.

Proved undeveloped reserves in Australia, Papua New Guinea, the United States, Kazakhstan, Nigeria, and the Netherlands have remained undeve for five years or more primarily due to constraints on the capacity of infrastructure, the pace of co-venturer/government funding, as well as the time re to complete development for very large projects. The Corporation is reasonably certain that these proved reserves will be produced; however, the timin amount recovered can be affected by a number of factors including completion of development projects, reservoir performance, regulatory approval significant changes in long-term oil and gas price levels. Of the proved undeveloped reserves that have been reported for five or more years, 91 perce contained in the aforementioned countries. The largest of these is related to LNG/Gas projects in Australia and Papua New Guinea, where construction initial development is under way. In Kazakhstan, the proved undeveloped reserves are related to the remainder of the initial development of the of Kashagan field which is included in the North Caspian Production Sharing Agreement and the Tengizchevroil joint venture which includes a prod license in the Tengiz – Korolev field complex. The Tengizchevroil joint venture is producing, and proved undeveloped reserves will continue to m proved developed as approved development phases progress. In the Netherlands, the Groningen gas field has proved undeveloped reserves reported th related to installation of future stages of compression. These reserves will move to proved developed when the additional stages of compression are in to maintain field delivery pressure.

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  3. Oil and Gas Production, Production Prices and Production Costs

A. Oil and Gas Production

The table below summarizes production by final product sold and by geographic area for the last three years. 2013 2012 2011 (thousands of barrels daily) Crude oil and natural gas liquids production Crude Oil NGL Crude Oil NGL Crude Oil NG Consolidated Subsidiaries United States 283 85 274 81 280 Canada/South America (1) 57 10 49 10 53 Europe 157 27 170 33 219 Africa 451 18 472 15 491 Asia 313 30 319 43 329 Australia/Oceania 29 19 32 18 34 Total Consolidated Subsidiaries 1,290 189 1,316 200 1,406 Equity Companies United States 61 2 61 2 65 Europe 6 - 4 - 5 Asia 373 68 345 65 358 Total Equity Companies 440 70 410 67 428 Total crude oil and natural gas liquids production 1,730 259 1,726 267 1,834 Bitumen production Consolidated Subsidiaries Canada/South America 148 123 120 Synthetic oil production Consolidated Subsidiaries Canada/South America 65 69 67 Total liquids production 2,202 2,185 2,312 (millions of cubic feet daily) Natural gas production available for sale Consolidated Subsidiaries United States 3,530 3,819 3,917 Canada/South America (1) 354 362 412 Europe 1,294 1,446 1,701 Africa 6 17 7 Asia 1,180 1,445 1,879 Australia/Oceania 351 363 331 Total Consolidated Subsidiaries 6,715 7,452 8,247 Equity Companies United States 15 3 - Europe 1,957 1,774 1,747 Asia 3,149 3,093 3,168 Total Equity Companies 5,121 4,870 4,915 Total natural gas production available for sale 11,836 12,322 13,162 (thousands of oil-equivalent barrels daily) Oil-equivalent production 4,175 4,239 4,506

(1) South America includes liquids production for 2012 and 2011 of one thousand barrels daily for each year and natural gas production available fo for 2013, 2012 and 2011 of 28 million, 38 million, and 45 million cubic feet daily, respectively.

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  B. Production Prices and Production Costs

The table below summarizes average production prices and average production costs by geographic area and by product type for the last three years. United Canada/ Australia/

States S. America Europe Africa Asia Oceania To During 2013 (dollars per unit) Consolidated Subsidiaries Average production prices Crude oil, per barrel 93.56 98.91 106.75 108.73 106.18 107.92 NGL, per barrel 44.30 44.96 65.36 75.24 40.83 59.55 Natural gas, per thousand cubic feet 2.99 2.80 10.07 2.79 4.10 4.20 Bitumen, per barrel - 59.63 - - - - Synthetic oil, per barrel - 93.96 - - - - Average production costs, per oil-equivalent barrel - total 12.02 32.02 19.57 13.95 8.95 16.81 Average production costs, per barrel - bitumen - 34.30 - - - - Average production costs, per barrel - synthetic oil - 50.94 - - - - Equity Companies Average production prices Crude oil, per barrel 102.24 - 99.26 - 103.96 - NGL, per barrel 42.02 - - - 70.90 - Natural gas, per thousand cubic feet 4.37 - 9.28 - 10.19 - Average production costs, per oil-equivalent barrel - total 22.77 - 3.79 - 1.87 - Total Average production prices Crude oil, per barrel 95.11 98.91 106.49 108.73 104.98 107.92 NGL, per barrel 44.24 44.96 65.36 75.24 61.64 59.55 Natural gas, per thousand cubic feet 3.00 2.80 9.59 2.79 8.53 4.20 Bitumen, per barrel - 59.63 - - - - Synthetic oil, per barrel - 93.96 - - - - Average production costs, per oil-equivalent barrel - total 12.72 32.02 12.42 13.95 4.41 16.81 Average production costs, per barrel - bitumen - 34.30 - - - - Average production costs, per barrel - synthetic oil - 50.94 - - - - During 2012 Consolidated Subsidiaries Average production prices Crude oil, per barrel 94.71 98.67 110.91 111.19 109.95 112.12 NGL, per barrel 50.32 57.84 68.08 76.63 43.65 56.85 Natural gas, per thousand cubic feet 2.15 1.98 8.92 2.77 3.91 4.39 Bitumen, per barrel - 58.91 - - - - Synthetic oil, per barrel - 92.77 - - - - Average production costs, per oil-equivalent barrel - total 11.14 26.94 15.06 13.35 7.27 12.11 Average production costs, per barrel - bitumen - 23.71 - - - - Average production costs, per barrel - synthetic oil - 47.45 - - - - Equity Companies Average production prices Crude oil, per barrel 105.02 - 104.59 - 106.59 - NGL, per barrel 58.38 - - - 75.24 - Natural gas, per thousand cubic feet 3.22 - 9.66 - 9.38 - Average production costs, per oil-equivalent barrel - total 20.15 - 3.36 - 1.43 - Total Average production prices Crude oil, per barrel 96.60 98.67 110.74 111.19 108.22 112.12 NGL, per barrel 50.46 57.84 68.08 76.63 62.61 56.85 Natural gas, per thousand cubic feet 2.15 1.98 9.33 2.77 7.64 4.39 Bitumen, per barrel - 58.91 - - - - Synthetic oil, per barrel - 92.77 - - - - Average production costs, per oil-equivalent barrel - total 11.68 26.94 10.34 13.35 3.74 12.11 Average production costs, per barrel - bitumen - 23.71 - - - - Average production costs, per barrel - synthetic oil - 47.45 - - - -

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  United Canada/ Australia/

States S. America Europe Africa Asia Oceania To During 2011 (dollars per unit) Consolidated Subsidiaries Average production prices Crude oil, per barrel 98.33 104.59 109.48 110.84 107.64 115.55 NGL, per barrel 62.48 65.71 66.80 78.20 44.16 59.44 Natural gas, per thousand cubic feet 3.45 3.29 9.32 2.83 3.37 3.98 Bitumen, per barrel - 64.65 - - - - Synthetic oil, per barrel - 102.80 - - - - Average production costs, per oil-equivalent barrel - total 11.14 23.58 13.58 14.04 6.58 12.85 Average production costs, per barrel - bitumen - 19.80 - - - - Average production costs, per barrel - synthetic oil - 47.68 - - - - Equity Companies Average production prices Crude oil, per barrel 105.00 - 103.23 - 105.87 - NGL, per barrel 77.84 - - - 69.65 - Natural gas, per thousand cubic feet 5.08 - 8.61 - 7.78 - Average production costs, per oil-equivalent barrel - total 19.96 - 2.92 - 1.09 - Total Average production prices Crude oil, per barrel 99.57 104.59 109.33 110.84 106.72 115.55 NGL, per barrel 62.75 65.71 66.80 78.20 58.33 59.44 Natural gas, per thousand cubic feet 3.45 3.29 8.96 2.83 6.14 3.98 Bitumen, per barrel - 64.65 - - - - Synthetic oil, per barrel - 102.80 - - - - Average production costs, per oil-equivalent barrel - total 11.68 23.58 9.85 14.04 3.41 12.85 Average production costs, per barrel - bitumen - 19.80 - - - - Average production costs, per barrel - synthetic oil - 47.68 - - - -

Average production prices have been calculated by using sales quantities from the Corporation’s own production as the divisor. Average production have been computed by using net production quantities for the divisor. The volumes of crude oil and natural gas liquids (NGL) production used fo computation are shown in the oil and gas production table in section 3.A. The volumes of natural gas used in the calculation are the production volum natural gas available for sale and are also shown in section 3.A. The natural gas available for sale volumes are different from those shown in the re table in the “Oil and Gas Reserves” part of the “Supplemental Information on Oil and Gas Exploration and Production Activities” portion of the Fin Section of this report due to volumes consumed or flared. Gas is converted to an oil-equivalent basis at six million cubic feet per one thousand barrels.

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  4. Drilling and Other Exploratory and Development Activities

A. Number of Net Productive and Dry Wells Drilled 2013 2012

Net Productive Exploratory Wells Drilled Consolidated Subsidiaries United States 8 7 Canada/South America 4 2 Europe - 1 Africa 2 2 Asia - 1 Australia/Oceania - 2 Total Consolidated Subsidiaries 14 15 Equity Companies United States - - Europe 1 1 Asia 1 - Total Equity Companies 2 1 Total productive exploratory wells drilled 16 16 Net Dry Exploratory Wells Drilled Consolidated Subsidiaries United States 2 2 Canada/South America 4 - Europe 1 2 Africa - - Asia - 2 Australia/Oceania - 1 Total Consolidated Subsidiaries 7 7 Equity Companies United States 1 - Europe - 1 Asia - - Total Equity Companies 1 1 Total dry exploratory wells drilled 8 8

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  2013 2012

Net Productive Development Wells Drilled Consolidated Subsidiaries United States 755 867 Canada/South America 201 73 Europe 13 10 Africa 33 39 Asia 30 28 Australia/Oceania 3 - Total Consolidated Subsidiaries 1,035 1,017 Equity Companies United States 328 282 Europe 2 4 Asia 8 7 Total Equity Companies 338 293 Total productive development wells drilled 1,373 1,310 Net Dry Development Wells Drilled Consolidated Subsidiaries United States 5 5 Canada/South America - - Europe 2 1 Africa - - Asia - 2 Australia/Oceania - - Total Consolidated Subsidiaries 7 8 Equity Companies United States - - Europe 1 - Asia - - Total Equity Companies 1 - Total dry development wells drilled 8 8 Total number of net wells drilled 1,405 1,342

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  B. Exploratory and Development Activities Regarding Oil and Gas Resources Extracted by Mining Technologies

Syncrude Operations. Syncrude is a joint venture established to recover shallow deposits of oil sands using open-pit mining methods to extract the bitumen, and then upgrade it to produce a high-quality, light (32 degrees API), sweet, synthetic crude oil. Imperial Oil Limited is the owner of a 25 p interest in the joint venture. Exxon Mobil Corporation has a 69.6 percent interest in Imperial Oil Limited. In 2013, the company’s share of net product synthetic crude oil was about 65 thousand barrels per day and share of net acreage was about 63 thousand acres in the Athabasca oil sands deposit.

Kearl Project. The Kearl project is a joint venture established to recover shallow deposits of oil sands using open-pit mining methods to extract the bitumen. Imperial Oil Limited holds a 70.96 percent interest in the joint venture and ExxonMobil Canada Properties holds the other 29.04 percent. E Mobil Corporation has a 69.6 percent interest in Imperial Oil Limited and a 100 percent interest in ExxonMobil Canada Properties. Kearl is comprised oil sands leases covering about 48 thousand acres in the Athabasca oil sands deposit.

The Kearl project is located approximately 40 miles north of Fort McMurray, Alberta, Canada. Bitumen is extracted from oil sands produced open-pit mining operations, and processed through a bitumen extraction and froth treatment train. The product, a blend of bitumen and diluent, is ship our refineries and to other third parties. Diluent is natural gas condensate or other light hydrocarbons added to the crude bitumen to facilitate transpor by pipeline. Production from the initial development began in April 2013 and production ramp-up continued throughout the remainder of the year. D 2013, average net production at Kearl was 21 thousand barrels per day. The Kearl Expansion project was 72 percent complete at the end of 2013.   5. Present Activities

A. Wells Drilling Year-End 2013 Year-End 2012 Gross Net Gross Wells Drilling Consolidated Subsidiaries United States 1,199 480 1,099 Canada/South America 107 95 138 Europe 29 10 26 Africa 38 11 33 Asia 112 32 108 Australia/Oceania 18 5 23 Total Consolidated Subsidiaries 1,503 633 1,427 Equity Companies United States 9 4 17 Europe 8 3 9 Asia 11 1 19 Total Equity Companies 28 8 45 Total gross and net wells drilling 1,531 641 1,472

B. Review of Principal Ongoing Activities

UNITED STATES

ExxonMobil’s year-end 2013 acreage holdings totaled 15.1 million net acres, of which 2.0 million net acres were offshore. ExxonMobil was active in onshore and offshore in the lower 48 states and in Alaska.

During 2013, 1080.3 net exploration and development wells were completed in the inland lower 48 states. Development activities focused on the B oil play in North Dakota and Montana, the San Joaquin Basin of California, the Woodford and Caney Shales in the Ardmore, Marietta and Arkoma bas Oklahoma, the Permian Basin of West Texas and New Mexico, the Marcellus Shale of Pennsylvania and West Virginia, the Haynesville Shale of Tex Louisiana, the Barnett Shale of North Texas, and the Fayetteville Shale of Arkansas.

ExxonMobil’s net acreage in the Gulf of Mexico at year-end 2013 was 1.9 million acres. A total of 2.5 net exploration and development wells completed during the year. Development activities continued on the deepwater Hadrian South project and the non-operated Lucius project. The Heid and Julia Phase 1 projects were funded in 2013.

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Participation in Alaska production and development continued with a total of 17.1 net development wells completed. Development activities continu the Point Thomson project.

CANADA / SOUTH AMERICA

Canada

Oil and Gas Operations: ExxonMobil's year-end 2013 acreage holdings totaled 5.6 million net acres, of which 1.0 million net acres were offshore. A to 86.2 net exploration and development wells were completed during the year. Celtic Exploration Ltd. was acquired in 2013.

In Situ Bitumen Operations: ExxonMobil's year-end 2013 in situ bitumen acreage holdings totaled 0.7 million net onshore acres. A total of 120 development wells were completed during the year. In 2013, ExxonMobil acquired an interest in the Clyden oil sands lease.

Argentina

ExxonMobil’s net acreage totaled 0.9 million onshore acres at year-end 2013, and there were 2.0 net exploration and development wells completed duri year.

Venezuela

ExxonMobil’s acreage holdings and assets were expropriated in 2007. Refer to the relevant portion of “Note 16: Litigation and Other Contingencies” Financial Section of this report for additional information.

EUROPE

Germany

A total of 4.9 million net onshore acres and 0.1 million net offshore acres were held by ExxonMobil at year-end 2013, with 5.3 net exploratio development wells completed during the year.

Netherlands

ExxonMobil’s net interest in licenses totaled approximately 1.5 million acres at year-end 2013, of which 1.2 million acres are onshore. A total of 4 exploration and development wells were completed during the year.

Norway

ExxonMobil's net interest in licenses at year-end 2013 totaled approximately 0.7 million acres, all offshore. A total of 7.5 net exploration and develo wells were completed in 2013.

United Kingdom

ExxonMobil’s net interest in licenses at year-end 2013 totaled approximately 0.4 million acres, all offshore. A total of 2.7 net development wells completed during the year.

AFRICA

Angola

ExxonMobil’s year-end 2013 acreage holdings totaled 0.4 million net offshore acres and 3.4 net development wells were completed during the ye Block 15, project activities are under way at Kizomba Satellites Phase 2. On the non-operated Block 17, work continued on the Cravo-Lirio-Orq Violeta project.

Chad

ExxonMobil’s net year-end 2013 acreage holdings consisted of 46 thousand onshore acres, with 22.0 net development wells completed during the year.

Equatorial Guinea

ExxonMobil’s acreage totaled 0.1 million net offshore acres at year-end 2013.

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  Nigeria

ExxonMobil’s net acreage totaled 0.9 million offshore acres at year-end 2013, with 8.2 net exploration and development wells completed during the y 2013, ExxonMobil continued development drilling on the Satellite Field Development Phase 1 and the deepwater Usan projects. The Erha North Ph deepwater project was funded in 2013.

ASIA

Azerbaijan

At year-end 2013, ExxonMobil’s net acreage totaled 9 thousand offshore acres. A total of 0.7 net development wells were completed during the year. continued on the Chirag Oil project.

Indonesia

At year-end 2013, ExxonMobil had 2.3 million net acres, 1.3 million net acres offshore and 1.0 million net acres onshore. There was 0.4 net exploratio completed during the year.

Iraq

At year-end 2013, ExxonMobil’s onshore acreage was 0.9 million net acres. A total of 23.2 net development wells were completed at the West Qurna P oil field during the year. Field rehabilitation activities continued during 2013, and across the life of this project will include drilling of new wells, wo over of existing wells, and optimization and debottlenecking of existing facilities. ExxonMobil sold a partial interest in West Qurna Phase I in 2013. Kurdistan Region of Iraq, ExxonMobil initiated a seismic program and exploration drilling in 2013.

Kazakhstan

ExxonMobil’s net acreage totaled 0.1 million acres onshore and 0.2 million acres offshore at year-end 2013. A total of 1.3 net development wells completed during 2013. Working with our partners, construction of the initial phase of the Kashagan field continued, and the project started up in 2013.

Malaysia

ExxonMobil has interests in production sharing contracts covering 0.4 million net acres offshore at year-end 2013. During the year, a total of 5 development wells were completed. Development activities continued on the Tapis and Damar projects and the Telok project started up in 2013.

Qatar

Through our joint ventures with Qatar Petroleum, ExxonMobil’s net acreage totaled 65 thousand acres offshore at year-end 2013. During the year, a to 0.7 net development wells were completed. ExxonMobil participated in 61.8 million tonnes per year gross liquefied natural gas capacity and 2.0 billion feet per day of flowing gas capacity at year end. Development activities continued on the Barzan project.

Republic of Yemen

ExxonMobil's net acreage in the Republic of Yemen production sharing areas totaled 10 thousand acres onshore at year-end 2013.

Russia

ExxonMobil’s net acreage holdings in Sakhalin at year-end 2013 were 85 thousand acres, all offshore. A total of 0.9 net development wells were comp Development activities continued on the Arkutun-Dagi project during 2013.

At year-end 2013, ExxonMobil’s net acreage in the Rosneft joint venture agreements for the Kara and Black Seas was 11.3 million acres, all off ExxonMobil and Rosneft formed a joint venture to evaluate the development of tight-oil reserves in western Siberia in 2013. Thailand

ExxonMobil’s net onshore acreage in Thailand concessions totaled 21 thousand acres at year-end 2013.

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  United Arab Emirates

ExxonMobil’s net acreage in the Abu Dhabi offshore Upper Zakum oil concession was 81 thousand acres at year-end 2013. The Upper Zakum 750 p was funded in 2013.

ExxonMobil’s net acreage in the Abu Dhabi onshore oil concession was 0.5 million acres at year-end 2013, of which 0.4 million acres are ons During the year, a total of 6.7 net exploration and development wells were completed. The onshore oil concession expired in January 2014.

AUSTRALIA / OCEANIA

Australia

ExxonMobil’s year-end 2013 acreage holdings totaled 1.7 million net acres, of which 1.6 million net acres were offshore. During the year, a total of 1 exploration and development wells were completed. The Kipper Tuna and Turrum projects started up during 2013.

Project construction activity for the co-venturer operated Gorgon liquefied natural gas (LNG) project progressed in 2013. The project consists of a s infrastructure for offshore production and transportation of the gas, and a 15.6 million tonnes per year LNG facility and a 280 million cubic feet p domestic gas plant located on Barrow Island, Western Australia.

Papua New Guinea

A total of 1.1 million net onshore acres were held by ExxonMobil at year-end 2013, with 1.3 net development wells completed during the year. continued on the Papua New Guinea (PNG) LNG project. The project consists of conditioning facilities in the southern PNG Highlands, a 6.9 million t per year LNG facility near Port Moresby and approximately 434 miles of onshore and offshore pipelines.

WORLDWIDE EXPLORATION

At year-end 2013, exploration activities were under way in several areas in which ExxonMobil has no established production operations and thus a included above. A total of 29.1 million net acres were held at year-end 2013, and 1.4 net exploration wells were completed during the year in these cou

6. Delivery Commitments ExxonMobil sells crude oil and natural gas from its producing operations under a variety of contractual obligations, some of which may specify the de of a fixed and determinable quantity for periods longer than one year. ExxonMobil also enters into natural gas sales contracts where the source of the n gas used to fulfill the contract can be a combination of our own production and the spot market. Worldwide, we are contractually committed to d approximately 2,800 billion cubic feet of natural gas for the period from 2014 through 2016. We expect to fulfill the majority of these delivery commit with production from our proved developed reserves. Any remaining commitments will be fulfilled with production from our proved undeveloped re and spot market purchases as necessary.

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  7. Oil and Gas Properties, Wells, Operations and Acreage

A. Gross and Net Productive Wells Year-End 2013 Year-End 2012 Oil Gas Oil Gas Gross Net Gross Net Gross Net Gross N Gross and Net Productive Wells Consolidated Subsidiaries United States 23,395 8,487 38,392 23,839 22,690 8,155 39,720 2 Canada/South America 5,486 4,990 4,478 1,762 5,283 4,825 4,271 Europe 1,254 352 649 269 1,255 346 622 Africa 1,186 472 16 6 1,231 491 11 Asia 756 270 207 151 792 370 204 Australia/Oceania 661 147 38 19 676 152 40 Total Consolidated Subsidiaries 32,738 14,718 43,780 26,046 31,927 14,339 44,868 2 Equity Companies United States 14,362 5,529 4,369 496 12,777 5,286 2,138 Europe 49 17 555 173 71 27 585 Asia 1,329 143 122 29 1,200 129 121 Total Equity Companies 15,740 5,689 5,046 698 14,048 5,442 2,844 Total gross and net productive wells 48,478 20,407 48,826 26,744 45,975 19,781 47,712 2

There were 37,661 gross and 31,823 net operated wells at year-end 2013 and 37,228 gross and 31,264 net operated wells at year-end 2012. The num wells with multiple completions was 1,531 gross in 2013 and 1,647 gross in 2012.

Note: Year-end 2012 well counts for gross and net gas wells in Canada/South America were restated.

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  B. Gross and Net Developed Acreage Year-End 2013 Year-End 2012 Gross Net Gross N (thousands of acres) Gross and Net Developed Acreage Consolidated Subsidiaries United States 16,504 10,061 16,444 1 Canada/South America (1) 4,421 2,041 4,545 Europe 3,355 1,511 3,382 Africa 2,105 780 2,105 Asia 1,828 557 1,322 Australia/Oceania 2,123 758 2,018 Total Consolidated Subsidiaries 30,336 15,708 29,816 1 Equity Companies United States 968 241 496 Europe 4,341 1,356 4,344 Asia 5,731 640 5,731 Total Equity Companies 11,040 2,237 10,571 Total gross and net developed acreage 41,376 17,945 40,387 1

(1) Includes developed acreage in South America of 214 gross and 109 net thousands of acres for 2013 and 618 gross and 202 net thousand acres for 2

Separate acreage data for oil and gas are not maintained because, in many instances, both are produced from the same acreage.

C. Gross and Net Undeveloped Acreage Year-End 2013 Year-End 2012 Gross Net Gross N (thousands of acres) Gross and Net Undeveloped Acreage Consolidated Subsidiaries United States 7,645 4,722 8,517 Canada/South America (1) 16,319 9,232 16,669 Europe 13,461 6,585 35,928 1 Africa 20,877 13,446 12,005 Asia 18,639 13,979 24,346 2 Australia/Oceania 7,144 1,991 7,460 Total Consolidated Subsidiaries 84,085 49,955 104,925 5 Equity Companies United States 363 121 351 Europe - - - Asia 34,147 11,352 73 Total Equity Companies 34,510 11,473 424 Total gross and net undeveloped acreage 118,595 61,428 105,349 5

(1) Includes undeveloped acreage in South America of 8,795 gross and 4,674 net thousands of acres for 2013 and 8,412 gross and 4,484 net thousa acres for 2012.

ExxonMobil’s investment in developed and undeveloped acreage is comprised of numerous concessions, blocks and leases. The terms and conditions which the Corporation maintains exploration and/or production rights to the acreage are property-specific, contractually defined and vary significantly property to property. Work programs are designed to ensure that the exploration potential of any property is fully evaluated before expiration. In instances, the Corporation may elect to relinquish acreage in advance of the contractual expiration date if the evaluation process is complete and there is business basis for extension. In cases where additional time may be required to fully evaluate acreage, the Corporation has generally been success obtaining extensions. The scheduled expiration of leases and concessions for undeveloped acreage over the next three years is not expected to have a m adverse impact on the Corporation.

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  D. Summary of Acreage Terms

UNITED STATES

Oil and gas leases have an exploration period ranging from one to ten years, and a production period that normally remains in effect until production c Under certain circumstances, a lease may be held beyond its exploration term even if production has not commenced. In some instances, a “fee inter acquired where both the surface and the underlying mineral interests are owned outright.

CANADA / SOUTH AMERICA

Canada

Exploration licenses or leases in onshore areas are acquired for varying periods of time with renewals or extensions possible. These licenses or leases the holder to continue existing licenses or leases upon completing specified work. In general, these license and lease agreements are held as long as th production on the licenses and leases. Exploration licenses in offshore eastern Canada and the Beaufort Sea are held by work commitments of v amounts and rentals. They are valid for a maximum term of nine years. Production licenses in the offshore are valid for 25 years, with rights of extensi continued production. Significant discovery licenses in the offshore, relating to currently undeveloped discoveries, do not have a definite term.

Argentina

The federal onshore concession terms in Argentina are up to four years for the initial exploration period, up to three years for the second exploration and up to two years for the third exploration period. A 50-percent relinquishment is required after each exploration period. An extension after the exploration period is possible for up to five years. The total production term is 25 years with a ten-year extension possible, once a field has been deve Argentine provinces are entitled to modify the concession terms granted within their territories. The concession terms of the exploration permits gran Neuquen Province are up to six years for the initial exploration period, up to four years for the second exploration period and up to three years for the exploration period depending on the classification of the area. An extension after the third exploration period is possible for up to one year.

EUROPE

Germany

Exploration concessions are granted for an initial maximum period of five years, with an unlimited number of extensions of up to three years Extensions are subject to specific, minimum work commitments. Production licenses are normally granted for 20 to 25 years with multiple po extensions as long as there is production on the license.

Netherlands

Under the Mining Law, effective January 1, 2003, exploration and production licenses for both onshore and offshore areas are issued for a period as exp defined in the license. The term is based on the period of time necessary to perform the activities for which the license is issued. License conditio stipulated in the license and are based on the Mining Law.

Production rights granted prior to January 1, 2003, remain subject to their existing terms, and differ slightly for onshore and offshore areas. On production licenses issued prior to 1988 were indefinite; from 1988 they were issued for a period as explicitly defined in the license, ranging from 35 years. Offshore production licenses issued before 1976 were issued for a fixed period of 40 years; from 1976 they were again issued for a period as exp defined in the license, ranging from 15 to 40 years.

Norway

Licenses issued prior to 1972 were for an initial period of six years and an extension period of 40 years, with relinquishment of at least one-fourth original area required at the end of the sixth year and another one-fourth at the end of the ninth year. Licenses issued between 1972 and 1997 were initial period of up to six years (with extension of the initial period of one year at a time up to ten years after 1985), and an extension period of up to 30 with relinquishment of at least one-half of the original area required at the end of the initial period. Licenses issued after July 1, 1997, have an initial of up to ten years and a normal extension period of up to 30 years or in special cases of up to 50 years, and with relinquishment of at least one-half original area required at the end of the initial period.

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  United Kingdom

Acreage terms are fixed by the government and are periodically changed. For example, many of the early licenses issued under the first four licensing r provided for an initial term of six years with relinquishment of at least one-half of the original area at the end of the initial term, subject to extension further 40 years. At the end of any such 40-year term, licenses may continue in producing areas until cessation of production; or licenses may conti development areas for periods agreed on a case-by-case basis until they become producing areas; or licenses terminate in all other areas. The licensing r was last updated in 2002, and the majority of licenses issued have an initial term of four years with a second term extension of four years and a final te 18 years with a mandatory relinquishment of 50 percent of the acreage after the initial term and of all acreage that is not covered by a development plan end of the second term.

AFRICA

Angola

Exploration and production activities are governed by production sharing agreements with an initial exploration term of four years and an optional s phase of two to three years. The production period is for 25 years, and agreements generally provide for a negotiated extension.

Chad

Exploration permits are issued for a period of five years, and are renewable for one or two further five-year periods. The terms and conditions of the pe including relinquishment obligations, are specified in a negotiated convention. The production term is for 30 years and may be extended at the discret the government.

Equatorial Guinea

Exploration and production activities are governed by production sharing contracts negotiated with the State Ministry of Mines, Industry and Energy exploration periods are for 10 to 15 years with limited relinquishments in the absence of commercial discoveries. The production period for crude oi years, while the production period for gas is 50 years. Under the Hydrocarbons Law enacted in 2006, the exploration terms for new production s contracts are four to five years with a maximum of two one-year extensions, unless the Ministry agrees otherwise.

Nigeria

Exploration and production activities in the deepwater offshore areas are typically governed by production sharing contracts (PSCs) with the nation company, the Nigerian National Petroleum Corporation (NNPC). NNPC holds the underlying Oil Prospecting License (OPL) and any resulting Oil M Lease (OML). The terms of the PSCs are generally 30 years, including a ten-year exploration period (an initial exploration phase plus one or two op periods) covered by an OPL. Upon commercial discovery, an OPL may be converted to an OML. Partial relinquishment is required under the PSC at th of the ten-year exploration period, and OMLs have a 20-year production period that may be extended.

Some exploration activities are carried out in deepwater by joint ventures with local companies holding interests in an OPL. OPLs in deepwater of areas are valid for ten years and are non-renewable, while in all other areas the licenses are for five years and also are non-renewable. Demonstra commercial discovery is the basis for conversion of an OPL to an OML.

OMLs granted prior to the 1969 Petroleum Act (i.e., under the Mineral Oils Act 1914, repealed by the 1969 Petroleum Act) were for 30 years onsho 40 years in offshore areas and have been renewed, effective December 1, 2008, for a further period of 20 years, with a further renewal option of 20 Operations under these pre-1969 OMLs are conducted under a joint venture agreement with NNPC rather than a PSC. In 2000, a Memorandu Understanding (MOU) was executed defining commercial terms applicable to existing joint venture oil production. The MOU may be terminated o calendar year’s notice.

OMLs granted under the 1969 Petroleum Act, which include all deepwater OMLs, have a maximum term of 20 years without distinction for onsh offshore location and are renewable, upon 12 months’ written notice, for another period of 20 years. OMLs not held by NNPC are also subjec mandatory 50-percent relinquishment after the first ten years of their duration.

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  ASIA

Azerbaijan

The production sharing agreement (PSA) for the development of the Azeri-Chirag-Gunashli field is established for an initial period of 30 years starting the PSA execution date in 1994.

Other exploration and production activities are governed by PSAs negotiated with the national oil company of Azerbaijan. The exploration period co of three or four years with the possibility of a one to three-year extension. The production period, which includes development, is for 25 years or 35 with the possibility of one or two five-year extensions.

Indonesia

Exploration and production activities in Indonesia are generally governed by cooperation contracts, usually in the form of a production sharing co (PSC), negotiated with BPMIGAS, a government agency established in 2002 to manage upstream oil and gas activities. In 2012, Indonesia’s Constitu Court ruled certain articles of law relating to BPMIGAS to be unconstitutional, but stated that all existing PSCs signed with BPMIGAS should rem force until their expiry, and the functions and duties previously performed by BPMIGAS are to be carried out by the relevant Ministry of the Governm Indonesia until the promulgation of a new oil and gas law. The current PSCs have an exploration period of six years, which can be extended up to 10 and an exploitation period of 20 years. PSCs generally require the contractor to relinquish 10 percent to 20 percent of the contract area after three yea generally allow the contractor to retain no more than 50 percent to 80 percent of the original contract area after six years, depending on the acreag terms.

Iraq

Development and production activities in the state-owned oil and gas fields are governed by contracts with regional oil companies of the Iraqi Minis Oil. An ExxonMobil affiliate entered into a contract with South Oil Company of the Iraqi Ministry of Oil for the rights to participate in the developme production activities of the West Qurna Phase I oil and gas field effective March 1, 2010. The term of the contract is 20 years with the right to extend fo years. The contract provides for cost recovery plus per-barrel fees for incremental production above specified levels.

Exploration and production activities in the Kurdistan Region of Iraq are governed by production sharing contracts negotiated with the re government of Kurdistan in 2011. The exploration term is for five years with the possibility of two-year extensions. The production period is 20 year the right to extend for five years.

Kazakhstan

Onshore exploration and production activities are governed by the production license, exploration license and joint venture agreements negotiated w Republic of Kazakhstan. Existing production operations have a 40-year production period that commenced in 1993.

Offshore exploration and production activities are governed by a production sharing agreement negotiated with the Republic of Kazakhstan exploration period is six years followed by separate appraisal periods for each discovery. The production period for each discovery, which in development, is for 20 years from the date of declaration of commerciality with the possibility of two ten-year extensions.

Malaysia

Exploration and production activities are governed by production sharing contracts (PSCs) negotiated with the national oil company. The more recent governing exploration and production activities have an overall term of 24 to 38 years, depending on water depth, with possible extensions to the explo and/or development periods. The exploration period is five to seven years with the possibility of extensions, after which time areas with no comm discoveries will be deemed relinquished. The development period is from four to six years from commercial discovery, with the possibility of exte under special circumstances. Areas from which commercial production has not started by the end of the development period will be deemed relinquis no extension is granted. All extensions are subject to the national oil company’s prior written approval. The total production period is 15 to 25 years first commercial lifting, not to exceed the overall term of the contract.

In 2008, the Company reached agreement with the national oil company for a new PSC, which was subsequently signed in 2009. Under the new from 2008 until March 31, 2012, the Company was entitled to undertake new development and production activities in oil fields under an existing subject to new minimum work and spending commitments, including an enhanced oil recovery project in one of the oil fields. When the existing PSC e on March 31, 2012, the producing fields covered by the existing PSC automatically became part of the new PSC, which has a 25-year duration from 2008.

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  Qatar

The State of Qatar grants gas production development project rights to develop and supply gas from the offshore North Field to permit the eco development and production of gas reserves sufficient to satisfy the gas and LNG sales obligations of these projects.

Republic of Yemen

The Jannah production sharing agreement has a development period extending 20 years from first commercial declaration, which was made in June 199

Russia

Terms for ExxonMobil’s Sakhalin acreage are fixed by the production sharing agreement (PSA) that became effective in 1996 between the R government and the Sakhalin-1 consortium, of which ExxonMobil is the operator. The term of the PSA is 20 years from the Declaration of Commerc which would be 2021. The term may be extended thereafter in ten-year increments as specified in the PSA.

Exploration and production activities in the Kara and Black Seas are governed by joint venture agreements concluded with Rosneft in 2013 that certain of Rosneft’s offshore licenses. The Kara Sea licenses extend through 2040 and include an exploration period through 2020, developmen submission within eight years of a discovery and development activities within five years of plan approval. The Black Sea exploration license ex through 2017 and a discovery is the basis for obtaining a license for production.

Thailand

The Petroleum Act of 1971 allows production under ExxonMobil’s concession for 30 years with a ten-year extension at terms generally prevalent at the

United Arab Emirates

Exploration and production activities for the major onshore oil fields in the Emirate of Abu Dhabi were governed by a 75-year oil concession agre executed in 1939, which expired in January 2014. An interest in the development and production activities of the Upper Zakum field, a major offshore was acquired effective as of January 2006, for a term expiring March 2026, and in 2013 the governing agreements were extended to 2041.

AUSTRALIA/OCEANIA

Australia

Exploration and production activities conducted offshore in Commonwealth waters are governed by Federal legislation. Exploration permits are grant an initial term of six years with two possible five-year renewal periods. Retention leases may be granted for resources that are not commercially viable time of application, but are expected to become commercially viable within 15 years. These are granted for periods of five years and renewals m requested. Prior to July 1998, production licenses were granted initially for 21 years, with a further renewal of 21 years and thereafter “indefinitely”, i. the life of the field. Effective from July 1998, new production licenses are granted “indefinitely”. In each case, a production license may be terminated production operations have been carried on for five years.

Papua New Guinea

Exploration and production activities are governed by the Oil and Gas Act. Petroleum Prospecting licenses are granted for an initial term of six years five-year extension possible (an additional extension of three years is possible in certain circumstances). Generally, a 50-percent relinquishment of the l area is required at the end of the initial six-year term, if extended. Petroleum Development licenses are granted for an initial 25-year period. An extens up to 20 years may be granted at the Minister’s discretion. Petroleum Retention licenses may be granted for gas resources that are not commercially via the time of application, but may become commercially viable within the maximum possible retention time of 15 years. Petroleum Retention licens granted for five-year terms, and may be extended, at the Minister’s discretion, twice for the maximum retention time of 15 years. Extensions of Petr Retention licenses may be for periods of less than one year, renewable annually, if the Minister considers at the time of extension that the resources become commercially viable in less than five years.

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  Information with regard to the Downstream segment follows:

ExxonMobil’s Downstream segment manufactures and sells petroleum products. The refining and supply operations encompass a global netwo manufacturing plants, transportation systems, and distribution centers that provide a range of fuels, lubricants and other products and feedstocks customers around the world.

Refining Capacity At Year-End 2013 (1) ExxonMobil ExxonMob Share KBD (2) Interest %

United States Torrance California 150 100 Joliet Illinois 238 100 Baton Rouge Louisiana 502 100 Baytown Texas 561 100 Beaumont Texas 345 100 Other (2 refineries) 155 Total United States 1,951 Canada Strathcona Alberta 189 69.6 Nanticoke Ontario 113 69.6 Sarnia Ontario 119 69.6 Total Canada 421 Europe Antwerp Belgium 307 100 Fos-sur-Mer France 133 82.9 Gravenchon France 236 82.9 Karlsruhe Germany 78 25 Augusta Italy 198 100 Trecate Italy 127 75.5 Rotterdam Netherlands 191 100 Slagen Norway 116 100 Fawley United Kingdom 260 100 Total Europe 1,646 Asia Pacific Jurong/PAC Singapore 592 100 Sriracha Thailand 167 66 Other (7 refineries) 297 Total Asia Pacific 1,056 Other Non-U.S. Yanbu Saudi Arabia 200 50 Laffan Qatar 15 10 Fort-de-France Martinique 2 14.5 Total Other Non-U.S. 217 Total Worldwide 5,291

(1) Capacity data is based on 100 percent of rated refinery process unit stream-day capacities under normal operating conditions, less the imp shutdowns for regular repair and maintenance activities, averaged over an extended period of time.

(2) Thousands of barrels per day (KBD). ExxonMobil share reflects 100 percent of atmospheric distillation capacity in operations of ExxonMob majority-owned subsidiaries. For companies owned 50 percent or less, ExxonMobil share is the greater of ExxonMobil’s equity interest or that por distillation capacity normally available to ExxonMobil.

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  The marketing operations sell products and services throughout the world through our Exxon, Esso and Mobil brands.

Retail Sites At Year-End 2013

United States Owned/leased - Distributors/resellers 9,196 Total United States 9,196

Canada Owned/leased 472 Distributors/resellers 1,259 Total Canada 1,731

Europe Owned/leased 3,445 Distributors/resellers 2,812 Total Europe 6,257

Asia Pacific Owned/leased 666 Distributors/resellers 313 Total Asia Pacific 979

Latin America Owned/leased 53 Distributors/resellers 705 Total Latin America 758

Middle East/Africa Owned/leased 436 Distributors/resellers 197 Total Middle East/Africa 633

Worldwide Owned/leased 5,072 Distributors/resellers 14,482 Total Worldwide 19,554

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  Information with regard to the Chemical segment follows:

ExxonMobil’s Chemical segment manufactures and sells petrochemicals. The Chemical business supplies olefins, polyolefins, aromatics, and a wide v of other petrochemicals.

Chemical Complex Capacity At Year-End 2013 (1)(2) ExxonMo Ethylene Polyethylene Polypropylene Paraxylene Interest % North America Baton Rouge Louisiana 1.0 1.3 0.4 - 100 Baytown Texas 2.2 - 0.7 0.6 100 Beaumont Texas 0.9 1.0 - 0.3 100 Mont Belvieu Texas - 1.0 - - 100 Sarnia Ontario 0.3 0.5 - - 69.6 Total North America 4.4 3.8 1.1 0.9 Europe Antwerp Belgium - 0.4 - - 100 Fife United Kingdom 0.4 - - - 50 Meerhout Belgium - 0.5 - - 100 Gravenchon France 0.4 0.4 0.3 - 100 Rotterdam Netherlands - - - 0.7 100 Total Europe 0.8 1.3 0.3 0.7 Middle East Al Jubail Saudi Arabia 0.6 0.7 - - 50 Yanbu Saudi Arabia 1.0 0.7 0.2 - 50 Total Middle East 1.6 1.4 0.2 - Asia Pacific Fujian China 0.2 0.2 0.1 0.2 25 Kawasaki Japan 0.1 - - - 22 Singapore Singapore 1.9 1.9 0.9 0.9 100 Sriracha Thailand - - - 0.5 66 Total Asia Pacific 2.2 2.1 1.0 1.6 All Other - - - 0.2 Total Worldwide 9.0 8.6 2.6 3.4

(1) Capacity for ethylene, polyethylene, polypropylene and paraxylene in millions of metric tons per year.

(2) Capacity reflects 100 percent for operations of ExxonMobil and majority-owned subsidiaries. For companies owned 50 percent or less, capa ExxonMobil’s interest.

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  ITEM 3. LEGAL PROCEEDINGS

In November 2013, the Texas Commission on Environmental Quality (TCEQ) contacted Exxon Mobil Corporation (the “Corporation”) concerning a violations of the Texas Clean Air Act, implementing regulations and the applicable new source review permit in connection with exceedances of v organic compound emissions from Tank 22 at the Corporation’s King Ranch Gas Plant. TCEQ is seeking a civil penalty in excess of $100,000 alon certain corrective action. The Corporation is working with TCEQ to resolve the matter.

Regarding the June 27, 2013, Administrative Consent Agreement between the North Dakota Department of Health (NDDOH) and XTO Energ (XTO) resolving the air enforcement matter previously reported in the Corporation’s Forms 10-Q for the first and second quarters of 2013, pursuant terms of the Administrative Consent Agreement, during the fourth quarter of 2013, XTO provided the NDDOH with an updated list of well sites on acquired assets with air emission control issues. On November 12, 2013, XTO paid an additional penalty assessment of $183,400 with respect to those s

Regarding the criminal charges filed against XTO by the Pennsylvania Attorney General’s Office pertaining to XTO’s Marquardt Well Site in Township, Pennsylvania, reported most recently in the Corporation’s Form 10-Q for the third quarter of 2013, on January 2, 2014, a Pennsylvania magistrate ruled that the Attorney General’s Office had presented sufficient evidence for the charges to proceed to trial in the Pennsylvania Court of Co Pleas. At the trial, XTO will have an opportunity to present its full defense to the charges, which it believes are unwarranted.

Regarding the settlement of matters between the Louisiana Department of Environmental Quality (LDEQ) and ExxonMobil Refining and S Company and ExxonMobil Chemical Company, both divisions of the Corporation, involving ExxonMobil facilities in Baton Rouge, Louisiana, last re in the Corporation’s Form 10-Q for the third quarter of 2013, during the fourth quarter of 2013, the public comment period on the proposed settlement e and the Louisiana Attorney General issued his concurrence with regard to the settlement terms. The parties executed the final documents in January thereby resolving the matters covered by the settlement. The settlement terms include payment of a $300,000 penalty, an agreement to complete c on-site improvement projects valued at $1,000,000, Beneficial Environmental Projects valued at $1,029,000 and a Stipulated Penalty Agreement to a any future environmental non-compliance.

On December 11, 2013, the TCEQ Commissioner’s Court accepted and signed the Agreed Order settling the enforcement action, including a pena $126,250, concerning emission events at ExxonMobil Oil Corporation’s (EMOC) Beaumont Refinery previously reported in the Corporation’s Forms for the first and third quarters of 2013.

Regarding the complaint against EMOC filed by the Attorney General for the State of New York alleging contamination of soil and groundwate former Mobil petroleum terminal at Lighthouse Point in Ogdensburg, New York, previously reported in the Corporation’s Form 10-Q for the third qua 2011, the parties reached a settlement agreement that was entered into the court record on November 14, 2013. On December 16, 2013, the parties sign agreement, and EMOC made a payment to the State of $8.05 million, pursuant to the agreement’s terms.

Refer to the relevant portions of “Note 16: Litigation and Other Contingencies” of the Financial Section of this report for additional information on proceedings.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

_______________________

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  Executive Officers of the Registrant [pursuant to Instruction 3 to Regulation S-K, Item 401(b)] Rex W. Tillerson Chairman of the Board

Held current title since: January 1, 2006 Age: 61 Mr. Rex W. Tillerson became a Director and President of Exxon Mobil Corporation on March 1, 2004. He became Chairman of the Board and Executive Officer on January 1, 2006. He still holds these positions as of this filing date.

Mark W. Albers Senior Vice President

Held current title since: April 1, 2007 Age: 57 Mr. Mark W. Albers became Senior Vice President of Exxon Mobil Corporation on April 1, 2007, a position he still holds as of this filing date.

Michael J. Dolan Senior Vice President

Held current title since: April 1, 2008 Age: 60 Mr. Michael J. Dolan became Senior Vice President of Exxon Mobil Corporation on April 1, 2008, a position he still holds as of this filing date.

Andrew P. Swiger Senior Vice President

Held current title since: April 1, 2009 Age: 57 Mr. Andrew P. Swiger was President of ExxonMobil Gas & Power Marketing Company and Vice President of Exxon Mobil Corporation October 1 – March 31, 2009. He became Senior Vice President of Exxon Mobil Corporation on April 1, 2009, a position he still holds as of this filing date.

S. Jack Balagia Vice President and General Counsel

Held current title since: March 1, 2010 Age: 62 Mr. S. Jack Balagia was Assistant General Counsel of Exxon Mobil Corporation April 1, 2004 – March 1, 2010. He became Vice President and G Counsel of Exxon Mobil Corporation on March 1, 2010, positions he still holds as of this filing date.

Randy J. Cleveland President, XTO Energy Inc., a subsidiary of the Corporation

Held current title since: June 1, 2013 Age: 52 Mr. Randy J. Cleveland was Production Manager, U.S. Production, ExxonMobil Production Company April 1, 2006 – April 30, 2009. He was Plann Commercial Manager, ExxonMobil Production Company May 1, 2009 – June 24, 2010. He was Vice President, XTO Integration, XTO Energy Inc 25, 2010 – January 31, 2012. He was Executive Vice President, XTO Energy Inc. February 1, 2012 – May 31, 2013. He became President of Energy Inc. on June 1, 2013, a position he still holds as of this filing date.

William M. Colton Vice President – Corporate Strategic Planning

Held current title since: February 1, 2009 Age: 60 Mr. William M. Colton was Assistant Treasurer of Exxon Mobil Corporation January 25, 2006 – January 31, 2009. He became Vice President – Cor Strategic Planning of Exxon Mobil Corporation on February 1, 2009, a position he still holds as of this filing date.

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  Michael G. Cousins Vice President

Held current title since: March 1, 2013 Age: 53 Mr. Michael G. Cousins was Planning Manager, ExxonMobil Exploration Company April 1, 2008 – May 31, 2009. He was Vice President Pacific/Middle East, ExxonMobil Exploration Company June 1, 2009 – March 31, 2012. He was Executive Assistant to the Chairman, Exxon Corporation April 1, 2012 – February 28, 2013. He became President of ExxonMobil Upstream Ventures and Vice President of Exxon Mobil Corpo on March 1, 2013, positions he still holds as of this filing date.

Neil W. Duffin President, ExxonMobil Development Company

Held current title since: April 13, 2007 Age: 57 Mr. Neil W. Duffin became President of ExxonMobil Development Company on April 13, 2007, a position he still holds as of this filing date.

Robert S. Franklin Vice President

Held current title since: May 1, 2009 Age: 56 Mr. Robert S. Franklin was Vice President, Europe/Russia/Caspian of ExxonMobil Production Company April 1, 2008 – May 1, 2009. He wa President of Exxon Mobil Corporation and President, ExxonMobil Upstream Ventures May 1, 2009 – February 28, 2013. He became Presid ExxonMobil Gas & Power Marketing Company and Vice President of Exxon Mobil Corporation on March 1, 2013, positions he still holds as of this date.

Stephen M. Greenlee Vice President

Held current title since: September 1, 2010 Age: 56 Mr. Stephen M. Greenlee was Vice President of ExxonMobil Exploration Company June 1, 2004 – June 1, 2009. He was President of Exxon Upstream Research Company June 1, 2009 – August 31, 2010. He became President of ExxonMobil Exploration Company and Vice President of E Mobil Corporation on September 1, 2010, positions he still holds as of this filing date.

Alan J. Kelly Vice President

Held current title since: December 1, 2007 Age: 56 Mr. Alan J. Kelly became President of ExxonMobil Lubricants & Petroleum Specialties Company and Vice President of Exxon Mobil Corporati December 1, 2007. On February 1, 2012, the businesses of ExxonMobil Lubricants & Petroleum Specialties Company and ExxonMobil Fuels Mar Company were consolidated and Mr. Kelly became President of the combined ExxonMobil Fuels, Lubricants & Specialties Marketing Company an President of Exxon Mobil Corporation, positions he still holds as of this filing date.

Patrick T. Mulva Vice President and Controller

Held current title since: February 1, 2002 (Vice President) July 1, 2004 (Controller)

Age: 62

Mr. Patrick T. Mulva became Vice President of Exxon Mobil Corporation on February 1, 2002 and Controller of Exxon Mobil Corporati July 1, 2004, positions he still holds as of this filing date.

Stephen D. Pryor Vice President

Held current title since: December 1, 2004 Age: 64 Mr. Stephen D. Pryor became Vice President of Exxon Mobil Corporation on December 1, 2004 and President of ExxonMobil Chemical Compa April 1, 2008, positions he still holds as of this filing date.

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  David S. Rosenthal Vice President - Investor Relations and Secretary

Held current title since: October 1, 2008 Age: 57 Mr. David S. Rosenthal became Vice President – Investor Relations and Secretary of Exxon Mobil Corporation on October 1, 2008, positions he still as of this filing date.

Robert N. Schleckser Vice President and Treasurer

Held current title since: May 1, 2011 Age: 57 Mr. Robert N. Schleckser was Downstream Treasurer, Downstream Business Services May 1, 2005 – January 31, 2009. He was Assistant Treasu Exxon Mobil Corporation February 1, 2009 – April 30, 2011. He became Vice President and Treasurer of Exxon Mobil Corporation on May 1, positions he still holds as of this filing date.

James M. Spellings, Jr. Vice President and General Tax Counsel

Held current title since: March 1, 2010 Age: 52 Mr. James M. Spellings, Jr. was Associate General Tax Counsel of Exxon Mobil Corporation April 1, 2007 – March 1, 2010. He became Vice Pre and General Tax Counsel of Exxon Mobil Corporation on March 1, 2010, positions he still holds as of this filing date.

Thomas R. Walters Vice President

Held current title since: April 1, 2009 Age: 59 Mr. Thomas R. Walters was Executive Vice President of ExxonMobil Development Company April 13, 2007 – April 1, 2009. He was Presid ExxonMobil Gas & Power Marketing Company and Vice President of Exxon Mobil Corporation April 1, 2009 – February 28, 2013. He became Pre of ExxonMobil Production Company and Vice President of Exxon Mobil Corporation on March 1, 2013, positions he still holds as of this filing date

Darren W. Woods Vice President

Held current title since: August 1, 2012 Age: 49 Mr. Darren W. Woods was Director, Refining Europe/Africa/Middle East, ExxonMobil Refining & Supply Company February 1, 2008 – June 30, He was Vice President, Supply & Transportation, ExxonMobil Refining & Supply Company July 1, 2010 – July 31, 2012. He became Presid ExxonMobil Refining & Supply Company and Vice President of Exxon Mobil Corporation on August 1, 2012, positions he still holds as of this date. Officers are generally elected by the Board of Directors at its meeting on the day of each annual election of directors, with each such officer serving

successor has been elected and qualified.

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PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Reference is made to the “Quarterly Information” portion of the Financial Section of this report. Issuer Purchases of Equity Securities for Quarter Ended December 31, 2013 Total Number of Shares Purchased as Maximum Numb Part of Publicly of Shares that M Total Number of Average Price Announced Yet Be Purchas Shares Paid per Plans or Under the Plans Period Purchased Share Programs Programs October 2013 12,589,049 87.12 12,589,049 November 2013 13,152,312 93.69 13,152,312 December 2013 10,025,720 97.08 10,025,720 Total 35,767,081 92.33 35,767,081 (See note 1)

Note 1 - On August 1, 2000, the Corporation announced its intention to resume purchases of shares of its common stock for the treasury both to offset issued in conjunction with company benefit plans and programs and to gradually reduce the number of shares outstanding. The announcement did not s an amount or expiration date. The Corporation has continued to purchase shares since this announcement and to report purchased volumes in its qua earnings releases. In its most recent earnings release dated January 30, 2014, the Corporation stated that first quarter 2014 share purchases are continuin pace consistent with fourth quarter 2013 share reduction spending of $3 billion. Purchases may be made in both the open market and through nego transactions, and purchases may be increased, decreased or discontinued at any time without prior notice.

ITEM 6. SELECTED FINANCIAL DATA

Years Ended December 31, 2013 2012 2011 2010 200 (millions of dollars, except per share amounts) Sales and other operating revenue (1) 420,836 451,509 467,029 370,125 30 (1) Sales-based taxes included 30,589 32,409 33,503 28,547 2 Net income attributable to ExxonMobil 32,580 44,880 41,060 30,460 1 Earnings per common share 7.37 9.70 8.43 6.24 Earnings per common share - assuming dilution 7.37 9.70 8.42 6.22 Cash dividends per common share 2.46 2.18 1.85 1.74 Total assets 346,808 333,795 331,052 302,510 23 Long-term debt 6,891 7,928 9,322 12,227

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIO

Reference is made to the section entitled “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the Financial S of this report.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Reference is made to the section entitled “Market Risks, Inflation and Other Uncertainties”, excluding the part entitled “Inflation and Other Uncertainti the Financial Section of this report. All statements other than historical information incorporated in this Item 7A are forward-looking statements. The impact of future market changes could differ materially due to, among other things, factors discussed in this report.

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  ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Reference is made to the following in the Financial Section of this report:

∙ Consolidated financial statements, together with the report thereon of PricewaterhouseCoopers LLP dated February 26, 2014, beginning wi section entitled “Report of Independent Registered Public Accounting Firm” and continuing through “Note 19: Income, Sales-Based and Taxes”;

∙ “Quarterly Information” (unaudited);

∙ “Supplemental Information on Oil and Gas Exploration and Production Activities” (unaudited); and

∙ “Frequently Used Terms” (unaudited).

Financial Statement Schedules have been omitted because they are not applicable or the required information is shown in the consolidated fin statements or notes thereto.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES

Management’s Evaluation of Disclosure Controls and Procedures

As indicated in the certifications in Exhibit 31 of this report, the Corporation’s Chief Executive Officer, Principal Financial Officer and Principal Acco Officer have evaluated the Corporation’s disclosure controls and procedures as of December 31, 2013. Based on that evaluation, these officers concluded that the Corporation’s disclosure controls and procedures are effective in ensuring that information required to be disclosed by the Corporat the reports that it files or submits under the Securities Exchange Act of 1934, as amended, is accumulated and communicated to them in a manner that a for timely decisions regarding required disclosures and are effective in ensuring that such information is recorded, processed, summarized and re within the time periods specified in the Securities and Exchange Commission’s rules and forms.

Management’s Report on Internal Control Over Financial Reporting

Management, including the Corporation’s Chief Executive Officer, Principal Financial Officer and Principal Accounting Officer, is responsib establishing and maintaining adequate internal control over the Corporation’s financial reporting. Management conducted an evaluation of the effectiv of internal control over financial reporting based on criteria established in Internal Control - Integrated Framework (1992) issued by the Commit Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that Exxon Mobil Corporation’s internal c over financial reporting was effective as of December 31, 2013.

PricewaterhouseCoopers LLP, an independent registered public accounting firm, audited the effectiveness of the Corporation’s internal contro financial reporting as of December 31, 2013, as stated in their report included in the Financial Section of this report.

Changes in Internal Control Over Financial Reporting

There were no changes during the Corporation’s last fiscal quarter that materially affected, or are reasonably likely to materially affect, the Corpora internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

None.

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PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Incorporated by reference to the following from the registrant’s definitive proxy statement for the 2014 annual meeting of shareholders (the “2014 Statement”):

∙

The section entitled “Election of Directors”;

∙

The portion entitled “Section 16(a) Beneficial Ownership Reporting Compliance” of the section entitled “Director and Executive Officer S Ownership”;

∙

The portions entitled “Director Qualifications” and “Code of Ethics and Business Conduct” of the section entitled “Corporate Governan and

∙

The “Audit Committee” portion and the membership table of the portion entitled “Board Meetings and Committees; Annual Me Attendance” of the section entitled “Corporate Governance”.

ITEM 11. EXECUTIVE COMPENSATION

Incorporated by reference to the sections entitled “Director Compensation,” “Compensation Committee Report,” “Compensation Discussion and Ana and “Executive Compensation Tables” of the registrant’s 2014 Proxy Statement.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

The information required under Item 403 of Regulation S-K is incorporated by reference to the sections “Director and Executive Officer Stock Owne and “Certain Beneficial Owners” of the registrant’s 2014 Proxy Statement.

Equity Compensation Plan Information (a) (b) (c)

Number of Securitie

Weighted- Remaining Available

Average for Future Issuance Number of Securities Exercise Price Under Equity

to be Issued Upon of Outstanding Compensation

Exercise of Options, Plans [Excluding

Outstanding Options, Warrants and Securities Reflected

Plan Category Warrants and Rights Rights in Column (a)] Equity compensation plans approved by security holders 17,358,275 (1)(2) - 117,260,597 (2)(3) Equity compensation plans not approved by security holders - - - Total 17,358,275 - 117,260,597  

(1) The number of restricted stock units to be settled in shares.

(2) Does not include options that ExxonMobil assumed in the 2010 merger with XTO Energy Inc. At year-end 2013, the number of securities to be upon exercise of outstanding options under XTO Energy Inc. plans was 1,505,820, and the weighted-average exercise price of such options was $ No additional awards may be made under those plans.

(3) Available shares can be granted in the form of restricted stock, options, or other stock-based awards. Includes 116,619,397 shares available for under the 2003 Incentive Program and 641,200 shares available for award under the 2004 Non-Employee Director Restricted Stock Plan.

(4) Under the 2004 Non-Employee Director Restricted Stock Plan approved by shareholders in May 2004, and the related standing resolution adop the Board, each non-employee director automatically receives 8,000 shares of restricted stock when first elected to the Board and, if the director re in office, an additional 2,500 restricted shares each following year. While on the Board, each non-employee director receives the same cash dividen restricted shares as a holder of regular common stock, but the director is not allowed to sell the shares. The restricted shares may be forfeited director leaves the Board early.

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  ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Incorporated by reference to the portions entitled “Related Person Transactions and Procedures” and “Director Independence” of the section e “Corporate Governance” of the registrant’s 2014 Proxy Statement.

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

Incorporated by reference to the portion entitled “Audit Committee” of the section entitled “Corporate Governance” and the section entitled “Ratificat Independent Auditors” of the registrant’s 2014 Proxy Statement.  

PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES

(a) (1) and (2) Financial Statements: See Table of Contents of the Financial Section of this report.

(a) (3) Exhibits: See Index to Exhibits of this report.

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FINANCIAL SECTION TABLE OF CONTENTS

Business Profile 35 Financial Summary 36 Frequently Used Terms 37 Quarterly Information 39 Management’s Discussion and Analysis of Financial Condition

and Results of Operations

Functional Earnings 40 Forward-Looking Statements 41 Overview 41 Business Environment and Risk Assessment 41 Review of 2013 and 2012 Results 44 Liquidity and Capital Resources 48 Capital and Exploration Expenditures 53 Taxes 53 Environmental Matters 54 Market Risks, Inflation and Other Uncertainties 54 Critical Accounting Estimates 56

Management’s Report on Internal Control Over Financial Reporting 60 Report of Independent Registered Public Accounting Firm 61 Consolidated Financial Statements

Statement of Income 62 Statement of Comprehensive Income 63 Balance Sheet 64 Statement of Cash Flows 65 Statement of Changes in Equity 66

Notes to Consolidated Financial Statements

1. Summary of Accounting Policies 67 2. Accounting Changes 69 3. Miscellaneous Financial Information 69 4. Other Comprehensive Income Information 70 5. Cash Flow Information 71 6. Additional Working Capital Information 71 7. Equity Company Information 72 8. Investments, Advances and Long-Term Receivables 73 9. Property, Plant and Equipment and Asset Retirement Obligations 74 10. Accounting for Suspended Exploratory Well Costs 75 11. Leased Facilities 77 12. Earnings Per Share 77 13. Financial Instruments and Derivatives 78 14. Long-Term Debt 79 15. Incentive Program 80 16. Litigation and Other Contingencies 81 17. Pension and Other Postretirement Benefits 83 18. Disclosures about Segments and Related Information 91 19. Income, Sales-Based and Other Taxes 94

Supplemental Information on Oil and Gas Exploration and Production Activities 97 Operating Summary 112

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  BUSINESS PROFILE

Return on Capital and Earnings After Average Capital Average Capital Exploration Income Taxes Employed Employed Expenditures Financial 2013 2012 2013 2012 2013 2012 2013 20 (millions of dollars) (percent) (millions of dollars Upstream United States 4,191 3,925 59,898 57,631 7.0 6.8 9,145 1 Non-U.S. 22,650 25,970 93,071 81,811 24.3 31.7 29,086 2 Total 26,841 29,895 152,969 139,442 17.5 21.4 38,231 3 Downstream United States 2,199 3,575 4,757 4,630 46.2 77.2 951 Non-U.S. 1,250 9,615 19,673 19,401 6.4 49.6 1,462 Total 3,449 13,190 24,430 24,031 14.1 54.9 2,413 Chemical United States 2,755 2,220 4,872 4,671 56.5 47.5 963 Non-U.S. 1,073 1,678 15,793 15,477 6.8 10.8 869 Total 3,828 3,898 20,665 20,148 18.5 19.3 1,832 Corporate and financing (1,538) (2,103) (6,489) (4,527) - - 13 Total 32,580 44,880 191,575 179,094 17.2 25.4 42,489 3

See Frequently Used Terms for a definition and calculation of capital employed and return on average capital employed. Operating 2013 2012 2013 20 (thousands of barrels daily) (thousands of barrel Net liquids production Refinery throughput United States 431 418 United States 1,819 Non-U.S. 1,771 1,767 Non-U.S. 2,766 Total 2,202 2,185 Total 4,585 (millions of cubic feet daily) (thousands of barrel Natural gas production available for sale Petroleum product sales United States 3,545 3,822 United States 2,609 Non-U.S. 8,291 8,500 Non-U.S. 3,278 Total 11,836 12,322 Total 5,887 (thousands of oil-equivalent barrels daily) (thousands of metr Oil-equivalent production (1) 4,175 4,239 Chemical prime product sales (2) United States 9,679 Non-U.S. 14,384 1 Total 24,063 2

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

(2) Prime product sales include ExxonMobil´s share of equity company volumes and finished-product transfers to the Downstream.

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  FINANCIAL SUMMARY

2013 2012 2011 2010 20 (millions of dollars, except per share amounts) Sales and other operating revenue (1) 420,836 451,509 467,029 370,125 30 Earnings Upstream 26,841 29,895 34,439 24,097 1 Downstream 3,449 13,190 4,459 3,567 Chemical 3,828 3,898 4,383 4,913 Corporate and financing (1,538) (2,103) (2,221) (2,117) ( Net income attributable to ExxonMobil 32,580 44,880 41,060 30,460 1 Earnings per common share 7.37 9.70 8.43 6.24 Earnings per common share – assuming dilution 7.37 9.70 8.42 6.22 Cash dividends per common share 2.46 2.18 1.85 1.74 Earnings to average ExxonMobil share of equity (percent) 19.2 28.0 27.3 23.7 Working capital (12,416) 321 (4,542) (3,649) Ratio of current assets to current liabilities (times) 0.83 1.01 0.94 0.94 Additions to property, plant and equipment 37,741 35,179 33,638 74,156 2 Property, plant and equipment, less allowances 243,650 226,949 214,664 199,548 13 Total assets 346,808 333,795 331,052 302,510 23 Exploration expenses, including dry holes 1,976 1,840 2,081 2,144 Research and development costs 1,044 1,042 1,044 1,012 Long-term debt 6,891 7,928 9,322 12,227 Total debt 22,699 11,581 17,033 15,014 Fixed-charge coverage ratio (times) 55.7 62.4 53.4 42.2 Debt to capital (percent) 11.2 6.3 9.6 9.0 Net debt to capital (percent) (2) 9.1 1.2 2.6 4.5 ExxonMobil share of equity at year-end 174,003 165,863 154,396 146,839 11 ExxonMobil share of equity per common share 40.14 36.84 32.61 29.48 Weighted average number of common shares outstanding (millions) 4,419 4,628 4,870 4,885 Number of regular employees at year-end (thousands) (3) 75.0 76.9 82.1 83.6 CORS employees not included above (thousands) (4) 9.8 11.1 17.0 20.1  

(1) Sales and other operating revenue includes sales-based taxes of $30,589 million for 2013, $32,409 million for 2012, $33,503 million for 2011, $2 million for 2010 and $25,936 million for 2009.

(2) Debt net of cash, excluding restricted cash.

(3) Regular employees are defined as active executive, management, professional, technical and wage employees who work full time or part time f Corporation and are covered by the Corporation’s benefit plans and programs.

(4) CORS employees are employees of company-operated retail sites.

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  FREQUENTLY USED TERMS Listed below are definitions of several of ExxonMobil’s key business and financial performance measures. These definitions are provided to fac 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 associated with sales of subsid property, plant and equipment, and sales and returns of investments from the Consolidated Statement of Cash Flows. This cash flow reflects the total so of cash from both operating the Corporation’s assets and from the divesting of assets. The Corporation employs a long-standing and regular disci review process to ensure that all assets are contributing to the Corporation’s strategic objectives. Assets are divested when they are no longer meeting 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 pro associated with asset sales together with cash provided by operating activities when evaluating cash available for investment in the business and fina activities, including shareholder distributions.

Cash flow from operations and asset sales 2013 2012 20 (millions of dollars) Net cash provided by operating activities 44,914 56,170 5 Proceeds associated with sales of subsidiaries, property, plant and equipment, and sales and returns of investments 2,707 7,655 1 Cash flow from operations and asset sales 47,621 63,825 6

  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 ExxonM net share of property, plant and equipment and other assets less liabilities, excluding both short-term and long-term debt. When viewed from the persp of the sources of capital employed in total for the Corporation, it includes ExxonMobil’s share of total debt and equity. Both of these views in ExxonMobil’s share of amounts applicable to equity companies, which the Corporation believes should be included to provide a more compreh measure of capital employed.

Capital employed 2013 2012 20 (millions of dollars) Business uses: asset and liability perspective Total assets 346,808 333,795 33 Less liabilities and noncontrolling interests share of assets and liabilities Total current liabilities excluding notes and loans payable (55,916) (60,486) (6 Total long-term liabilities excluding long-term debt (87,698) (90,068) (8 Noncontrolling interests share of assets and liabilities (8,935) (6,235) ( Add ExxonMobil share of debt-financed equity company net assets 6,109 5,775 Total capital employed 200,368 182,781 17 Total corporate sources: debt and equity perspective Notes and loans payable 15,808 3,653 Long-term debt 6,891 7,928 ExxonMobil share of equity 174,003 165,863 15 Less noncontrolling interests share of total debt (2,443) (438) Add ExxonMobil share of equity company debt 6,109 5,775 Total capital employed 200,368 182,781 17

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  FREQUENTLY USED TERMS 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 bu segment earnings divided by average business segment capital employed (average of beginning and end-of-year amounts). These segment earnings in ExxonMobil’s share of segment earnings of equity companies, consistent with our capital employed definition, and exclude the cost of financing Corporation’s total ROCE is net income attributable to ExxonMobil excluding the after-tax cost of financing, divided by total corporate average c employed. The Corporation has consistently applied its ROCE definition for many years and views it as the best measure of historical capital productiv our capital-intensive, long-term industry, both to evaluate management’s performance and to demonstrate to shareholders that capital has been used w over the long term. Additional measures, which are more cash flow based, are used to make investment decisions.

Return on average capital employed 2013 2012 20 (millions of dollars) Net income attributable to ExxonMobil 32,580 44,880 4 Financing costs (after tax) Gross third-party debt (163) (401) ExxonMobil share of equity companies (239) (257) All other financing costs – net 83 100 Total financing costs (319) (558) Earnings excluding financing costs 32,899 45,438 4 Average capital employed 191,575 179,094 17 Return on average capital employed – corporate total 17.2% 25.4%

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  QUARTERLY INFORMATION

2013 2012 First Second Third Fourth First Second Third Fourth Quarter Quarter Quarter Quarter Year Quarter Quarter Quarter Quarter Ye Volumes Production of crude oil (thousands of barrels daily) and natural gas liquids, 2,193 2,182 2,199 2,235 2,202 2,214 2,208 2,116 2,203 synthetic oil and bitumen Refinery throughput 4,576 4,466 4,847 4,452 4,585 5,330 4,962 4,929 4,837 Petroleum product sales 5,755 5,765 6,031 5,994 5,887 6,316 6,171 6,105 6,108 Natural gas production (millions of cubic feet daily) available for sale 13,213 11,354 10,914 11,887 11,836 14,036 11,661 11,061 12,541 1 (thousands of oil-equivalent barrels daily) Oil-equivalent production (1) 4,395 4,074 4,018 4,216 4,175 4,553 4,152 3,960 4,293 (thousands of metric tons) Chemical prime product sales 5,910 5,831 6,245 6,077 24,063 6,337 5,972 5,947 5,901 2 Summarized financial data Sales and other operating (millions of dollars) revenue (2)(3) 103,378 103,050 108,390 106,018 420,836 118,961 112,398 110,989 109,161 45 Gross profit (4) 30,083 28,689 30,300 29,901 118,973 35,672 32,715 33,209 31,969 13 Net income attributable to ExxonMobil 9,500 6,860 7,870 8,350 32,580 9,450 15,910 9,570 9,950 4 Per share data (dollars per share) Earnings per common share (5) 2.12 1.55 1.79 1.91 7.37 2.00 3.41 2.09 2.20 Earnings per common share – assuming dilution (5) 2.12 1.55 1.79 1.91 7.37 2.00 3.41 2.09 2.20 Dividends per common share 0.57 0.63 0.63 0.63 2.46 0.47 0.57 0.57 0.57 Common stock prices High 91.93 93.50 95.49 101.74 101.74 87.94 87.67 92.57 93.67 Low 86.59 85.02 85.61 84.79 84.79 83.19 77.13 82.83 84.70

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

(2) Prior periods’ data has been reclassified in certain cases to conform to the 2013 presentation basis.

(3) Includes amounts for sales-based taxes.

(4) Gross profit equals sales and other operating revenue less estimated costs associated with products sold.

(5) Computed using the average number of shares outstanding during each period. The sum of the four quarters may not add to the full year.

  The price range of ExxonMobil common stock is as reported on the composite tape of the several U.S. exchanges where ExxonMobil common st traded. The principal market where ExxonMobil common stock (XOM) is traded is the New York Stock Exchange, although the stock is traded on exchanges in and outside the United States.

There were 450,634 registered shareholders of ExxonMobil common stock at December 31, 2013. At January 31, 2014, the registered sharehold ExxonMobil common stock numbered 449,312.

On January 29, 2014, the Corporation declared a $0.63 dividend per common share, payable March 10, 2014.

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

FUNCTIONAL EARNINGS 2013 2012 20 (millions of dollars, except per share amounts) Earnings (U.S. GAAP) Upstream United States 4,191 3,925 Non-U.S. 22,650 25,970 2 Downstream United States 2,199 3,575 Non-U.S. 1,250 9,615 Chemical United States 2,755 2,220 Non-U.S. 1,073 1,678 Corporate and financing (1,538) (2,103) ( Net income attributable to ExxonMobil (U.S. GAAP) 32,580 44,880 4 Earnings per common share 7.37 9.70 Earnings per common share – assuming dilution 7.37 9.70   References in this discussion to total corporate earnings mean net income attributable to ExxonMobil (U.S. GAAP) from the consolidated income state Unless otherwise indicated, references to earnings, Upstream, Downstream, Chemical and Corporate and Financing segment earnings, and earning share are ExxonMobil’s share after excluding amounts attributable to noncontrolling interests.

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  MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS FORWARD-LOOKING STATEMENTS

Statements in this discussion regarding expectations, plans and future events or conditions are forward-looking statements. Actual future results, inc demand growth and energy source mix; capacity increases; production growth and mix; rates of field decline; financing sources; the resoluti contingencies and uncertain tax positions; environmental and capital expenditures; could differ materially depending on a number of factors, such as ch in the supply of and demand for crude oil, natural gas, and petroleum and petrochemical products; the outcome of commercial negotiations; politi regulatory events, and other factors discussed herein and in Item 1A. Risk Factors.

The term “project” as used in this report can refer to a variety of different activities and does not necessarily have the same meaning as in any gover payment transparency reports.

  OVERVIEW

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

ExxonMobil, with its resource base, financial strength, disciplined investment approach and technology portfolio, is well-positioned to particip substantial investments to develop new energy supplies. While commodity prices are volatile on a short-term basis and depend on supply and de ExxonMobil’s investment decisions are based on our long-term business outlook, using a disciplined approach in selecting and pursuing the most attr investment opportunities. The corporate plan is a fundamental annual management process that is the basis for setting near-term operating and c objectives in addition to providing the longer-term economic assumptions used for investment evaluation purposes. Volumes are based on individua production profiles, which are also updated annually. Price ranges for crude oil, natural gas, refined products, and chemical products are based on cor plan assumptions developed annually by major region and are utilized for investment evaluation purposes. Potential investment opportunities are teste a wide range of economic scenarios to establish the resiliency of each opportunity. Once investments are made, a reappraisal process is completed to e relevant lessons are learned and improvements are incorporated into future projects.

  BUSINESS ENVIRONMENT AND RISK ASSESSMENT

Long-Term Business Outlook

By 2040, the world’s population is projected to grow to approximately 8.8 billion people, or close to 2 billion more than in 2010. Coincident wit population increase, the Corporation expects worldwide economic growth to average close to 3 percent per year. As economies and populations grow, living standards improve for billions of people, the need for energy will continue to rise. Even with significant efficiency gains, global energy dem projected to rise by about 35 percent from 2010 to 2040. This demand increase is expected to be concentrated in developing countries (i.e., those that a member nations of the Organisation for Economic Co-operation and Development).

As expanding prosperity drives global energy demand higher, increasing use of energy-efficient and lower-emission fuels, technologies and practice continue to help significantly reduce energy consumption and emissions per unit of economic output over time. Substantial efficiency gains are likely key aspects of the world’s economy through 2040, affecting energy requirements for transportation, power generation, industrial applications, and resid and commercial needs.

Energy for transportation – including cars, trucks, ships, trains and airplanes – is expected to increase by about 40 percent from 2010 to 2040. The growth in transportation demand is likely to account for approximately 70 percent of the growth in liquid fuels demand over this period. Nearly a world’s transportation fleets will continue to run on liquid fuels because they are abundant, widely available, easy to transport, and provide a large quan energy in small volumes.

Demand for electricity around the world is likely to increase approximately 90 percent by 2040, led by growth in developing countries. Consisten this projection, power generation is expected to remain the largest and fastest-growing major segment of global energy demand. Meeting the expected g in power demand will require a diverse set of energy sources. Natural gas demand is likely to grow most significantly and become the leading sou generated electricity by 2040, reflecting the efficiency of gas-fired power plants. Today, coal has the largest fuel share in the power sector, but its sh likely to decline significantly by 2040 as policies are gradually adopted to reduce environmental impacts including those related to local air qualit greenhouse gas emissions. Nuclear power and renewables, led by hydropower and wind, are also expected to grow significantly over the period.

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

Liquid fuels provide the largest share of global energy supplies today due to their broad-based availability, affordability and ease of transpor distribution and storage to meet consumer needs. By 2040, global demand for liquid fuels is expected to grow to approximately 112 million barr oil‑equivalent per day, an increase of about 25 percent from 2010. This demand will be met by a wide variety of sources. Globally, conventional production will likely decline slightly through 2040. However, this decline is expected to be more than offset by rising production from a wide vari emerging supply sources – including tight oil, deepwater, oil sands, natural gas liquids and biofuels. The world’s resource base is sufficient to meet pro demand through 2040 as technology advances continue to expand the availability of economic supply options. However, access to resources and investments will remain critical to meeting global needs with reliable, affordable supplies.

Natural gas is a versatile fuel, suitable for a wide variety of applications, and is expected to be the fastest growing major fuel source through 2040. G demand is expected to rise about 65 percent from 2010 to 2040, with demand likely to increase in all major regions of the world. Helping meet these will be significant growth in supplies of unconventional gas – the natural gas found in shale and other rock formations that was once considered uneco to produce. About 65 percent of the growth in natural gas supplies is expected to be from unconventional sources, which will account for about one-th global gas supplies by 2040. Growing natural gas demand will also stimulate significant growth in the worldwide liquefied natural gas (LNG) market, is expected to reach about 15 percent of global gas demand by 2040.

The world’s energy mix is highly diverse and will remain so through 2040. Oil is expected to remain the largest source of energy with its share rem close to one-third in 2040. Coal is currently the second largest source of energy, but it is likely to lose that position to natural gas by approximately The share of natural gas is expected to exceed 25 percent by 2040, while the share of coal falls to less than 20 percent. Nuclear power is projected to significantly, albeit at a slower pace than otherwise expected in the aftermath of the Fukushima incident in Japan following the earthquake and tsuna March 2011. Total renewable energy is likely to reach close to 15 percent of total energy by 2040, with biomass, hydro and geothermal contribu combined share of about 11 percent. Total energy supplied from wind, solar and biofuels is expected to increase close to 450 percent from 2010 to reaching a combined share of about 4 percent of world energy.

The Corporation anticipates that the world’s available oil and gas resource base will grow not only from new discoveries, but also from reserve inc in previously discovered fields. Technology will underpin these increases. The cost to develop and supply these resources will be significant. Accord the International Energy Agency, the investment required to meet total oil and gas energy needs worldwide over the period 2012‑2035 will be cl $19 trillion (measured in 2011 dollars) or close to $800 billion per year on average.

International accords and underlying regional and national regulations covering greenhouse gas emissions are evolving with uncertain timin outcome, making it difficult to predict their business impact. ExxonMobil includes estimates of potential costs related to possible public policies co energy-related greenhouse gas emissions in its long-term Outlook for Energy, which is used for assessing the business environment and in its inves evaluations.

The information provided in the Long-Term Business Outlook includes ExxonMobil’s internal estimates and forecasts based upon internal dat analyses as well as publicly available information from external sources including the International Energy Agency.

  Upstream

ExxonMobil continues to maintain a diverse portfolio of exploration and development opportunities, which enables the Corporation to be sele maximizing shareholder value and mitigating political and technical risks. ExxonMobil’s fundamental Upstream business strategies guide our exploration, development, production, and gas and power marketing activities. These strategies include identifying and selectively capturing the h quality opportunities, exercising a disciplined approach to investing and cost management, developing and applying high-impact technologies, maxim the profitability of existing oil and gas production, and capitalizing on growing natural gas and power markets. These strategies are underpinned relentless focus on operational excellence, commitment to innovative technologies, development of our employees, and investment in the communities which we operate.

As future development projects and drilling activities bring new production online, the Corporation expects a shift in the geographic mix of its prod volumes between now and 2018. Oil equivalent production from North America is expected to increase over the next five years based on current c activity plans. Currently, this growth area accounts for 32 percent of the Corporation’s production. By 2018, it is expected to generate about 35 perc total volumes. The remainder of the Corporation’s production is expected to include contributions from both established operations and new projects a the globe.

In addition to an evolving geographic mix, we expect there will also be continued change in the type of opportunities from which volumes are prod Production from diverse resource types utilizing specialized technologies such as arctic technology, deepwater drilling and production systems, heavy o oil sands recovery processes, unconventional gas and oil production and

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  MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS LNG is expected to grow from about 45 percent to around 55 percent of the Corporation’s output between now and 2018. We do not anticipate th expected change in the geographic mix of production volumes, and in the types of opportunities from which volumes will be produced, will have a m impact on the nature and the extent of the risks disclosed in Item 1A. Risk Factors, or result in a material change in our level of unit operating expense Corporation’s overall volume capacity outlook, based on projects coming onstream as anticipated, is for production capacity to grow over the 2014‑2018. However, actual volumes will vary from year to year due to the timing of individual project start-ups and other capital activities, opera outages, reservoir performance, performance of enhanced oil recovery projects, regulatory changes, asset sales, weather events, price effects production sharing contracts and other factors described in Item 1A. Risk Factors. Enhanced oil recovery projects extract hydrocarbons from reservo excess of that which may be produced through primary recovery, i.e., through pressure depletion or natural aquifer support. They include the inject water, gases or chemicals into a reservoir to produce hydrocarbons otherwise unobtainable.

  Downstream

ExxonMobil’s Downstream is a large, diversified business with refining, logistics, and marketing complexes around the world. The Corporation presence in mature markets in North America and Europe, as well as in the growing Asia Pacific region. ExxonMobil’s fundamental Downstream bu strategies position the company to deliver long-term growth in shareholder value that is superior to competition across a range of market conditions. strategies include maintaining best‑in‑class operations in all aspects of the business, maximizing value from leading-edge technologies, capitalizi integration across ExxonMobil businesses, selectively investing for resilient, advantaged returns, leading the industry in efficiency and effectivenes providing quality, valued products and services to customers.

ExxonMobil has an ownership interest in 31 refineries, located in 17 countries, with distillation capacity of 5.3 million barrels per day and lub basestock manufacturing capacity of 126 thousand barrels per day. ExxonMobil’s fuels and lubes marketing businesses have significant global reach multiple channels to market serving a diverse customer base. Our portfolio of world-renowned brands includes Exxon, Mobil, Esso and Mobil 1.

The downstream industry environment remains challenging. Demand weakness and overcapacity in the refining sector will continue to put pressu margins. In the near term, we see variability in refining margins, with some regions seeing stronger margins as refineries rationalize. In North Am lower raw material and energy cost driven by increasing crude oil and natural gas production has strengthened refining margins in several areas.

Refining margins are largely driven by differences in commodity prices and are a function of the difference between what a refinery pays for i materials (primarily crude oil) and the market prices for the range of products produced (primarily gasoline, heating oil, diesel oil, jet fuel and fuel oil). oil and many products are widely traded with published prices, including those quoted on multiple exchanges around the world (e.g., New York Merc Exchange and Intercontinental Exchange). Prices for these commodities are determined by the global marketplace and are influenced by many fa including global and regional supply/demand balances, inventory levels, industry refinery operations, import/export balances, currency fluctuations, se demand, weather and political climate.

ExxonMobil’s long‑term outlook is that industry refining margins will remain weak as competition remains intense and, in the near term, new ca additions outpace the growth in global demand. Additionally, as described in more detail in Item 1A. Risk Factors, proposed carbon policy and other cl related regulations in many countries, as well as the continued growth in biofuels mandates, could have negative impacts on the refining bus ExxonMobil’s integration across the value chain, from refining to marketing, enhances overall value in both fuels and lubricants businesses.

In the retail fuels marketing business, competition has caused inflation-adjusted margins to decline. In 2013, ExxonMobil completed the prev announced transition of the direct served (i.e., dealer, company-operated) retail network in the U.S. to a more capital-efficient branded distributor mod progressed this same model in portions of Europe. ExxonMobil is increasing investment in its fuels brands and developing multiple programs tha enhance the value of its consumer retail offer. The company’s lubricants business continues to grow, leveraging world-class brands and integration industry-leading basestock refining capability. ExxonMobil remains the market leader in the high‑value synthetic lubricants sector where competit increasing.

The Downstream portfolio is continually evaluated during all parts of the business cycle, and numerous asset divestments have been made over th decade. When investing in the Downstream, ExxonMobil remains focused on selective and resilient projects. These investments capitalize o Corporation’s world-class scale and integration, industry leading efficiency, leading-edge technology and respected brands, enabling ExxonMobil t advantage of attractive emerging growth opportunities around the globe. In 2013, the company completed a hydrotreater project at the Singapore refin produce ultra‑low sulfur diesel, and a cogeneration project at the Augusta, Italy refinery to improve energy efficiency. Additionally, construction of a sulfur fuels facility at the joint Saudi Aramco and ExxonMobil SAMREF Refinery in Yanbu, Saudi Arabia is nearly complete. The company i expanding lubricant basestock manufacturing capacity at refineries in Baytown,

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  MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Texas and Singapore, and expanding lube oil blending plants in China, Finland, and the U.S. to support future demand growth for finished lubricants markets.

  Chemical

Worldwide petrochemical demand grew in 2013, led by growing demand from Asia manufacturers and consumers. North America continued to benefi abundant supplies of natural gas and gas liquids, providing both low-cost feedstock and energy savings. Specialty product margins declined refl significant new industry capacity following several years of tight supplies.

ExxonMobil sustained its competitive advantage through continued operational excellence, investment and cost discipline, a balanced portfo products, integration with refining and upstream operations, all underpinned by proprietary technology.

In 2013 ExxonMobil started up the Singapore Chemical Expansion Project, more than doubling steam‑cracking capacity at the site and signifi increasing premium and specialty products capacity. Singapore is now ExxonMobil’s largest integrated petrochemical complex.

REVIEW OF 2013 AND 2012 RESULTS 2013 2012 20 (millions of dollars) Earnings (U.S. GAAP) 32,580 44,880 4

2013

Earnings in 2013 of $32,580 million decreased $12,300 million from 2012.

2012

Earnings in 2012 of $44,880 million increased $3,820 million from 2011. Upstream 2013 2012 20 (millions of dollars) Upstream United States 4,191 3,925 Non-U.S. 22,650 25,970 2 Total 26,841 29,895 3

  2013

Upstream earnings were $26,841 million, down $3,054 million from 2012. Higher gas realizations, partially offset by lower liquids realizations, inc earnings by $390 million. Production volume and mix effects decreased earnings by $910 million. All other items, including lower net gains from sales, mainly in Angola, and higher expenses, reduced earnings by $2.5 billion. On an oil‑equivalent basis, production was down 1.5 percent compa 2012. Excluding the impacts of entitlement volumes, OPEC quota effects and divestments, production was essentially flat. Liquids production of 2,20 (thousands of barrels per day) increased 17 kbd compared with 2012. Excluding the impacts of entitlement volumes, OPEC quota effects and divestm liquids production was up 1.6 percent, as project ramp‑up and lower downtime were partially offset by field decline. Natural gas production of 11,836 (millions of cubic feet per day) decreased 486 mcfd from 2012. Excluding the impacts of entitlement volumes and divestments, natural gas productio down 1.5 percent, as field decline was partially offset by higher demand, lower downtime, and project ramp‑up. Earnings from U.S. Upstream operatio 2013 were $4,191 million, up $266 million from 2012. Earnings outside the U.S. were $22,650 million, down $3,320 million from the prior year.

2012

Upstream earnings were $29,895 million, down $4,544 million from 2011. Lower liquids realizations, partly offset by improved natural gas realiza decreased earnings by about $100 million. Production volume and mix effects decreased earnings by $2.3 billion. All other items, including operating expenses, unfavorable tax items, lower gains on asset sales, and unfavorable foreign exchange effects, reduced earnings by $2.1 billion. oil‑equivalent basis, production was down 5.9 percent compared to 2011. Excluding the impacts of entitlement volumes, OPEC quota effect divestments, production was down 1.7 percent. Liquids production of 2,185 kbd decreased 127 kbd from 2011. Excluding the impacts of entitlement

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  MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS volumes, OPEC quota effects and divestments, liquids production was down 1.6 percent, as field decline was partly offset by project ramp‑up in West and lower downtime. Natural gas production of 12,322 mcfd decreased 840 mcfd from 2011. Excluding the impacts of entitlement volume divestments, natural gas production was down 1.9 percent, as field decline was partially offset by higher demand and lower downtime. Earnings from Upstream operations for 2012 were $3,925 million, down $1,171 million from 2011. Earnings outside the U.S. were $25,970 million, down $3,373 mil

Upstream additional information

2013 2012 20

(thousands of barrels daily)

Volumes Reconciliation (Oil-equivalent production)(1)

Prior year 4,239 4,506 4 Entitlements - Net Interest (38) (129) Entitlements - Price / Spend (9) (10) ( Quotas 3 9 Divestments (26) (61) Net growth 6 (76) Current Year 4,175 4,239 4 (1) Gas converted to oil-equivalent at 6 million cubic feet = 1 thousand barrels.

Listed below are descriptions of ExxonMobil’s entitlement volume effects. These descriptions are provided to facilitate understanding of the terms.

Production Sharing Contract (PSC) Net Interest Reductions are contractual reductions in ExxonMobil’s share of production volumes covered by These reductions typically occur when cumulative investment returns or production volumes achieve thresholds as specified in the PSCs. Once a net in reduction has occurred, it typically will not be reversed by subsequent events, such as lower crude oil prices.

Price and Spend Impacts on Volumes are fluctuations in ExxonMobil’s share of production volumes caused by changes in oil and gas prices or spe levels from one period to another. For example, at higher prices, fewer barrels are required for ExxonMobil to recover its costs. According to the ter contractual arrangements or government royalty regimes, price or spending variability can increase or decrease royalty burdens and/or volumes attributa ExxonMobil. These effects generally vary from period to period with field spending patterns or market prices for crude oil or natural gas.

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  MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Downstream 2013 2012 20 (millions of dollars) Downstream United States 2,199 3,575 Non-U.S. 1,250 9,615 Total 3,449 13,190

  2013

Downstream earnings of $3,449 million decreased $9,741 million from 2012 driven by the absence of the $5.3 billion gain associated with the restructuring. Lower margins, mainly refining, decreased earnings by $2.9 billion. Volume and mix effects decreased earnings by $310 million. All items, including higher operating expenses, unfavorable foreign exchange impacts, and lower divestments, decreased earnings by $1.2 billion. Petr product sales of 5,887 kbd decreased 287 kbd from 2012. U.S. Downstream earnings were $2,199 million, down $1,376 million from 2012. Non Downstream earnings were $1,250 million, a decrease of $8,365 million from the prior year.

2012

Downstream earnings of $13,190 million increased $8,731 million from 2011. Stronger refining-driven margins increased earnings by $2.6 billion, volume and mix effects increased earnings by about $200 million. All other items increased earnings by $5.9 billion due primarily to the $5.3 billio associated with the Japan restructuring and other divestment gains. Petroleum product sales of 6,174 kbd decreased 239 kbd from 2011 due mainly Japan restructuring and divestments. U.S. Downstream earnings were $3,575 million, up $1,307 million from 2011. Non-U.S. Downstream earnings $9,615 million, an increase of $7,424 million from 2011.

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  MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Chemical

2013 2012 20 (millions of dollars)

Chemical United States 2,755 2,220 Non-U.S. 1,073 1,678 Total 3,828 3,898

  2013

Chemical earnings of $3,828 million were $70 million lower than 2012. The absence of the gain associated with the Japan restructuring decreased ea by $630 million. Higher margins increased earnings by $480 million, while volume and mix effects increased earnings by $80 million. Prime produc of 24,063 kt (thousands of metric tons) were down 94 kt from 2012. U.S. Chemical earnings were $2,755 million, up $535 million from 2012. Non Chemical earnings were $1,073 million, $605 million lower than the prior year.

2012

Chemical earnings of $3,898 million were $485 million lower than 2011. Margins decreased earnings by $440 million, while volume effects lo earnings by $100 million. All other items increased earnings by $50 million, as a $630 million gain associated with the Japan restructuring and favorab impacts were mostly offset by unfavorable foreign exchange effects and higher operating expenses. Prime product sales of 24,157 kt were down 849 k 2011. U.S. Chemical earnings were $2,220 million, up $5 million from 2011. Non-U.S. Chemical earnings were $1,678 million, $490 million lowe 2011.

Corporate and Financing

2013 2012 20 (millions of dollars) Corporate and financing (1,538) (2,103) (   2013

Corporate and financing expenses were $1,538 million, down $565 million from 2012, as favorable tax impacts were partially offset by the absence Japan restructuring gain.

2012

Corporate and financing expenses were $2,103 million, down $118 million from 2011.

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  MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS LIQUIDITY AND CAPITAL RESOURCES Sources and Uses of Cash 2013 2012 20 (millions of dollars) Net cash provided by/(used in) Operating activities 44,914 56,170 5 Investing activities (34,201) (25,601) (2 Financing activities (15,476) (33,868) (2 Effect of exchange rate changes (175) 217 Increase/(decrease) in cash and cash equivalents (4,938) (3,082)

(December 31) Cash and cash equivalents 4,644 9,582 1 Cash and cash equivalents - restricted 269 341 Total cash and cash equivalents 4,913 9,923 1

  Total cash and cash equivalents were $4.9 billion at the end of 2013, $5.0 billion lower than the prior year. The major sources of funds in 2013 we income including noncontrolling interests of $33.4 billion, the adjustment for the noncash provision of $17.2 billion for depreciation and depletion, and debt increase of $11.6 billion. The major uses of funds included spending for additions to property, plant and equipment of $33.7 billion, the purch shares of ExxonMobil stock of $16.0 billion, dividends to shareholders of $10.9 billion and a change in working capital, excluding cash and debt, o billion. Included in total cash and cash equivalents at year-end 2013 was $0.3 billion of restricted cash.

Total cash and cash equivalents were $9.9 billion at the end of 2012, $3.1 billion lower than the prior year. Higher earnings and a higher adjustme noncash transactions were more than offset by lower proceeds from sales of subsidiaries and property, plant and equipment, a net debt decrease compa a prior year debt increase, and a higher adjustment for net gains on asset sales. Included in total cash and cash equivalents at year-end 2012 was $0.3 b of restricted cash. For additional details, see the Consolidated Statement of Cash Flows.

The Corporation has access to significant capacity of long-term and short-term liquidity. Internally generated funds are expected to cover the majo financial requirements, and may be supplemented by long-term and short-term debt, including a revolving commercial paper program. The Corporatio committed lines of credit of $6.5 billion which were unused as of December 31, 2013. Cash that may be temporarily available as surplus to the Corpora immediate needs is carefully managed through counterparty quality and investment guidelines to ensure it is secure and readily available to me Corporation’s cash requirements and to optimize returns.

To support cash flows in future periods the Corporation will need to continually find and develop new fields, and continue to develop and appl technologies and recovery processes to existing fields, in order to maintain or increase production. After a period of production at plateau rates, it nature of oil and gas fields eventually to produce at declining rates for the remainder of their economic life. Averaged over all the Corporation’s existi and gas fields and without new projects, ExxonMobil’s production is expected to decline at an average of approximately 3 percent per year over the ne years. Decline rates can vary widely by individual field due to a number of factors, including, but not limited to, the type of reservoir, fluid prop recovery mechanisms, work activity, and age of the field. Furthermore, the Corporation’s net interest in production for individual fields can vary with and contractual terms.

The Corporation has long been successful at offsetting the effects of natural field decline through disciplined investments in quality opportunitie project execution. Over the last decade, this has resulted in net annual additions to proved reserves that have exceeded the amount produced. Projects progress or planned to increase production capacity. However, these volume increases are subject to a variety of risks including project start-up t operational outages, reservoir performance, crude oil and natural gas prices, weather events, and regulatory changes. The Corporation’s cash flows ar highly dependent on crude oil and natural gas prices. Please refer to Item 1A. Risk Factors for a more complete discussion of risks.

The Corporation’s financial strength enables it to make large, long-term capital expenditures. Capital and exploration expenditures in 2013 were billion, reflecting the Corporation’s continued active investment program. The Corporation anticipates an average investment profile of about $37 billi year for the next several years. Actual spending could vary depending on the progress of individual projects and property acquisitions. The Corporation large and diverse portfolio of development projects and exploration opportunities, which helps mitigate the overall political and technical risks Corporation’s Upstream segment and associated cash flow. Further, due to its financial strength, debt capacity and diverse portfolio of opportunities, th associated with failure or delay of any single project would not have a significant impact on the

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  MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Corporation’s liquidity or ability to generate sufficient cash flows for operations and its fixed commitments. The purchase and sale of oil and gas prop have not had a significant impact on the amount or timing of cash flows from operating activities.

Cash Flow from Operating Activities 2013

Cash provided by operating activities totaled $44.9 billion in 2013, $11.3 billion lower than 2012. The major source of funds was net income inc noncontrolling interests of $33.4 billion, a decrease of $14.2 billion. The noncash provision of $17.2 billion for depreciation and depletion was highe 2012. The adjustment for net gains on asset sales was $1.8 billion compared to an adjustment of $13.0 billion in 2012. Changes in operational wo capital, excluding cash and debt, decreased cash in 2013 by $4.7 billion.

2012

Cash provided by operating activities totaled $56.2 billion in 2012, $0.8 billion higher than 2011. The major source of funds was net income inc noncontrolling interests of $47.7 billion, an increase of $5.5 billion. The noncash provision of $15.9 billion for depreciation and depletion was sl higher than 2011. The adjustments for other noncash transactions and changes in operational working capital, excluding cash and debt, both increase in 2012, while the adjustment for net gains on asset sales decreased cash by $13.0 billion in 2012.   Cash Flow from Investing Activities 2013

Cash used in investment activities netted to $34.2 billion in 2013, $8.6 billion higher than 2012. Spending for property, plant and equipment of $33.7 b decreased $0.6 billion from 2012. Proceeds associated with sales of subsidiaries, property, plant and equipment, and sales and returns of investments o billion compared to $7.7 billion in 2012. Additional investments and advances were $3.8 billion higher in 2013.

2012

Cash used in investment activities netted to $25.6 billion in 2012, $3.4 billion higher than 2011. Spending for property, plant and equipment of $34.3 b increased $3.3 billion from 2011. Proceeds associated with sales of subsidiaries, property, plant and equipment, and sales and returns of investments o billion compared to $11.1 billion in 2011. The decrease reflects that a $3.6 billion deposit was received in 2011 for a sale that closed in 2012. Add investments and advances were $3.0 billion lower in 2012.

  Cash Flow from Financing Activities 2013

Cash used in financing activities was $15.5 billion in 2013, $18.4 billion lower than 2012. Dividend payments on common shares increased to $2.4 share from $2.18 per share and totaled $10.9 billion, a pay-out of 33 percent of net income. Total debt increased $11.1 billion to $22.7 billion at year-en

ExxonMobil share of equity increased $8.1 billion to $174.0 billion. The addition to equity for earnings of $32.6 billion was partially offset by redu for distributions to ExxonMobil shareholders of $10.9 billion of dividends and $15.0 billion of purchases of shares of ExxonMobil stock to reduce outstanding.

During 2013, Exxon Mobil Corporation purchased 177 million shares of its common stock for the treasury at a gross cost of $16.0 billion. purchases were to reduce the number of shares outstanding and to offset shares issued in conjunction with company benefit plans and programs. S outstanding were reduced by 3.7 percent from 4,502 million to 4,335 million at the end of 2013. Purchases were made in both the open market and th negotiated transactions. Purchases may be increased, decreased or discontinued at any time without prior notice.

2012

Cash used in financing activities was $33.9 billion in 2012, $5.6 billion higher than 2011. Dividend payments on common shares increased to $2.18 per from $1.85 per share and totaled $10.1 billion, a pay-out of 22 percent of net income. Total debt decreased $5.5 billion to $11.6 billion at year-end.

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

ExxonMobil share of equity increased $11.5 billion to $165.9 billion. The addition to equity for earnings of $44.9 billion was partially offset by redu for distributions to ExxonMobil shareholders of $10.1 billion of dividends and $20.0 billion of purchases of shares of ExxonMobil stock to reduce outstanding.

During 2012, Exxon Mobil Corporation purchased 244 million shares of its common stock for the treasury at a gross cost of $21.1 billion. purchases were to reduce the number of shares outstanding and to offset shares issued in conjunction with company benefit plans and programs. S outstanding were reduced by 4.9 percent from 4,734 million to 4,502 million at the end of 2012. Purchases were made in both the open market and th negotiated transactions.

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  MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Commitments

Set forth below is information about the outstanding commitments of the Corporation’s consolidated subsidiaries at December 31, 2013. It combine from the Consolidated Balance Sheet and from individual notes to the Consolidated Financial Statements.

Payments Due by Period Note 2019 Reference 2015- and Commitments Number 2014 2018 Beyond To (millions of dollars) Long-term debt (1) 14 - 3,052 3,839 – Due in one year (2) 6 1,034 - - Asset retirement obligations (3) 9 799 3,026 9,163 1 Pension and other postretirement obligations (4) 17 2,983 4,379 14,074 2 Operating leases (5) 11 2,391 3,530 1,517 Unconditional purchase obligations (6) 16 144 629 463 Take-or-pay obligations (7) 3,060 10,893 15,657 2 Firm capital commitments (8) 19,258 9,616 885 2   This table excludes commodity purchase obligations (volumetric commitments but no fixed or minimum price) which are resold shortly after purchase, in an active, highly liquid market or under long-term, unconditional sales contracts with similar pricing terms. Examples include long-term, noncanc LNG and natural gas purchase commitments and commitments to purchase refinery products at market prices. Inclusion of such commitments would meaningful in assessing liquidity and cash flow, because these purchases will be offset in the same periods by cash received from the related transactions. The table also excludes unrecognized tax benefits totaling $7.8 billion as of December 31, 2013, because the Corporation is unable to reasonably reliable estimates of the timing of cash settlements with the respective taxing authorities. Further details on the unrecognized tax benefits c found in Note 19, Income, Sales-Based and Other Taxes.

Notes:

(1) Includes capitalized lease obligations of $375 million.

(2) The amount due in one year is included in notes and loans payable of $15,808 million.

(3) The fair value of asset retirement obligations, primarily upstream asset removal costs at the completion of field life.

(4) The amount by which the benefit obligations exceeded the fair value of fund assets for certain U.S. and non-U.S. pension and other postretirement at year end. The payments by period include expected contributions to funded pension plans in 2014 and estimated benefit payments for unfunded in all years.

(5) Minimum commitments for operating leases, shown on an undiscounted basis, cover drilling equipment, tankers, service stations and other propert

(6) Unconditional purchase obligations (UPOs) are those long-term commitments that are noncancelable or cancelable only under certain condition that third parties have used to secure financing for the facilities that will provide the contracted goods or services. The undiscounted obligati $1,236 million mainly pertain to pipeline throughput agreements and include $457 million of obligations to equity companies.

(7) Take-or-pay obligations are noncancelable, long-term commitments for goods and services other than UPOs. The undiscounted obligations of $2 million mainly pertain to pipeline, manufacturing supply and terminaling agreements.

(8) Firm commitments related to capital projects, shown on an undiscounted basis, totaled approximately $29.8 billion. These commitments were prim associated with Upstream projects outside the U.S., of which $16.3 billion was associated with projects in Canada, Australia, Africa, United Emirates and Malaysia. The Corporation expects to fund the majority of these projects with internally generated funds that may be supplemen long-term and short-term debt, including a revolving commercial paper program.

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  MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Guarantees

The Corporation and certain of its consolidated subsidiaries were contingently liable at December 31, 2013, for guarantees relating to notes, loan performance under contracts (Note 16). Where guarantees for environmental remediation and other similar matters do not include a stated cap, the am reflect management’s estimate of the maximum potential exposure. These guarantees are not reasonably likely to have a material effect on the Corpora financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources.

  Financial Strength

On December 31, 2013, the Corporation’s unused short-term committed lines of credit totaled approximately $5.9 billion (Note 6) and unused long committed lines of credit totaled approximately $0.6 billion (Note 14).

The table below shows the Corporation’s fixed-charge coverage and consolidated debt-to-capital ratios. The data demonstrate the Corpora creditworthiness.

2013 2012 Fixed-charge coverage ratio (times) 55.7 62.4 Debt to capital (percent) 11.2 6.3 Net debt to capital (percent) 9.1 1.2   Management views the Corporation’s financial strength, as evidenced by the above financial ratios and other similar measures, to be a competitive adva 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 m conditions, and enables the Corporation to take on large, long-term capital commitments in the pursuit of maximizing shareholder value.

  Litigation and Other Contingencies

As discussed in Note 16, a variety of claims have been made against ExxonMobil and certain of its consolidated subsidiaries in a number of pe lawsuits. Based on a consideration of all relevant facts and circumstances, the Corporation does not believe the ultimate outcome of any currently pe lawsuit against ExxonMobil will have a material adverse effect upon the Corporation’s operations, financial condition, or financial statements take whole. There are no events or uncertainties beyond those already included in reported financial information that would indicate a material change in operating results or financial condition. Refer to Note 16 for additional information on legal proceedings and other contingencies.

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  MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS CAPITAL AND EXPLORATION EXPENDITURES 2013 2012 U.S. Non-U.S. Total U.S. Non-U.S. To (millions of dollars) Upstream (1) 9,145 29,086 38,231 11,080 25,004 3 Downstream 951 1,462 2,413 634 1,628 Chemical 963 869 1,832 408 1,010 Other 13 - 13 35 - Total 11,072 31,417 42,489 12,157 27,642 3 (1) Exploration expenses included.   Capital and exploration expenditures in 2013 were $42.5 billion, including $4.3 billion for acquisitions, as the Corporation continued to pursue opportu to find and produce new supplies of oil and natural gas to meet global demand for energy. The Corporation anticipates an average investment pro about $37 billion per year for the next several years. Actual spending could vary depending on the progress of individual projects and property acquisiti

Upstream spending of $38.2 billion in 2013 was up 6 percent from 2012. Property acquisition costs in the Upstream in 2013 of $4.2 billion wer billion higher than in 2012. Investments in 2013 included projects in the U.S. Gulf of Mexico and Alaska, exploration in Russia and continued progr world-class projects in Canada, Australia and Papua New Guinea. The majority of expenditures are on development projects, which typically take t four years from the time of recording proved undeveloped reserves to the start of production from those reserves. The percentage of proved deve reserves was 66 percent of total proved reserves at year-end 2013, and has been over 60 percent for the last ten years, indicating that proved reserv consistently moved from undeveloped to developed status.

Capital investments in the Downstream totaled $2.4 billion in 2013, an increase of $0.2 billion from 2012, mainly reflecting higher refining m improvement project spending. The Chemical capital expenditures of $1.8 billion increased $0.4 billion from 2012 with higher investments in the U.S., Arabia and China more than offsetting reduced spending on the completed Singapore Chemical Plant expansion.

TAXES 2013 2012 20 (millions of dollars) Income taxes 24,263 31,045 3 Effective income tax rate 48% 44% Sales-based taxes 30,589 32,409 3 All other taxes and duties 36,396 38,857 4 Total 91,248 102,311 10

  2013

Income, sales-based and all other taxes and duties totaled $91.2 billion in 2013, a decrease of $11.1 billion or 11 percent from 2012. Income tax ex both current and deferred, was $24.3 billion, $6.8 billion lower than 2012, with the impact of lower earnings partially offset by the higher effective tax The effective tax rate was 48 percent compared to 44 percent in the prior year due to the absence of favorable tax impacts on divestments. Sales-base all other taxes and duties of $67.0 billion in 2013 decreased $4.3 billion reflecting the 2012 Japan restructuring.

2012

Income, sales-based and all other taxes and duties totaled $102.3 billion in 2012, a decrease of $5.8 billion or 5 percent from 2011. Income tax expense current and deferred, was $31.0 billion, flat with 2011, with the impact of higher earnings offset by the lower effective tax rate. The effective tax rate w percent compared to 46 percent in the prior year due to a lower effective tax rate on divestments. Sales-based and all other taxes and duties of $71.3 b in 2012 decreased $5.8 billion reflecting the Japan restructuring.

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  MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS ENVIRONMENTAL MATTERS Environmental Expenditures 2013 20 (millions of dollars) Capital expenditures 2,474 Other expenditures 3,538 Total 6,012

  Throughout ExxonMobil’s businesses, new and ongoing measures are taken to prevent and minimize the impact of our operations on air, water and gr These include a significant investment in refining infrastructure and technology to manufacture clean fuels as well as projects to monitor and reduce ni oxide, sulfur oxide and greenhouse gas emissions and expenditures for asset retirement obligations. Using definitions and guidelines established b American Petroleum Institute, ExxonMobil’s 2013 worldwide environmental expenditures for all such preventative and remediation steps, inc ExxonMobil’s share of equity company expenditures, were about $6.0 billion. The total cost for such activities is expected to remain in this range in and 2015 (with capital expenditures approximately 45 percent of the total).

Environmental Liabilities

The Corporation accrues environmental liabilities when it is probable that obligations have been incurred and the amounts can be reasonably estimated policy applies to assets or businesses currently owned or previously disposed. ExxonMobil has accrued liabilities for probable environmental remed obligations at various sites, including multiparty sites where the U.S. Environmental Protection Agency has identified ExxonMobil as one of the pote responsible parties. The involvement of other financially responsible companies at these multiparty sites could mitigate ExxonMobil’s actual joint and s liability exposure. At present, no individual site is expected to have losses material to ExxonMobil’s operations or financial condition. Consolidated com provisions made in 2013 for environmental liabilities were $321 million ($391 million in 2012) and the balance sheet reflects accumulated liabilit $773 million as of December 31, 2013, and $841 million as of December 31, 2012.

  MARKET RISKS, INFLATION AND OTHER UNCERTAINTIES Worldwide Average Realizations (1) 2013 2012 Crude oil and NGL ($/barrel) 97.48 100.29 1 Natural gas ($/kcf) 4.60 3.90 (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 fluctu on earnings from Upstream, Downstream and Chemical operations have varied. In the Upstream, a $1 per barrel change in the weighted-average re price of oil would have approximately a $350 million annual after-tax effect on Upstream consolidated plus equity company earnings. Similarly, a $0. kcf change in the worldwide average gas realization would have approximately a $175 million annual after-tax effect on Upstream consolidated plus company earnings. For any given period, the extent of actual benefit or detriment will be dependent on the price movements of individual types of cru taxes and other government take impacts, price adjustment lags in long-term gas contracts, and crude and gas production volumes. Accordingly, chan benchmark prices for crude oil and natural gas only provide broad indicators 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 lev 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 for the range of products produced. These prices in turn depend on global and regional supply/demand balances, inventory levels, refinery opera import/export balances and weather.

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

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 conditions, along with the capital-intensive nature of the industry and very long lead times associated with many of our projects, underscore the impo of maintaining a strong financial position. Management views the Corporation’s financial strength 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 they are the result of efficiencies and competitive advantages of integrated refinery/chemical complexes. Additionally, intersegment sales are at market- prices. The products bought and sold between segments can also be acquired in worldwide markets that have substantial liquidity, capacity and transpor capabilities. About 35 percent of the Corporation’s intersegment sales are crude oil produced by the Upstream and sold to the Downstream. 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 action other factors, industry economics over the long term will continue to be driven by market supply and demand. Accordingly, the Corporation tests the vi of all of its investments over a broad range of future prices. The Corporation’s assessment is that its operations will continue to be successful in a vari market conditions. This is the outcome of disciplined investment and asset management programs.

The Corporation has an active asset management program in which underperforming assets are either improved to acceptable levels or consider divestment. The asset management program includes a disciplined, regular review to ensure that all assets are contributing to the Corporation’s str objectives. The result is an efficient capital base, and the Corporation has seldom had to write down the carrying value of assets, even during periods o commodity prices.

  Risk Management

The Corporation’s size, strong capital structure, geographic diversity and the complementary nature of the Upstream, Downstream and Chemical busi reduce the Corporation’s enterprise-wide risk from changes in interest rates, currency rates and commodity prices. As a result, the Corporation makes l use of derivative instruments to mitigate the impact of such changes. With respect to derivatives activities, the Corporation believes that there are no m market or credit risks to the Corporation’s financial position, results of operations or liquidity as a result of the derivatives described in Note 13 Corporation does not engage in speculative derivative activities or derivative trading activities nor does it use derivatives with leveraged features. Cred associated with the Corporation’s derivative position is mitigated by several factors, including the use of derivative clearing exchanges and the quality financial limits placed on derivative counterparties. The Corporation maintains a system of controls that includes the authorization, reporting and moni of derivative activity.

The Corporation is exposed to changes in interest rates, primarily on its short-term debt and the portion of long-term debt that carries floating in rates. 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 valu Corporation has access to significant capacity of long-term and short-term liquidity. Internally generated funds are expected to cover the majority of fin requirements, and may be supplemented by long-term and short-term debt, including a revolving commercial paper program. Some joint-venture partne dependent on the credit markets, and their funding ability may impact the development pace of joint-venture projects.

The Corporation conducts business in many foreign currencies and is subject to exchange rate risk on cash flows related to sales, expenses, financin investment transactions. The impacts of fluctuations in exchange rates on ExxonMobil’s geographically and functionally diverse operations are varie often offsetting in amount. The Corporation makes limited use of currency exchange contracts to mitigate the impact of changes in currency value exposures related to the Corporation’s limited use of the currency exchange contracts are not material.

  Inflation and Other Uncertainties

The general rate of inflation in many major countries of operation has remained moderate over the past few years, and the associated impact on non-e costs has generally been mitigated by cost reductions from efficiency and productivity improvements. Increased demand for certain services and ma has resulted in higher operating and capital costs in recent years. The Corporation works to counter upward pressure on costs through its economies of in global procurement and its efficient project management practices.

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  MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS CRITICAL ACCOUNTING ESTIMATES

The Corporation’s accounting and financial reporting fairly reflect its straightforward business model involving the extracting, refining and market hydrocarbons and hydrocarbon-based products. The preparation of financial statements in conformity with U.S. Generally Accepted Accounting Prin (GAAP) requires management to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses an disclosure of contingent assets and liabilities. The Corporation’s accounting policies are summarized in Note 1.

  Oil and Gas Reserves

Evaluations of oil and gas reserves are important to the effective management of upstream assets. They are an integral part of investment decisions abo and gas properties such as whether development should proceed. Oil and gas reserve quantities are also used as the basis to calculate unit-of-prod depreciation rates and to evaluate impairment.

Oil and gas reserves include both proved and unproved reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analy geoscience and engineering data, can be estimated with reasonable certainty to be economically producible. Unproved reserves are those with les reasonable certainty of recoverability and include probable reserves. Probable reserves are reserves that are more likely to be recovered than not.

The estimation of proved reserves is an ongoing process based on rigorous technical evaluations, commercial and market assessment, and de analysis of well information such as flow rates and reservoir pressure declines. The estimation of proved reserves is controlled by the Corporation th long-standing approval guidelines. Reserve changes are made within a well-established, disciplined process driven by senior level geoscienc engineering professionals, assisted by the Reserves Technical Oversight group which has significant technical experience, culminating in reviews wi approval by senior management. Notably, the Corporation does not use specific quantitative reserve targets to determine compensation. Key features reserve estimation process are covered in Disclosure of Reserves in Item 2.

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

Proved reserves can be further subdivided into developed and undeveloped reserves. The percentage of proved developed reserves was 66 percent o proved reserves at year-end 2013 (including both consolidated and equity company reserves), and has been over 60 percent for the last ten years, indi that proved reserves are consistently moved from undeveloped to developed status.

Revisions can include upward or downward changes in previously estimated volumes of proved reserves for existing fields due to the evaluat re-evaluation of (1) already available geologic, reservoir or production data, (2) new geologic, reservoir or production data or (3) changes in price year-end costs that are used in the estimation of reserves. Revisions can also result from significant changes in development strategy or prod equipment/facility capacity.

Impact of Oil and Gas Reserves on Depreciation. The calculation of unit-of-production depreciation is a critical accounting estimate that measur depreciation of upstream assets. It is the ratio of actual volumes produced to total proved developed reserves (those proved reserves recoverable th existing wells with existing equipment and operating methods), applied to the asset cost. The volumes produced and asset cost are known and, while p developed reserves have a high probability of recoverability, they are based on estimates that are subject to some variability. While the revisio 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 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 review impairment whenever events or circumstances indicate that the carrying amounts may not be recoverable. Assets are grouped at the lowest level for 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. Impai analyses are generally based on proved reserves. Where probable reserves exist, an appropriately risk-adjusted amount of these reserves may be inclu the impairment evaluation. An asset group would be impaired if its undiscounted cash flows were less than the asset’s carrying value. Impairmen measured by the amount by which the carrying value exceeds fair value.

Significant unproved properties are assessed for impairment individually, and valuation allowances against the capitalized costs are recorded based estimated economic chance of success and the length of time that the Corporation expects to hold the properties. Properties that are not indivi significant are aggregated by groups and amortized based on development risk and average holding period.

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

The Corporation performs asset valuation analyses on an ongoing basis as a part of its asset management program. These analyses assist the Corpo 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 cond these analyses, it is also necessary to estimate future oil and gas prices. Potential trigger events for impairment evaluation include a significant decre current and projected reserve volumes, an accumulation of project costs significantly in excess of the amount originally expected, and current operating losses combined with a history and forecast of operating or cash flow losses.

In general, the Corporation does not view temporarily low prices or margins as a trigger event for conducting the impairment tests. The markets for oil and natural gas have a history of significant price volatility. Although prices will occasionally drop significantly, industry prices over the long term continue to be driven by market supply and demand. On the supply side, industry production from mature fields is declining, but this is being off production from new discoveries and field developments. OPEC production policies also have an impact on world oil supplies. The demand side is lar function of global economic growth. The relative growth/decline in supply versus demand will determine industry prices over the long term, and these c be accurately predicted.

Accordingly, any impairment tests that the Corporation performs make use of the Corporation’s price assumptions developed in the annual plannin budgeting process for the crude oil and natural gas markets, petroleum products and chemicals. These are the same price assumptions that are used for c investment decisions. Volumes are based on field production profiles, which are updated annually. Cash flow estimates for impairment testing exclu effects of derivative instruments.

Supplemental information regarding oil and gas results of operations, capitalized costs and reserves is provided following the notes to consol financial statements. Future prices used for any impairment tests will vary from the ones used in the supplemental oil and gas disclosure and could be or higher for any given year.

Asset Retirement Obligations

The Corporation incurs retirement obligations for certain assets. The fair values of these obligations are recorded as liabilities on a discounted basis, wh typically at the time the assets are installed. In the estimation of fair value, the Corporation uses assumptions and judgments regarding such factors existence of a legal obligation for an asset retirement obligation; technical assessments of the assets; estimated amounts and timing of settlements; di rates; and inflation rates. Asset retirement obligations are disclosed in Note 9 to the financial statements.

  Suspended Exploratory Well Costs

The Corporation continues capitalization of exploratory well costs when the well has found a sufficient quantity of reserves to justify its completio producing well and the Corporation is making sufficient progress assessing the reserves and the economic and operating viability of the project. Explo well costs not meeting these criteria are charged to expense. The facts and circumstances that support continued capitalization of suspended wells at ye are disclosed in Note 10 to the financial statements.

  Consolidations

The Consolidated Financial Statements include the accounts of those subsidiaries that the Corporation controls. They also include the Corporation’s sh the undivided interest in certain upstream assets, liabilities, revenues and expenses. Amounts representing the Corporation’s interest in the underlyin assets of other significant entities that it does not control, but over which it exercises significant influence, are accounted for using the equity meth accounting.

Investments in companies that are partially owned by the Corporation are integral to the Corporation’s operations. In some cases they serve to b 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 ha equity interest in these companies are either independent third parties or host governments that share in the business results according to their ownership Corporation does not invest in these companies in order to remove liabilities from its balance sheet. In fact, the Corporation has long been on supporting an alternative accounting method that would require each investor to consolidate its share of all assets and liabilities in these partially o companies rather than only its interest in net equity. This method of accounting for investments in partially-owned companies is not permitted by U.S. G except where the investments are in the direct ownership of a share of upstream assets and liabilities. However, for purposes of calculating return on av capital employed, which is not covered by U.S. GAAP standards, the Corporation includes its share of debt of these partially-owned companies determination of average capital employed.

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  MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Pension Benefits

The Corporation and its affiliates sponsor over 100 defined benefit (pension) plans in about 50 countries. Pension and Other Postretirement Benefits 17) 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 than a separate pension fund. Book reserves are established for these plans because tax conventions and regulatory practices do not encourage ad funding. The portion of the pension cost attributable to employee service is expensed as services are rendered. The portion attributable to the incre 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 differe 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 assets.

For funded plans, including those in the U.S., pension obligations are financed in advance through segregated assets or insurance arrangements. plans are managed in compliance with the requirements of governmental authorities and meet or exceed required funding levels as measured by re actuarial and government standards at the mandated measurement dates. In determining liabilities and required contributions, these standards often r approaches and assumptions that differ from those used for accounting purposes.

The Corporation will continue to make contributions to these funded plans as necessary. All defined-benefit pension obligations, regardless of the fu 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 f benefit obligations and the long-term rate for future salary increases. Pension assumptions are reviewed annually by outside actuaries and management. These assumptions are adjusted as appropriate to reflect changes in market rates and outlook. The long-term expected earnings rate on pension plan assets in 2013 was 7.25 percent. The 10‑year and 20‑year actual returns on U.S. pension plan assets were 7 percent and 9 percent, respec The Corporation establishes the long-term expected rate of return by developing a forward-looking, long-term return assumption for each pension fund 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 calc as the weighted average of the target asset allocation percentages and the long-term return assumption for each asset class. A worldwide reduction percent in the long-term rate of return on assets would increase annual pension expense by approximately $150 million before tax.

Differences between actual returns on fund assets and the long-term expected return are not recognized in pension expense in the year that the diffe occurs. Such differences are deferred, along with other actuarial gains and losses, and are amortized into pension expense over the expected rem service life of employees.

  Litigation Contingencies

A variety of claims have been made against the Corporation and certain of its consolidated subsidiaries in a number of pending lawsuits. Manageme regular litigation reviews, including updates from corporate and outside counsel, to assess the need for accounting recognition or disclosure of contingencies. The status of significant claims is summarized in Note 16.

The Corporation accrues an undiscounted liability for those contingencies where the incurrence of a loss is probable, and the amount can be reaso estimated. These amounts are not reduced by amounts that may be recovered under insurance or claims against third parties, but undiscounted recei from insurers or other third parties may be accrued separately. The Corporation revises such accruals in light of new information. For contingencies wh unfavorable outcome is reasonably possible and which are significant, the Corporation discloses the nature of the contingency and, where feasib estimate of the possible loss. For purposes of our litigation contingency disclosures, “significant” includes material matters as well as other items management believes should be disclosed.

Management judgment is required related to contingent liabilities and the outcome of litigation because both are difficult to predict. Howeve Corporation has been successful in defending litigation in the past. Payments have not had a material adverse effect on operations or financial conditi 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 app settlement.

Tax Contingencies

The Corporation is subject to income taxation in many jurisdictions around the world. Significant management judgment is required in the accounti income tax contingencies and tax disputes because the outcomes are often difficult to predict.

The benefits of uncertain tax positions that the Corporation has taken or expects to take in its income tax returns are recognized in the financial state if management concludes that it is more likely than not that the position will be sustained

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  MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS with the tax authorities. For a position that is likely to be sustained, the benefit recognized in the financial statements is measured at the largest amount greater than 50 percent likely of being realized. A reserve is established for the difference between a position taken or expected to be taken in an incom return and the amount recognized in the financial statements. The Corporation’s unrecognized tax benefits and a description of open tax yea summarized in Note 19.

  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 G Under these principles, it is necessary to select the functional currency of these subsidiaries. The functional currency is the currency of the primary eco environment in which the subsidiary operates. Management selects the functional currency after evaluating this economic environment.

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

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  MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Management, including the Corporation’s Chief Executive Officer, Principal Financial Officer, and Principal Accounting Officer, is responsib establishing and maintaining adequate internal control over the Corporation’s financial reporting. Management conducted an evaluation of the effectiv of internal control over financial reporting based on criteria established in Internal Control – Integrated Framework (1992) issued by the Commit Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that Exxon Mobil Corporation’s internal c over financial reporting was effective as of December 31, 2013.

PricewaterhouseCoopers LLP, an independent registered public accounting firm, audited the effectiveness of the Corporation’s internal contro financial reporting as of December 31, 2013, as stated in their report included in the Financial Section of this report.

      Rex W. Tillerson Chief Executive Officer

Andrew P. Swiger Senior Vice President (Principal Financial Officer)

Patrick T. Mulva Vice President and Controller (Principal Accounting Officer)

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  REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Shareholders of Exxon Mobil Corporation:

In our opinion, the accompanying Consolidated Balance Sheets and the related Consolidated Statements of Income, Comprehensive Income, Chan Equity and Cash Flows present fairly, in all material respects, the financial position of Exxon Mobil Corporation and its subsidiaries at December 31, and 2012, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2013, in conformity accounting principles generally accepted in the United States of America. Also in our opinion, the Corporation maintained, in all material respects, eff internal control over financial reporting as of December 31, 2013, based on criteria established in Internal Control – Integrated Framework (1992) issu the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Corporation’s management is responsible for these fin statements, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over fin reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express opinio these financial statements and on the Corporation’s internal control over financial reporting based on our integrated audits. We conducted our aud accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perfor audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal contro financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporti amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and eval the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal contro financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal c based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe th audits provide 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 reportin the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal contro financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to p preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevent 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 evaluat effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of comp with the policies or procedures may deteriorate.

/s/ PricewaterhouseCoopers LLP

Dallas, Texas February 26, 2014

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  CONSOLIDATED STATEMENT OF INCOME

Note Reference Number 2013 2012 201 (millions of dollars) Revenues and other income Sales and other operating revenue (1) 420,836 451,509 46 Income from equity affiliates 7 13,927 15,010 1 Other income 3,492 14,162 Total revenues and other income 438,255 480,681 48 Costs and other deductions Crude oil and product purchases 244,156 263,535 26 Production and manufacturing expenses 40,525 38,521 4 Selling, general and administrative expenses 12,877 13,877 1 Depreciation and depletion 17,182 15,888 1 Exploration expenses, including dry holes 1,976 1,840 Interest expense 9 327 Sales-based taxes (1) 19 30,589 32,409 3 Other taxes and duties 19 33,230 35,558 3 Total costs and other deductions 380,544 401,955 41 Income before income taxes 57,711 78,726 7 Income taxes 19 24,263 31,045 3 Net income including noncontrolling interests 33,448 47,681 4 Net income attributable to noncontrolling interests 868 2,801 Net income attributable to ExxonMobil 32,580 44,880 4 Earnings per common share (dollars) 12 7.37 9.70 Earnings per common share - assuming dilution (dollars) 12 7.37 9.70  

(1) Sales and other operating revenue includes sales-based taxes of $30,589 million for 2013, $32,409 million for 2012 and $33,503 million for 2011.  

The information in the Notes to Consolidated Financial Statements is an integral part of these statements.

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  CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME

2013 2012 201 (millions of dollars) Net income including noncontrolling interests 33,448 47,681 4 Other comprehensive income (net of income taxes) Foreign exchange translation adjustment (3,620) 920 Adjustment for foreign exchange translation (gain)/loss included in net income (23) (4,352) Postretirement benefits reserves adjustment (excluding amortization) 3,174 (3,574) ( Amortization and settlement of postretirement benefits reserves adjustment included in net periodic benefit costs 1,820 2,395 Change in fair value of cash flow hedges - - Realized (gain)/loss from settled cash flow hedges included in net income - - Total other comprehensive income 1,351 (4,611) ( Comprehensive income including noncontrolling interests 34,799 43,070 3 Comprehensive income attributable to noncontrolling interests 760 1,251 Comprehensive income attributable to ExxonMobil 34,039 41,819 3

The information in the Notes to Consolidated Financial Statements is an integral part of these statements.

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  CONSOLIDATED BALANCE SHEET

Note Reference Dec. 31 Dec. 3 Number 2013 2012 (millions of dollars) Assets Current assets Cash and cash equivalents 4,644 Cash and cash equivalents - restricted 269 Notes and accounts receivable, less estimated doubtful amounts 6 33,152 3 Inventories Crude oil, products and merchandise 3 12,117 1 Materials and supplies 4,018 Other current assets 5,108 Total current assets 59,308 6 Investments, advances and long-term receivables 8 36,328 3 Property, plant and equipment, at cost, less accumulated depreciation and depletion 9 243,650 22 Other assets, including intangibles, net 7,522 Total assets 346,808 33 Liabilities Current liabilities Notes and loans payable 6 15,808 Accounts payable and accrued liabilities 6 48,085 5 Income taxes payable 7,831 Total current liabilities 71,724 6 Long-term debt 14 6,891 Postretirement benefits reserves 17 20,646 2 Deferred income tax liabilities 19 40,530 3 Long-term obligations to equity companies 4,742 Other long-term obligations 21,780 2 Total liabilities 166,313 16 Commitments and contingencies 16 Equity Common stock without par value (9,000 million shares authorized, 8,019 million shares issued) 10,077 Earnings reinvested 387,432 36 Accumulated other comprehensive income (10,725) (1 Common stock held in treasury (3,684 million shares in 2013 and 3,517 million shares in 2012) (212,781) (19 ExxonMobil share of equity 174,003 16 Noncontrolling interests 6,492 Total equity 180,495 17 Total liabilities and equity 346,808 33

The information in the Notes to Consolidated Financial Statements is an integral part of these statements.

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  CONSOLIDATED STATEMENT OF CASH FLOWS

Note Reference Number 2013 2012 2011 (millions of dollars) Cash flows from operating activities Net income including noncontrolling interests 33,448 47,681 4 Adjustments for noncash transactions Depreciation and depletion 17,182 15,888 1 Deferred income tax charges/(credits) 754 3,142 Postretirement benefits expense in excess of/(less than) net payments 2,291 (315) Other long-term obligation provisions in excess of/(less than) payments (2,566) 1,643 Dividends received greater than/(less than) equity in current earnings of equity companies 3 (1,157) Changes in operational working capital, excluding cash and debt Reduction/(increase) - Notes and accounts receivable (305) (1,082) ( - Inventories (1,812) (1,873) ( - Other current assets (105) (42) Increase/(reduction) - Accounts and other payables (2,498) 3,624 Net (gain) on asset sales 5 (1,828) (13,018) ( All other items - net 350 1,679 Net cash provided by operating activities 44,914 56,170 5 Cash flows from investing activities Additions to property, plant and equipment (33,669) (34,271) (3 Proceeds associated with sales of subsidiaries, property, plant and equipment, and sales and returns of investments 5 2,707 7,655 1 Decrease/(increase) in restricted cash and cash equivalents 72 63 Additional investments and advances (4,435) (598) ( Collection of advances 1,124 1,550 Additions to marketable securities - - ( Sales of marketable securities - - Net cash used in investing activities (34,201) (25,601) (2 Cash flows from financing activities Additions to long-term debt 345 995 Reductions in long-term debt (13) (147) Additions to short-term debt 16 958 Reductions in short-term debt (756) (4,488) ( Additions/(reductions) in debt with three months or less maturity 12,012 (226) Cash dividends to ExxonMobil shareholders (10,875) (10,092) ( Cash dividends to noncontrolling interests (304) (327) Changes in noncontrolling interests (1) 204 Tax benefits related to stock-based awards 48 130 Common stock acquired (15,998) (21,068) (2 Common stock sold 50 193 Net cash used in financing activities (15,476) (33,868) (2 Effects of exchange rate changes on cash (175) 217 Increase/(decrease) in cash and cash equivalents (4,938) (3,082) Cash and cash equivalents at beginning of year 9,582 12,664 Cash and cash equivalents at end of year 4,644 9,582 1

The information in the Notes to Consolidated Financial Statements is an integral part of these statements.

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  CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

ExxonMobil Share of Equity

Accumulated Common

Other Stock ExxonMobil Non-

Common Earnings Comprehensive Held in Share of controlling To

Stock Reinvested Income Treasury Equity Interests Eq

(millions of dollars)

Balance as of December 31, 2010 9,371 298,899 (4,823) (156,608) 146,839 5,840 1

Amortization of stock-based awards 742 - - - 742 -

Tax benefits related to stock-based awards 202 - - - 202 -

Other (803) - - - (803) (5)

Net income for the year - 41,060 - - 41,060 1,146

Dividends - common shares - (9,020) - - (9,020) (306)

Other comprehensive income - - (4,300) - (4,300) (312)

Acquisitions, at cost - - - (22,055) (22,055) (15) (

Dispositions - - - 1,731 1,731 -

Balance as of December 31, 2011 9,512 330,939 (9,123) (176,932) 154,396 6,348 1

Amortization of stock-based awards 806 - - - 806 -

Tax benefits related to stock-based awards 178 - - - 178 -

Other (843) - - - (843) (1,441)

Net income for the year - 44,880 - - 44,880 2,801

Dividends - common shares - (10,092) - - (10,092) (327) (

Other comprehensive income - - (3,061) - (3,061) (1,550)

Acquisitions, at cost - - - (21,068) (21,068) (34) (

Dispositions - - - 667 667 -

Balance as of December 31, 2012 9,653 365,727 (12,184) (197,333) 165,863 5,797 1

Amortization of stock-based awards 761 - - - 761 -

Tax benefits related to stock-based awards 162 - - - 162 -

Other (499) - - - (499) 240

Net income for the year - 32,580 - - 32,580 868

Dividends - common shares - (10,875) - - (10,875) (304) (

Other comprehensive income - - 1,459 - 1,459 (108)

Acquisitions, at cost - - - (15,998) (15,998) (1) (

Dispositions - - - 550 550 -

Balance as of December 31, 2013 10,077 387,432 (10,725) (212,781) 174,003 6,492 1

Held in Common Stock Share Activity Issued Treasury Outsta

(millions of shares)

Balance as of December 31, 2010 8,019 (3,040)

Acquisitions - (278)

Dispositions - 33

Balance as of December 31, 2011 8,019 (3,285)

Acquisitions - (244)

Dispositions - 12

Balance as of December 31, 2012 8,019 (3,517)

Acquisitions - (177)

Dispositions - 10

Balance as of December 31, 2013 8,019 (3,684)

The information in the Notes to Consolidated Financial Statements is an integral part of these statements.

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  NOTES TO CONSOLIDATED FINANCIAL STATEMENTS The accompanying consolidated financial statements and the supporting and supplemental material are the responsibility of the management of Exxon Corporation.

The Corporation’s principal business is energy, involving the worldwide exploration, production, transportation and sale of crude oil and natur (Upstream) and the manufacture, transportation and sale of petroleum products (Downstream). The Corporation is also a major worldwide manufactur 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 estimates that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. Actual r could differ from these estimates. Prior years’ data has been reclassified in certain cases to conform to the 2013 presentation basis.

  1. Summary of Accounting Policies

Principles of Consolidation. The Consolidated Financial Statements include the accounts of subsidiaries the Corporation controls. They also inclu Corporation’s share of the undivided interest in certain upstream assets, liabilities, revenues and expenses.

Amounts representing the Corporation’s interest in entities that it does not control, but over which it exercises significant influence, are includ “Investments, advances and long-term receivables.” The Corporation’s share of the net income of these companies is included in the Consolidated Stat of Income caption “Income from equity affiliates.”

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

The Corporation’s share of the cumulative foreign exchange translation adjustment for equity method investments is reported in Accumulated Comprehensive Income.

Evidence of loss in value that might indicate impairment of investments in companies accounted for on the equity method is assessed to determine i evidence represents a loss in value of the Corporation’s investment that is other than temporary. Examples of key indicators include a history of ope losses, a negative earnings and cash flow outlook, significant downward revisions to oil and gas reserves, and the financial condition and prospects f investee’s business segment or geographic region. If evidence of an other than temporary loss in fair value below carrying amount is determin 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 prev market prices. In some cases (e.g., natural gas), products may be sold under long-term agreements, with periodic price adjustments. Revenues are recog when the products are delivered, which occurs when the customer has taken title and has assumed the risks and rewards of ownership, prices are fix determinable and collectibility is reasonably assured.

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

Purchases and sales of inventory with the same counterparty that are entered into in contemplation of one another are combined and record exchanges measured at the book value of the item sold.

Sales-Based Taxes. The Corporation reports sales, excise and value-added taxes on sales transactions on a gross basis in the Consolidated Statem Income (included in both revenues and costs).

Derivative Instruments. The Corporation makes limited use of derivative instruments. The Corporation does not engage in speculative derivative act or derivative trading activities, nor does it use derivatives with leveraged features. When the Corporation does enter into derivative transactions, it is to exposures associated with interest rates, foreign currency exchange rates and hydrocarbon prices that arise from existing assets, liabilities and fore transactions.

The gains and losses resulting from changes in the fair value of derivatives are recorded in income. In some cases, the Corporation designates deriv as fair value hedges, in which case the gains and losses are offset in income by the gains and losses arising from changes in the fair value of the unde hedged item.

Fair Value. Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market partici Hierarchy Levels 1, 2 and 3 are terms for the priority of inputs to valuation techniques used to measure fair value. Hierarchy Level 1 inputs are quoted in active markets for identical assets or liabilities. Hierarchy

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  NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Level 2 inputs are inputs other than quoted prices included within Level 1 that are directly or indirectly observable for the asset or liability. Hierarchy L

inputs are inputs that are not observable in the market.

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

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

Interest costs incurred to finance expenditures during the construction phase of multiyear projects are capitalized as part of the historical cost of acq the constructed assets. The project construction phase commences with the development of the detailed engineering design and ends when the const assets are ready for their intended use. Capitalized interest costs are included in property, plant and equipment and are depreciated over the service life related assets.

The Corporation uses the “successful efforts” method to account for its exploration and production activities. Under this method, costs are accumula a field-by-field basis with certain exploratory expenditures and exploratory dry holes being expensed as incurred. Costs of productive wells and develo dry holes are capitalized and amortized on the unit-of-production method.

The Corporation carries as an asset exploratory well costs when the well has found a sufficient quantity of reserves to justify its completion as a prod well and where the Corporation is making sufficient progress assessing the reserves and the economic and operating viability of the project. Explorator costs not meeting these criteria are charged to expense. Other exploratory expenditures, including geophysical costs and annual lease rentals, are expen incurred.

Acquisition costs of proved properties are amortized using a unit-of-production method, computed on the basis of total proved oil and gas reserves.

Capitalized exploratory drilling and development costs associated with productive depletable extractive properties are amortized using unit-of-prod rates based on the amount of proved developed reserves of oil, gas and other minerals that are estimated to be recoverable from existing facilities current operating methods.

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

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

Proved oil and gas properties held and used by the Corporation are reviewed for impairment whenever events or changes in circumstances indicate th carrying amounts may not be recoverable. Assets are grouped at the lowest level for which there are identifiable cash flows that are largely independ 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 flow in impairment evaluations are developed using annually updated corporate plan investment evaluation assumptions for crude oil commodity prices, re and chemical margins and foreign currency exchange rates. Annual volumes are based on field production profiles, which are also updated annually. for natural gas and other products are based on corporate plan assumptions developed annually by major region and also for investment evaluation pur 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 reserve be included in the impairment evaluation. An asset group would be impaired if the undiscounted cash flows were less than its carrying value. Impair are measured by the amount the carrying value exceeds fair value.

Significant unproved properties are assessed for impairment individually, and valuation allowances against the capitalized costs are recorded based estimated economic chance of success and the length of time that the Corporation expects to hold the properties. Properties that are not indivi significant are aggregated by groups and amortized based on development risk and average holding period. The valuation allowances are reviewed a annually.

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  NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Gains on sales of proved and unproved properties are only recognized when there is neither uncertainty about the recovery of costs applicable t interest retained nor any 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 ca value.

Asset Retirement Obligations and Environmental Liabilities. The Corporation incurs retirement obligations for certain assets. The fair values of obligations are recorded as liabilities on a discounted basis, which is typically at the time the assets are installed. The costs associated with these liabilit capitalized as part of the related assets and depreciated. Over time, the liabilities are accreted for the change in their present value.

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

Foreign Currency Translation. The Corporation selects the functional reporting currency for its international subsidiaries based on the currency primary economic environment in which each subsidiary operates.

Downstream and Chemical operations primarily use the local currency. However, the U.S. dollar is used in countries with a history of high inf (primarily in Latin America) and Singapore, which predominantly sells into the U.S. dollar export market. Upstream operations which are rela self-contained and integrated within a particular country, such as Canada, the United Kingdom, Norway and continental Europe, use the local currency. Upstream operations, primarily in Asia and Africa, use the U.S. dollar because they predominantly sell crude and natural gas production into U.S. d denominated markets.

For all operations, gains or losses from remeasuring foreign currency transactions into the functional currency are included in income.

Stock-Based Payments. The Corporation awards stock-based compensation to employees in the form of restricted stock and restricted stock Compensation expense is measured by the price of the stock at the date of grant and is recognized in income over the requisite service period. See No Incentive Program, for further details.

  2. Accounting Changes

The Corporation did not adopt authoritative guidance in 2013 that had a material impact on the Corporation’s financial statements.

  3. Miscellaneous Financial Information

Research and development expenses totaled $1,044 million in 2013, $1,042 million in 2012 and $1,044 million in 2011.

Net income included before-tax aggregate foreign exchange transaction gains of $155 million and $159 million, and losses of $184 million in 2013 and 2011, respectively.

In 2013, 2012 and 2011, net income included gains of $282 million, $328 million and $292 million, respectively, attributable to the combined effe LIFO inventory accumulations and drawdowns. The aggregate replacement cost of inventories was estimated to exceed their LIFO carrying values by billion and $21.3 billion at December 31, 2013, and 2012, respectively.

Crude oil, products and merchandise as of year-end 2013 and 2012 consist of the following:

2013 (billions of dollars) Petroleum products 3.9 Crude oil 4.7 Chemical products 2.9 Gas/other 0.6 Total 12.1

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  NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 4. Other Comprehensive Income Information

Cumulative Post- Unrealized Foreign retirement Change in Exchange Benefits Fair Value ExxonMobil Share of Accumulated Other Translation Reserves on Cash Comprehensive Income Adjustment Adjustment Flow Hedges Total (millions of dollars) Balance as of December 31, 2010 5,011 (9,889) 55 (4,82 Current period change excluding amounts reclassified from accumulated other comprehensive income (843) (4,557) 28 (5,3 Amounts reclassified from accumulated other comprehensive income - 1,155 (83) 1,0 Total change in accumulated other comprehensive income (843) (3,402) (55) (4,3 Balance as of December 31, 2011 4,168 (13,291) - (9,12 Balance as of December 31, 2011 4,168 (13,291) - (9,12 Current period change excluding amounts reclassified from accumulated other comprehensive income 842 (3,402) - (2,5 Amounts reclassified from accumulated other comprehensive income (2,600) 2,099 - (5 Total change in accumulated other comprehensive income (1,758) (1,303) - (3,0 Balance as of December 31, 2012 2,410 (14,594) - (12,1 Balance as of December 31, 2012 2,410 (14,594) - (12,1 Current period change excluding amounts reclassified from accumulated other comprehensive income (3,233) 2,963 - (2 Amounts reclassified from accumulated other comprehensive income (23) 1,752 - 1,7 Total change in accumulated other comprehensive income (3,256) 4,715 - 1,4 Balance as of December 31, 2013 (846) (9,879) - (10,72 Amounts Reclassified Out of Accumulated Other Comprehensive Income - Before-tax Income/(Expense) 2013 2012 20 (millions of dollars) Foreign exchange translation gain/(loss) included in net income (Statement of Income line: Other income) 23 4,352 Amortization and settlement of postretirement benefits reserves adjustment included in net periodic benefit costs (1) (2,616) (3,621) ( Realized gain from settled cash flow hedges included in net income (Statement of Income line: Sales and other operating revenue) - -

                  (1) These accumulated other comprehensive income components are included in the computation of net periodic pension cost. (See Note 17 – Pension

Other Postretirement Benefits for additional details.)   Income Tax (Expense)/Credit For Components of Other Comprehensive Income 2013 2012 20 (millions of dollars) Foreign exchange translation adjustment 218 (236) Postretirement benefits reserves adjustment Postretirement benefits reserves adjustment (excluding amortization) (1,540) 1,619 Amortization and settlement of postretirement benefits reserves adjustment included in net periodic benefit costs (796) (1,226) Unrealized change in fair value on cash flow hedges Change in fair value of cash flow hedges - - Settled cash flow hedges included in net income - - Total (2,118) 157

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  NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 5. Cash Flow Information

The Consolidated Statement of Cash Flows provides information about changes in cash and cash equivalents. Highly liquid investments with maturi three months or less when acquired are classified as cash equivalents.

The “Net (gain) on asset sales” in net cash provided by operating activities on the Consolidated Statement of Cash Flows includes before-tax gains the sale of a partial interest in Iraq, the sale of Downstream affiliates in the Caribbean and the sale of service stations in 2013; the Japan restructuring, th of an Upstream property in Angola, exchanges of Upstream properties, the sale of U.S. service stations, and the sale of the Downstream affilia Malaysia and Switzerland in 2012; and from the sale of some Upstream Canadian, U.K. and other producing properties and assets, and the sale o service stations in 2011. These gains are reported in “Other income” on the Consolidated Statement of Income.

In 2012, the Corporation’s interest in a cost company was redeemed. As part of the redemption, a variable note due in 2035 issued by Mobil Se (Bahamas) Ltd. was assigned to a consolidated ExxonMobil affiliate. This note is no longer classified as third party long-term debt. This assignment d result in a “Reduction in long-term debt” on the Statement of Cash Flows.

In 2012, ExxonMobil completed asset exchanges, primarily noncash transactions, of approximately $1 billion. This amount is not included in the of subsidiaries, investments, and property, plant and equipment” or the “Additions to property, plant and equipment” lines on the Statement of Cash Flo

In 2011, included in “Proceeds associated with sales of subsidiaries, property, plant and equipment, and sales and returns of investments” is a $3.6 b deposit for an asset that was sold in 2012.

2013 2012 20 (millions of dollars) Cash payments for interest 426 555 Cash payments for income taxes 25,066 24,349 2   6. Additional Working Capital Information Dec. 31 De 2013 20 (millions of dollars) Notes and accounts receivable Trade, less reserves of $112 million and $109 million 25,993 2 Other, less reserves of $28 million and $36 million 7,159 Total 33,152 3 Notes and loans payable Bank loans 722 Commercial paper 14,051 Long-term debt due within one year 1,034 Other 1 Total 15,808 Accounts payable and accrued liabilities Trade payables 30,920 3 Payables to equity companies 6,587 Accrued taxes other than income taxes 3,883 Other 6,695 Total 48,085 5

  The Corporation has short-term committed lines of credit of $5.9 billion which were unused as of December 31, 2013. The majority of these lin available for general corporate purposes, however $0.5 billion has been designated as specifically supporting commercial paper programs. The wei average interest rate on short-term borrowings outstanding was 0.4 percent and 1.7 percent at December 31, 2013, and 2012, respectively.

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  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 subsid where minority shareholders possess the right to participate in significant management decisions (see Note 1). These companies are primarily engaged and gas exploration and production, natural gas marketing and refining operations in North America; natural gas exploration, production and distributio downstream operations in Europe; and research, exploration, production, liquefied natural gas (LNG) operations, refining operations, petroche manufacturing, fuel sales and power generation in Asia. Also included are several refining, petrochemical manufacturing and marketing ventures.

The Corporation’s ownership in these ventures is in the form of shares in corporate joint ventures as well as interests in partnerships. Differences be the company’s carrying value of an equity investment and its underlying equity in the net assets of the affiliate are assigned to the extent practica specific assets and liabilities based on the company’s analysis of the factors giving rise to the difference. The amortization of this difference, as appro is included in “income from equity affiliates.”

The share of total equity company revenues from sales to ExxonMobil consolidated companies was 13 percent, 16 percent and 19 percent in the 2013, 2012 and 2011, respectively.

In 2013, the Corporation and Rosneft established various entities to conduct exploration and research activities. Periods of disproportionate fundin result in the Corporation recognizing, during the early phases of the projects, an investment that is larger than its equity share of these entities. Thes ventures are considered Variable Interest Entities (VIEs). However, since the Corporation is not the primary beneficiary of these entities the joint ve are reported as equity companies. The Corporation’s maximum exposure to loss from these joint ventures is limited to its investment of $0.1 billion an commitments of $1.1 billion at December 31, 2013.

2013 2012 2011 Equity Company ExxonMobil ExxonMobil ExxonM Financial Summary Total Share Total Share Total Sha (millions of dollars) Total revenues 236,161 68,084 224,953 67,572 204,635 6 Income before income taxes 69,454 19,999 69,411 20,882 68,908 2 Income taxes 21,618 6,069 20,703 5,868 19,812 Income from equity affiliates 47,836 13,930 48,708 15,014 49,096 1 Current assets 62,398 19,545 59,612 18,483 52,879 1 Long-term assets 116,450 35,695 111,131 33,798 96,908 3 Total assets 178,848 55,240 170,743 52,281 149,787 4 Current liabilities 54,550 15,243 49,698 14,265 41,016 1 Long-term liabilities 68,857 20,873 68,855 19,715 62,472 1 Net assets 55,441 19,124 52,190 18,301 46,299 1

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  NOTES TO CONSOLIDATED FINANCIAL STATEMENTS A list of significant equity companies as of December 31, 2013, together with the Corporation’s percentage ownership interest, is detailed below:

Percentage Ownership Interest Upstream Aera Energy LLC 48 BEB Erdgas und Erdoel GmbH & Co. KG 50 Cameroon Oil Transportation Company S.A. 41 Castle Peak Power Company Limited 60 Cross Timbers Energy, LLC 50 Golden Pass LNG Terminal LLC 18 Karmorneftegaz Holding SARL 33 LLC Arctic Research and Design Center For Continental Shelf Development 33 Nederlandse Aardolie Maatschappij B.V. 50 Qatar Liquefied Gas Company Limited 10 Qatar Liquefied Gas Company Limited (2) 24 Ras Laffan Liquefied Natural Gas Company Limited 25 Ras Laffan Liquefied Natural Gas Company Limited (II) 31 Ras Laffan Liquefied Natural Gas Company Limited (3) 30 South Hook LNG Terminal Company Limited 24 Tengizchevroil, LLP 25 Terminale GNL Adriatico S.r.l. 71 Trizneft Pilot SARL 49 Tuapsemorneftegaz Holding SARL 33 Downstream Chalmette Refining, LLC 50 Fujian Refining & Petrochemical Co. Ltd. 25 Saudi Aramco Mobil Refinery Company Ltd. 50 TonenGeneral Sekiyu K.K. 22 Chemical Al-Jubail Petrochemical Company 50 Infineum Holdings B.V. 50 Infineum USA L.P. 50 Saudi Yanbu Petrochemical Co. 50

  8. Investments, Advances and Long-Term Receivables

Dec. 31, Dec 2013 20

(millions of dollars) Companies carried at equity in underlying assets Investments 19,619 1 Advances 10,476 Total equity company investments and advances 30,095 2 Companies carried at cost or less and stock investments carried at fair value 115 Long-term receivables and miscellaneous investments at cost or less, net of reserves of $2,938 million and $2,499 million 6,118 Total 36,328 3

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  NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 9. Property, Plant and Equipment and Asset Retirement Obligations

December 31, 2013 December 31, 2012 Property, Plant and Equipment Cost Net Cost Ne (millions of dollars) Upstream 336,359 197,554 313,181 18 Downstream 54,456 23,219 53,737 2 Chemical 29,487 13,965 29,437 1 Other 14,215 8,912 12,959 Total 434,517 243,650 409,314 22

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

Accumulated depreciation and depletion totaled $190,867 million at the end of 2013 and $182,365 million at the end of 2012. Interest capitalized in 2012 and 2011 was $309 million, $506 million and $593 million, respectively.

  Asset Retirement Obligations

The Corporation incurs retirement obligations for certain assets. The fair values of these obligations are recorded as liabilities on a discounted basis, wh typically at the time the assets are installed. In the estimation of fair value, the Corporation uses assumptions and judgments regarding such factors existence of a legal obligation for an asset retirement obligation; technical assessments of the assets; estimated amounts and timing of settlements; di rates; and inflation rates. Asset retirement obligations incurred in the current period were Level 3 (unobservable inputs) fair value measurements. The associated with these liabilities are capitalized as part of the related assets and depreciated as the reserves are produced. Over time, the liabilities are ac for the change in their present value.

Asset retirement obligations for downstream and chemical facilities generally become firm at the time the facilities are permanently shut dow dismantled. These obligations may include the costs of asset disposal and additional soil remediation. However, these sites have indeterminate lives ba plans for continued operations and as such, the fair value of the conditional legal obligations cannot be measured, since it is impossible to estimate the settlement dates of such obligations.

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

2013 (millions of dollars) Beginning balance 11,973 1 Accretion expense and other provisions 785 Reduction due to property sales (97) Payments made (664) Liabilities incurred 603 Foreign currency translation (344) Revisions 732 Ending balance 12,988 1

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  NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 10. Accounting for Suspended Exploratory Well Costs

The Corporation continues capitalization of exploratory well costs when the well has found a sufficient quantity of reserves to justify its completio producing well and the Corporation is making sufficient progress assessing the reserves and the economic and operating viability of the project. The “project” as used in this report can refer to a variety of different activities and does not necessarily have the same meaning as in any government pa transparency reports.

The following two tables provide details of the changes in the balance of suspended exploratory well costs as well as an aging summary of those cos

Change in capitalized suspended exploratory well costs:

2013 2012 (millions of dollars) Balance beginning at January 1 2,679 2,881 Additions pending the determination of proved reserves 293 868 Charged to expense (52) (95) Reclassifications to wells, facilities and equipment based on the determination of proved reserves (107) (631) Divestments/Other (106) (344) Ending balance at December 31 2,707 2,679 Ending balance attributed to equity companies included above 13 3

Period end capitalized suspended exploratory well costs:

2013 2012 (millions of dollars) Capitalized for a period of one year or less 293 866 Capitalized for a period of between one and five years 1,705 1,176 Capitalized for a period of between five and ten years 470 401 Capitalized for a period of greater than ten years 239 236 Capitalized for a period greater than one year - subtotal 2,414 1,813 Total 2,707 2,679

Exploration activity often involves drilling multiple wells, over a number of years, to fully evaluate a project. The table below provides a num breakdown of the number of projects with suspended exploratory well costs which had their first capitalized well drilled in the preceding 12 month those that have had exploratory well costs capitalized for a period greater than 12 months.

2013 2012 Number of projects with first capitalized well drilled in the preceding 12 months 8 10 Number of projects that have exploratory well costs capitalized for a period of greater than 12 months 50 45 Total 58 55

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  NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Of the 50 projects that have exploratory well costs capitalized for a period greater than 12 months as of December 31, 2013, 17 projects have drilling preceding 12 months or exploratory activity planned in the next two years, while the remaining 33 projects are those with completed exploratory a progressing toward development. The table below provides additional detail for those 33 projects, which total $925 million.

Years Dec. 31, Wells

Country/Project 2013 Drilled Comment (millions of dollars)

Angola - Kaombo Split Hub 155 2003 - 2012 Multiple deepwater oil discoveries, progressing development plan. - Perpetua-Zinia-Acacia 15 2008 - 2009 Oil field near Pazflor development, awaiting capacity in existing/planned infrastructure. Australia - East Pilchard 9 2001 Gas field near Kipper/Tuna development, awaiting capacity in existing/planned infrastructure. - SE Longtom 13 2010 Gas field near Tuna development, awaiting capacity in existing/planned infrastructure. - SE Remora 42 2010 Gas field near Marlin development, awaiting capacity in existing/planned infrastructure. Indonesia - Alas Tua West 16 2010 Evaluating development plan to tie into planned production facilities. - Cepu Gas 28 2008 - 2011 Development activity under way, while continuing commercial discussions with the government. - Kedung Keris 11 2011 Evaluating development plan to tie into planned production facilities. - Natuna 118 1981 - 1983 Development activity under way, while continuing discussions with the government on contract terms pursuant to executed Heads of Agreement. Kazakhstan - Kairan 53 2004 - 2007 Evaluating commercialization and field development alternatives, while continuing discussions with the government regarding the development plan. Malaysia - Besar 18 1992 - 2010 Gas field off the east coast of Malaysia; progressing development plan. - Bindu 2 1995 Awaiting capacity in existing/planned infrastructure. Nigeria - Bolia 15 2002 - 2006 Evaluating development plan, while continuing discussions with the government regarding regional hub strategy. - Bosi 79 2002 - 2006 Development activity under way, while continuing discussions with the government regarding development plan. - Bosi Central 16 2006 Development activity under way, while continuing discussions with the government regarding development plan. - Owowo 50 2009 - 2012 Continuing discussions with the government regarding contract terms. - Pegi 32 2009 Awaiting capacity in existing/planned infrastructure. - Uge 18 2005 - 2008 Evaluating development alternatives, while continuing discussions with the government regarding development plan. - Other (4 projects) 14 2002 Evaluating and pursuing development of several additional discoveries. Norway - Gamma 19 2008 - 2009 Evaluating development plan for tieback to existing production facilities. - Other (5 projects) 21 2008 - 2010 Evaluating development plans, including potential for tieback to existing production facilities. Papua New Guinea - Juha 28 2007 Working on development plans to tie into planned LNG facilities. - P'nyang 58 2012 Working on development plans to tie into planned LNG facilities. Republic of Congo - Mer Tres Profonde Sud 56 2000 - 2007 Evaluating development alternatives, while continuing discussions with the government regarding development plan. United Kingdom - Phyllis 8 2004 Evaluating development plan for tieback to existing production facilities. United States - Tip Top 31 2009 Evaluating development concept and requisite facility upgrades. Total 2013 (33 projects) 925

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  NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 11. Leased Facilities

At December 31, 2013, the Corporation and its consolidated subsidiaries held noncancelable operating charters and leases covering drilling equip tankers, service stations and other properties with minimum undiscounted lease commitments totaling $7,438 million as indicated in the table. Esti related rental income from noncancelable subleases is $95 million.

Related Lease Payments Sublease Under Minimum Rental Commitments Income (millions of dollars) 2014 2,391 33 2015 1,724 29 2016 1,036 7 2017 481 5 2018 289 2 2019 and beyond 1,517 19 Total 7,438 95

Net rental cost under both cancelable and noncancelable operating leases incurred during 2013, 2012 and 2011 were as follows:

2013 2012 (millions of dollars) Rental cost 3,841 3,851 Less sublease rental income 44 44 Net rental cost 3,797 3,807

  12. Earnings Per Share

2013 2012 Earnings per common share Net income attributable to ExxonMobil (millions of dollars) 32,580 44,880 4 Weighted average number of common shares outstanding (millions of shares) 4,419 4,628 Earnings per common share (dollars) 7.37 9.70 Earnings per common share - assuming dilution Net income attributable to ExxonMobil (millions of dollars) 32,580 44,880 4 Weighted average number of common shares outstanding (millions of shares) 4,419 4,628 Effect of employee stock-based awards - - Weighted average number of common shares outstanding - assuming dilution 4,419 4,628 Earnings per common share - assuming dilution (dollars) 7.37 9.70 Dividends paid per common share (dollars) 2.46 2.18

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  NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 13. Financial Instruments and Derivatives

Financial Instruments. The fair value of financial instruments is determined by reference to observable market data and other valuation techniq appropriate. The only category of financial instruments where the difference between fair value and recorded book value is notable is long-term deb estimated fair value of total long-term debt, excluding capitalized lease obligations, was $6.8 billion and $8.0 billion at December 31, 2013, and respectively, as compared to recorded book values of $6.5 billion and $7.5 billion at December 31, 2013, and 2012, respectively.

The fair value of long-term debt by hierarchy level at December 31, 2013, is: Level 1 $5,756 million; Level 2 $967 million; and Level 3 $64 mi Level 1 represents quoted prices in active markets. Level 2 includes debt whose fair value is based upon a publicly available index. Level 3 involves internal data augmented by relevant market indicators if available.

Derivative Instruments. The Corporation’s size, strong capital structure, geographic diversity and the complementary nature of the Upstream, Downs and Chemical businesses reduce the Corporation’s enterprise-wide risk from changes in interest rates, currency rates and commodity prices. As a resu Corporation makes limited use of derivatives to mitigate the impact of such changes. The Corporation does not engage in speculative derivative activi derivative trading activities nor does it use derivatives with leveraged features. When the Corporation does enter into derivative transactions, it is to exposures associated with interest rates, foreign currency exchange rates and hydrocarbon prices that arise from existing assets, liabilities and fore transactions.

The estimated fair value of derivative instruments outstanding and recorded on the balance sheet was a net asset of $1 million at year-end 2013 and asset of $2 million at year-end 2012. Assets and liabilities associated with derivatives are usually recorded either in “Other current assets” or “Acc payable and accrued liabilities.”

The Corporation’s fair value measurement of its derivative instruments use either Level 1 (observable quoted prices on active exchanges) or L (derivatives that are determined by either market prices on an active market for similar assets or by prices quoted by a broker or other market-corrob prices) inputs.

The Corporation recognized a before-tax gain or (loss) related to derivative instruments of $(7) million, $(23) million and $131 million during 2013 and 2011, respectively. Income statement effects associated with derivatives are usually recorded either in “Sales and other operating revenue” or “Cru and product purchases.”

The Corporation believes there are no material market or credit risks to the Corporation’s financial position, results of operations or liquidity as a re the derivative activities described above.

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  NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 14. Long-Term Debt

At December 31, 2013, long-term debt consisted of $6,542 million due in U.S. dollars and $349 million representing the U.S. dollar equivalent at ye exchange rates of amounts payable in foreign currencies. These amounts exclude that portion of long-term debt, totaling $1,034 million, which m within one year and is included in current liabilities. The amounts of long-term debt maturing in each of the four years after December 31, 2014, in m of dollars, are: 2015 – $782; 2016 – $513; 2017 – $857; and 2018 – $900.

Summarized long-term debt at year-end 2013 and 2012 are shown in the table below:

2013 2012 (millions of dollars) XTO Energy Inc. (1) 4.900% senior note due 2014 - 254 5.000% senior note due 2015 132 135 5.300% senior note due 2015 243 249 5.650% senior note due 2016 212 217 6.250% senior note due 2017 489 501 5.500% senior note due 2018 389 396 6.500% senior note due 2018 485 495 6.100% senior note due 2036 200 201 6.750% senior note due 2037 312 314 6.375% senior note due 2038 238 240 Mobil Services (Bahamas) Ltd. (2) Variable note due 2034 - 311 Mobil Producing Nigeria Unlimited (3) Variable notes due 2014-2019 742 751 Esso (Thailand) Public Company Ltd. (4) Variable notes due 2014-2017 177 414 Mobil Corporation 8.625% debentures due 2021 249 249 Industrial revenue bonds due 2014-2051 (5) 2,527 2,690 Other U.S. dollar obligations (6) 112 74 Other foreign currency obligations 9 6 Capitalized lease obligations (7) 375 431 Total long-term debt 6,891 7,928

(1) Includes premiums of $271 million in 2013 and $326 million in 2012.

(2) Average effective interest rate of 0.5% in 2012.

(3) Average effective interest rate of 4.6% in 2013 and 4.6% in 2012.

(4) Average effective interest rate of 3.3% in 2013 and 3.5% in 2012.

(5) Average effective interest rate of 0.1% in 2013 and 0.1% in 2012.

(6) Average effective interest rate of 4.4% in 2013 and 2.7% in 2012.

(7) Average imputed interest rate of 7.8% in 2013 and 7.6% in 2012.

The Corporation has long-term committed lines of credit of $0.6 billion which were unused as of December 31, 2013. Of this total, $0.5 billion supp

commercial paper programs.

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  NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 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 m granted to eligible employees of the Corporation and those affiliates at least 50 percent owned. Outstanding awards are subject to certain forfeiture prov contained in the program or award instrument. Options and SARs may be granted at prices not less than 100 percent of market value on the date of gra have a maximum life of 10 years. The maximum number of shares of stock that may be issued under the 2003 Incentive Program is 220 million. Award are forfeited, expire or are settled in cash, do not count against this maximum limit. The 2003 Incentive Program does not have a specified term. New a may be made until the available shares are depleted, unless the Board terminates the plan early. At the end of 2013, remaining shares available for under the 2003 Incentive Program were 117 million.

Restricted Stock and Restricted Stock Units. Awards totaling 9,729 thousand, 10,017 thousand, and 10,533 thousand of restricted (nonvested) co stock and restricted (nonvested) common stock units were granted in 2013, 2012 and 2011, respectively. Compensation expense for these awards is ba the price of the stock at the date of grant and is recognized in income over the requisite service period. Shares for these awards are issued to employee treasury stock. The units that are settled in cash are recorded as liabilities and their changes in fair value are recognized over the vesting period. Duri applicable restricted periods, the shares and units may not be sold or transferred and are subject to forfeiture. The majority of the awards have graded v periods, with 50 percent of the shares and units in each award vesting after three years and the remaining 50 percent vesting after seven years. A granted to a small number of senior executives have vesting periods of five years for 50 percent of the award and of 10 years or retirement, whichever o later, for the remaining 50 percent of the award.

The Corporation has purchased shares in the open market and through negotiated transactions to offset shares issued in conjunction with benefit plan programs. Purchases may be discontinued at any time without prior notice.

The following tables summarize information about restricted stock and restricted stock units for the year ended December 31, 2013.

2013 Weighted Average Grant-Date Restricted stock and units outstanding Shares Fair Value per Share (thousands) (dollars) Issued and outstanding at January 1 46,451 73.94 2012 award issued in 2013 10,016 87.24 Vested (11,068) 68.15 Forfeited (192) 77.22 Issued and outstanding at December 31 45,207 78.29 Value of restricted stock and units 2013 2012 Grant price (dollars) 94.47 87.24 Value at date of grant: (millions of dollars) Restricted stock and units settled in stock 843 797 Units settled in cash 76 77 Total value 919 874

                          As of December 31, 2013, there was $2,269 million of unrecognized compensation cost related to the nonvested restricted awards. This cost is expected recognized over a weighted-average period of 4.5 years. The compensation cost charged against income for the restricted stock and restricted stock uni $854 million, $854 million and $793 million for 2013, 2012 and 2011, respectively. The income tax benefit recognized in income related t compensation expense was $78 million, $79 million and $73 million for the same periods, respectively. The fair value of shares and units vested in 2012 and 2011 was $1,040 million, $926 million and $801 million, respectively. Cash payments of $67 million, $66 million and $46 million for restricted stock units settled in cash were made in 2013, 2012 and 2011, respectively.

Stock Options. The Corporation has not granted any stock options under the 2003 Incentive Program and all stock options granted under the prior pr were exercised by the end of 2011. In 2010, the Corporation granted 12,393 thousand of converted XTO stock options of which 1,506 thousand options, with an average exercise price of $85.57, were outstanding as of December 31, 2013.

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  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 law Management has regular litigation reviews, including updates from corporate and outside counsel, to assess the need for accounting recognition or disc of these contingencies. The Corporation accrues an undiscounted liability for those contingencies where the incurrence of a loss is probable and the a can be reasonably estimated. If a range of amounts can be reasonably estimated and no amount within the range is a better estimate than any other am then the minimum of the range is accrued. The Corporation does not record liabilities when the likelihood that the liability has been incurred is probab the amount cannot be reasonably estimated or when the liability is believed to be only reasonably possible or remote. For contingencies where an unfav outcome is reasonably possible and which are significant, the Corporation discloses the nature of the contingency and, where feasible, an estimate possible loss. For purposes of our contingency disclosures, “significant” includes material matters as well as other matters which management be should be disclosed. ExxonMobil will continue to defend itself vigorously in these matters. Based on a consideration of all relevant facts and circumst the Corporation does not believe the ultimate outcome of any currently pending lawsuit against ExxonMobil will have a material adverse effect up Corporation’s operations, financial condition, or financial statements taken as a whole.

Other Contingencies. The Corporation and certain of its consolidated subsidiaries were contingently liable at December 31, 2013, for guarantees relat notes, loans and performance under contracts. Where guarantees for environmental remediation and other similar matters do not include a stated ca amounts reflect management’s estimate of the maximum potential exposure.

         Dec. 31, 2013

         Equity Company Other Third-Party Obligations (1) Obligations Total

(millions of dollars) Guarantees Debt-related 3,086 46 Other 2,939 4,507 Total 6,025 4,553 1 (1) ExxonMobil share.   Additionally, the Corporation and its affiliates have numerous long-term sales and purchase commitments in their various business activities, all of whi expected to be fulfilled with no adverse consequences material to the Corporation’s operations or financial condition. Unconditional purchase obligati defined by accounting standards are those long-term commitments that are noncancelable or cancelable only under certain conditions, and that third p have used to secure financing for the facilities that will provide the contracted goods or services.

Payments Due by Period 2015- 2019 and 2014 2018 Beyond T (millions of dollars) Unconditional purchase obligations (1) 144 629 463

(1) Undiscounted obligations of $1,236 million mainly pertain to pipeline throughput agreements and include $457 million of obligations to companies. The present value of these commitments, which excludes imputed interest of $267 million, totaled $969 million.

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  NOTES TO CONSOLIDATED FINANCIAL STATEMENTS In accordance with a nationalization decree issued by Venezuela’s president in February 2007, by May 1, 2007, a subsidiary of the Venezuelan Nation Company (PdVSA) assumed the operatorship of the Cerro Negro Heavy Oil Project. This Project had been operated and owned by ExxonMobil aff holding a 41.67 percent ownership interest in the Project. The decree also required conversion of the Cerro Negro Project into a “mixed enterprise” a increase in PdVSA’s or one of its affiliate’s ownership interest in the Project, with the stipulation that if ExxonMobil refused to accept the terms f formation of the mixed enterprise within a specified period of time, the government would “directly assume the activities” carried out by the joint ve ExxonMobil refused to accede to the terms proffered by the government, and on June 27, 2007, the government expropriated ExxonMobil’s 41.67 p interest in the Cerro Negro Project. ExxonMobil’s remaining net book investment in Cerro Negro producing assets is about $750 million.

On September 6, 2007, affiliates of ExxonMobil filed a Request for Arbitration with the International Centre for Settlement of Investment Di (ICSID) invoking ICSID jurisdiction under Venezuela’s Investment Law and the Netherlands-Venezuela Bilateral Investment Treaty. The ICSID Tr issued a decision on June 10, 2010, finding that it had jurisdiction to proceed on the basis of the Netherlands-Venezuela Bilateral Investment Treaty ICSID arbitration proceeding is continuing and a hearing on the merits was held in February 2012. At this time, the net impact of these matters o Corporation’s consolidated financial results cannot be reasonably estimated. Regardless, the Corporation does not expect the resolution to have a m effect upon the Corporation’s operations or financial condition.

An affiliate of ExxonMobil is one of the Contractors under a Production Sharing Contract (PSC) with the Nigerian National Petroleum Corpo (NNPC) covering the Erha block located in the offshore waters of Nigeria. ExxonMobil’s affiliate is the operator of the block and owns a 56.25 p interest under the PSC. The Contractors are in dispute with NNPC regarding NNPC’s lifting of crude oil in excess of its entitlement under the terms PSC. In accordance with the terms of the PSC, the Contractors initiated arbitration in Abuja, Nigeria, under the Nigerian Arbitration and Conci Act. On October 24, 2011, a three-member arbitral Tribunal issued an award upholding the Contractors’ position in all material respects and aw damages to the Contractors jointly in an amount of approximately $1.8 billion plus $234 million in accrued interest. The Contractors petitioned a Ni federal court for enforcement of the award, and NNPC petitioned the same court to have the award set aside. On May 22, 2012, the court set aside the a The Contractors have appealed that judgment. In June 2013, the Contractors filed a lawsuit against NNPC in the Nigerian federal high court in or preserve their ability to seek enforcement of the PSC in the courts if necessary. At this time, the net impact of this matter on the Corporation’s consol financial results cannot be reasonably estimated. However, regardless of the outcome of enforcement proceedings, the Corporation does not expe proceedings to have a material effect upon the Corporation’s operations or financial condition.

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  NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 17. Pension and Other Postretirement Benefits

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

Pension Benefits Other Postretiremen U.S. Non-U.S. Benefits 2013 2012 2013 2012 2013 20 (percent) Weighted-average assumptions used to determine benefit obligations at December 31 Discount rate 5.00 4.00 4.30 3.80 5.00 Long-term rate of compensation increase 5.75 5.75 5.40 5.50 5.75 (millions of dollars) Change in benefit obligation Benefit obligation at January 1 19,779 17,035 28,670 29,068 9,058 Service cost 801 665 697 648 176 Interest cost 749 820 1,076 1,145 352 Actuarial loss/(gain) (1,520) 2,553 (1,454) 2,335 (1,267) Benefits paid (1) (2) (2,520) (1,294) (1,311) (1,330) (511) Foreign exchange rate changes - - (284) 651 (43) Japan restructuring and other divestments - - (77) (3,952) - Plan amendments, other 15 - 40 105 103 Benefit obligation at December 31 17,304 19,779 27,357 28,670 7,868 Accumulated benefit obligation at December 31 13,989 15,902 23,949 24,345 -  

(1) Benefit payments for funded and unfunded plans.

(2) For 2013 and 2012, other postretirement benefits paid are net of $20 million and $23 million of Medicare subsidy receipts, respectively.

For selection of the discount rate for U.S. plans, several sources of information are considered, including interest rate market indicators and the discou determined by constructing a portfolio of high-quality, noncallable bonds with cash flows that match estimated outflows for benefit payments. For non-U.S. plans, the discount rate is determined by using bond portfolios with an average maturity approximating that of the liabilities or spot yield c both of which are constructed using high-quality, local-currency-denominated bonds.

The measurement of the accumulated postretirement benefit obligation assumes a health care cost trend rate of 4.5 percent in 2015 and subsequent A one-percentage-point increase in the health care cost trend rate would increase service and interest cost by $68 million and the postretirement b obligation by $734 million. A one-percentage-point decrease in the health care cost trend rate would decrease service and interest cost by $53 million a postretirement benefit obligation by $597 million.

Pension Benefits Other Postretiremen U.S. Non-U.S. Benefits 2013 2012 2013 2012 2013 20 (millions of dollars) Change in plan assets Fair value at January 1 12,632 10,656 18,090 17,117 581 Actual return on plan assets 617 1,457 1,604 1,541 64 Foreign exchange rate changes - - (270) 462 - Company contribution 101 1,560 919 1,604 35 Benefits paid (1) (2,171) (1,041) (869) (922) (60) Japan restructuring and other divestments - - (45) (1,696) - Other 11 - (146) (16) - Fair value at December 31 11,190 12,632 19,283 18,090 620

(1) Benefit payments for funded plans.

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  NOTES TO CONSOLIDATED FINANCIAL STATEMENTS The funding levels of all qualified pension plans are in compliance with standards set by applicable law or regulation. As shown in the table below, c smaller U.S. pension plans and a number of non-U.S. pension plans are not funded because local tax conventions and regulatory practices do not enco funding of these plans. All defined benefit pension obligations, regardless of the funding status of the underlying plans, are fully supported by the fin strength of the Corporation or the respective sponsoring affiliate.

Pension Benefits U.S. Non-U.S. 2013 2012 2013 20 (millions of dollars) Assets in excess of/(less than) benefit obligation Balance at December 31 Funded plans (3,547) (4,438) (941) ( Unfunded plans (2,567) (2,709) (7,133) ( Total (6,114) (7,147) (8,074) (1

  The authoritative guidance for defined benefit pension and other postretirement plans requires an employer to recognize the overfunded or underfunded of a defined benefit postretirement plan as an asset or liability in its statement of financial position and to recognize changes in that funded status in th in which the changes occur through other comprehensive income.

Pension Benefits Other Postretiremen U.S. Non-U.S. Benefits 2013 2012 2013 2012 2013 20 (millions of dollars) Assets in excess of/(less than) benefit obligation Balance at December 31 (1) (6,114) (7,147) (8,074) (10,580) (7,248) ( Amounts recorded in the consolidated balance sheet consist of: Other assets 1 1 201 49 - Current liabilities (275) (279) (358) (352) (359) Postretirement benefits reserves (5,840) (6,869) (7,917) (10,277) (6,889) ( Total recorded (6,114) (7,147) (8,074) (10,580) (7,248) ( Amounts recorded in accumulated other comprehensive income consist of: Net actuarial loss/(gain) 4,780 7,451 7,943 10,904 1,603 Prior service cost 60 67 665 758 65 Total recorded in accumulated other comprehensive income 4,840 7,518 8,608 11,662 1,668

(1) Fair value of assets less benefit obligation shown on the preceding page.

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  NOTES TO CONSOLIDATED FINANCIAL STATEMENTS The long-term expected rate of return on funded assets shown below is established for each benefit plan by developing a forward-looking, long-term 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-ter of return is then calculated as the weighted average of the target asset allocation percentages and the long-term return assumption for each asset class.

Other Pension Benefits Postretirement U.S. Non-U.S. Benefits 2013 2012 2011 2013 2012 2011 2013 2012 Weighted-average assumptions used to determine net periodic benefit cost for years ended December 31 (percent) Discount rate 4.00 5.00 5.50 3.80 4.00 4.80 4.00 5.00 Long-term rate of return on funded assets 7.25 7.25 7.50 6.40 6.60 6.80 7.25 7.25 Long-term rate of compensation increase 5.75 5.75 5.25 5.50 5.40 5.20 5.75 5.75 Components of net periodic benefit cost (millions of dollars) Service cost 801 665 546 697 648 574 176 134 Interest cost 749 820 792 1,076 1,145 1,267 352 380 Expected return on plan assets (835) (789) (769) (1,128) (1,109) (1,168) (41) (38) Amortization of actuarial loss/(gain) 646 576 485 852 844 647 228 170 Amortization of prior service cost 7 7 9 117 117 103 21 34 Net pension enhancement and curtailment/settlement cost (1) 723 333 286 22 1,540 34 - - Net periodic benefit cost 2,091 1,612 1,349 1,636 3,185 1,457 736 680 (1) Non-U.S. net pension enhancement and curtailment/settlement cost for 2012 includes $1,420 million (on a consolidated-company,

before-tax basis) of accumulated other comprehensive income for the postretirement benefit reserves adjustment that was recycled into earnings and included in the Japan restructuring gain reported in “Other income”.

            Changes in amounts recorded in accumulated other comprehensive income: Net actuarial loss/(gain) (1,302) 1,885 2,218 (1,938) 1,906 4,133 (1,290) 1,008 Amortization of actuarial (loss)/gain (1,369) (909) (771) (874) (2,384) (681) (228) (170) Prior service cost/(credit) - - - 30 71 187 - - Amortization of prior service (cost)/credit (7) (7) (9) (117) (117) (103) (21) (34) Foreign exchange rate changes - - - (155) 271 (90) (10) 3 Total recorded in other comprehensive income (2,678) 969 1,438 (3,054) (253) 3,446 (1,549) 807 Total recorded in net periodic benefit cost and other comprehensive income, before tax (587) 2,581 2,787 (1,418) 2,932 4,903 (813) 1,487

  Costs for defined contribution plans were $392 million, $382 million and $378 million in 2013, 2012 and 2011, respectively.

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  NOTES TO CONSOLIDATED FINANCIAL STATEMENTS A summary of the change in accumulated other comprehensive income is shown in the table below:

Total Pension and Other Postretirement Benefits 2013 2012 20 (millions of dollars) (Charge)/credit to other comprehensive income, before tax U.S. pension 2,678 (969) ( Non-U.S. pension 3,054 253 ( Other postretirement benefits 1,549 (807) Total (charge)/credit to other comprehensive income, before tax 7,281 (1,523) ( (Charge)/credit to income tax (see Note 4) (2,336) 393 (Charge)/credit to investment in equity companies 49 (49) (Charge)/credit to other comprehensive income including noncontrolling interests, after tax 4,994 (1,179) ( Charge/(credit) to equity of noncontrolling interests (279) (124) (Charge)/credit to other comprehensive income attributable to ExxonMobil 4,715 (1,303) (

The Corporation’s investment strategy for benefit plan assets reflects a long-term view, a careful assessment of the risks inherent in various asset class broad diversification to reduce the risk of the portfolio. The benefit plan assets are primarily invested in passive equity and fixed income index fu diversify risk while minimizing costs. The equity funds hold ExxonMobil stock only to the extent necessary to replicate the relevant equity index. The income funds are largely invested in high-quality corporate and government debt securities.

Studies are periodically conducted to establish the preferred target asset allocation percentages. The target asset allocation for the U.S. benefit plans percent equity securities and 50 percent debt securities. The target asset allocation for the non-U.S. plans in aggregate is 49 percent equity securities a percent debt securities. The equity targets for the U.S. and non-U.S. plans include an allocation to private equity partnerships that primarily foc early-stage venture capital of 5 percent and 3 percent, respectively.

The fair value measurement levels are accounting terms that refer to different methods of valuing assets. The terms do not represent the relative r credit quality of an investment.

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  NOTES TO CONSOLIDATED FINANCIAL STATEMENTS The 2013 fair value of the benefit plan assets, including the level within the fair value hierarchy, is shown in the tables below:

U.S. Pension Non-U.S. Pension Fair Value Measurement Fair Value Measurement at December 31, 2013, Using: at December 31, 2013, Using: Quoted Quoted Prices Prices in Active Significant in Active Significant Markets for Other Significant Markets for Other Significant Identical Observable Unobservable Identical Observable Unobservable Assets Inputs Inputs Assets Inputs Inputs (Level 1) (Level 2) (Level 3) Total (Level 1) (Level 2) (Level 3) T

(millions of dollars) Asset category: Equity securities U.S. - 2,514 (1) - 2,514 - 3,046 (1) - Non-U.S. - 2,622 (1) - 2,622 294 (2) 5,608 (1) - Private equity - - 523 (3) 523 - - 502 (3) Debt securities Corporate - 3,430 (4) - 3,430 - 2,125 (4) - Government - 2,056 (4) - 2,056 272 (5) 7,100 (4) - Asset-backed - 6 (4) - 6 - 103 (4) - Real estate funds - - - - - - 136 (6)

Cash - 27 (7) - 27 57 20 (8) - Total at fair value - 10,655 523 11,178 623 18,002 638 1 Insurance contracts at contract value 12 Total plan assets 11,190 1

(1) For U.S. and non-U.S. equity securities held in the form of fund units that are redeemable at the measurement date, the unit value is treated as a L input. The fair value of the securities owned by the funds is based on observable quoted prices on active exchanges, which are Level 1 inputs.

(2) For non-U.S. equity securities held in separate accounts, fair value is based on observable quoted prices on active exchanges.

(3) For private equity, fair value is generally established by using revenue or earnings multiples or other relevant market data including Initial P Offerings.

(4) For corporate, government and asset-backed debt securities, fair value is based on observable inputs of comparable market transactions.

(5) For corporate and government debt securities that are traded on active exchanges, fair value is based on observable quoted prices.

(6) For real estate funds, fair value is based on appraised values developed using comparable market transactions.

(7) For cash balances held in the form of short-term fund units that are redeemable at the measurement date, the fair value is treated as a Level 2 inpu

(8) For cash balances that are subject to withdrawal penalties or other adjustments, the fair value is treated as a Level 2 input.

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  NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Other Postretirement Fair Value Measurement at December 31, 2013, Using: Quoted Prices in Active Significant Markets for Other Significant Identical Observable Unobservable Assets Inputs Inputs (Level 1) (Level 2) (Level 3) To (millions of dollars) Asset category: Equity securities U.S. - 157 (1) - Non-U.S. - 149 (1) - Private equity - - 9 (2) Debt securities Corporate - 129 (3) - Government - 168 (3) - Asset-backed - 4 (3) - Cash - 4 - Total at fair value - 611 9

(1) For U.S. and non-U.S. equity securities held in the form of fund units that are redeemable at the measurement date, the unit value is treated as a L

input. The fair value of the securities owned by the funds is based on observable quoted prices on active exchanges, which are Level 1 inputs.

(2) For private equity, fair value is generally established by using revenue or earnings multiples or other relevant market data including Initial P Offerings.

(3) For corporate, government and asset-backed debt securities, fair value is based on observable inputs of comparable market transactions.   The change in the fair value in 2013 of Level 3 assets that use significant unobservable inputs to measure fair value is shown in the table below:

2013 Pension Other U.S. Non-U.S. Postretiremen

  Private Private Real Private Equity Equity Estate Equity (millions of dollars) Fair value at January 1 489 448 293 Net realized gains/(losses) (1) 11 (13) Net unrealized gains/(losses) 86 57 10 Net purchases/(sales) (51) (14) (154) Fair value at December 31 523 502 136

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  NOTES TO CONSOLIDATED FINANCIAL STATEMENTS The 2012 fair value of the benefit plan assets, including the level within the fair value hierarchy, is shown in the tables below:

U.S. Pension Non-U.S. Pension Fair Value Measurement Fair Value Measurement at December 31, 2012, Using: at December 31, 2012, Using: Quoted Quoted Prices Prices in Active Significant in Active Significant Markets for Other Significant Markets for Other Significant Identical Observable Unobservable Identical Observable Unobservable Assets Inputs Inputs Assets Inputs Inputs (Level 1) (Level 2) (Level 3) Total (Level 1) (Level 2) (Level 3) T

(millions of dollars) Asset category: Equity securities U.S. - 2,600 (1) - 2,600 - 2,671 (1) - Non-U.S. - 3,227 (1) - 3,227 203 (2) 5,308 (1) - Private equity - - 489 (3) 489 - - 448 (3) Debt securities Corporate - 3,872 (4) - 3,872 - 2,005 (4) - Government - 2,223 (4) - 2,223 271 (5) 6,643 (4) - Asset-backed - 10 (4) - 10 - 100 (4) - Real estate funds - - - - - - 293 (6)

Cash - 198 (7) - 198 93 35 (8) - Total at fair value - 12,130 489 12,619 567 16,762 741 1 Insurance contracts at contract value 13 Total plan assets 12,632 1

(1) For U.S. and non-U.S. equity securities held in the form of fund units that are redeemable at the measurement date, the unit value is treated as a L input. The fair value of the securities owned by the funds is based on observable quoted prices on active exchanges, which are Level 1 inputs.

(2) For non-U.S. equity securities held in separate accounts, fair value is based on observable quoted prices on active exchanges.

(3) For private equity, fair value is generally established by using revenue or earnings multiples or other relevant market data including Initial P Offerings.

(4) For corporate, government and asset-backed debt securities, fair value is based on observable inputs of comparable market transactions.

(5) For corporate and government debt securities that are traded on active exchanges, fair value is based on observable quoted prices.

(6) For real estate funds, fair value is based on appraised values developed using comparable market transactions.

(7) For cash balances held in the form of short-term fund units that are redeemable at the measurement date, the fair value is treated as a Level 2 inpu

(8) For cash balances that are subject to withdrawal penalties or other adjustments, the fair value is treated as a Level 2 input.

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  NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Other Postretirement Fair Value Measurement at December 31, 2012, Using: Quoted Prices in Active Significant Markets for Other Significant Identical Observable Unobservable Assets Inputs Inputs (Level 1) (Level 2) (Level 3) To (millions of dollars) Asset category: Equity securities U.S. - 166 (1) - Non-U.S. - 160 (1) - Private equity - - 7 (2) Debt securities Corporate - 91 (3) - Government - 136 (3) - Asset-backed - 14 (3) - Cash - 7 - Total at fair value - 574 7

(1) For U.S. and non-U.S. equity securities held in the form of fund units that are redeemable at the measurement date, the unit value is treated as a L input. The fair value of the securities owned by the funds is based on observable quoted prices on active exchanges, which are Level 1 inputs.

(2) For private equity, fair value is generally established by using revenue or earnings multiples or other relevant market data including Initial P Offerings.

(3) For corporate, government and asset-backed debt securities, fair value is based on observable inputs of comparable market transactions.   The change in the fair value in 2012 of Level 3 assets that use significant unobservable inputs to measure fair value is shown in the table below:

2012 Pension Other U.S. Non-U.S. Postretiremen Private Private Real Private Equity Equity Estate Equity (millions of dollars) Fair value at January 1 458 393 397 Net realized gains/(losses) 2 2 (14) Net unrealized gains/(losses) 41 22 (1) Net purchases/(sales) (12) 31 (89) Fair value at December 31 489 448 293

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  NOTES TO CONSOLIDATED FINANCIAL STATEMENTS A summary of pension plans with an accumulated benefit obligation in excess of plan assets is shown in the table below:

Pension Benefits U.S. Non-U.S. 2013 2012 2013 201 (millions of dollars) For funded pension plans with an accumulated benefit obligation in excess of plan assets: Projected benefit obligation 14,737 17,070 891 Accumulated benefit obligation 12,342 14,171 689 Fair value of plan assets 11,189 12,631 611 For unfunded pension plans: Projected benefit obligation 2,567 2,709 7,133 Accumulated benefit obligation 1,647 1,731 6,070 Other Pension Benefits Postretireme U.S. Non-U.S. Benefits (millions of dollars) Estimated 2014 amortization from accumulated other comprehensive income: Net actuarial loss/(gain) (1) 827 649 Prior service cost (2) 8 122  

(1) The Corporation amortizes the net balance of actuarial losses/(gains) as a component of net periodic benefit cost over the average remaining s period of active plan participants.

(2) The Corporation amortizes prior service cost on a straight-line basis as permitted under authoritative guidance for defined benefit pension and postretirement benefit plans.

Pension Benefits Other Postretirement Benefits Medicare U.S. Non-U.S. Gross Subsidy Recei (millions of dollars) Contributions expected in 2014 1,400 800 - Benefit payments expected in: 2014 1,540 1,279 458 2015 1,520 1,293 473 2016 1,501 1,348 485 2017 1,467 1,383 496 2018 1,387 1,423 505 2019 - 2023 6,519 7,480 2,608   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 u identify these reportable segments are based on the nature of the operations that are undertaken by each segment. The Upstream segment is organize operates to explore for and produce crude oil and natural gas. The Downstream segment is organized and operates to manufacture and sell petr products. The Chemical segment is organized and operates to manufacture and sell petrochemicals. These segments are broadly understood acro petroleum and petrochemical industries.

These functions have been defined as the operating segments of the Corporation because they are the segments (1) that engage in business activitie which revenues are earned and expenses are incurred; (2) whose operating results are regularly reviewed by the Corporation’s chief operating decision to make decisions about resources to be allocated to the segment and assess its performance; and (3) for which discrete financial information is availabl

Earnings after income tax include transfers at estimated market prices.

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  NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

In corporate and financing activities, interest revenue relates to interest earned on cash deposits and marketable securities. Interest expense in non-debt-related interest expense of $202 million and $165 million in 2012 and 2011, respectively. For 2013, non-debt-related interest expense was credit of $123 million, primarily reflecting the effect of credits from the favorable resolution of prior year tax positions.

Corporate Upstream Downstream Chemical and Corp

U.S. Non-U.S. U.S. Non-U.S. U.S. Non-U.S. Financing T

(millions of dollars)

As of December 31, 2013 Earnings after income tax 4,191 22,650 2,199 1,250 2,755 1,073 (1,538) 3 Earnings of equity companies above 1,576 11,627 (460) 22 189 1,422 (449) 1 Sales and other operating revenue (1) 13,712 25,349 123,802 218,904 15,295 23,753 21 42 Intersegment revenue 8,343 45,761 20,781 52,624 11,993 8,232 285 Depreciation and depletion expense 5,170 8,277 633 1,390 378 632 702 1 Interest revenue - - - - - - 87 Interest expense 30 26 7 8 1 - (63) Income taxes 2,197 21,554 721 481 989 363 (2,042) 2 Additions to property, plant and equipment 7,480 26,075 616 1,072 840 272 1,386 3 Investments in equity companies 4,975 9,740 62 1,749 217 3,103 (227) 1 Total assets 88,698 157,465 19,261 40,661 7,816 19,659 13,248 34 As of December 31, 2012 Earnings after income tax 3,925 25,970 3,575 9,615 2,220 1,678 (2,103) 4 Earnings of equity companies above 1,759 11,900 6 387 183 1,267 (492) 1 Sales and other operating revenue (1) 11,039 27,673 125,088 248,959 14,723 24,003 24 45 Intersegment revenue 8,764 47,507 20,963 62,130 12,409 9,750 258 Depreciation and depletion expense 5,104 7,340 594 1,280 376 508 686 1 Interest revenue - - - - - - 117 Interest expense 37 13 3 36 - (1) 239 Income taxes 2,025 25,362 1,811 1,892 755 232 (1,032) 3 Additions to property, plant and equipment 9,697 21,769 480 1,153 338 659 1,083 3 Investments in equity companies 4,020 9,147 195 2,069 233 3,143 (277) 1 Total assets 86,146 140,848 18,451 40,956 7,238 18,886 21,270 33 As of December 31, 2011 Earnings after income tax 5,096 29,343 2,268 2,191 2,215 2,168 (2,221) 4 Earnings of equity companies above 2,045 11,768 7 353 198 1,365 (447) 1 Sales and other operating revenue (1) 14,023 32,419 120,844 257,779 15,466 26,476 22 46 Intersegment revenue 9,807 49,910 18,489 73,549 12,226 10,563 262 Depreciation and depletion expense 4,879 7,021 650 1,560 380 458 635 1 Interest revenue - - - - - - 135 Interest expense 30 36 10 24 2 (1) 146 Income taxes 2,852 25,755 1,123 696 1,027 465 (867) 3 Additions to property, plant and equipment 10,887 18,934 400 1,334 241 910 932 3 Investments in equity companies 2,963 8,439 210 1,358 253 3,973 (228) 1 Total assets 82,900 127,977 18,354 51,132 7,245 19,862 23,582 33

(1) Sales and other operating revenue includes sales-based taxes of $30,589 million for 2013, $32,409 million for 2012 and $33,503 million for 201 Note 1, Summary of Accounting Policies.

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  NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Geographic Sales and other operating revenue (1) 2013 2012 20 (millions of dollars) United States 152,820 150,865 15 Non-U.S. 268,016 300,644 31 Total 420,836 451,509 46 Significant non-U.S. revenue sources include: Canada 35,924 34,325 3 United Kingdom 34,061 33,600 3 Belgium 20,973 23,567 2 Italy 19,273 18,228 1 France 18,444 19,601 1 Germany 15,701 15,871 1 Singapore 15,623 14,606 1 Japan 124 14,162 3  

(1) Sales and other operating revenue includes sales-based taxes of $30,589 million for 2013, $32,409 million for 2012 and $33,503 million for 201 Note 1, Summary of Accounting Policies.

Long-lived assets 2013 2012 20 (millions of dollars) United States 98,271 94,336 9 Non-U.S. 145,379 132,613 12 Total 243,650 226,949 21 Significant non-U.S. long-lived assets include: Canada 41,522 31,979 2 Australia 14,258 13,415 Nigeria 12,343 12,216 1 Singapore 9,570 9,700 Kazakhstan 8,530 7,785 Angola 8,262 8,238 1 Norway 6,542 7,040 Papua New Guinea 5,768 4,599

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  NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 19. Income, Sales-Based and Other Taxes

2013 2012 2011 U.S. Non-U.S. Total U.S. Non-U.S. Total U.S. Non-U.S. To

(millions of dollars) Income tax expense Federal and non-U.S. Current 1,073 22,115 23,188 1,791 25,650 27,441 1,547 28,849 3 Deferred - net (116) 757 641 1,097 1,816 2,913 1,577 (1,417) U.S. tax on non-U.S. operations 37 - 37 89 - 89 15 - Total federal and non-U.S. 994 22,872 23,866 2,977 27,466 30,443 3,139 27,432 3 State 397 - 397 602 - 602 480 - Total income tax expense 1,391 22,872 24,263 3,579 27,466 31,045 3,619 27,432 3 Sales-based taxes 5,992 24,597 30,589 5,785 26,624 32,409 5,652 27,851 3 All other taxes and duties Other taxes and duties 955 32,275 33,230 1,406 34,152 35,558 1,539 38,434 3 Included in production and manufacturing expenses 1,318 1,182 2,500 1,242 1,308 2,550 1,342 1,425 Included in SG&A expenses 150 516 666 154 595 749 181 623 Total other taxes and duties 2,423 33,973 36,396 2,802 36,055 38,857 3,062 40,482 4 Total 9,806 81,442 91,248 12,166 90,145 102,311 12,333 95,765 10

All other taxes and duties include taxes reported in production and manufacturing and selling, general and administrative (SG&A) expenses. The provisions for deferred income taxes include net credits of $310 million in 2013 and $330 million in 2011 and a net charge of $244 million in 2012 f effect of changes in tax laws and rates.

  The reconciliation between income tax expense and a theoretical U.S. tax computed by applying a rate of 35 percent for 2013, 2012 and 2011

follows:

2013 2012 20 (millions of dollars) Income before income taxes United States 9,746 11,222 1 Non-U.S. 47,965 67,504 6 Total 57,711 78,726 7 Theoretical tax 20,199 27,554 2 Effect of equity method of accounting (4,874) (5,254) ( Non-U.S. taxes in excess of theoretical U.S. tax 10,528 8,434 1 U.S. tax on non-U.S. operations 37 89 State taxes, net of federal tax benefit 258 391 Other (1,885) (169) Total income tax expense 24,263 31,045 3 Effective tax rate calculation Income taxes 24,263 31,045 3 ExxonMobil share of equity company income taxes 6,061 5,859 Total income taxes 30,324 36,904 3 Net income including noncontrolling interests 33,448 47,681 4 Total income before taxes 63,772 84,585 7 Effective income tax rate 48% 44%

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  NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Deferred income taxes reflect the impact of temporary differences between the amount of assets and liabilities recognized for financial reporting pu 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: 2013 20 (millions of dollars) Property, plant and equipment 50,884 4 Other liabilities 3,474 Total deferred tax liabilities 54,358 5 Pension and other postretirement benefits (6,573) ( Asset retirement obligations (6,083) ( Tax loss carryforwards (3,393) ( Other assets (6,246) ( Total deferred tax assets (22,295) (2 Asset valuation allowances 2,491 Net deferred tax liabilities 34,554 3

Deferred income tax (assets) and liabilities are included in the balance sheet as shown below. Deferred income tax (assets) and liabilities are classif current or long term consistent with the classification of the related temporary difference – separately by tax jurisdiction.

Balance sheet classification 2013 20 (millions of dollars) Other current assets (3,575) ( Other assets, including intangibles, net (2,822) ( Accounts payable and accrued liabilities 421 Deferred income tax liabilities 40,530 3 Net deferred tax liabilities 34,554 3

The Corporation had $47 billion of indefinitely reinvested, undistributed earnings from subsidiary companies outside the U.S. Unrecognized deferred on remittance of these funds are not expected to be material.

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  NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Unrecognized Tax Benefits. The Corporation is subject to income taxation in many jurisdictions around the world. Unrecognized tax benefits refle difference between positions taken or expected to be taken on income tax returns and the amounts recognized in the financial statements. Resolution related tax positions through negotiations with the relevant tax authorities or through litigation will take many years to complete. It is difficult to pred timing of resolution for tax positions since such timing is not entirely within the control of the Corporation. It is reasonably possible that the total amo unrecognized tax benefits could increase by up to 20 percent in the next 12 months, with no material impact on near-term earnings. Given the long periods involved in resolving tax positions, the Corporation does not expect that the recognition of unrecognized tax benefits will have a material imp the Corporation’s effective income tax rate in any given year.

The following table summarizes the movement in unrecognized tax benefits.

Gross unrecognized tax benefits 2013 2012 20 (millions of dollars) Balance at January 1 7,663 4,922 Additions based on current year's tax positions 1,460 1,662 Additions for prior years' tax positions 464 2,559 Reductions for prior years' tax positions (249) (535) Reductions due to lapse of the statute of limitations (588) (79) Settlements with tax authorities (849) (855) Foreign exchange effects/other (63) (11) Balance at December 31 7,838 7,663

  The additions and reductions in unrecognized tax benefits shown above include effects related to net income and equity, and timing differences for whi ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility. The 2013, 2012 and 2011 chan unrecognized tax benefits did not have a material effect on the Corporation’s net income or cash flow.

The following table summarizes the tax years that remain subject to examination by major tax jurisdiction:

Country of Operation Open Tax Years Abu Dhabi 2006 - 2013 Angola 2009 - 2013 Australia: 2000 - 2003 2005 2008 - 2013 Canada 2006 - 2013 Equatorial Guinea 2007 - 2013 Malaysia 2007 - 2013 Nigeria 1998 - 2013 Norway 2000 - 2013 Qatar 2007 - 2013 Russia 2010 - 2013 United Kingdom 2010 - 2013 United States 2006 - 2013   The Corporation classifies interest on income tax-related balances as interest expense or interest income and classifies tax-related penalties as ope expense.

For 2013, the Corporation’s net interest expense was a credit of $207 million, reflecting the effect of credits from the favorable resolution of prior ye positions. The Corporation incurred $46 million and $62 million in interest expense on income tax reserves in 2012 and 2011, respectively. The r interest payable balances were $156 million and $385 million at December 31, 2013, and 2012, respectively.

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  SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES (unaudited) The results of operations for producing activities shown below do not include earnings from other activities that ExxonMobil includes in the Ups function, such as oil and gas transportation operations, LNG liquefaction and transportation operations, coal and power operations, technical s agreements, other nonoperating activities and adjustments for noncontrolling interests. These excluded amounts for both consolidated and equity com totaled $886 million in 2013, $2,832 million in 2012, and $2,600 million in 2011. Oil sands mining operations are included in the results of operati accordance with Securities and Exchange Commission and Financial Accounting Standards Board rules.

Canada/ United South Australia/ Results of Operations States America Europe Africa Asia Oceania T

(millions of dollars) Consolidated Subsidiaries 2013 - Revenue Sales to third parties 8,371 2,252 5,649 3,079 5,427 730 2 Transfers 6,505 5,666 5,654 15,738 8,936 1,405 4 14,876 7,918 11,303 18,817 14,363 2,135 6 Production costs excluding taxes 4,191 3,965 2,859 2,396 1,763 654 1 Exploration expenses 394 386 245 288 571 92 Depreciation and depletion 4,926 989 1,881 3,269 1,680 334 1 Taxes other than income 1,566 94 474 1,583 1,794 427 Related income tax 1,788 542 4,124 6,841 5,709 202 1 Results of producing activities for consolidated subsidiaries 2,011 1,942 1,720 4,440 2,846 426 1

Equity Companies 2013 - Revenue Sales to third parties 1,320 - 6,768 - 21,463 - 2 Transfers 1,034 - 64 - 6,091 - 2,354 - 6,832 - 27,554 - 3 Production costs excluding taxes 551 - 459 - 660 - Exploration expenses 19 - 15 - 426 - Depreciation and depletion 207 - 169 - 955 - Taxes other than income 51 - 3,992 - 7,352 - Related income tax - - 832 - 8,482 - Results of producing activities for equity companies 1,526 - 1,365 - 9,679 - 1

Total results of operations 3,537 1,942 3,085 4,440 12,525 426 2

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Canada/ United South Australia/ Results of Operations States America Europe Africa Asia Oceania T

(millions of dollars) Consolidated Subsidiaries 2012 - Revenue Sales to third parties 6,977 1,804 5,835 3,672 6,536 1,275 2 Transfers 6,996 5,457 6,366 16,905 9,241 932 4 13,973 7,261 12,201 20,577 15,777 2,207 7 Production costs excluding taxes 4,044 3,079 2,443 2,395 1,606 488 1 Exploration expenses 391 292 274 234 513 136 Depreciation and depletion 4,862 848 1,559 2,879 1,785 264 1 Taxes other than income 1,963 89 513 1,702 2,248 446 Related income tax 1,561 720 5,413 8,091 6,616 281 2 Results of producing activities for consolidated subsidiaries 1,152 2,233 1,999 5,276 3,009 592 1 Equity Companies 2012 - Revenue Sales to third parties 1,284 - 6,380 - 20,017 - 2 Transfers 1,108 - 67 - 5,693 - 2,392 - 6,447 - 25,710 - 3 Production costs excluding taxes 467 - 369 - 484 - Exploration expenses 9 - 17 - - - Depreciation and depletion 176 - 152 - 676 - Taxes other than income 42 - 3,569 - 6,658 - 1 Related income tax - - 894 - 8,234 - Results of producing activities for equity companies 1,698 - 1,446 - 9,658 - 1 Total results of operations 2,850 2,233 3,445 5,276 12,667 592 2

Consolidated Subsidiaries 2011 - Revenue Sales to third parties 8,579 1,056 8,050 3,507 6,813 1,061 2 Transfers 8,190 7,022 7,694 16,704 9,388 1,213 5 16,769 8,078 15,744 20,211 16,201 2,274 7 Production costs excluding taxes 4,107 2,751 2,722 2,608 1,672 497 1 Exploration expenses 268 290 599 233 618 73 Depreciation and depletion 4,664 980 1,928 2,159 1,680 236 Taxes other than income 2,157 79 631 2,055 2,164 295 Related income tax 2,445 969 6,842 7,888 6,026 353 2 Results of producing activities for consolidated subsidiaries 3,128 3,009 3,022 5,268 4,041 820 1 Equity Companies 2011 - Revenue Sales to third parties 1,356 - 5,580 - 18,855 - 2 Transfers 1,163 - 103 - 5,666 - 2,519 - 5,683 - 24,521 - 3 Production costs excluding taxes 482 - 315 - 378 - Exploration expenses 10 - 13 - - - Depreciation and depletion 151 - 160 - 576 - Taxes other than income 36 - 2,995 - 6,173 - Related income tax - - 847 - 8,036 - Results of producing activities for equity companies 1,840 - 1,353 - 9,358 - 1

Total results of operations 4,968 3,009 4,375 5,268 13,399 820 3

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  Oil and Gas Exploration and Production Costs

The amounts shown for net capitalized costs of consolidated subsidiaries are $13,667 million less at year-end 2013 and $10,643 million less at year-end than the amounts reported as investments in property, plant and equipment for the Upstream in Note 9. This is due to the exclusion from capitalized co certain transportation and research assets and assets relating to LNG operations. Assets related to oil sands and oil shale mining operations are included capitalized costs in accordance with Financial Accounting Standards Board rules.

Canada/ United South Australia/ Capitalized Costs States America Europe Africa Asia Oceania T (millions of dollars) Consolidated Subsidiaries As of December 31, 2013 Property (acreage) costs - Proved 13,881 3,595 188 874 1,620 863 2 - Unproved 23,945 5,390 61 583 701 146 3 Total property costs 37,826 8,985 249 1,457 2,321 1,009 5 Producing assets 74,743 34,487 44,161 40,424 30,082 7,973 23 Incomplete construction 5,640 11,811 2,219 5,913 8,387 4,194 3 Total capitalized costs 118,209 55,283 46,629 47,794 40,790 13,176 32 Accumulated depreciation and depletion 39,505 16,827 35,108 24,570 17,455 4,529 13

Net capitalized costs for consolidated subsidiaries 78,704 38,456 11,521 23,224 23,335 8,647 18

Equity Companies As of December 31, 2013 Property (acreage) costs - Proved 77 - 5 - - -

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